Good morning, ladies and gentlemen. Welcome to the Canadian Natural Resources 2012 Fourth Quarter and Year-End Conference Call. I would now like to turn the meeting over to Mr. John Langille, Vice Chairman of Canadian Natural Resources. Please go ahead, Mr. Langille.
John G. Langille
Thank you very much, operator, and good morning, everyone. Thank you for attending this conference call where we will discuss our 2012 fourth quarter results, review our planned activities for 2013 and, in some cases, beyond. Participating with me today will be Steve Laut, our President; Doug Proll, our Chief Financial Officer; and Lyle Stephens, our Senior Vice President overseeing reserves.
Before we start, I would refer you to the comments regarding forward-looking information contained in our press release and also note that all dollar amounts are in Canadian dollars, and production and reserves are both expressed as before royalties unless otherwise stated.
I'd like to make some additional comments before I turn the call over to Steve, Lyle and Doug for their in-depth discussion.
In 2012, our balance producing asset base continued to achieve significant cash flow of over $6 billion. We followed our disciplined balanced approach of allocating the disbursement of this cash flow in the following manners: We cost effectively continued to develop our large resource potential, which resulted in growth of our 2P reserves to 7.9 billion barrels of oil equivalent, replacing 276% of our production, with 90% -- 95% of that addition being oil reserves. We maintained our strong balance sheet and debt metrics. We returned funds to our shareholders through dividends, which increased 17% in 2012, followed up by a further 19% for this year. And we returned to our shareholders through share repurchases of over 11 million shares at an average price of $28.91 in 2012 and firm plans to continue a similar type of program depending on market conditions throughout 2013.
And 2013 has started out with strong operating results. Our production rates are all holding within our guidance, with particular emphasis in the first 2 months of 2013 on high production in our cyclic steam in Primrose thermal operations during this current production cycle, continuing increased production from primary heavy oil and daily average SCO production from our Horizon mining operations of over 110,000 barrels per day.
With that, I will now hand the meeting over to Steve.
Steve W. Laut
Thanks, John, and good morning, everyone. This morning most of my comments will be forward-looking, along with -- touching briefly on our strategy and highlighting each of our assets. There are 5 key points that you should listen for as we go through the talk this morning: first, our review on heavy oil differentials and market access, Horizon reliability, Kirby development uptick, our year-end reserves and the monetization of the portion of our Montney asset base, our land base.
As you know, Canadian Natural has and will continue to build a premium value, defined growth independent. We're one of the few companies in our peer group that has the assets that deliver free cash flow on a sustainable basis, a direct result of our ability to effectively execute our strategies. Canadian Natural has the largest reserve base in our peer group, a reserve base that ranks with global industry players. It's balanced and is delivering significant cash flow.
Critical to our ability to continue to grow free cash flow is our very large undeveloped resources that we own and control. Resources that are long life and low decline. Importantly, we require only a portion of our cash flow to grow current year production, about 47% in 2013, reflecting the strength of our assets and Canadian Natural's tremendous capital flexibility.
The remaining cash flow can be utilized to increase the strength of our free cash flow and reserves by unlocking the value of our undeveloped resources, return to shareholders through increasing dividends and share buybacks, acquisitions or pay down debt.
Probably most important of all, we have the people, the expertise and experience to execute our programs and operate effective, efficient operations.
Our balance sheet is strong, with a capacity to capture opportunities and weather any commodity price volatility we might encounter.
Canadian Natural is in a very enviable position and has a clear advantage compared to many of our peers when it comes to unlocking the value of our free cash flow on our long-life, low-decline resources.
Now before I touch on our oil assets, I will comment on the current North American oil markets and Canadian Natural's view of that market. And as you know, we're bullish on heavy oil pricing in 2013, as well as the mid and long term, as there's significant heavy oil conversion capacity coming onstream in PAD II, significant current underutilized heavy oil refinery capacity on the Gulf Coast, and we see the infrastructure constraints to get the Gulf Coast being removed.
Although there will be some headwinds for late production, we believe these are manageable. Cushing is on its way to being debottlenecked, which will reduce the LLS to WTI differential. Although we expect light oil production to keep increasing, we believe the access to incremental light oil markets in North America will be realized. If you look at the infrastructure issues first, the Cushing bottlenecks are well underway to being removed.
