Good morning, ladies and gentlemen. Welcome to the Canadian Natural Resources 2011 First Quarter Conference Call. I would 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 first quarter 2011 results and also update our plans for the balance of this year and beyond. Participating with me today are Allan Markin, our Chairman; Steve Laut, President; Réal Doucet; and Peter Janson, our Senior Vice Presidents at our Horizon Oil Sands mining operations; 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 reserves are both expressed as before royalties, unless otherwise stated.
I'll just make some initial comments before I turn the call over to the other participants. Our operational and financial results from our E&P assets continue to perform extremely well with production gains, good control over operating cost and cash flow of almost $1 billion from North American operations and $260 million from our international areas. The cash flow from our mining operations was adversely affected by the suspension of production due to the coker fire early in January, with revenues declining by almost $600 million from the fourth quarter of 2010, and continuing operational costs reflecting the fixed nature of those costs. We are now making good progress to get the mining operation repaired and back in operation as soon as possible to again provide substantial cash flow to our operations.
Crude oil sales prices continue to be volatile, with the Brent pricing receiving of premium over the West Texas price. Our international sales are priced off the Brent benchmark and are, therefore, benefiting this quarter. Our revenues from sales of heavy oil have been adversely affected by the higher differential resolving from pipeline restrictions, a differential of 24% off West Texas in Q1 of this year versus a differential of only 12% in Q1 of last year. Recent indicative spreads, however, for May and June, appear to be improving coming in closer to 16% off the West Texas price. Our overall financial position continues to be excellent, with debt-to-book cap [capitalization] remaining at 29% and debt-to-EBITDA amounting to only 1.1x.
Before we turn the call over to Steve, Allan, would you like to make some comments?
Yes, thank you, John. Good morning, everyone. Today, I'm 66 years old going on 46 (sic). Hang on. We are now well into 2011 and are well focused to deliver. This strength is demonstrated by our commitment to maximizing shareholder value and we've done so by working hard to achieve the most efficient and effective operations. We are minimizing our environmental footprint and are implementing safe production, which allows good to excellent cost control.
During the first quarter of 2011, our teams have again demonstrated this in the North American Exploration and Production crude oil and NGLs area, as we lowered per-barrel production expense by 6% from the same quarter last year. As well, record production of approximately 97,000 barrels per day of primary heavy crude oil, one of our several highest return assets was attained, and we showed a 6% increase from the same quarter last year. The strong production we had in the North American Exploration and Production areas was supported by our record drilling program in primary heavy oil and continued development from our thermal assets. We are making good progress on Horizon repairs and look to be coming on stream in line with our previous thoughts.
Additionally, we took advantage of this downtime to accelerate some of the turnaround work originally planned for 2012 into 2011. This will allow us to defer the balance of that turnaround into 2013. Our diversified and vast portfolio of assets allows us the flexibility to allocate capital to projects that provide the highest return to our shareholders. This, coupled with our strong balance sheet, allows us to support mid- and long-term projects that provide sustainable growth for Canadian Natural. We are continually poised for a progressive future as we have the people and the management expertise to execute these projects and to overcome and learn from hurdles as we continue to build a world-class Canadian oil and gas company.
Over to you Steve.
Thanks, Al, and good morning, everyone. As Al said, Canadian Natural is a strong well-balanced company with diversified assets, which hold significant upside. Our assets are complimented by strong and experienced technical, operational and financial teams who, working together, have consistently delivered effective and efficient operations that are safe, minimize our environmental footprint and are low cost. As we enter into our next step in the evolution and growth of the company, we are generating substantial cash flow, so the focus becomes on ensuring effective allocation of our cash flow to maximize returns. Our ability to take on more mid- and long-term projects leverage our expertise and technology, across our vast asset base, is significantly enhanced. Canadian Natural is poised to unlock significant value and generate more sustainable returns for shareholders on a consistent basis, year after year.
Canadian Natural is in a very strong position, and we will maintain our 2011 capital program despite the Horizon incident. In fact, as you'll see, we increase our oil and liquids-rich drilling budget for 2011. In 2011, we'll see significant production growth for primary heavy oil, light oil and Pelican oil. Not only are we delivering growth on oil production of our asset base, even more impressively is our roughly 40% of our 2011 capital spend does not add production in 2011.
Now clearly, the Horizon fire result in a temporary hit to our 2011 production and cash flow. However, it is also very clear that our assets are strong and generate significant free cash flow, allowing Canadian Natural to not only deliver the value growth from our assets in the near term, but ensure we keep our mid- and long-term capital projects on track and do not compromise the future. Few, if any, companies in our peer group have the assets, the balance sheet and the people to effectively execute our defined yet flexible plan, which delivers not only production growth but generates substantial free cash flow and sustain an event, such as Horizon fire, ongoing.
Before I touch on each of the operating areas, I'll make a few comments on the change to our capital budget. The first quarter saw very good results from our oil drilling in Canada. And as a result, we'll increase our capital spending on light and primary heavy oil by about $230 million. We've also increased our spending and Liquids-rich Gas in Canada by $150 million. Most of this crux will be coming on in the fourth quarter, as it's drilled late in the year, and as a result, we'll not adjust our production guidance for these changes. You'll also see that we anticipate spending up to $550 million on property acquisitions in 2011, up $200 million from the last conference call. A significant portion of these acquisitions is on land purchases outside the normal land sales and brings no new production at this point. However, we've increased our midpoint of gas guidance by 2% or 25 million cubic feet a day.
