Welcome to the Canadian Natural Resources 2009 second quarter results conference call.
I would now like to turn the meeting over to Mr. John Langille, Vice-Chairman of Canadian Natural Resources.
Thank you for attending this conference call. We will discuss our second quarter and first half results and our outlook for the balance of 2009, which were covered in a press release issued earlier this morning.
Participating with me today are Allan Markin, our Chairman; Steve Laut, our President and Chief Operating Officer; Réal Doucet, our Senior Vice President of Oil Sands; 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.
Before I turn the meeting over to the rest of the participants here, I'd just like to make some initial comments.
First of all, our financial results are obviously affected by the sales price we received for our oil and natural gas production. Year-over-year prices are reduced by about 50% and continue to be very volatile, but in this second quarter, they reacted in opposite directions, with oil increasing 38%, and natural gas decreasing 35% from the prior quarter. We would expect that this time the sales price of natural gas will continue to be under pressure as the fundamentals of supply versus demand continue to be negative.
Despite these swings in commodity prices, our balance portfolio of producing properties, backstopped by our prudent hedging programs and emphasis on cost control and returns contribute to a strong cash flow position, and importantly, in the second quarter, we realized almost $900 million of cash flow in excess of our capital expenditures. As expected, these funds have been directed toward repayment of our maturing bank debt and overall strengthening of our balance sheet.
Steve and Réal will cover our operations in more detail and Doug will expand on our financial results, but before we get those updates, I would ask Allan to make some comments.
Canadian Natural's balanced asset base and flexibility allows us to grow value in any business cycle. Overall, daily production is up on a BOE basis by 6% from last quarter, largely due to the addition of Horizon production volumes. Substantial progress has been made at Horizon during the second quarter and ramp up has been going very well.
Conventionally, we continue to allocate capital towards higher returning projects in crude oil. It has been challenging for the natural gas side of the business as returns currently remain far more attractive in our crude oil. We all need to get our costs down. In my opinion, the Canadian natural gas industry is at a crossroads.
To remain viable, all of industry, including producers, all levels of government, suppliers and other stakeholders must be vigilant on reducing cost and improving efficiencies. We see some provinces, such as British Columbia, which are proactively looking at ways to support the industry, but more must be done by all of us.
That said, natural gas remains an important part of Canadian Natural's portfolio. Though natural gas drilling is down significantly for the first half of the year, we have a very strong asset base, and continue to maintain our extensive land base throughout the basin, building an even stronger inventory of prospects for when improved natural gas economics return.
With over half of our crude oil projects falling into the heavy oil category, the second quarter benefited from a historically narrow heavy oil differentials contributing to strong returns in oil.
Internationally, the drilling program at Baobab in Offshore Cote d'Ivoire was completed during the quarter, and first production at Olowi in Offshore Gabon was also achieved.
Our priorities for the remainder of the year remain the same. We will continue to strengthen our balance sheet through the effective utilization of our resources, including capital, infrastructure, and services, and our people. Flexibility is getting tougher because of lack of natural gas drilling activity. Thank you.
As both John and Al have said, the second quarter was a solid quarter for Canadian Natural. Oil production was up 11% over the first quarter, driven by strong production volumes at Horizon, Baobab and from our primary heavy oil assets. We were well within our oil production guidance ranges and for Horizon, the North Sea and Offshore West Africa, we exceeded the top end of our production guidance.
Our operating cost remain low and with the exception of natural gas and Horizon, which remain unchanged, we lowered our operating cost guidance for the year. In these periods of commodity price volatility, Canadian Natural's strong, balanced and diverse asset portfolio, combined with our focus on low cost and affective operations, has allowed the company to generate substantial free cash flow. In 2009, each component of our asset base, gas, light oil, heavy and thermal oil, as well as Horizon will generate free cash flow. Our assets are strong and we are low-cost.