Seaway has been expanded to 400,000 barrels a day of takeaway capacity in Q1 and an additional 450,000 barrels a day in mid-2014 with the Seaway twin project coming on. Plus, you have the Keystone-Cushing market link will add 700,000 barrels a day capacity by the second half of 2013. As a result, we expect to see the WTI to LLS differential to narrow as each of these projects are completed. Once completed, we expect the LLS to WTI differential to be essentially the transportation cost between Cushing and the Gulf, about $5 a barrel.
In the mid to long term, access to the Gulf Coast for light and heavy oil will come from the Enbridge Flanagan South expansion of 585,000 barrels a day, which is slated to come onstream in Q2 2014. This pipeline does not require a presidential permit and has the required producer and refinery support to proceed.
We'll also cover the Keystone XL project, which does need a presidential permit, and is slated to add 800,000 -- 803,000 barrels a day of capacity in Q1 2015 if approved in Q2 2013.
In addition, there'll be 220,000 to 300,000 barrels a day of access to the Line 9 reversal and longer term via Gateway at 525,000 barrels a day or TMX at 550,000 barrels a day on the West Coast or via the East Coast in the TCL option for 800,000 barrels a day. These last 3 options face their own unique regulatory and stakeholder challenges and provide export capacity to new markets.
In the meantime, we expect significant movement of light oil and, to a lesser degree, heavy via rail to access refinery capacity currently being supplied from foreign offshore sources. There's 2 million barrels a day of capacity on the East Coast and 350,000 barrels a day on the West Coast. These markets could be supplied via rail as the rail infrastructure gets built out, and there is a strong economic incentive for both refiners and producers to ensure these offloading facilities get built.
Now there's significant increase in heavy oil demand for the Canadian heavy oil producers on the way as a result of PAD II supply-demand balance is about to change dramatically. With 80,000 barrels a day additional capacity now on but still working on some minor infrastructure issues and the new capacity coming on by Q2, Q3 2013, we will see an additional 260,000 barrels a day of heavy oil conversion capacity come onstream.
So the total will add up to 340,000 barrels a day. And on the Canadian heavy oil market of 1.5 million barrels a day, that will add over 20% heavy oil capacity for Canadian heavy oil. Once heavy oil gains market access through Flanagan in 2014 and we expect Keystone in 2015, there's significant demand for heavy oil in the Gulf Coast. Once connected, we have 1 million barrels a day of heavy oil demand that today is not satisfied.
In addition, over time, and it will take some time for the Canadian heavy oil to fill that 1 million barrels of Gulf Coast demand, we will be able to push out foreign heavy oil enforcing the Gulf Coast. What this means for heavy oil pricing in our view is that the increasing refining conversion capacity coming on, the Flanagan and Keystone access to the Gulf Coast, we expect Cold Lake heavy oil differentials to Mayan heavy crude to narrow to reflect the spreads, which will be the transportation cost between Hardisty and the Gulf Coast.
Heavy oil diffs in January were 34%; February, 39%. And we see March come down to 29% and indication for April, although early, of 27%.
Turning to our gas assets. Canadian Natural is the second largest gas producer in Canada, with a very large land base and effective and efficient operations. When gas prices strengthen, Canadian Natural's in great shape. Our vast asset base and conventional and unconventional gas and our dollar infrastructure position allows us to maximize the benefits of higher gas prices and, if we choose, allow us to quickly and efficiently increase gas drilling and production at very effective costs.
Canadian Natural has a dominant Montney land position with over 1 million high-quality net acres, the largest in the industry. In order to maximize the value of this very important asset, Canadian Natural has begun the process to monetize approximately 250,000 net acres, or roughly 390 net sections, of our Montney land base in the liquids-rich fairway in the Graham[ph] Kobes area of Northeast BC. Under this process, Canadian Natural will consider either an outright sale of the lands or a joint venture partner with LNG expertise to jointly develop the lands. If this process meets our internal targets and a transaction is completed, Canadian Natural will continue to have one of the largest undeveloped Montney land bases in Canada, with lands contained in 2 major areas, Septimus in BC and Northwest Alberta.