At Horizon, we have reduced the capital we allocated in 2011, due to some cost savings achieved on the expansion plans and a deferral of some work in to 2012, as we take the opportunity to better plan and cash our potential cost synergies. Capital reduced at Horizon by $170 million to $300 million in 2011, as we have a flexible capital budget at Horizon, as you know. Overall, the capital budget has increased by about $360 million.
Now, we'll quickly hit each of the areas, starting with gas in Canada. Canadian Natural's overall gas strategy for gas is to leverage or dominate infrastructure and land base, maintain our position as the most effective producer and continue to strengthen our unconventional and tight gas asset base, by delaying new and emerging plays and leveraging new technology to open up additional resources, lower cost and ultimately position ourselves for strengthening of gas prices when they arrive. Septimus is a good example of this strategy. Our money play at Septimus, where we have been running production, about 60 million [cubic feet] a day and 1,800 barrels of liquids, well above the 50 million a day design capacity of the plant. Septimus production performance has been very strong and we'll be able to expand our plant to 200 million a day and 10,000 barrels a day of liquids. So we choose to allocate the capital to Septimus. The original expectations at Septimus were about 4 Bcf per well and it's now clear, based on production performance, that we're headed for reserves north of 6 Bcf a well and close to 300,000 barrels a day of liquids per well. As a result, we have decided to drill another 8 wells at Septimus in the second half of 2011, with production coming on stream in 2012. With the excellent results and strong cost controls of Septimus, it now competes with our oil projects at $3.50 AECO gas price. A decision to expand the Septimus plant to 100 million a day in 2012 will be made towards the end of 2011.
We're also drilling another 14 gas wells in 2 of our liquids-rich unconventional plays at the Cardium, at Edson and Wild Hay, Northwest Alberta. As a result our gas capital program, as I said earlier, will be increased by roughly $150 million for 2011.
Let me turn to our primary heavy oil assets. Canadian Natural has a dominant land and infrastructure position, with 9,000 wells in inventory. As a result, Canadian Natural's operations in heavy oil are very, very effective. With current oil prices and heavy oil differentials, even though they're wider, our heavy oil projects generate some of the highest return projects in our portfolio. As you heard me say in the last conference call, we expect to grow primary heavy oil production by 11% in 2011. However, the execution and results from our winter drilling program have been highly effective. And as a result, we'll now expect to grow production by 13%, with a midpoint guidance range rate of roughly 105,000 barrels a day. We're add another 35 wells to our planned 790-well drilling program, taking us to 825 wells, up 27% over 2010. And deliver over 20% exit-to-exit production growth. With similar drilling programs in 2012 and beyond, you can expect to see production growth of roughly 10% per year going forward as we have the inventory to maintain this program for many years to come, as long as commodity prices remain favorable in this very high-value portion of Canadian Natural's portfolio.
We're also increasing our targets for light oil and liquids production growth in Canada. At the last call, we targeted production growth of 11% in 2011. And based on the first quarter performance and adding 20 more light oil wells, we now target midpoint guidance growth of 15%. A very strong performance in the Light Oil and Liquid side of the business. As you know, Canadian Natural has large light oil land holdings in Canada, and then the light oil basin in Canada is a mature basin. However, with an advancement in technology and higher oil prices, we're able to implement this technology to increase recovery and production over the mid- and long-term, creating significant value for shareholders. Our light oil liquids growth target for 2011, as you know, has been increased to 15%. And going forward, it will be a bit lumpy as EOR projects kick in. So we expect to target about 7% growth in 2012, and average 6% to 7% growth year after year. Substantial light oil growth in Canada.
Turning to Canadian Natural's vast and superior thermal heavy oil asset base, where we have a dominant land position, with over 1.1 million acres of high-quality undeveloped land. Canadian Natural's thermal heavy oil assets contain over 34 billion barrels of bitumen in place and over 6 billion barrels recoverable. Very comparable to the 6 billion barrels we have at our world-class Horizon asset. Canadian Natural's taking a very disciplined, stepwise and cost-effective plan to develop these resources with production steps of between 30,000 or 40,000 and 60,000 barrels a day every 2 to 3 years, hopefully taking production to over 480,000 barrels a day of capacity.
Production growth for 2011 is targeted at 8%, down somewhat from expectations, as we have adjusted the steam schedule and pushed a portion of the production cycle into 2012. The steam schedule is pushed out to make some steam header repairs, heat integration, steam proportion issues, as well as some modifications to our steaming strategy at Primrose East to ensure reservoir steam conformance. These issues are, for the most part, behind us. However, the result is a delay in production volumes showing up as steam was delayed in the cyclic process.
Kirby is our next step in Canadian Natural's defined plan to add over 480,000 barrels a day of thermal production capacity. We'll develop Kirby in 2 phases, as well as de-bottleneck opportunities for Phase 1 down the road. We have over 1.5 billion barrels of petroleum in place and 500 million barrels to recover in the Kirby development. Kirby South was sanctioned in November 2010 and is expected to peak at 40,000 barrels a day. In 2011, we will submit the rig pre-application for Kirby North and to take Kirby to be between 70,000 and 100,000 barrels a day.