Let me briefly update you on each of our assets. Starting in Canada with gas. Our gas production delivered as expected in Q2, with no gas drilling occurring in second quarter, production declined as reflected in our Q2 guidance. For the remainder of 2009, we will reallocate capital from gas to our oil projects. We now expect to drill roughly 110 gas wells for 2009 versus roughly 140 wells previously planned.
Our gas production guidance remains unchanged and will decline as previously expected, reflecting the strength of our gas assets. The gas wells that are now being drilled in 2009 are being drilled to offset drainage, conserve land or are strategic in nature. With the current gas price and cost environment, it makes no sense to drill gas wells for any other reason.
Canadian Natural has a very well positioned gas land base, with strong positions and teams in conventional, foothills, resource and unconventional plays. Canadian Natural's plan in 2009 is not only to preserve, but strengthen our dominant gas asset base. For example, we continue to progress the delineation and understanding of our Septimus, Montney unconventional gas play. Despite the very low gas prices, we will drill five wells in 2009, two of which have been drilled in Q1 and continue to monitor the results from our existing eight wells.
We have over 70,000 acres of land on this play and we have seen a steady improvement in well results and our ability to lower cost. Our latest horizontal well IP'd at 15 million a day. We are strategically setting the company up for a meaningful, low cost development in the future. Any meaningful development on these lands however will wait until gas prices strengthen and the relative economics of gas can compete with the economics of oil.
Canadian Natural has the second largest land base in Western Canada. Canadian Natural dominates the land base and infrastructure in our core areas and as result we are a low-cost producer. As a low-cost producer, Canadian Natural is well-positioned to withstand a sustained low cost price environment. Currently, we have roughly 10 million cubic feet a day of gas shut in due to low prices. It pays to be the low-cost producer.
One of the strength of Canadian Natural is our low-cost diversified asset base and portfolio, and in this period of low gas prices, this is clearly evident. It is very difficult for gas assets in our portfolio to compete for capital with oil projects. That being said, low gas prices have a very positive impact on our Horizon operations, as well as our thermal heavy oil operations and hefty returns on these assets.
Canadian Natural's heavy and thermal oil assets in Canada are very strong and will continue to add tremendous value to Canadian Natural shareholders. Our thermal assets alone have 33 billion barrels of oil in place with 5.6 billion recoverable in our defined plan. Our plan is to add approximately 300,000 barrels a day of heavy oil production in a very step-wise, disciplined cost controlled manner.
Primrose East is our most recent incremental step on our road to 300,000 barrels a day of incremental production. As you know, we experienced a containment event at Primrose East early in Q1. We completed a significant amount of diagnostic work in the field and analysis of the containment event.
We believe we identified the event as a well-bore issue with one well-bore. A detailed report and an analysis was submitted to the provincial regulators in Q2. Our report recommends a number of preventative steps and further diagnostic testing, including diagnostic steam testing before we bring Primrose East back to full steaming capacity.
We are confident that this issue can and will be resolved and effectively managed going forward with minimal effect on the long-term performance of Primrose East. We have been working effectively with the regulators and have received regulatory approval to proceed with our diagnostic steam program. We expect to have all of the monitoring in place and calibrated and ready for first diagnostic steaming in the next two weeks, a very positive result.
As I mentioned in the last quarter, the results from Primrose East production flow back have been encouraging and continue to be encouraging. We're confident that Primrose East will meet and more than likely exceed pre-project expectations once these operational issues are behind us.
At Kirby, our next incremental 45,000 barrels a day production addition, we expect to receive regulatory approval this year. Before we kick off the development, we'll need this regulatory approval as well as complete the detailed engineering design work. As we said in our last conference call, we expect to see capital cost reductions in this commodity price environment and we'll need to see commodity prices and costs move more in line with each other before we proceed with Kirby.