As you know, the main theme of Canadian Natural's strategy is to maximize the value of our assets by optimizing our capital allocation. And historically, we have nothing keen on JVs as we believe having a high degree of control of our capital allocation allows us to maximize value. We also believe the efforts of our strong team should be directed to creating value for our shareholders, not working interest partners. That is still the case. However, in this situation, when we look at the size of our Montney land base and balancing our capital allocation going forward, combined with the strong demand we see for this type of high-quality asset, plus the fact that Graham Kobes is somewhat removed from our core Montney asset base, it is prudent to monetize a portion of our Montney asset base at this time. Overall strategy remains unchanged. And in this case, because of our very large Montney land base, we see a unique opportunity to maximize value today and a different approach from what we have done in the past while still ensuring we have a strong land base, which we can create significant long-term value for shareholders as we go forward.
Turning to our oil assets. On Canadian Natural's thermal heavy oil lands, we have 79 billion barrels in place, and we expect to recover 8.8 million barrels from our vast thermal heavy oil resources. Canadian Natural is executing a disciplined stepwise plan to unlock the huge value of this asset by bringing on 40,000 to 60,000 barrels a day every 2 to 3 years, taking production facility capacity to 510,000 barrels a day or 0.5 million barrels a day, all at a 100% working interest.
At Primrose, we continue to add pads at a very effective cost rate of roughly $13,000 of flowing barrel and op cost under $10 a barrel, making Primrose one of the most robust thermal projects in the industry. Primrose production was very strong in Q4 at 120,000 barrels a day and exit rates over 128,000 barrels per day, setting us up for a strong first quarter. Primrose is a cyclic process so we have seen strong rates in January and February, with rates beginning to drop in March, with much lower rates expected in Q2. The production will then cycle higher with strong rates in Q3 and Q4. As a result, production guidance for the year is 100,000 to 107,000 barrels a day, up 5% over 2012.
At Kirby South, we're on track. We're slightly ahead of schedule and on cost, with first steam scheduled for November of this year and then production ramping up to 40,000 barrels a day by late 2014 at a cost of 30,000 per flowing barrel. Kirby South is the first step of a step-wide development to take overall production to 140,000 barrels a day of high-quality, high-value barrels. With additional lands acquired in 2012, we will evaluate in 2013 the optimum production level for Kirby area, potentially increasing it to 180,000 barrels a day range.
Canadian Natural is the largest primary heavy oil producer in Canada. We dominate the land base and the infrastructure. We have 8,500 locations in inventory. And due in part to our dominance, we have excellent capital efficiencies and low operating costs, making primary heavy oil one of the highest return on capital projects in our portfolio and generate significant free cash flow.
Canadian Natural delivered a strong fourth quarter, with 886 wells drilled in 2012, and we will continue with a very strong program in 2013 with 890 wells. We expect to deliver 12% production growth to just over 140,000 barrels a day at the midpoint of guidance.
At our world-class Pelican Lake pool, our leading-edge polymer flood is driving significant reserves and value growth. We have over 550 million barrels to develop under polymer flood. Our plan in 2013 at Pelican is to continue development of the polymer flood, with 56% of the pool converted to polymer flood by the end of 2013. We're seeing good production response from the polymer flood, and we see production increases of 19% in 2013.
In the fourth quarter, production averaged roughly 36,400 barrels a day, as volumes at Pelican Lake were restricted due to temporary produced polymer treatment and facility constraints. In addition, production volumes at Woodenhouse were also restricted as they utilized the Pelican Lake facilities. The new Pelican Lake facility, with a capacity of 20,000 barrels a day, is expected onstream early June. At that time, we expect a step increase in production volumes. We're currently holding back in the field today roughly 4,000 barrels a day of production at Pelican Lake and another 8,000 barrels a day at Woodenhouse for a total of 12,000 barrels a day of field production capacity, which will come on in June.
Turning to light oil in Canada. We continue to authorize our existing waterfloods and leverage technology over extensive land base. We expect solid production growth of 5% to 67,000 barrels a day at midpoint of our guidance, with exit growth rates targeted at 10%. We will continue to progress our secondary and tertiary recovery projects and drill 40 net wells, targeting new play developments that were initiated in 2012.
In the North Sea, production was relatively flat from Q4 to Q3. And in 2013, we'll run 2 rigs in the North Sea and drill 3.6 net wells, as well as perform a number of workovers and safety-critical work on the platforms. We have a rig on Espoir and the infill drilling program is underway. When completed in 2013, we'll add 6,500 BOEs a day of light oil at a cost of 24,000 of flowing barrel. We'll also prepare for the inflow program at Baobab in 2014 with the purchase of long lead items.