We're on track at Kirby South. All major equipment has been ordered. And we committed to roughly 34% of that overall capital project or $400 million, and are tracking to our cost estimate. Our workforce camp is nearing completion and we're expecting to gear up for full construction in June. The mechanical completion of the plant and plant facilities is targeted for August 2013, with first team in December 2013 and first oil out February 2014.
Our thermal heavy assets are very strong and are a value growth for many years to come. Canadian Natural's program targets production growth 8% in 2011. For 2012, production is targeted to 105,000 to 115,000 barrel a day range, up 10%. And in 2013, production will increase roughly 15% to 125,000 to 130,000 barrels a day. And in 2014, with Kirby carrying on stream, we targeted production growth over 20% in the 150,000 to 160,000 barrel a day range, so production growth from our thermal assets, which are key drivers in our overall corporate near mid- and long-term production growth profile.
Turning to Pelican Lake. Our world-class oil pool, with 4.1 billion barrels of oil in place and 500 million barrels recoverable. About 17%, overall, is expected to Pelican Lake. We continue to roll out the highly successful leading-edge polymer flood, which creates significant value for shareholders. We have had great success at Pelican Lake. However, we're still in the steep part of the learning curve, and we believe there is significant room to optimize performance and cost. As I mentioned at the last conference call, we are seeing different response times across the pool, particularly in the South. Production responses have been slower and we look to be about 6 months longer than we had previously expected. Based on this response, we're expecting oil recoveries that could be significantly exceed our expected recovery of 25% in certain areas of the polymer flood. Although it's too early to be definitive, it appears that we may be in a 30%-35% range in some portions of the South Pelican. This, of course, is affecting overall shape of the pool production profile and on top of that, we experienced some regulatory delays in getting our drilling and injection plants approved by the ERCB. So along with the slow response in South Pelican Lake and these delays, has caused us to revise our production growth forecast for Pelican to only 6% for 2011. But we expect significant exit-to-exit growth in the order of 16% and substantial growth in 2012. Our plan is to convert Pelican over to polymer flood in a staged manner with 54% of the pool converted by the end of 2011 and reaching 71% by 2013. We'll expand the facilities in stages. Capacity was increased to 52,500 in 2010. We're going to go to 68,500 barrels a day in 2011 and then up to 100,000 barrels a day by 2012 as we prepare for that wall of polymer driven production in the next few years.
As you know, Canadian Natural is the largest heavy oil producer in Canada. And with our growth targets in primary, thermal and Pelican Lake, we are set to unlock significant value for shareholders. As part of that value creation chain, it is important that additional operating capacity get built to process the significant volumes of heavy oil expected from Alberta. To facilitate additional heavy oil processing capacity and to accommodate the expected volume growth and to dampen somewhat the volatility of heavy oil differentials, Canadian Natural has entered into a partnership with North West Upgrading to build a 50,000 barrel a day upgrader/refiner in Edmonton. Engineering is progressing at pace. We expect to be able to sanction this project late 2011 or early 2012.
Turning to our international operations. Our strategy is to maintain our existing operations and convert our undeveloped resources as slots become available on the platforms. We'll also progress Espoir development in Côte d'Ivoire and progress our Big E on our exploration prospect in South Africa.
As we all know, the U.K. government increased the taxation rate by 24% in the last month, significantly eroding the economics of doing business in the U.K. North Sea. As a result, almost half of our project inventory does not compete with capital in Canadian Natural's overall portfolio. Canadian Natural has 2 platform rigs under operation and was making plans for a semisub [semisubmersible] drillings vessel in 2012. As a direct result of the tax change, Canadian Natural dropped down to one platform rig, completing essentially, only safety critical work only. We have canceled plans for the subsea activity and we'll now accelerate the abandonment of the Murchison platform. This tax increase instituted by the U.K. government is very shortsighted and will, in effect, result in less tax revenue for the U.K. in a very short time as investment dries up and production declines. It's important to point out that when production declines by about 7.5%, the U.K. government revenues will be identical to where they were before the tax changes. It's clear the increased tax take will -- there will be significantly less activity, less jobs, less production, and significantly less revenue for the U.K. government. Everyone loses.
In Côte d'Ivoire, Baobab mass oil production continues to be stable. Throughout the recent political turmoil, we have effectively managed our operations with no impact on our production. We did, however, move our operation space to Takoradi, in Ghana, during the crisis. Life is beginning to return to normal in Côte d'Ivoire and we will, in the next month or so, look to move the base back to Abidjan.
At our Olowi Field in Gabon, we have encountered yet another setback. The mid-water arch support for the pipeline rise has experienced a support failure. As a result, we have shut Olowi in until we can effect repairs to the arch. We expect 2 new platforms on stream will remain shut in for the remainder of 2011. This will reduce production guidance by about 1,800 barrels a day for 2011.