At Pelican Lake, we continue with our program to convert the field to our highly successful polymer flood. As you know, Pelican Lake is a world-class pool, with four billion barrels of oil in place, and between 350 and 475 million barrels recoverable, a very large pool. We expect to have the entire field on polymer flood by 2016. Pelican continues to generate significant value for shareholders.
Our primary heavy oil program continues to roll along effectively and efficiently. In this commodity and cost environment, primary heavy oil generates top-decile returns on capital in our asset portfolio. Importantly, it also generates the quickest payout and largest cash on cash return. Our dominant high-quality land base, infrastructure, and effective operations continue to make primary heavy oil one of the best value generators in our portfolio.
As a result of the very strong economic performance of oil relative to gas, we have allocated roughly $100 million of capital from gas to oil and we'll drill 40 less gas wells in 2009 and add 121 oil wells, made up of 86 primary heavy oil wells, seven Pelican wells, 17 thermal wells and 11 light oil wells.
In the North Sea, production has been steady and was slightly above the upper end of our guidance in Q2. In Q2 and in the first part of Q3, we successfully completed the 23-day plant turnaround in Ninian Central Platform on time and on budget. We also completed the drilling of the Deep Banff high pressure, high temperature gas exploration prospect, which was not successful and abandoned. Canadian Natural paying interest on this well is roughly 19%.
Turning to Offshore West Africa; at Baobab, our very successful four-well program was completed early in Q2, providing another 11,000 barrels a day of incremental net production. Production has remained solid through the second quarter and we are very happy with the performance of Baobab.
At Espoir production is steady. We had anticipated being able to accelerate the installation of additional compression capacity this summer. However, we reverted to the original schedule, which has the installation scheduled for late 2009 or early 2010, as we optimize the utilization of the heavy lift vessel between Espoir and Olowi. The additional Espoir compression will increase gas processing capacity and provide better processing reliability.
At Olowi and Gabon we have three producing wells on and one gas injection well. With two additional wells expected to come on stream within the next two weeks on platform C, our first of four platforms. In addition to placing these two wells on stream, we'll undertake a diagnostic work-over on our first production well with the goal of identifying any production restrictions that maybe impairing the production performance of the Olowi wells.
Production performance has not met our expectations from Olowi and current production performance seems to indicate that we have some form of impairment. It is anticipated that results from this work-over will identify any well-bore or reservoir impairment issues and potentially to remedial work-overs at later date to enhance production.
We have seen some positive indications from Olowi production, however, as the gas-oil ratios are lower than anticipated and if we can identify the pressure impairment mechanisms, does leave us some optimism about the overall success of Olowi in the platform C area.
As far as the progress in overall development of Olowi, all three remaining jackets have been installed and the deck for platform B will be installed in the next week or two depending on, to a small degree, to weather. The decks for platform D and A will be installed in sequence following platform B. The jack-up rig will complete the diagnostic work-over and then move to platform B.
It is too early at this point to address the ultimate reserve potential at Olowi and we'll monitor the well performance, and particularly results of the remaining wells on the next two platforms. We have to re-drill closely before revising the reserve potential at Olowi.
Overall, Offshore West Africa continues to provide some of the highest return on capital projects in our portfolio. Going forward, we'd be focused on reducing the cost of all developments, including the ongoing development of Olowi to be more in line with the current commodity price environment.
At Horizon, our world class oil sands mining project, we have made considerable progress and our ramp up in production volumes have exceeded the forecast. The second quarter production averaged 59,599 barrels a day, well ahead of expectations, driven by a strong month of June, in which production averaged 92,097 barrels a day of light sweet, 34 degree API oil. In July, we also exceeded our forecast with production of 83,573 barrels a day, despite an unexpected failure of an ancillary component on our wet gas compressor.
Although this failure was unexpected, we are well aware that we're likely to have more of these issues until we reach a point where all the kinks in our operations are worked out and we make it through the high infant mortality period on equipment, normally seen on new plants, particularly with the plants of the size and complexity of Horizon.
