Cenovus Energy Inc. (CVE) Q1 2013 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Cenovus Energy's First Quarter 2013 Financial and Operating Results. As a reminder, today's call is being recorded. [Operator Instructions] Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of Cenovus Energy. I would now like to turn the conference call over to Jim Campbell, Vice President Government Affairs and Corporate Responsibility. Please go ahead, Mr. Campbell.

Thank you, operator. Good morning, and welcome, everyone, to Cenovus' First Quarter 2013 Conference Call. I would like to refer you to the advisory located at the end of today's news release. This advisory describes the non-GAAP measures referred to today and outlines the risk factors and assumptions relevant to this discussion. Additional information is available in our Annual Information Form and first quarter report. Quarterly results have been presented in Canadian dollars and on a before royalties basis. Brian Ferguson, President and Chief Executive Officer, will begin with an overview of our results; and then turn the call over to John Brannan, Executive Vice President and Chief Operating Officer, who will talk about our operating performance. Don Swystun, Executive Vice President, Refining, Marketing, Transportation and Development, will highlight results from refining and provide an update on transportation. Following that, Ivor Ruste, Executive Vice President and Chief Financial Officer, will discuss our financial performance. Brian will then provide closing comments before we begin the question-and-answer portion of the call. Please go ahead, Brian.

Thanks, Jim. Good morning. This quarter, we have clearly demonstrated the value of our integrated strategy. It's protected us from wider light-heavy differentials. Our overall corporate cash flow continued to be very strong, supporting our oil growth strategy. We had a great quarter from our refining business, as wider heavy oil differentials in the Brent to WTI premium resulted in strong refining margins. Our refineries are running very well following the major turnaround work that was completed late last year, and we expect to continue to benefit from our ability to process discounted crude feedstocks. Once again, we've reported strong production from our oil sands assets, demonstrating our manufacturing approach. On a Conventional side, we've made some minor reductions to our capital plans for the year. John Brannan was going to provide more details about that in a moment. This highlights the flexibility of our Conventional program to efficiently allocate capital while maintaining our momentum on the oil sands side. Our focus as always is on total shareholder return and building net asset value. I'm going to turn the call over to John Brannan now who will provide more detail on our operational performance.

Thank you, Brian, and good morning. I am pleased to discuss our first quarter operating results, highlighted by the performance of our refining assets that clearly demonstrated the benefit of our integrated strategy. We continue to execute on our oil growth strategy, increasing overall oil production by 15% when compared to the first quarter of 2012. We also continued to progress development across all phases of our oil sands construction projects. Our oil sands growth plans remain on track at our 2 producing properties. At Christina Lake phase E, construction is about 90% complete and we anticipate first oil in the third quarter of this year. We expect performance of phase E to be similar to last 2 phases at Christina Lake, ramping up to a design capacity in 6 to 9 months. Procurement, plant construction and major equipment fabrication continue for phase F at Christina Lake, and front-end engineering and design is underway for phase G. At Foster Creek, construction of the phase F plant is 73% complete, and we anticipate first oil in the third quarter of 2014. Phase F is critical as it includes prebuild for the subsequent expansions at phases G and H. In addition to our current expansions, we filed regulatory applications and environmental impact assessments for Foster Creek phase J and Christina Lake phase H. Both of these expansions will add 50,000 barrels per day of gross capacity. Foster Creek production averaged approximately 112,000 barrels per day gross in the first quarter. This was down 2% from the 114,000 barrels per day a year ago, and about 5% below the 118,000 barrels per day in the fourth quarter of 2012. This was primarily due to higher-than-expected downtime on some producing wells. Including wedge wells, we had 229 producing wells at Foster Creek. Foster Creek…