Turning to Horizon. Let me summarize where we are, where the plant is going forward and, in general terms, both Peter -- we all are here to give you more detail on rebuild and collateral damage. And we can break down our activities at Horizon as the following: The fire rebuild, the collateral damage from the fire, our accelerated turnaround and opportunity maintenance and our expansion activities. Our progress on all fronts has been good. However, we continue to find some additional collateral freezing damage in the first quarter, which has increased the scope of work. We have identified all work in construction work packages, and they have all been issued. And the weather is good and May will be a critical month in terms of execution, to ensure we stay on track for startup. At this point, we expect to have the first set of Coke Drums, 2A and 2B, ready to startup in June and expect production by the end of Q2, as originally expected. We're now expecting the second set of drums to be ready by mid-August and, depending on commissioning time, to be close to full production by the end of Q3. The cost estimates for the rebuild and repair to the collateral damage is still within our original estimate of between $350 million to $450 million. Canadian Natural carries insurance to cover the cost of these repairs, as well as business interruption insurance after 90 days to cover the operating cost, up to $30 a barrel.
Now to give you more detail, I'll turn it over to Réal who'll update you on the rebuild. Réal?
Thank you, Steve. On the major rebuild, despite the extreme cold weather, the high wind and the icy conditions, we had no major incident on the safety side, which was really an outstanding action there.
So what I will do is, I will explain to you here by skilled trade how we're proceeding on the rebuild side. First of all, from the engineering standpoint, we have accomplished and completed all the work -- engineering work packages for the ice removal, damage inspection, repair evaluation, demolition and construction. So this way, this allowed the contractor to proceed ahead with the work. On the procurement side, most of the material required is already on site. The last pieces, in fact, are arriving next week. All the structural steel are on site. The spool to change all the piping, we have 192 spools on site out of 254, and the last 52 are already fabricated and coming on site next week.
Crew [ph] pump and decoking equipment coming from Germany. Three loads were flown from Germany and are on site, 3 loads came from Edmonton. There's 2 more loads coming up here early next week, which complete the entire procurement for the decoking equipment. All of the delta valves , which are also critical items for rebuilding this plant, are on site. We need 4 of them. Three of them were rebuilt in Houston and they are on site right now. The hydraulic power unit, which powers the derrick and the decoking equipment is also on site. It was entirely fabricated from scratch in Toronto. We also have received 8,000 meters of electric and communication cable, of which a substantial portion of it has already been installed.
On the civilian structural side, the east derrick suffered substantial damage and had to be replaced. The east derrick down is down on the ground now and 50% of the 1B damage structural steel above the drum has been removed and the remaining is in progress as planned. Prefabrication of the new derrick is progressing, as per plan, on site. Section 1 is fully assembled, including all the electrical and all the dressed up [ph] we need for it. Section 2 and 3 structural steel is complete, and the electrical is in progress to be completed by mid-next week. Section 4, which is the penthouse on top of the derrick. All the material and equipment are on site and it's scheduled to be assembled next week. The east derrick will be lifted in place by the end of May. The cutting deck structural steel installation, mainly above the 1B drum where the main fire was, will start next week once the demolition is complete. The west derrick has very little damage. The drill stem, drill stem railings, the small braces, all these, in fact, are repaired and the completion of all this work would be done by May 15.
On the mechanical and piping, all the piping spools have been fabricated. And, like I said, most of them are on site already. A substantial amount of them have been installed already. The PSVs [ph] , the MOVs [ph] testing is in progress as per plan and no major discoveries there or surprises. Two delta valves, out of the 4, have been installed already, on 2A and B, which for the 2 cokers that are going to be starting first. The hydraulic power unit is on site and is being installed right now. The operator shelter, the west one is near completion. The east one should be removed and replaced by the end of May. Started hydro-testing instrument there, as well, and the medium pressure steam line, so that we can return them to operation. The anti-foam building, in fact, suffered very little damage and the piping is progressing quite well also. On the electrical and instrumentation, 85% of the cable have been pulled already and we're slightly ahead of schedule. So over 4,000 meters have been done so far. On the cable termination, 50% of them have been completed as per the plan.
So overall, on the coker rebuild progress, 50% of the job has been accomplished. On the 2A, 2B, which are the ones to be started early, 70% of the job has been accomplished. Which, by the way, includes also all the common system that will be there for number 2 and number 1, also coker system. The critical task right now for us is the decoking equipment installation for 2A and B, the electrical instrumentation loop check and the firewall installation between 2A and B and 1A and B on the cutting deck.
So on this, Peter?
Thank you, Réal. Good morning, everyone. I'll focus my update to the collateral damage and the progress on the turnaround maintenance work opportunity, as well as our readiness to operate. Collateral damage in our coker unit resulted from freezing of the equipment, including the fired heaters, exchangers and piping. Because of the restricted access due to the hazards and risks associated with the damaged overhead derrick structure at that time, systems couldn't be properly purged or drained. That, combined with frigid temperatures experienced in early January, caused extensive freezing and damage. No other units at Horizon were affected, as they were shut down in a controlled fashion. All the equipment and piping assessments of the coker unit have been completed at this point in time. Instrument control systems are more than half completed with respect to communication and function tests. In terms of the collateral damage, we are near 60% complete overall. The critical path for getting us to the half-rate production is the repair or replacement of a number of heat exchangers. Delivery of repaired and replacement components for these heat exchangers is being expedited on a daily basis. The repairs to the coker heater 33F2 [ph], which was originally on our critical path, has been brought forward sufficiently ahead of the exchanger work.