It's, however, clear from the performance of Horizon to-date, the following key points.
One, there are no design flaws that will restrict meeting the Phase I design capacity of 110,000 barrels a day. In fact, we've had days where we've run up just over 120,000 barrels a day. Admittedly, the sun, moon and all of the stars lined up on these days allow us to exceed design capacity and it is unreasonable to expect that we can sustain rates of our design capacity. Nonetheless, design is not an issue.
Our product quality is excellent and we have demonstrated our ability to exceed target specifications. We have, in fact, out-backed the amount of treating, we're undertaking a higher treaters as we are producing a product to a higher spec and not receiving commensurate pricing towards increase in quality.
Thirdly, we have a very strong operations, maintenance and process teams, who have done an outstanding job ramping up production, as well as proactively solving ramp up issues.
Four, the Horizon operation is capable of being very effective and efficient. Our operating costs in Q2 were C$42.65 a barrel, significantly better than we had forecast for this part of the ramp up schedule. Helped somewhat by energy costs, at this point we expect to be well within our offering cost guidance for the year of C$35 to C$40 a barrel.
The fifth point, although it's early, we already have seen some indications of potential de-bottlenecking opportunities to enhance the overall reliability, increase throughput and lower operating costs. We expect over the remainder of the year to fully evaluate these opportunities for execution in the future.
With the great success we've had ramping up Horizon production, it is tempting to raise our production guidance for the year. However, Horizon is a big, complex new operation and we can expect some rough patches in the days ahead. That being said, every week that goes by we overcome additional operational challenges and put them behind us as we progress to a steady reliable operations.
Now, before I give you a quick update on where we are in future expansions at Horizon, I'll ask Réal to give you a quicker update on some of the challenges we have overcome, the risks and challenges we see upcoming, what our plans are to address these potential risks and a bit of color on the potential de-bottlenecking opportunities identified at this point.
So I'll take you plan by plan and give you few example here of the challenges and the opportunities we have, starting with the mine. We have basically no or very little risk right now in challenges. We have five shovels running. We have 23 trucks in operation. We have ramp up of manpower and everything is running okay. We're using some of the trucks right now to do our inter-burden, waiting for having a full production because we have this capability.
In the ore preparation plant, we have several issues and I'll name you four here. One is the ore quality. We're opening up the mine, so we're on the top bench, and the top bench is great or slightly lower than our average and the fine is slightly higher. We have 10% grade. We have two to 25% fine.
What the higher fines does is when we get into the extraction plant, it takes longer to process the material. Another thing it does also is, when the product that comes out of the ore preparation plant to go into the froth treatment plant has a higher water content. Normally by design, the bitumen content coming out of the OPP would be about 50% to 60%. Right now, we're around 40% to 50%. So we have to tweak and tune the plant to really get to these specs for the froth treatment plant.
Another challenge we have is the higher-abrasive material. That has forced us to readjust our preventative maintenance schedule. The fillings pipe and the hydro-transport pipe replacement and rotation cycle has been reduced, so we have more maintenance to do.
Another thing too is that that allowed us also to determine the trend of wear on the pipe, which when we replace them, we're going with a different specification of the pipe, higher, wear resistant pipe and different kind of material to help us out also to sustain our operation.
Another one was, we saw our conveyor pulley bearing running pretty hot. That was due to clearance we had on the bearings, even though these bearings have been used in the oil sands before. The one we bought, as you remember, we bought pretty well all of our equipment at a very high economy time and the bearing clearance wasn't quite adequate. So we're changing them under the bitumen maintenance right now. We have already about 70% of them changed and the other ones are going to be changed also before the end of the year. It does not effect the production since we have two plants and we're changing them on the opportune.
Another significant improvement was the secondary crusher design, and we have done this so that we end up with an oversized reject material down to zero and that's a big advantage because now we can process 100% of our material that way. There have been significant changes there in terms of tooth arrangement, design and so on and reliability also of that secondary crusher.