Thank you, John, and good morning. As Brian mentioned, we are very happy with the operating performance of our U.S. mid-continent refineries following major turnarounds completed in the fourth quarter. These refineries continue to benefit from sourcing discounted crude feedstocks, both heavy and light, while selling finished products at higher prices. Further pipeline congestion in the quarter led to wider light-heavy differentials, offsetting a narrowing Brent-WTI spread from the fourth quarter. We reported another outstanding quarter in terms of operating cash flow. The primary driver of the improved cash flow was a market crack spread of approximately $27.50 per barrel or about $4 a barrel higher than strip pricing used in our guidance. A higher crude advantage relative to benchmark pricing also contributed to strong cash flow. These factors more than offset lower refined product volumes produced due to minor planned maintenance. At Wood River, we ran an average of 103,000 barrels per day of high-TAN crude during the quarter, including our Christina Dilbit Blend or CDB. This integration is extremely valuable to Cenovus, recovering the incremental discount we normally see on our CDB stream. We have the ability to ran up to 130,000 barrels per day of high-TAN crudes at Wood River. At Borger, we also benefited from discounted West Texas sour crudes coming from the Permian Basin, where strong supply and pipeline constraints persisted in the quarter. For the second quarter of 2013, we're expecting $250 million to $350 million of operating cash flow from our refining business based on a Chicago 3-2-1 strip price of $25 a barrel and the recent narrowing in light-heavy differentials. I'd now like to talk about our transportation portfolio. We continue to proactively seek transportation solutions for our growing production. Accessing the West Coast through our firm service on the Trans Mountain…

Thanks very much, Don, and good morning, everyone. Cenovus' strong financial performance in the first quarter allows us to support our business strategy with balance sheet strength and capital flexibility. For the first quarter, Cenovus reported fully diluted cash flow per share of $1.28, ahead of the consensus estimate of $1.14 per share. Strength in refining margins during the quarter offsets weaker upstream pricing, again, highlighting the value of our integrated business model. Operating cash flow from refining totaled $524 million, coming in above our Q1 guidance and nearly double what was generated in the first quarter last year. Using the last in, first-out, LIFO accounting method employed by most U.S. refiners, Cenovus' first quarter operating cash flow would've been $20 million lower, not a significant difference this quarter. Operating cash flow from Foster Creek and Christina Lake was $262 million in the first quarter, approximately 10% lower than the prior year. Benchmark WCS prices were down 24% over the same period, although pricing weakness was partly offset by growing production volumes from Christina Lake phases C and D. Our WCS hedging program benefited us in the first quarter with 49,000 barrels per day of light-heavy differential locked in at USD 20.74 per barrel discount. And compared to the actual discount of almost USD 32 per barrel in the quarter, we realized a pretax gain of approximately $50 million on our differential hedges. Operating cash flow from Pelican Lake and our other Conventional assets was $302 million in the quarter compared with $394 million in the same quarter last year. Despite higher volumes, weaker price realization and higher operating cost contributed to the decline in operating cash flow for the period. We invested only $9 million in our natural gas business this quarter, but generated $115 million of operating cash…

Thanks, Ivor. We continued to deliver on our commitments, and this is translated into steady production growth from our oil assets, excellent refining results and a strong consolidated financial performance. We remain well positioned to execute on our plans in 2013, anchored by our integrated strategy and a strong balance sheet. Cenovus achieved the milestones we set for ourself in the first quarter. This included completion of our strat well program, which we expect will continue to contribute to growing both reserves and resources. We progressed procurement and site preparation for Narrows Lake, our third commercial oil sands project, which is now underdevelopment. Finally, we submitted regulatory applications for expansions at Foster Creek with phase J and another expansion at Christina Lake for phase H. I believe we are off to a good start in 2013, and our teams are focused on maintaining our operating momentum throughout the year. Our integrated approach has reduced the volatility of our cash flow, and we are on track with the development plans we have in place to build net asset value. As a reminder, we're hosting an Investor Day in -- here in Calgary on June 18, which will provide a more thorough review of our strategy, our assets and our growth plans. With that, the Cenovus team is now ready to respond to your questions.

[Operator Instructions] Your first caller is Arjun Murti from Goldman Sachs.

My first question was really on the comments about taking a portion of Foster Creek into blowdown mode, I was intrigued by the notion of that. I think you mentioned 3 pads will be moving to this blowdown mode. Can you talk about what this will mean for Foster Creek production? I assume these are some of the original phase A and B type pads you're doing. And I guess over the next year -- next several years, how much of this field will move into blowdown mode? I assume that also means a pretty rapid decline in production in those areas. But if you can provide any more color in general, that'd be great.