The critical path for the full production capability is the completion of 33F1 [ph], which is the other coker heater. Now, as Steve had mentioned, during this outage we have undertaken effort to complete opportunity maintenance in all plant areas across Horizon and have also advanced roughly about half of the 2012 turnaround activity. None of this work will interfere or impact schedule to return to operations. But I will go through an example of what we're doing in each of the plant areas. In bitumen production, repairs to work protection linings in the tailings pump boxes, primary separation cells, that work is more than half completed. Reliability work associated with improvements to our slurry prep plants, the screens, secondary crushers is also being completed. In our utility plant, the annual boiler and hertzig [ph] inspections and repairs are being completed, and are not critical to the restart. Some reliability improvement work has been completed in the hydro-treaters and aiming [ph] units. The hydrogen PSA catalyst has been changed out. And finally, multiple vessels and pressure relief safety valves have been inspected and tested. As a result of the advancement of the 2012 turnaround work, sufficient inspection and testing has been completed so that the balance of the remaining inspection work and catalyst change outs have been deferred to 2013.
In order to prepare for operations, a significant amount of work has been completed to ensure that we have a safe and reliable plant, as well as the right operating discipline prior to startup. Design changes are being made to the safety interlocks and layers of protection on the unheading valve on top of the coke drums. This includes some logic corrections, as well as additional procedural changes associated with the operation. Hazard and operability reviews are completed to ensure all standard and emergency operating procedures are in place. Pre-startup safety reviews are underway to again, verify that procedures are ready. The process hazard analysis and modifications have been completed where necessary. Operators are reviewing and updating all the critical and emergency operating procedures. They're being retrained on them and then being independently tested in the field on these procedures, to ensure that they have the confidence and discipline necessary to operate.
Lastly, a site-wide supervisory training model is being delivered, which reinforces the accountability and necessity to adhere to procedures. The biggest risk of the startup is the potential for leaks on piping systems and flanges. We're mitigating this exposure by completing hydro tests and service tests, which have already begun. With the completion of these initiatives, I know we will be ready to operate.
Back to you, Steve.
Thanks, Peter and Réal. As you can see, we have taken this opportunity to enhance our readiness for operations and ensure a solid performance once we get back on stream. We believe our operations are safe and our procedures are solid. That being said, we will, as a result of this incident, not only increase focus on safe and effective operations at Horizon, but across all our operations. As a result, I firmly believe that Canadian Natural will come out this incident a much stronger and effective company than before the incident. And consistent with other areas in the company, we have not lost focus on the value creation of future expansions. We expect, in Q3, to have a completed and more detailed cost estimate for Horizon expansions.
As we discussed at the last conference call, we'll break expansion into 5 major components. The first component, reliability, has been previously improved and is well underway, will add about 5,000 barrels a day. The second component is named, Directive 74, and this involves all equipment and tailings processes to meet the new regulatory standards mandated by the ERCB by 2015. Our current cost assessment for this work is roughly $900 million. The third component is Phase 2a, which is essentially an upgrading de-bottlenecking project, and the acceleration of coker expansion that will provide an additional 10,000 barrels a day of capacity. The fourth component, Phase 2b, includes a major component as a fourth OPP or Ore Preparation Plant, an additional froth treatment plant, vacuumed installation and a gas-oil hydro-treater, providing an additional 45,000 barrels a day of STO [ph] capacity, as well as setting the stage for Phase 3 work. And of course, the fifth component is Phase 3, which increases capacity by 80,000 barrels a day and includes a fifth OPP, the third and fourth extraction trains, a combined hydro-treater and additional sulfur recovery.
To deliver these projects and ensure a greater cost -- degree of cost certainty and at cost control, we've applied our execution strategy based on lessons learned and our view of the market going forward. So going forward, de-bottlenecking expansion will be combined. Expansion will be broken into 5 components and further broken into 46 individual components. The Canadian Natural can, at our discretion, start or stop, depending on marketing conditions. On top of this, the individual 46 projects can be broken into engineering, procurement and construction, giving us even greater flexibility to control the projects and keep costs under control. And we expect that there'll be cost pressures in '12, '13 and '14 going ahead.
Construction will be awarded to an E&P at required levels and the market can absorb that construction. We'll also extend engineering beyond the 80-100 rule we've developed and have successfully utilized in Phase 1. We will use lump sum for E&P or construction when possible and the use of a combined EPC lump sum contracts are possible but not really expected.
We will cap the construction labor force at 5,500 people compared to the peak at 10,000 in Phase 1. And we'll also cap yearly expenditures in that $2 billion to $2.5 billion range. Horizon is a world-class asset and we have 16 billion barrels on our lease with 6 billion recoverable. Our design capacity is currently a 110,000 barrels a day, and our plan is to take a staged approach to expand to the first 250,000 barrels per day and then ultimately just under 500,000 barrels a day or 0.5 million barrels a day of light, sweet 34-degree API crude for 40 years with no declines.