On the primary upgrader, we had, like Steve mentioned, our wet gas compressor. You got to understand that this compressor is a 21,000 horsepower, electrical driven compressor. So it's a huge machine and the startup of this machine, which usually take anywhere from 15 to 30 seconds to a minute, has a tremendous amount of torque. So we cannot start this machine more than three times a day, otherwise we're burning equipment and we are overheating it.
As a matter of fact, we did burn the exciter, which we've changed already and few other peripheral components on it, which we are continuing to change right now. We're monitoring that. We've learned a great deal about it. This machine, once it's in operation, is a very highly reliable machine and shouldn't be a problem in the future. So we have pinpoint what was the issue and we have solved them.
We had also several pump failure infant mortality. The good news about it is, once we've changed them, they run really good. The vibration is reduced to almost zero, and we can see that they're going to be a very highly reliable also from now on.
All in all, in these things in the froth treatment and the extraction plant and the upgrading has given us here a tremendous learning experience.
We also had a pressure swing absorber valve replacement in our hydrogen plant. There is 12 beds in the hydrogen plant on this PSA plant and there is six valves per bed. So that's 72 valves here that also during the manufacturing process and the assembly process were done below standard. So, each of these valves will have to be replaced.
We have replaced eight beds already and the other four are in the schedule also to be replaced under opportune time. We lost some production because of it so far. However, from now on, they will be under opportune maintenance, so we will have no more loss of production. Second thing is the new valves, once they've been replaced they behave really well and the plant is becoming quite reliable.
We have seen some opportunities throughout the plant also. We are running right now and mining on the top bench and it looks like the top bench is producing lighter bitumen than anticipated, which is an advantage actually because the API is higher for the our bitumen coming into the plant.
What is does, is it brings more diesel into the SCO mix and with this we see an opportunity right now with very, very little modification to the plant to be able to produce raw diesel material, which would have, of course, an enhanced price for it. So that would be a good advantage for us. So we're evaluating this right now. It looks like it's quite feasible for us to do that here shortly.
I think we've looked at tool is the addition of a one intermediate tank that would allow us to continue production next year while we're changing the catalyst in our gas oil plant. That would be also a tremendous advantage actually, because it would allow us another 10 to 14 days of production that otherwise were planned to be down.
So week-over-week we have our process people and we have our maintenance people, who are watching this plant, and we're getting more and more reliable. Most of all, we're having a higher predictability now on the production for the future. So we've learned a great deal this way.
Another opportunity that we've had, whether we turn this into an opportunity actually was the winter startup. In doing so, we've learned a tremendous amount of experience in terms of running throughout the winter. It has helped a great deal so far to enhance our winterization program, which is well underway right now and should be completed in September. All the installations and heat tracings and so on have been tested and we would be quite in good shape right now to run over the winter.
Those are only a few examples of what we're doing these days, and I think the learning is very efficient and we're putting that into operations to get a better reliability on this.
As you can see, we're not without our challenges and our opportunities. From the beginning we have faced many challenges at Horizon and have overcome each and every challenge. Getting through the production ramp up and achieving steady, reliable production is the yet an other challenge.
I'm not only confident that we will, as we have in the past, overcome these challenges, but we'll capture the opportunities that will present themselves as we gain operating experience with this new operation. That confidence is based on the strength and depth of our teams throughout the company.
Horizon is a world-class asset with over 6 billion barrels of recoverable oil. We have 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.
Currently Canadian Natural is proceeding with tranche 2 of our phase 2/3 expansion and we will only proceed and proceed very carefully with tranches 3 and 4 when we are certain of the following.
One, we can implement all our lessons learned from phase 1 to build and enhance on our successful phase 1 execution strategy. Two, we see significantly less cost and cost pressure going forward and we see a period of more stable commodity prices with a risk basis biased to the upside versus the down side.