Sure. I'll get Harbir to respond to that. This is part of our overall development plan and part of the development and the growth of the resource. So over to you, Harbir.

First, the blowdown, normally -- this is a normal phase for SAGD. We've gone through doing our pilot years and stuff. After about 7, 8 years of production, when you get to about somewhere between 60% to 70% recovery factor, we start to slowdown the steam injection and start putting in methane. Sometimes we even put in air, and then over time, we just shut off the steam totally. So you continue to produce oil. There is a decline rate on that well pair. But overall, that steam is used to start up other well pairs. So blowdown will reduce our overall steam-to-oil ratio because you're continuing to produce oil for probably another, I would say, at least 5, 10-year-plus type numbers without any steam injection. And so the wells, you asked about which pads are on. It's generally phase A pads that have gone on blowdown right now, and we'll -- over time, as we get closer to that 60% to 70% recovery factor, we'll start to put more pads on blowdown. So right now, as a percentage of the field, those 3 pads are like 8% compared to the whole field. So over time, that does -- that number does get higher. But like I said, this is a good thing because it helps reduce the SOR. And as you know, these plants are water plants, so when the SOR goes down, the oil production tends to improve.

That's very helpful, Harbir. Can you talk about the type of decline you expect when you remove the steam?

Okay. The type of decline is -- the numbers -- I don't know. It's -- I don't know if I can comment on that. It's probably like 20%. But overall, though, in terms of the project, production capacity should tend to improve with this. So the individual well decline isn't that relevant because you're using that steam to start up other well pairs. But yes, for an individual well, it will go down with time, and then it stabilizes and gradually goes on for the next 7 to 10 years.

Got it. That's very helpful. And then just switching gears on some of the market access commentary. I noticed that in this quarter's release, you talked about 40,000 barrels a day having market access. Do you have a goal of where you want to take that to over the next 1, 2, 3, 5 years? I assume rail is an important component of that. Can you talk about representative rail tariffs to either the Gulf Coast and East Coast? And sorry for all the questions, but lastly, do you see the West Coast as a viable option for a Canadian heavy -- the U.S. West Coast -- excuse me, as a viable option for WCS-type crudes?

Thanks for that question, Arjun. The whole issue of market access is probably the most significant issue for Canadian oil industry as you're well aware. I think we're very well-positioned in terms of portfolio that we have. We're actually just in the process right now of updating our strategic plan, so we'll be able to give a little more color, overall, on our general strategy in terms of target. You asked the 40,000 and where will that get to. So we're probably a couple of months away from being able to talk publicly about where we expect that bigger picture to go to. But Don can certainly comment about the viability West Coast access and what our plans are on the costs here particularly that relates to the first quarter and where we're planning for 2013, too.

Yes. Thanks, Arjun. I guess, first, I'll sort of reiterate some of Brian's comments. We've got 7 years of experience in direct marketing production to the U.S. Gulf Coast, particularly Port Arthur, and that's your Pegasus. That's your barge, that's your rail. We do -- we've done a lot of things to get volumes to that market, and we will continue to look to increase our volumes over time through commitments we've made. In terms of -- you've got 2 questions. On the rail side, certainly, very viable. I think long-term, maybe we'd look at kind of 10% of our volumes moving on a rail. I think it's very beneficial in the fact that if you're moving volumes on rail, you've got them off the pipeline system, which, overall, helps the upstream producer. At this point, we've railed pretty much to the West Coast, East Coast and Gulf Coast in a lot -- and typically, the range is -- the tolling varies quite a bit. I'll throw around an average of $12 to $15. It can be slightly higher than that in some cases, depending where you're going. But I think, typically, if you think of $12 to $15, that's a good number. West Coast, in terms of Western Canada Select, it's a great area to send volumes to, or Cold Lake Blend that we send there. Typically, we're moving on quite a lot of volumes, 11,500, going to -- off the West Coast to firm transportation on Trans Mountain. Virtually, all those cargoes are bound for the California market, and it's been quite strong pricing in that area. And we will generally continue to do that going forward.