Horizon is a world-class asset and will continue to deliver significant free cash flow for decades. It's very important that we get our expansion plans right and we effectively execute our expansion plans and strategies. It goes without saying that no future expansions will be proceeding if the economics do not meet our thresholds. Canadian Natural is in a very strong position and we're able to maintain our capital program, despite the Horizon incident. In fact, as I stated earlier, we'll see significant production growth for primary heavy oil, light oil, and thermal heavy oil, as well as Pelican in 2011. Not only are we delivering growth on the oil portion of our asset base. Even more impressively is that roughly 40% of our '11 budget does not add production in 2011.
Clearly, the Horizon fire was only a temporary hit to our 2011 production and cash flow. However, it is also very clear that our assets are strong and generating significant free cash flow, allowing Canadian Natural not only to deliver the value growth from our assets in the near term, but ensure we keep our mid- and long-term capital projects on track and do not compromise the future. Not many, if any of the companies in our peer group, have the assets, the balance sheet and the people to effectively execute our defined yet flexible plan, which delivers not only production growth, but generates significant free cash flow and sustain an event such as the Horizon fire. Canadian Natural's obviously in great shape. Our management, business philosophies and practices work. We have a strong, well-balanced and diversified asset base with vast opportunities. Our strategy is balanced, effective and proven, and we have control of our capital allocation and are nimble enough to capture those opportunities. Our strong assets, combined with our great teams of people and our culture, which is focused on execution excellence and effective operations, continues to generate significant free cash flow. As we enter the next step in the evolution and growth of the company, we are generating substantial cash flow, so that focus becomes on effective capital allocation to maximize returns. And with our major spend of Horizon Phase 1 behind us, we will return to stable operations after the fire, are completed. Our ability to take on more mid- and long-term projects, leverage our expertise and technology across our vast asset base is significantly enhanced. Canadian Natural is poised, not only in 2011, but for many years to come, to unlock significant value and generate more sustainable returns for shareholders.
With that, I'll turn it over to Doug, to give you an update on our prudent financial management.
Thank you, Steve, and good morning. Welcome to the new world of International Financial Reporting Standards. In essence, you will note there are no significant changes to the way we report items impacting cash flow. From an earnings standpoint, the largest changes from prior standards of Canadian GAAP are in the areas of the calculation of depreciation, depletion and amortization expense of our property plant and equipment, which is now calculated at an individual asset pool level rather than a country cost center level. Second, the calculation of share-based compensation, which now uses a fair value approach, determined utilizing a block shareholder approach adjusted at each reporting period. And finally, the way we treat U.K. petroleum revenue tax as an income tax and therefore, calculate a deferred tax liability using income tax conventions as opposed to utilizing a life-of-field approach. As you will see in Note 18 to the financial statements, Transition to IFRS, the resulting adjustments were not significant to either the opening balance sheet at January 1, 2010, or the comparative reporting periods for 2010. Thus, the resulting impacts on our financial reporting metrics are largely insignificant from a historical perspective. Going forward, the impacts remain to be seen, but Canadian Natural will be guided by our principles of doing business, which will remain unchanged.
The financial results in the first quarter for Canadian Natural were significantly impacted by the fire at Horizon, which occurred in early January. Production was reduced to 5.5 days and cash flow before income taxes reduced by approximately $550 million from Q4 2010. Despite higher WTI and benchmark pricing, our crude oil realizations for Q1 2011 compared to Q4 2010 were relatively flat. The reduced income from Horizon also resulted in an upward shift in our 2011 income tax rate on adjusted earnings to 28% to 32% on an annualized basis. This results from the proportionate shift of income to higher tax jurisdictions outside Alberta and particularly, the United Kingdom. Throughout this, our balance sheet remains strong. We exited the quarter with $8.5 billion of outstanding indebtedness, the same as at year end. Our debt to book capitalization remained at 29%, again bringing focus to the importance of a strong balance sheet to weather uncertain commodity prices or unpredictable events. Our liquid resources also remained strong. At March 31, our undrawn bank lines were approximately $2.3 billion. We remain committed to maintaining a strong balance sheet, adequate liquid resources and a flexible capital structure.
As Steve has discussed, this financial and operating flexibility has allowed us to increase our capital expenditure budget by $360 million, which is net of a reduction in our North Sea budget of $85 million or a 23% reduction. I would like to echo Steve's thoughts in that we were surprised and disappointed in the actions of the United Kingdom's Chancellor of the Exchequer annual budget in March. Where income taxes were again increased on crude oil and natural gas profits, resulting in a 24% reduction of after-tax profits to exploration and production companies in the North Sea. We believe this action is shortsighted and will result in reduced investment and job losses, and a deterioration of the North Sea crude oil and natural gas reserve life index. This is the third increase in the taxation of oil and natural gas profits in the U.K. since 2002, with current tax rates amounting to 62% on non-PRT paying fields and 81% on PRT paying fields. We also note that during the same period, corporate income taxes for all other industries in the U.K. have been reduced from 30% to 26%, with further reductions planned to 23% by 2014.
We have also renewed our Normal Course Issuer Bid through the Toronto Stock Exchange and the New York Stock Exchange, up to 2.5% of our outstanding shares during the period April 6 through to April 5, 2012. Our commodity hedging programs remain actively managed, albeit at lower volumes, given our strong balance sheet. Details of all of our positions are available in the notes to the financial statements and are also posted on our website.
Thank you, and I will now return you to John for some closing comments.