In South Africa, we're tracking to plan and our plan is to process the bringing a partner for a big E exploration project. As a reminder, this development has up to 5 significant structures on our lands, billion-barrel-type structures that we currently own 100%. We're in the final stages completing the paperwork with a partner, and we'll then need to complete all the necessary documentation with the South African government before we disclose our path forward. We anticipate the completion of the necessary documentation and required South African approvals will be somewhat lengthy process based on some of the third-party approvals obtained and our own experience in obtaining the exploration rate with the South African government. We're targeting a period of up to 6 months to get that done. The earliest likely drilling date for the South African exploration well would be late 2013 or early 2014. Long lead equipment for this well has been ordered and will be delivered on time.
At Horizon, production in the fourth quarter was over 83,000 barrels a day. Our more conservative approach saw us take 12-day downtime in October to fix its leaking exchangers. In addition, we had a conveyor and apron feeder maintenance issues in the second half of December, which turned out to be one of the coldest spells in the winter, combined with the Christmas season, caused production to be curtailed. Some of you may have heard me discuss the change in our maintenance strategy, which we have undertaken to address the issues we've seen in December. And so far, they've been very effective.
First quarter production has been solid so far. January production was 113,000 barrels a day and 107,000 barrels a day produced in February. We expect March also to be a very solid month in the 110,000 barrel a day range.
Over the course of 2012, we have made significant strides in improving reliability at Horizon. Improvement in reliability will continue through 2013, and we expect to see a step change in reliability after we complete the May turnaround. We've increased the turnaround outage from 18 days to 24 days to address additional scope, which we believe will enhance our reliability going forward. Now although we've added 6 days to the turnaround, our production guidance remains -- for the year remains unchanged and reflects our confidence and our ability to deliver increased revivability after the turnaround.
Expansion of Horizon is on track, and we continue to see good cost being delivered. Currently, we're running under our cost estimate, and we are continuing to see bidders sharpen their pencils as we let out additional work. Today, we're roughly 18% complete on the overall combined Phase 2, 3 expansion. We are 86% complete on reliability; 16% complete on Directive 74; and 40% -- 47% on Phase 2b (sic) [Phase 2a], which will add 10,000 barrels a day in 2015; 8% on Phase 2b, which will add 45,000 barrels a day in 2016; and 8% on Phase 3, which will add 80,000 barrels a day in 2017.
Before I make some concluding remarks, I'll turn it over to Lyle now to comment on our strong 2012 year-end reserves.
Lyle G. Stevens
Thanks, Steve. Good morning, ladies and gentlemen. To start our reserves review, I'd like to point out that as in previous years, 100% of our reserves are externally evaluated and reviewed by independent qualified reserves evaluators. Our 2012 reserves disclosure is presented in accordance with Canadian reporting requirements using forecast prices and escalated costs. The Canadian standards also require the disclosure of reserves on a company growth working interest share before royalties.
Moving on to our results. In 2012, we had another very strong year, replacing 178% of our production on a proved basis, with 245% for crude oil, NGLs, bitumen and synthetic crude oil and 30% for natural gas, reflecting our capital allocation to higher-return crude oil project.
On a proved plus probable basis, we replaced 246% of our production, 342% for crude oil, NGLs, bitumen and synthetic crude and 30% for natural gas. Total corporate proved reserves increased by 4% to 5.0 billion BOEs.
Proved additions and revisions, excluding production, totaled 426 million BOEs. Of the 426 million BOEs, 95% were liquids, primarily North American crude oil, bitumen and synthetic crude oil.
On a proved plus probable basis, total company reserves increased by 5% to 7.9 billion BOEs. On a 2P basis additions and revisions, excluding production, totaled 587 million BOEs. 96% of those 587 million BOEs were liquids additions.
The most significant reserves increases were in synthetic crude at Horizon, in thermal bitumen and in primary heavy crude oil. On the Horizon mining side, proved synthetic crude oil reserves increased 6% to 2.3 billion barrels. This is primarily the result of the continued strat well drilling to further delineate the North pit.