Don, that's very helpful color. I appreciate it. Just a quick follow-up on the $12 to $15 a barrel. Is that for upgraded or lighter oil, or would heavy oil volumes also be at that type of tariffs? And I'd imagine it is going to vary depending on which end market. I think we've thought of numbers to some markets that's being kind of a decent chunk above that, but maybe some of the closer markets are more in that range?

You're probably right. You could probably see costs up to $18. Currently, we move medium kind of -- lighter medium crudes at this point, primarily Saskatchewan is where we've been moving from southern Alberta also. To this point, we don't -- we haven't been moving any of our heavy crudes. We do plan to be doing that starting more later next year would be the plan for that. That's all, as you realize on using oil [ph]-insulated cars, which you have to have generally when you're moving your heavier crudes. We currently have approximately 225 kind of general purpose cars that we use -- that we own, and we're slowly increasing that as well.

Your next caller is Greg Pardy with RBC Capital Markets.

Just a couple of questions. With respect to Christina Lake, I mean, it's great news that you're able to process a lot of that at Wood River. But what do you think is going to -- what is required in order for that differential to begin to narrow vis-à-vis the benchmarks? Is it -- is Flannigan, is it being able to access other markets? Just curios on that front. And then secondly, with respect to the sale of Southeast Saskatchewan assets, I know you're suggesting it may or may not close this year. But just any color on that would be helpful, because it's April, so I'm surprised that, that conclusion is there at this state. That's all.

Sure. Greg, it's Brian. Perhaps I'll take the last question first, and then ask Don to respond to the first one with regard to the Christina Lake Blend. With regard to Lower Shaunavon and Bakken process, those are non-core assets for us. And what we've seen, as Ivor has indicated, you've certainly seen a very significant downdraft in the Canadian energy market here over the last 3 to 4-week period. What we've been advised, and there's been a very active data room, is that companies that would like to participate and like to offer are telling us that right now, they're having a challenge accessing capital markets here in Canada because they're smaller Canadian players, and some of the names would be familiar to you. So what we're saying is that we will continue to optimize those assets and the cash flow coming off of the minimize capital over the course of this -- the balance of this year, and we're ready to move them out when we think that we've got a satisfactory capital market and allow funding for some of these other companies. We continue to have good interest in the process. It's really a question of access to capital markets during the short-term. So markets improve and I expect that we will be able to announce that we've got a transaction we can close. And I'll turn over to Don now with regard to the Christina Lake question.

Can you repeat that question again on Christina Lake? Sorry.

Your -- so the -- it just sounds like the acceptance of Christina Lake is somewhat problematic. I know it's a higher TAN crude and so on. Even though you're sending some of the -- I know you're effectively getting better pricing in some of the Foster Creek stuff because you're sending it to the West Coast, so you're jacking up pricing a bit. But if you look at the differential on Christina Lake, what I'm curious about is how is that gap going to close? Is that a function of just better access for Canadian crudes to Gulf Coast, like through Flanagan South? Or are we going to continue to sort of live with a pretty big discount on this stuff vis-a-vis benchmarks?

Yes. I think the way to think about it, Christina Lake -- Christina Dilbit Blend or Access Western Blend are -- have been relatively new crudes in the marketplace, so the whole process that we've gone through is trying to get, what we call, market development and trying to move substantial amounts of volumes basically to as many refineries as we can, and that has helped starting to narrow the differential on CDB blend quite a bit from even the first quarter of last year. We had a -- this quarter was kind of a bit of an anomaly. But we think we're moving that below kind of the $5 level and maybe bring in -- it's something more like a $3 to $4 level. I think the challenge is, it's a higher TAN crude, so that doesn't mean -- that does mean that metal refineries can run it. So definitely, when you get access to the Gulf Coast market and a lot more coking refineries and people who have the metallurgy to run higher TAN crudes, it opens up a lot more access to more refineries. And in that case, you should see much better or a narrower differential on that CDB stream. And we had been moving some of that volume, some CDB volumes to the Gulf Coast actually that we've done previously on the Pegasus line, and it's got generally very good acceptance down there.