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 in magnitude to Horizon, yet in more manageable sizes and are in my opinion the hidden gem in our portfolio and in this low gas price environment, generate even a greater value for shareholders.
Our light oil assets internationally and our primary heavy oil assets in Canada continue to generate strong returns. In this low gas price environment, our strategy of maintaining a well-balanced portfolio and the fact that we are a low-cost producer, will ensure that we'll be able to weather a sustained period of low gas prices.
Our teams are strong throughout the company, and as Doug will point out, our balance sheet is strong and getting stronger. Our capital program is very flexible, giving Canadian Natural the ability not to only maximize the value of our well-balanced portfolio but also capture any opportunities that will present themselves this environment.
Canadian Natural is strong, and in today's environment, with our team, our strategy and our assets, I believe Canadian Natural has a clear competitive advantage.
With that, I'll turn it over to Doug to update you on our financial position and our prudent financial management.
Operationally and financially, the results of the second quarter and the first half of 2009 were very good. We have now completed our big dollar projects and with Horizon phase 1 on-stream and producing SCO at better than anticipated grades in the second quarter, all of our core areas are generating free cash flow.
In the first half of 2009, Canadian Natural generated close to $2.9 billion of cash flow from operations or $5.32 per share and $467 million of earnings. We incurred $1.7 billion of capital expenditures. This has allowed us to reduce long-term debt by $1 billion from the beginning of the year to slightly less than $12 billion at June 30, with targeted reductions as we move through the year.
Our balance sheet metrics continue to improve with debt-to-book capitalization of 39% and debt-to-EBITDA of 1.7 times, both at or below the midpoint of our targeted ranges. Our liquid resources remain strong.
At the end of the second quarter, our undrawn bank lines exceeded $1.7 billion. We continue to systematically retire the non-revolving credit facility which matures in October. To-date, we have reduced the outstanding balance to just over $1 billion from the $2.3 billion outstanding at December 31. With a further $350 million being repaid since June 30, we are in excellent position to retire the remaining $1 billion outstanding from an allocation of cash flow from operations, which includes the proceeds from our commodity hedge program.
Our revolving syndicated facilities are in place through June 2012, and our debt maturities are manageable at less than $500 million per year through 2012. Our access to the debt capital markets is good, with strong and stable rating and of course considering the apparent and remarkable recovery of the financial and debt capital markets.
We remain active with our commodity hedge program, 92,000 barrels of oil per day of crude oil puts with a floor of $100 per barrel. In addition, we have 25,000 of collars with a floor of $70 through the remainder of 2009. For natural gas, we have 400,000 GJs per day of AECO natural gas physical sales contracts with an average price of $5.29 per GJ through to the end of December. In 2010, we have 50,000 barrels per day of crude oil collars with a floor of $60 and a ceiling of $75 per barrel. In addition, we have 220,000 GJs of AECO with a floor of $60 and a ceiling of $8 for all of next year.
We continue to monitor this program for expansion opportunities into 2010 and our commodity hedge book is posted on our website and is presented in the press release.
Finally, we have declared a quarterly cash dividend of $0.105 per share, payable October 1, continuing in the tradition of paying dividend for the ninth consecutive year.
Canadian Natural continues to grow and diversify our asset portfolio with production from conventional oil and natural gas, new production fields in Canada and Offshore West Africa and the addition of synthetic crude oil volumes from the oil sands mining and upgrading, we continue to grow shareholder value through the prudent management of our world-class assets.
I will return you to John for some closing comments.
Thanks very much for the updates Steve, Réal and Doug. As you have heard, our operations continue to be driven by our long-standing basic strategy of having a balanced portfolio that allows us to allocate capital where it can create sustainable returns and value.
With that, operator, I would open up the conference call for any questions that people may have.
Our first question is from Andrew Fairbanks from Banc of America.