The magnitude and quality of our thermal assets continues to have a significant impact on our reserves. On a proved basis, bitumen reserves increased by 9% to 1.1 billion barrels. This increase is primarily due to an enlarged development plan for one of our Clearwater sands at Primrose South and our Grand Rapids development at Wolf Lake, both of which were defined through strat well drilling.
On a proved plus probable basis, bitumen reserves increased 23% to 2.1 billion barrels, largely due to the addition of bitumen reserves associated with the Grouse project, coupled with our Primrose, Wolf Lake additions.
In primary and heavy crude oil, proved reserves increased 17% to 204 million barrels. This was largely driven by the excellent results of our record heavy oil drilling program.
Crude oil, NGLs, bitumen and SCO now account for 86% of our proved reserves and 88% on a proved plus probable basis. Our reserve life index with the company is now 23 years using proved reserves and 36 years using 2P reserves. Even if Horizon is excluded, we still have long reserve life indices, which reflects the strength of our asset base. It's 15 years using proved reserves and 25 years using 2P reserves.
In summary, these excellent results reflect the strength, balance and opportunities that we have in our asset base.
I'd now like to turn the call back to Steve.
Steve W. Laut
Thanks, Lyle. As you can see, our reserves are strong. Our reserve replacement was excellent at 246% in 2012 as we continue to transition to that longer-life, low-decline asset base that's weighted towards oil.
In summary, Canadian Natural is in great shape. Our balance reserve base is the largest in our peer group, a reserve base that ranks with global industry players and delivers significant cash flow. Importantly, we're able to effectively allocate a portion of our free cash flow to our very large undeveloped resources that we own and control, resources that are long life and low decline, which further strengthens our ability to generate even greater amounts of free cash flow in the future, providing every amounts of free cash flow for allocation outside the development of our vast resource base, as well as to increase our ability to withstand potential commodity price downturns in the future.
Probably most important of all, we have the people, the expertise and the experience to execute our programs and operate effective, efficient operations. And as Doug will point out, our balance sheet is strong, with the capacity to capture opportunities and weather commodity price volatility.
Now before I turn it over to John, I'd just like to take a minute to thank John for his tremendous contribution to Canadian Natural over the years. As you have read the press release -- actually, I'll turn it over to Doug first before I do this. How's that, Doug?
Douglas A. Proll
Perfect, because we should always save John for last.
Steve W. Laut
Save the best to last.
Douglas A. Proll
Thank you, Steve, and good morning. On balance, 2012 was a successful year both financially and operational for Canadian Natural.
Cash flow from operations was $6 billion or $5.48 per share and adjusted net earnings amounted to $1.6 billion or $1.48 per share. While we saw a decrease in our netback realizations for crude oil and SCO due largely to widening heavy oil differentials and lower SCO benchmark pricing, we increased oil production from our diverse asset base to 451,000 barrels per day.
As overall pricing remained relatively strong, crude oil was a positive story. 69% of our BOE production was oil related in 2012, and we are very well positioned in North America and internationally. Due to continuing low natural gas prices in 2012, our natural gas production declined 3% to 1.22 Bcf per day, and our natural gas netback realizations declined 56% to $1.04 per Mcf. As 31% of our production mix is natural gas, the impact on cash flow was approximately $625 million, accounting for much of the year-over-year decline in cash flow.
In midyear, we responded and we downsized our -- to these lower natural gas prices, and we downsized our capital expenditure budget in response to the pricing. And we exited the year spending $6.3 billion. In addition to our active dividend program, we purchased for cancellation over 11 million common shares for $318 million, reducing our outstanding common shares year-over-year by over 4 million shares.
The end result was we exited 2012 with long-term debt of $8.7 billion, a small increase from the $8.6 billion at the end of 2011. Our debt metrics remained solid, with debt to EBITDA at 1.2x, and debt to book capitalization at 26%. Our available lines of credit at the end of 2012 were $3.7 billion. Our pro forma available lines of credit amount to $2.9 billion after repaying $400 million of maturing Canadian medium-term notes and $400 million of U.S. debt securities early in 2013. We have no further debt maturities until the fourth quarter of 2014.
We have expanded our actively managed crude oil commodity hedge program for 2013 to ensure the protection of our capital expenditure program. We have hedged 48% of our forecasted crude oil production for 2013, with price collars on 200,000 barrels a day for Q1 and 250,000 barrels a day for the remainder of the year, all with a floor of $80 per barrel.
