Cenovus Energy Inc. (CVE) Q1 2012 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Cenovus Energy's First Quarter 2012 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 Ms. Susan Grey, Director of Investor Relations. Please go ahead, Ms. Grey.

Thank you, operator, and welcome, everyone, to our first quarter 2012 results conference call. I would like to refer you to the advisories located at the end of today's news release. In particular, I draw your attention to the risk factors and assumptions. Additional information is available in our annual information form and quarterly report. Today's quarterly results have been presented in Canadian dollars and on a before-royalties basis. Bryan 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 comment on our upstream operating performance. Don Swystun, Executive Vice President of Refining, Marketing, Transportation and Development will then discuss our refining results; following that, Ivor Ruste, Executive Vice President and Chief Financial Officer, will discuss our financial performance. Brian will then provide some closing comments before we begin the Q&A portion of the call. Please go ahead, Brian.

Thanks, Susan. Good morning. Quarter-after-quarter, Cenovus continues to build on its reputation for delivering. We are delivering on our commitment to our shareholders to build net asset value and grow total shareholder return. This is highlighted and measured by the milestones that we set and achieve. Cenovus is delivering predictable, reliable oil growth and our integrated strategy increases the stability of our financial results. During our first quarter, we generated steady production growth from our oil assets, great results from our Refining business and overall solid financial results. We continued to demonstrate progress on the milestones that we have set for ourselves to build net asset value. This includes completing our winter stratigraphic test well program, advancing construction at Christina Lake phases D and E, and Foster Creek phases F, G and H. And establishing our dewatering pilot for the Telephone Lake project. John Brannan and Don Swystun will provide a more in-depth review of our operating results, but I am pleased to say that we carried our momentum through the first quarter of 2012 and have positioned ourselves well for the remainder of the year. Based in our financial performance and current market conditions, we have provided an update to a few items of our full-year guidance. The key changes include increases to operating cash flow and cash flow and revised royalty expectations based on updated commodity price forecasts. Overall, we continue to deliver on our operating and financial objectives and we remain on track with our development plans for the balance of the year, and well into the future. I will now turn the call over to our Chief Operating Officer, John Brannan.