Andrew Fairbanks - Banc of America
Just a couple of questions on Horizon, if I could. There seems to be still a reasonable wedge between the production at about 60 MBD and then the sales barrels at 47. So first, do you think that that wedge will continue as a ramp up through the balance of the year or will production and sales come together a little more closely as you get into the second quarter?
Andrew, Steve Laut here. That wedge will disappear as we sort of get towards steady operation. I think it will be less in the third quarter and it all will disappear in the fourth quarter and the first quarter. It's just part of the ramp up where you get to fill the tanks faster than you're selling, and we've got that happening in second quarter.
Andrew Fairbanks - Banc of America
Then the next one is just on operating costs with $42.65 also on sales barrels, if you could put that on a production barrel basis, we would get that to be $33.50 per barrel, and just want to ask is that fair. So is that really the case at 54% of capacity essentially, you're already down to $34 a barrel on an operating cost basis.
I think maybe it's going to be less, giving us the benefit of the doubt in your math, I think it would be probably more like $38.
Our next question is from Martin Molyneaux from FirstEnergy Capital.
Martin Molyneaux - FirstEnergy Capital
Réal you kind of lost me a little bit in terms of saying that the SCO mix had a higher diesel content. Does that mean that you can actually output diesel component that you'd be able to use yourselves?
Martin, I think we'll get Réal to give you a little bit more detail, but what it says is our percentage of the SCO split has higher distillate or diesel content.
Martin Molyneaux - FirstEnergy Capital
So we have more diesel available and what we'll have to do is fine tune our hydrotreating. We can make road diesel by having higher C10 content and less sulphur. That's what we have got to get to. Réal I think we can do that.
That's the intent here. Instead of selling a higher percentage of diesel in our CO, which we're not getting really a real good value for, we'll segregate this and sell diesel.
Martin Molyneaux - FirstEnergy Capital
Second question goes to Primrose East. What do you think the problem is? Assuming that your steam diagnostics in the next few weeks here shows what you think it's going to show, what is the remediation process and what's the timing?
Well, Martin, we believe strongly that it is a well-bore issue and that we have lost I'd say a good bond between the cement and the formation, basically the well-bore hole. That when the pressure that we had steam and oil go up that sheath, and make its way to a containment problem. So we need to determine that for sure, and rule out any other possibilities, but if it is that issue, then it's a simple matter of abandoning that well and making sure it's cemented off properly. We'll be able to continue. Again, we don't know exactly for sure and we have to rule out all other possibilities before we can go to proceeding, that's the whole process of diagnostic steaming, so we could step into it and see early on exactly what's happening.
Martin Molyneaux - FirstEnergy Capital
I guess probably the best way to look at it is, if we take the full program before we find out exactly what it is and to remediate it, we could be in full steaming probably later this year, but more likely early in 2010.
Martin Molyneaux - FirstEnergy Capital
Like a lot of other companies, you're probably getting into 2010 early budget mode right now. What are your thoughts in terms of kind of giving marching ordering to the troops in terms of commodity price outlook?
In terms of commodity prices, Martin, we feel oil prices will be probably fairly stable, although I'd say, have a fairly high level of anxiety that they could retrace back to lower levels. On the gas side, I think we are fairly confident that gas prices in the short-term are going to be low and may go lower than they are today. I think we'll see some rebound in gas prices, but likely not to a level that many in the industry would hope for. So we're probably seeing $5 range for 2010 as a upside number.
Martin Molyneaux - FirstEnergy Capital
Given where oil prices are today in differentials and the success you had with the polymer flood to-date, what's holding you back from accelerating the Pelican Lake polymer flood?
I think only thing that holds us back is that we're very focused on being effective and cost effective primarily. We want to make sure that we do it probably. We have to have the facilities matched with the drilling and conversion. So it's just a case of being very methodical and disciplined and keeping your costs low.
Our next question is from Mark Polak of Scotia Capital.