As a result, our balance sheet and liquid resources are strong. We are very well positioned as we continue to develop our diverse asset base, including our strategic projects at Horizon and Kirby. This financial strength complements our management strategies and the company's disciplined approach to execution and operational excellence. In addition to adherence to maintaining a strong balance sheet, having available liquid resources and structuring our risk management programs to protect against short-term negative commodity price movements, we focused on sustainable returns to our shareholders.
For 2013, we have increased the dividend to $0.125 per common share, payable quarterly, which is $0.50 a share paid on annual basis, representing, as John mentioned, a 19% increase. This is the 13th year of consecutive dividend increases and represents a 21% CAGR over the period. In addition, we have reaffirmed our commitment to the continued active management of our Normal Course Issuer Bid for 2013.
Thank you, and I will turn you back to Steve.
Steve W. Laut
Thanks, Doug. As I said, I'd like to take a minute to thank John for his tremendous contribution to Canadian Natural over the years. As you have read in the press release, John will be retiring at the Annual Meeting in May. Many of you may not know this but John is the longest member of the Canadian -- longest-serving member of the Canadian Natural team, joining Canadian Natural in 1986 or 37 [sic 27] years with the company. During his time, John has been an important member of our team and has provided strong leadership and wisdom as the company has grown from a very small junior to the large independent we are today. John has been a steady and calming influence throughout this period and has been a mentor to many of us, myself included. Personally, I'd like thank you, John, for all the help and advice you have given me over the years. Thanks a lot for that. And all of us at Canadian Natural wish you all the best when you retire at the Annual Meeting.
You've also read that Doug Proll has decided to take on a somewhat less demanding role with the company as Executive Vice President. As a result, you'll be seeing more of Doug on road shows and investor conferences, along with other members of the management committee. As you know, Doug has done an outstanding job for us as CFO and has built a very strong financial team.
As the result of this change, Corey Bieber has been promoted to Chief Financial Officer. Many of you know Corey, who is a very talented individual with strong financial and leadership skills. And having been mentored by both John and Doug over the last 12 years, I am very confident he'll do a great job leading the strong financial team. Of course Doug will still be around to provide Corey any help he needs in his new role.
I believe these changes reflect the depth and strength of the Canadian Natural team and allows us to strengthen the team and still benefit from the wisdom and experience when John was transitioned from President to Vice Chairman and now as Doug transitions out of the CFO role. So with that, John, some concluding remarks.
John G. Langille
Thank you very much, Steve, Lyle and Doug for your comments. And thank you, Steve, for those additional comments, much appreciated.
It's never an easy decision to decide to retire. But unfortunately, age does catch up to you, and I still have a number of personal interests that I want to pursue. And so that's why I have made the decision to retire. Makes it equally difficult because Canadian Natural continues to be in a very strong position, with large reserves producing significant cash flow and many, many excellent opportunities to expand that reserve base.
Just to reiterate a couple of the points, I think, that Steve made. Our time-tested management and operating principles provide the right checks for determining economic capital spending; for balancing activities to mitigate as much as possible against extreme volatility in commodity pricing; and at the end of the day, ensuring our shareholders, of which I will certainly still be a major member of, have the opportunity to realize an increase in value from their holdings.
With that, operator, I'd like to open up the call to questions.
[Operator Instructions] Our first question comes from George Toriola of UBS.
George Toriola - UBS Investment Bank, Research Division
My best wishes to John as he retires as well. A couple of questions here, the first is on the Montney monetization. Could you provide some more clarity as to what has drove this decision? It's quite a departure from what you've done in the past. So is it pure economics? Are you trying to accelerate sort of value from the asset base? Or sort of the thinking behind that together with how much work have you done on this assets, the 250,000 net acres here, have you -- do you have wells in there? Do you understand the potential here? That will be helpful. That's the first question. And then the second question is on the reserve -- year-over-year reserve change in the North Sea and in Africa, so sort of looking for some clarity as to what has driven the year-over-year declines in those regions.