Okay. Can you just remind me how much exposure you've got to Flanagan South?

We haven't been quoting those commitments yet. We might have some update in the -- at Investor Day. But at this point, we haven't been specific.

I think what we did say in our last call, Greg, was that we anticipate having 150,000 barrels a day going down to the U.S. Gulf Coast market.

Through a combination.

Through a combination of Flanagan and Keystone and Pegasus.

You're next caller is Mark Polak with Scotia Bank.

First question, I was just curious generally in terms of the expansion at Foster and Christina and an earlier work you're doing at Narrows, what kind of inflationary pressures you might be seeing, if there's any change in that regard? And then the second question in regards to production at Foster Creek. It's been sort of a slight but steady sort of monthly decline sort of middle of next -- last year, and just curious of any commentary on that. Is it just a function of it was some very large flush production coming out of a turnaround middle of last year, and then you've just gradually been increasing the number of wells you've been working on? Or is there something else going on there?

John Brannan will comment on that.

I think, Mark, in general, for the inflation this year has been less than we have seen in previous year. Previous year, we're saying around 3 to 5. This year, we're not seeing very much inflation at all. With the slowdown of other major products -- projects like the Curl [ph] project and those are actually getting a bit better quality and experience level of workers that are working at our facilities, say, like Foster Creek, Christina Lake and Narrows. So overall, there are a few places where prices are up a little bit and the prices are down, but in general, we've said that it's fairly flat so far this year. And then also -- I hope you heard that, Mark, because my mic wasn't on initially.

I did.

Okay. And then also on the production at Foster Creek, if you take a look at the production that we had, say, in the third or fourth quarter, we did get a bit of flushed production from -- after the turnarounds, so our numbers were over the 120,000 barrel a day range. But going forward, we expect to stay in that 110,000 to 120,000 barrels a day range. As Harbir talked earlier, we do have some pads that have gone on blowdown, so we've moved that steam over to other pads. When that steam becomes effective, volumes will increase from those particular pads, and we expect to work off a little bit of a backlog that we've got on some of our wells that are down and things like that by the end of the -- or end of the second quarter into the third quarter, and we would expect that second half of this year, we're running closer to the high end of our range.

That's helpful.

The other thing I might want to add, Mark, is like Foster Creek is actually performing better than we designed it for. We actually designed it for steam-oil ratio of 2 at a 120,000 barrels a day. And so we expect us to, given where our steam-oil ratios are today, we -- our production is actually very good. So we have the opportunity to push that plant even further, but that's going to be a normal range in the 110,000 to 120,000, and we will get to the higher end of that range again in the third quarter. But overall, everything is performing as we expected or better.

Your next caller is Amir Arif with Stifel, Nicolaus. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: The first question on the blowdown of Foster Creek. When you replace that with a new well pair, is that happening in the same area as the original phase? Or have you sort of used up the inventory phase A and sort of the growth needs to come from the next phases?

Yes, we don't really have a set area for the different phases. What we've done is prioritizes what adds the most value in terms of net present value, and those pads are controlled and their sequences is controlled. And so independent of whether phase A needs those pads or phase C or D needs them, that sequence is set up, and generally, they're not close to the blowdown phases, but they're in a new area that we're starting up and are not linked in thermal communication with them. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: So once you've hit that recovery factor that you mentioned, is that sort of the limit of the life for that reservoir or for that area?

Yes. Our goal is like we're generally, we're pretty happy when we reach about 70% recovery factor. Our IQREs are actually only sitting at 55% to 63%. So the fact that we're putting wells on blowdown when we've already recovered 70% is actually great news because that tells you that we have a chance of getting close to an 80% recovery factor, which is kind of the best recovery factors you can achieve anywhere around the world in an oil field. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. So the new well pair that you drilled, Harbir, I would assume that's considered more maintenance capital because you're just keeping the production flat. Can you break out how much of the Foster Creek CapEx is maintenance versus growth? I'm just looking at your full year CapEx guidance in terms of Foster Creek. It has a higher CapEx number than Christina Lake, yet the production growth is similar?