Thanks, Doug. As you can see, our financial position is strong and our asset base gives us many opportunities to effect value creation for our shareholders. We are prudently working to unlock that value, not just for the next year, but for all the years beyond 2012.
With that, operator, we would now like to open the call to questions that participants may have.
The first question is from Joe Citarrella from Goldman Sachs.
Joe Citarrella - Goldman Sachs
My questions are really around some of the Pelican Lake commentary. Could you elaborate a bit on the polymer flood response times taking longer than anticipated? But recovery is potentially being a good deal higher than I think you initially thought. How exactly has your understanding there evolved recently? And could you help us understand what's driving that dynamic? And then second, could you just give us some more color on what's driving the regulatory approval delays and why you're being held back on injection pressures in some of those areas?
Okay. Thanks, Joe, and thanks for the question. Because it's actually a very good news story. What we're finding is, that in the southern portion of the Pelican Lake in particular, that as we inject polymer solution into the reservoir, it sweeps across to the production well. And it creates a bank of oil in front of the polymer and the time it takes for that bank of oil to hit the production well is a function of how good the sweep is. So if we have a very effective sweep, so essentially that polymer flood is very effective and a very balanced flood front, even more effectively sweeped. So it takes longer to get that, I would say, that production wave, to hit the producing well. So we know recoveries are going to be higher because production response is slower and we know the pressures are behaving as they expected, and the solution is staying in the zone. So that tells us that the sweep is much more effective and we have better performance within the reservoir. So we do get production, the wave will probably be very strong and it'll be more substantial and last longer, giving increased recoveries. So there's a lot of other factors that go into it, but that's the quick synopsis. As far as the regulatory approvals, we were slowed down on the drilling side and in injections. We are injecting at fairly high pressures in the -- if the polymer takes a higher pressure to get into the reservoir because it's more viscous. And there was some concerns with the ERCB, the regulator, thinking that the pressures are too high and we could have some wellbore issues breaking out. So as a result, they had to request a whole bunch of testing be done on cap rock capacity, ensuring the cement bonds are good. All that, we knew we're well within range. We had the data. But it took time to get more data for the ERCB and to ensure that they feel confident going forward. I think those issues, for the most part, are behind us. But it did put a delay in 2011 drilling and injection plans, which we didn't anticipate in November.
Joe Citarrella - Goldman Sachs
That's great. If I could just ask a quick follow-up -- well, a separate question. But color on the land purchases you mentioned. Is that just a consolidation of some of the more liquids-rich gas areas you're looking to grow in? Or any color you could provide on those?
We don't give you too much color because we like to keep our activities on the acquisition front fairly confidential. But most of the land acquisitions we bought, actually we bought some fairly large blocks, contiguous blocks in the heavy oil region. That actually increases our heavy oil inventory significantly. We haven't had that into our 9,000 wells yet, but we'll probably add 500 to 800 extra heavy oil drilling wells because of that land purchase. There was no production on that land. But we've been coveting this land for a long time.
Joe Citarrella - Goldman Sachs
Makes sense. That's very helpful.
The next question is from John Herrlin from Societe Generale.
John Herrlin - Societe Generale Cross Asset Research
I've got 3 quick ones. With the Horizon rig starts, will you have any recertification or regulatory issues with the government to get going?
Yes, on that one, we have -- we obviously, have to have occupational health and safety sign off to get the return to use work order in place. And we have to have ABSA or the Alberta Boiler Branch brew [ph] vessels. All that stuff is ongoing right now, we're to have that all ahead of time before startup. So we don't see any issues from the regulator on startup. We'll get all that done before we start up.
George Toriola - UBS Investment Bank
With Western Canadian Select differentials worldwide, you're a big heavy oil producer, a lot of heavy oil exposure. Do you think you need even more upgrading capacity than what you currently have planned?
I think, John, we feel fairly confident, on a overall portfolio basis, we have the right balance. Obviously, everything at Horizon will be upgraded. So we'll have light synthetic oil there. So when you look at our heavy oil capacity, it'll probably be -- our oil capacity will probably 1/3 light, 1/3 heavy oil and then obviously we're going to have the upgrader at Edmonton here when Redwater gets approved. So we're adding some more capacity there. So we've got natural light, SCO and heavy, about 1/3, 1/3, 1/3 across the board.
George Toriola - UBS Investment Bank
Okay. Last one for me is on the U.K. It was a high margin area for you. Are you going to remain a consolidator? Or given this latest tax increase, you're just going to work out your assets to the end of field life and call it a day? Or are you going to continue to ultimately consolidate, if there are the opportunities?
I think at this point, we're assessing the impact of the tax effect. I think ultimately, we'll stay in the North Sea. We believe that the U.K. government, although it may take them some time, they'll quickly realize within a year, maybe 2 years, that their tax revenue is down. They've lost a lot of jobs and they've actually put themselves in the hole. We lived through this in Alberta. It took the Alberta government a while before they realized they'd actually hurt themselves more than helped themselves. And we feel confident that the same thing will happen in the U.K., it's just whether they respond to it or not is yet to be seen.
The next question is from Mike Dunn from FirstEnergy Capital.
Michael P. Dunn - FirstEnergy Capital Corp.