Steve W. Laut
I'll answer the first question and I'll get Lyle to give a comment on the reserve changes in Africa and the North Sea. So as you know, it maybe does seem like a departure for us but it really isn't. It's a case of we're trying to maximize value. As I said in the call, we have the largest Montney land base in Canada, 1 million undeveloped acres. This is a very high-quality portion of our land base. It's somewhat removed from the core of our land base at Septimus and in Northern Alberta -- Northwestern Alberta. So we see this as an opportunity to maybe, I should say, accelerate some value but create some value. And the asset, we think, is high quality. It's in liquids-rich fairway. And we're not going to give you all the details about it here today. Obviously, we're in the process now, and that will all come out when we put the package together. But there is significant penetrations in the area. I think there's 105 penetrations in the Montney ourselves, and there's about 1,000 penetrations in the overall area so this is not moose pasture by any means. This is high quality. There is wells in the area that have rates, massive rates in the 25 million a day range. So this is clearly a high-quality portion of the land base. We think it will be a while before we get there because the other part of our land base is even higher quality in our mind, and it's a way to capture some value. So that's the rationale for it, and it's all about maximizing value, which we're always trying to do.
George Toriola - UBS Investment Bank, Research Division
Can I just quickly follow up on that? As you look to rationalize this, would you be looking to -- would you be looking for cash or you'll be looking for an interest in some sort of JV, some sort of LNG project? What's the preferred outcome from this process?
Steve W. Laut
So George, we're looking at all options. We're open to them all. So I guess, if you say in a sort of a macro level, we're looking to maximize the value of this asset. And so we would look at outright sale. We'd look at a joint venture. We'd look at different types of joint ventures, and we'll leave that open here as the process goes. And we're not going to preclude anything at this point in time.
Lyle G. Stevens
And on your reserves question, George, as you know, we had no drilling activity internationally, so that's both in the North Sea and Offshore Africa. The change in reserves on the oil side, it's really on the U.K. side. We had a little bit longer life in one of the Ninian hubs, so that extended the total proved reserves there. At Baobab, we have improved well performance, so that increased the reserves there. And Olowi reserves, we had sort of a writedown there, reflecting poor performance of the Olowi wells. The largest changes on the international total reserve side were actually related to natural gas, both in North Sea and Offshore Africa, and that's really a reflection of an update in the fuel usage and the shrinkage in both areas.
Our next question comes from Arjun Murti of Goldman Sachs.
Arjun N. Murti - Goldman Sachs Group Inc., Research Division
Let me offer my offer my best wishes and congratulations to John Langille as well and certainly appreciate all his help over the years and helping us understand CNQ. And we'll miss talking to him. My question was a follow-up to you, Steve, on your comments on the infrastructure. And I think we certainly agree that over some very long period of time, there's no doubt transportation bottlenecks get alleviated. I think the issue is some of the real solutions here XL, the West Coast pipelines, all have a number of stakeholder issues or presidential issues, as you mentioned. And I think we're starting to wonder as Keystone XL continues to face delays, in the event it doesn't happen, should we start worrying about your 2015 to 2017 growth profile? You guys have an outstanding resource base that you've highlighted, significant growth plans. In the event you continue to get delays and deferrals, what is your plan B to getting the oil out of Canada in the event XL faces issues and some of these West Coast options face, I think, local Canadian issues?
Steve W. Laut
Thanks, Arjun. That's actually a very good question, and it's something we take a lot of time thinking about. And I will say our view is, firstly, we believe Keystone will get approved. But you're right, it may not get approved. I think the West Coast options are facing some strong hurdles, and so it might be tougher to get those approved. We actually think the East Coast option with TCPL to Quebec, which already has a pipe in the ground, it's a gas pipeline, and then take it up to Quebec City. Maybe the most likely option, obviously the pipes in the ground. It's an elegant because it gets that gas pipeline out of the rate base for the toll base. And we believe that the opposition to that would be somewhat less than going to the West Coast. So our view is that Keystone will get approved most likely, and we believe that we can get to the East Coast. Other than that, you will need to look at rail options to do that. And at this point in time, we have enough flexibility, particularly in our thermal program. We can dial up or dial down to a certain degree how fast we develop these resources if we have any issues with pipeline access.
Arjun N. Murti - Goldman Sachs Group Inc., Research Division
Steve, just 2 follow-ups to that. But can you talk about how much you committed to XL and/or the West Coast options? And does -- what to me kind of feels like the worst-case outcome, which is it's neither rejected nor approved. It's sits in this purgatory and, therefore, could preclude you from being willing to commit to other projects and that there clearly are other alternatives. But how tied up are you to XL? And then if it -- again, if it remains in this limbo, does that preclude you from being able to sign up for whether it's Enbridge or TCPL or some of the other options that you mentioned?