Mark Polak - Scotia Capital
Thanks. Few questions for you on West Africa. First Baobab, now that you've got the four wells completed, where would you see peak production heading to, would be somewhere up in the 50,000 barrels a day gross eventually?
I think what we're seeing at Baobab is, is it a water flood. At some point in time here we expect to see some water breakthrough in the wells as you do in all water floods. So, I don't expect to see peak production grow much from where we're today. We will maintain that production. There will be another in-field program that we will develop, and that really depends on how the water flood progresses and how soon we see water breakthrough. So, we're monitoring that very carefully, but obviously Baobab has turned out to be a very good project for us. We're already working on what the next in-field program will be.
Mark Polak - Scotia Capital
Is there I guess in addition to the in-field, would you see, now that you're finished up, is there more exploration potential on the block there.
In Côte d'Ivoire itself we do see some potential to drill at Acajou, which is between Baobab and Espoir. It is partially in deep water and partially in more moderate depth water. We have a discovery there already. We need to delineate that pool and there are other smaller pools around Espoir that we may take a look at drilling off the platform. So there is smaller pools there, plus Acajou could be, I would say a pool maybe 50% to 60% the size of Espoir.
Mark Polak - Scotia Capital
At Olowi, with the problems you've had on the C platform, do you see any problems getting up to the 20,000 barrel a day or so level as the other platforms come on, or do you think with the remediation work that shouldn't be a problem?
I think it could be a concern. We are concerned about it. Platform C has raised some concerns for us. We may have some impending issues that may take that away, but it can't be say that for sure. It is one of the platforms out of the four platforms. Olowi is a big pool clearly, so we may see some variability. We need to drill the other platforms before we know for sure. But I would say just based platform C it would be difficult to get to the 20,000 barrels a day if we have the same kind of results.
Mark Polak - Scotia Capital
Then just one final one. Can we just talk about the potential for commercializing the gas reserves at Olowi and if there are any discussions underway with regards to that?
We have had discussions and we have entered into some sort of general understanding or memorandum of understanding with some L&G players in the area who are trying to tie much of these what we call big gas pools, but are actually small gas pools for an L&G project together to make one L&G project. So, we are participating with that. We are also looking at maybe a gas to liquids type plant and things like that. But that's very early on and we're not even really in the scoping stage yet.
Our next question is from Brian Dutton from Credit Suisse. You may go ahead.
Brian Dutton - Credit Suisse
I was just wondering if you could give us some of your thoughts here on the heavy oil market and where you think markets may be trending both near and long term?
Thanks, Brian. Our view is that the heavy oil differential has traditionally been around that 30 to 32%. We believe there has been a structural change in the heavy oil market with Mexico volumes coming off and coming off hard and looking like it will be very difficult for them to return to levels they were before. Venezuela has its own issues that will probably be here for a while. That gives an opportunity for Canadian heavy oil to move into that market with the pipelines being built.
We will see that between the Midwest and the Gulf Coast where the differentials in the Midwest are much higher than the Gulf Coast collapse. So, structurally we believe the differentials for heavy oil will probably be more in that 20 to 24% range. Obviously, it will fluctuate as it always does but averaging around that range versus the 30 to 32% has historically. So, we think there has been a structural change in the heavy oil market and it's for the positive benefit of all heavy oil producers.
Brian Dutton - Credit Suisse
Is there any way for you at this time to walk in the spread to reduce your risk on your investments?
It's difficult to do that right now. There's not much liquidity, there is not much of a market. We are trying to build a market but it will take time before that happens.
There are no further questions registered at this time. I'd like to turn the meeting back to the presenters.
Thank you very much, operator, and thank you very much attendees for dialing into our conference call. As always, if you have further questions, don't hesitate to contact us. Have a good day. Thank you very much.
Thank you. The conference call is now concluded. Please disconnect your lines at this time and we thank you for your participation.
Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.
THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.
If you have any additional questions about our online transcripts, please contact us at: email@example.com. Thank you!