Yes. I don't know if I can answer that question exactly, but I'll just give you a general feel for when we look at our total F&Ds for a 30-year life period, we're coming out with numbers in the $8 to $10 per barrel range, and approximately about 25% to 30% of that comes with the initial plans. The rest of it is kind of spread out. And the maintenance capital goes up and down with time, like there'll be years where we won't have anything significant for 2, 3 years, and then all of a sudden, we'll have a lot of expenditures. But on the average, that's kind of how you should look at the business is that you're trying to -- we think we can run this business with an $8 to $10 F&D total for a 30-year life period. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. But as -- I mean, we should be assuming that more wells should struck to enter blowdown over time here?

Yes, absolutely. All the wells will go on blowdown. And generally, it's -- depending upon oil prices, that controls whether you're at the 50% to 60% range or the 60% to 70% recovery factor range. Today, we think we're in the 60% to 70% recovery factor range. And so you do -- you should expect us to have more and more wells going on blowdown in the future years. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. So what I'm trying to get at, Harbir, is the difference in the capital for Foster Creek versus Christina Lake given that there's similar amount of growth coming out. Is that difference due to the maintenance capital, or is that due to additional capital you're putting in for the additional growth phases coming in Foster Creek?

No, no -- yes. What you got to remember is that when we did Christina C, D, E, most of the expenditures occurred in C for D and E, so there's not -- the capital is substantially less on an E works as a first phase. So Foster F were spending a lot more money and prebuilding for G and H. And so that's how you should look at it. It's kind of like a 60% for C and then the remaining 20%, 20% for kind of like a D and an E. So the capital is substantially less for the second and the third phase. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. That sounds good. And then just moving over to Pelican Lake. Can you give just some more color in terms of what are the issues in terms of the lower production response?

Okay. First of all, Pelican, we really love this play. We think this has got a lot of potential. Our guidance says that our cash flow is about $400 million to $440 million. But as we grow this production, we see our cash flow reaching like $1 billion a year on this play. Now the thing with the play is that over the last 1.5 years, some of the pads have responded really fast, some of them have responded a little slower than we've expected. The ones that were lower pressures are taking a little bit longer to respond. But overall, we've proven this concept of infill drilling with our pilot that was down to 25-meter spacing, we've actually exceeded 40% recovery factor on that pilot. And so what we're trying to do in reducing these well spacing from 200 to 67 is actually only achieved about a 30% recovery factor. So fundamentally, the reservoir is performing like we expected, except for that delay in response on some of the low-pressure pads. And because of that, we feel that our ramp up to 55,000 barrels per day is going to take a little bit longer, which means that we don't really need to put that facility in right now. We can afford to wait in a year to start building that facility. Plus the environment is pretty good to actually hold off, and we're getting pretty good prices on a lot of the stuff that we're building right now and good quality people. So overall, that play is really working as we expected with the caveat that some pads are slower to response. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. And so when you say slower to respond, that doesn't mean you're getting fingering or breakthrough of the polymers. It's just taking longer to get there?

No, no, no. This is really what we call fill-up is that before you can start displacing this oil, you need to put a little bit of polymer and water to just fill up that reservoir and get the pressure up, and that's what we're doing. So the fingering is long in the future from this. So -- and the other thing is, to answer your question on the fingering, a 25-meter spacing pilot would've seen a lot more fingering than a 67-meter infill pilot or development. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. That's good to know. Just a final question on the rail option. Just curious to know what's the hold back in terms of being able to try to accelerate the volume on rail faster? I mean, I know you've gone from 6 to 10. Just curious given the differentials you can capture and the operating costs you mentioned for transportation in terms of what do you need or what are the bottlenecks to expand that faster?