Steve W. Laut
So, Arjun, we have roughly today, 500,000 barrels a day of oil production. We have signed up for 120,000 barrels a day on Keystone. We have 75,000 barrels a day committed on TMX to the West Coast. And one other point I should make on opportunities, there is significant number of opportunities, I won't go through in detail, with the other pipeline operators to get capacity, including Flanagan South, to increase -- to give access to the Gulf Coast for heavy oil. So we think other options will pop up. They'll be smaller but -- smaller in size but may not need presidential permit to have it happen. So there will be a lot of -- you've seen all the industries very driven to develop opportunities to challenge these issues and I expect this also to pop up probably through the Enbridge systems. So we're not too tied up, if Keystone doesn't get approved. Obviously, we're not committed. But even with -- if it does, we still have room to commit to other pipelines.
Arjun N. Murti - Goldman Sachs Group Inc., Research Division
And just lastly to round it out. On the rail, I believe that's more suitable for lighter oil production and maybe more of a challenge for heavier. Does that -- a, is that true? And then if it is, does it make you want to do additional upgrading or upgrading-type projects within Canada?
Steve W. Laut
Okay, so you could say rail is more suited for light, but there's also another benefit for rail in heavy. If you rail heavy and you have some steam coils in those rail cars, you don't need to deal with it, so that reduce a bunch of your cost on your heavy oil transportation. And also, there's an opportunity to rail back on the backhaul, dealing with it for the rest of your heavy oil production. So there's some advantages in both ways. And as far as upgrading goes, as you know, we are working with Redwater, building that refinery here in Edmonton. It's on track in terms of engineering. So at this point in time, we don't see doing anymore.
Our next question comes from John Herrlin of Societe Generale.
John P. Herrlin - Societe Generale Cross Asset Research
Just a quick one for you, Steve, on South Africa. You mentioned that we could have news this year on the partnership. Were you looking for a carry or are you using this to get into other exploration opportunities?
Steve W. Laut
I guess the answer will be the same as with just the Montney. We're not going to disclose the -- how good the deal is until we've got it all approved through the South African governments. We'll go through due process with them before we announce it and just -- it's just the due process. But obviously, we're open to everything.
[Operator Instructions] Our next question comes from Kyle Preston of National Bank.
Kyle Preston - National Bank Financial, Inc., Research Division
You guys talk about seeing a step change in Horizon reliability once you come off the May turnaround. Is that just a function of coming off a fresh turnaround? Or is there something different that you're doing there?
Steve W. Laut
In a part, Kyle, it is coming out of the turnaround. You expect it to have greater reliability, obviously, if you've addressed all the issues. But the other reason we think we'll have a step change is, by then, we'll have fully implemented our change in maintenance philosophy on the ore preparation plant, which is the big thing there, our most unreliable part of the whole process. The other part that will happen here is, as it is our first turnaround, as you know, process engineers, they all design where the corrosion's going to be, where the erosion will be. And what you get in real life, sometimes, that's not always right. When we open up all the vessels and inspect everything, we expect to see places where corrosion was happening where we didn't expect and places where corrosion is less than we expect. And that allows us to take mitigating actions. In some case, we may replace some piping or we'll put in different corrosion inhibitors or different programs to address that. So going forward, after the turnaround, in essence, we'll find out where our weak spots are or where our weak issues could be going forward and be able to address so we won't get any surprises as we sort of had last October with those exchanger leaks in the DRU. So that's why we say we'll have a step change in reliability because we'll have a better feel for what's really going on inside our plant. Even though we have tremendous amount of corrosion monitors throughout the plant, this will give us even greater feel and then allow us to be that much more reliable going forward.
There are no further questions registered at this time. I'd like to turn the meeting back over to Mr. Langille.
John G. Langille
Thank you very much, operator, and thank you, ladies and gentlemen, for attending our call. As usual, if you have any further questions you would like clarity on, please do not hesitate to get a hold of us. And thank you, and have a good day. Bye-bye.
Thank you. The conference has now ended. Please disconnect your lines. We thank you for your participation.
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