Just wondering on Pelican Lake. Mostly, my questions have been answered. But could you talk about the size of, I guess, the southern part of the Pelican Lake field compared to the size of what's being produced right now? Just want to get a sense of what portion of the field might see higher recovery rates.
So the southern portion of the field probably accounts for maybe a third of the size of the pool. And so we expect to see higher recovery there. But ultimately, what we think is, this may actually have good signals for the whole pool. Because we may be able to tweak our polymer. Obviously, we're in the steep part of the curve here. So we think there's potential to increase recovery across the whole pool. It's just going to take us some time to make sure we optimize the technology here.
Michael P. Dunn - FirstEnergy Capital Corp.
Great. And on Horizon, guys, as you think about and evaluate where the expansion projects rank, in terms of your portfolio of opportunities. How do you -- I mean, I'm assuming you're looking at more than just after-tax rate of return on that. How do you -- what other factors go into that decision? And how do you rank or how do you assess the, I guess, operational risk that seems to be higher with these integrated projects versus just drilling primary wells?
Well, obviously, Horizon is a much more complex development than drilling a primary heavy oil well or a shallow gas well in southern Alberta or even an offshore well off a platform in the North Sea. But it is much more sustainable and it has virtually no reserve replacement cost when it comes on. So we obviously, we looked at after-tax returns in our evaluation. But it does have a 40-year reserve life, virtually no reserve and replacement cost. And to be honest, with on this -- on the performance, we believe and I firmly believe this, that our operations will be much stronger and I'm looking forward to a very solid run of reliable production once we come back on. So we think we can do a lot better than we have here. You know we're new to the game, but I think we have a track record of continually improving and becoming even more effective operators as we go forward.
And the next question is from Menno Hulshof from TD Securities.
I've got a couple of questions. The first is yet another follow-up question on Pelican Lake. Is your long-term goal of increasing recoveries by roughly 3.5x and growth to something in the 80,000-barrel per day range as per your April presentation still current? Or has that profile now changed?
So recovery is probably -- we think we're going to go 25% in the areas of the polymer flood, 17% overall. I think we're going to get better than that, but we're not ready to commit to that yet. We want to really see that response time and the response of the producers. But I think it's pretty clear that we're going to get better recovery. The 80,000 barrels a day, I believe we're going to get to 80,000 barrels per day. It may take us 6 months to a year, maybe 18 months before -- later than we expected to get there because of the response time. But what's important is once we get to our peak, if it's 80,000, we still think it will be. Is that, that peak or the plateau is likely to last a lot longer than we originally expected.
Menno Hulshof - TD Newcrest Capital Inc.
Okay, perfect. And then the second question relates to turnaround activity. I believe you mentioned that roughly one half of 2012 turnaround activity has been pushed forward into 2011. What would that amount to, in terms of weeks of planned downtime? I'm just trying to get a sense of how much this offsets the roughly 6 months of downtime that you incurred with this fire?
Yes, so our turnaround was planned to be about 2 weeks in 2012, maybe 17 days. That's gone completely in 2012. So we gained all those days back. So it's a good gain, but it obviously doesn't compare to the 4 or 5 months we're going to be down here because of the fire.
Menno Hulshof - TD Newcrest Capital Inc.
Perfect. That's it for me.
The next question is from George Toriola from UBS.
George Toriola - UBS Investment Bank
I apologize if the questions I'm asking here have been answered. I got off the line there. Two questions. The first is on your thermal oil growth. What are the key risks you see to the growth projections that you have? Would they be cost inflation, heavy oil spreads? What are the key risks that you see to that growth projection?
George, I think really the key risk -- there is some cost inflation risk but we have, as you see, a very sort of incremental step-by-step, piece-by-piece or a 40,000 to 60,000 barrel increment. So we're not doing large projects. So we think we can control the costs, although the cost pressures will likely be there. I think the biggest risk for us from hitting our profile is really going to be regulatory approvals and any delays. We're starting to see that, as you could see in Pelican Lake. It's hurt us a bit. We are concerned that, that may hurt us a bit on the thermal profile. We're being proactive in getting out there and trying to make sure that there's any delays -- if there are any delays, that we can mitigate those going forward with the regulators. But they're under a lot of pressure with a lot of work to do and they have lots of concerns that are probably heightened because of all the activities. So that is our -- I think our biggest risk.
George Toriola - UBS Investment Bank
Okay. And maybe just a follow-up. On Septimus, how big could that -- what's the potential there? In terms of gas and liquids production.
So we think -- our original plan, when we had it at 4 Bcf per well, was to take this thing to 200 million a day, and that would give us about 10,000 barrels a day of liquids. Obviously, we're seeing production reserves that look like they're going to be north of that, in that 6 Bcf range. So I would think -- while we haven't done the analysis yet, because clearly, we're not ready to go there yet. But the size of the plant would get bigger because you have, obviously, have more reserves so the maximum rate to maximized value would be higher than 200 million a day and 10,000 barrels a day.
There are no further questions registered at this time. I'd like to turn the meeting back over to Mr. Langille.
Thank you very much, operator, and thank you for participating in the call today. As usual if you have any further questions, don't hesitate to contact u, and have a good day. Thank you.
Thank you. The conference has now ended. Please disconnect your lines at this time, and thank you for your participation.
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