First off, I mean, rail provides a nice supplement to moving volumes. I guess, number one, if we can move it on the pipeline, we do because it's lower cost and more value to us, so we try to that. When we're moving on rail, we -- at this point, because we're not using coal-insulated cars, we're typically moving on only kind of our medium and light volumes. And as you've probably seen, there's -- the kind of bottlenecks occur with -- you have to have onloading facilities, you have to have offloading facilities on place and working with your customers in particular. So that's one of the issues. Another one is backlog of cars, particularly coal-insulated cars. It takes time to get those. But I think oil producers are slowly getting up the learning curve and starting advance the whole rail initiative. And it's become, as you've seen, bigger and bigger part of the transportation network. And I think as we're get into Alberta, we haven't even moved -- we're just starting to move unit trains, and that's another big win for everyone in terms of lower cost. So I think it's going to be more to come. It's just a little bit delayed and just waiting to get all the infrastructure in place.

Your next caller is Paul Cheng with Barclays.

Two questions. First, strategically, do you want to increase your refining exposure, somewhat in line with your production growth outlook to match the integration, or you don't really think that that's necessary? Secondly, on the rail to the Gulf Coast, have you looked at one of the possibilities to bring the Bridgemont [ph] down without the condensate into the -- without the dilution to the Gulf Coast, and then in the return car, bring back to condensate? By doing it this way, then you may actually allow you to lower the condensate price in Alberta, so that should be good news there for you guys.

Paul, I think you answered the second question yourself with the -- with your -- the description of the question there. Now with regard to the refining growth, as I mentioned, we're going through a process right now of updating our strategic plans, so we'll be able to give you a more fulsome update on that in a couple of months time at our Investor Day. As a general statement, right now, we are, in terms of total refining capacity versus net production capacity, we actually consume more and purchase more crude of all kinds for the refineries than what we're actually producing today. If you look at our heavy capacity, then we're almost in balance today just on heavies. As we go forward, we will look at a combination of accomplishing economic integration as opposed to just physical integration. So we have the option of potentially some greenfield organic expansion at Wood River, which we're giving some thought to today. We also are looking at a combination of firm transportation capacity on both pipe and rail that would get us to markets where we can change the marketing point that we're selling out. So all of those things are taken together in terms of our total marketing strategy, and as I said, we will be updating opportunities and our strategy here over the next couple of months. And we can maybe get back to you on that one a little more fulsome at our Investor Day.

Your next caller is Mike Dunn with FirstEnergy.

A few questions from me. Maybe I'll just start with Pelican Lake. I guess, probably for Harbir. Harbir, you mentioned that some of these areas take slower to respond, some are faster. What is it that gives you the confidence that this slower response, the ones that are taking longer, are responding? Do you have some loads where they did take longer to respond but subsequently have responded, and that's what's giving you the confidence? And then just wondering also if you have any sort of notional indication of how much more capital is going to be required to get this to the sort of 55,000 barrel a day level, and when might that be reached?

Okay, Mike. In terms of the confidence, you're actually right. When we look at our pads, some of the pads have already responded on the lower pressure ranges. So it's a question of the new ones that are coming on and taking longer that we think will respond too. So we have our actual data that we feel comfortable that we will exit at that number that John told you, that 27,000 to 29,000 by the end of this year. In terms of the capital, I think depending upon how fast of a pace we go, we do have the option to slow down or speed up this play going from anywhere from 2 to 6 rigs. So the capital is really in a yearly basis controlled by that number. And then when we reach the 55,000, it is actually controlled by how much investment we're making over the next 4 or 5 years. So we could ramp up to that number, that 55,000 anywhere from like 2017 would be the earliest and depending upon the expenditures. We can't do it any faster, but we could slow it down and it could take longer to ramp up, so...

Okay, great. And maybe, Harbir, while you're talking here. On Narrows Lake, earlier in this call, you had mentioned that I think with Foster Creek, the upfront cost for the initial one of those phases is a lot higher than the subsequent ones. I was a bit surprised with your Narrows Lake that phase 1 costs estimates about 30,000 of flowing barrel. Is that sort of allocation between that and the future phases different than other phases, or should we be assuming that the future ones are -- would be quite a bit lower?

Yes, that one is -- because it's a new project, doesn't have any infrastructure, that's really why that number is at that 30,000 barrels per day. And so I think that number is pretty representative of the next couple of phases in that area. We might be able to bring that number down for the third phase, which we still have to kind of figure out how we're going to do that one in terms of are we going to be optimizing it or actually adding to the facility. So -- but it's -- generally, the number is higher than the 22 to 24 that you've seen for Foster Creek and Christina Lake.

Right. Just to be clear, I would've expected that just on a single phase to be higher for the initial phase so...

Yes, yes, so -- that number is a combination of the first few phases.

Okay, okay. That's where my misunderstanding was. Great. And then last one...

Just -- Mike, just so we understand, just like we're prebuilding for F, G, H and C, D, E at Christina, we're kind of doing the same strategy for Narrows on A, B, C.

Right, right. And then last question, just a modeling question. The guidance for refining cash flow in the second quarter, I believe you said based on a $25 WTI 3-2-1 crack spread for the Midwest? And just wondering what the crude differential assumptions are going into that as well?

We've gone with the $25, what would be a Chicago crack spread. That's -- at this point, looks conservative. It wasn't -- about a week ago, we've had -- there's a lot of volatility in the Chicago markets. Chicago was up to $35 or something today. So it's been moving a lot. But we're recognizing, as you pointed out, there are narrowing differentials that we've seen in the last little while, as also West Texas to Brent continues to narrow somewhat, or Brent -- or LLS. So that's why we're a little more cautious on the $250 million to $350 million for the quarter. I think for our differentials, we're kind of in that -- we're in a bit of a lull. I think what we tend to see going forward is that as more volume comes on again, I think we're going to see differentials widen. We're in a short period right now because there's a bit of production that's kind of not showing up in the market. One being Curl [ph] is a good example, I think, and that's kind of kept the differentials narrow here for a bit of this quarter. But I expect the third, fourth quarter, that we'll actually start widening somewhat more in the $20-plus range.

Your next caller is David McColl with Morningstar.

So 2 questions on separate topics. I will just get them out right away. The first question goes back to the asset sales. I'm curious if you're finding that market access or really the difficulty of market access right now could be a bit of a contributing factor to the lack of interest or, perhaps, what I should say is more of a difficulty with potential buyers securing access to capital. So just wondering if you would have any thoughts on that. And then the second question jumps back to Foster Creek and the blowdown. What I'm curious about is, on one hand, you're talking about lower operating costs but also some methane injections. So I'm just kind of curious, if you could give a little bit of insight into the volume of methane that's being injected? And whether there's plans, which I assume there is, to recover a significant portion of this methane as the wells go into a full blowdown.

Thanks, Dave. I'll -- this is Brian. I'll answer the asset sale question. As we've said the -- it's really market conditions and access to capital. We continue to see a lot of interest in the assets by the data room. And you're quite right, you've seen a big downdraft in the Canadian energy sector. My view is that, that has been primarily driven by the issues we're seeing around market access, the congestion, the wider differentials that we have been experiencing and likely will experience. Also as Don mentioned, as additional volumes come on here, we do expect them to widen again in third quarter, so that is the constraint in terms of smaller companies being able to access capital markets. And so that is the constraint. You're quite right there. With regard to Foster Creek blowdown and methane, I'll ask Harbir to respond to that.

Okay. With respect to the blowdown, first of all, that all is included in the costs in terms of methane injection. We do recover a lot of that methane already. But in the future, we will -- our plans are to actually go to more air injection rather than methane injection, and that actually helps us generate a little bit of heat, too. So that's on a pilot stage right now. So the methane injection is a temporary thing, but we do intend on recovering that over time, the methane back. And we recover -- we generally -- you asked about volumes. We probably put in like 250 Mcf per day-type number when we go on blowdown. Now that's -- we'll start with a smaller rate and then we gradually, over a year, go to that rate. So -- but that is all included in our op cost numbers, and that numbers will go down with time, we expect.

There are no further questions at this time. I'll turn the call back over to Brian Ferguson.

Thank you for joining us today on our first quarter conference call. This call is now complete.

This concludes today's conference call. You may now disconnect.