Thank you, Brian, and good morning. As Bryan mentioned, we had a great start to the year. Beginning with our oil sands operations, first quarter production from Foster Creek and Christina Lake increased to about 82,000 barrels per day net to Cenovus, 23% higher than the same period in 2011. This production growth is a result of the industry-leading ramp-up at Christina Lake phase C. Total net production from Christina Lake averaged about 24,700 barrels per day for the quarter, or about 85% of nameplate capacity with a steam to oil ratio of 2.1. The impressive ramp-up can be attributed to overall reservoir performance and great execution from our teams, combined with the application of accelerated startup techniques. Based on this performance, we now expect ramp-up to full production to range between 6 and 12 months for future phases at Christina Lake, rather than the historical 12 to 18 months. The team was also successful in actually exceeding gross nameplate capacity of 58,000 barrels per day on February 19, and we are working hard to maximize production at those rates through the year. Construction at Christina Lake phase D is over 75% complete, and we are on track for first production during the fourth quarter of this year. We also advanced construction of phase E to over 40% complete with first production expected during the fourth quarter of 2013. Given the production growth at Christina Lake, we recently established a bitumen blend stream called Christina Dilbit blend, or CDB. In addition to CDB, we continue to sell our Christina Lake production into Western Canada Select, or WCS, subject to a quality equalization charge. We expect that the CDB differential to WCS will narrow as production from Christina Lake continues to grow and gains acceptance with a wider base of refining customers. Our Foster Creek operations continue to demonstrate reliable performance with production averaged 57,200 barrels per day on a net basis, or about 95% of design capacity during the quarter at a steam to oil ratio of about 2.1. We are working hard to operate the facilities at full capacity, but we had a few minor power outages and some unscheduled maintenance that negatively impacted our production volumes during the quarter. Looking forward, we anticipate continued strong operation performance but have a 17-day turnaround plan during the second quarter. This work has been built into our guidance and is expected to impact volumes by about 2,100 barrels per day on an annualized basis, or about 8,300 barrels per day for the second quarter net to Cenovus. We also completed our winter drilling program during the quarter, which included about 450 gross stratigraphic and observation wells drilled across our oil sands operations. These wells help advance our development plans, by supporting a regulatory application process, assist in our understanding of the reservoir basin and help move our resource barrels along the value chain from resources ultimately to reserves. Looking at our emerging oil sands areas, we successfully completed the winter work program required for the dewatering pilot at Telephone Lake. We will be starting up this pilot in May. The pilot is designed to test the efficiency of removing the freshwater off the top of the reservoir. This is expected ultimately to lead to a reduced steam to oil ratio for the commercial project. At the Grand Rapids pilot, we drilled our second SAGD well pair during the quarter which will help us understand more about the reservoir performance of this emerging play. At Narrows Lake, our next oil sands development, the project team continues to work on detailed engineering and design and have placed orders for some long lead items. We are also ready to begin our initial site preparation once regulatory approval is received, which we anticipate obtaining in the second quarter. At Pelican Lake, our infield drilling and polymer flood program continued through the first quarter. Overall performance is as expected. We currently have 4 rigs drilling in the area and we are beginning to see positive results from our program despite essentially flat production levels compared to the first quarter of 2011. Production during the quarter was negatively impacted by natural declines of the reservoir and reduced operating pressures in the reservoir as a result of shut-ins, which were required to complete infield drilling between existing wells. We saw a strong growth in oil volumes from tight oil plays in Saskatchewan and Southern Alberta. In the Lower Shaunavon and Bakken, quarterly production averaged just under 6,900 barrels per day, up about 10% from 2011 exit rates. Construction of central facilities to connect the Lower Shaunavon and Bakken production to pipelines continue throughout the quarter and we now expect completion of these central batteries by the end of the second quarter. In Southern Alberta, we continue to assess the opportunities on our existing properties in the region. We are encouraged by early results from these emerging tight oil plays and have added about 2,300 barrels per day of light oil production in Southern Alberta since the start of this year. From a capital perspective, we are on track with our spending plans this year. We continue to monitor inflation with all of our -- in all of our operating areas and we have built in about 5% to 7% inflation on our oil sands projects this year. In our conventional operations, demand for services also remained strong and we have included about 5% inflation into our full-year plans. So let's talk about the operating cost. Operating costs at Foster Creek and Christina Lake were at or above the high end of our guidance range for the quarter. At Foster Creek, we incurred higher repairs and maintenance and work over costs during the quarter. At Christina Lake, the ramp-up in production had a positive impact on the per barrel operating cost. However, this benefit was slightly offset by non-recurring repair and maintenance costs associated with the ramp-up of phase C. For the remainder of the year, we expect that per unit operating costs at Christina Lake will continue to decrease as production increases. We anticipate that annual operating cost at Foster Creek and Christina Lake will remain in line with guidance expectations for the year. We continue to manage the decline on natural gas volumes throughout the quarter with minimal capital spending. Unseasonably warm weather this winter resulted in fewer freeze offs than expected during the first quarter. This clearly had a positive effect on production. It was slightly offset by the sale of a non-core natural gas asset in the Borger region. This small disposition impacted our production by about 15 million cubic feet per day during the quarter. We continue to shift capital from natural gas to oil development and expect to be at or below the low end of guidance on natural gas spending this year. Even with this lower spending, we expect that our natural gas assets will achieve our guidance expectations on production. So before I turn the call over to Don to provide an overview of our refining results, I want to point out that our first quarter results clearly highlight the value of our integrated business model. With widening upstream differentials such as we saw in the first quarter, cash flows from our producing assets were negatively impacted. However, these same wider differentials made feedstock for our refineries less expensive. This, combined with strong -- very strong market crack spreads translated into strong refining performance that more than offset the impact of widening differentials on the upstream. In summary, we posted another operationally solid quarter. Volume growth from our oil sands assets and emerging tight oil plays combined with stable production from our conventional oil assets and another strong quarter from refining have given us a great start to this year. Now over to you, Don.

Well, thanks, John, and good morning. In the first quarter, our refining operations generated operating cash flow of $266 million, slightly above the $150 million to $250 million range we were expecting. Recent variability in supply and demand fundamentals for Canadian-based crudes has resulted in wider differentials and helped our mid-continent refineries continue to generate significant operating cash flow. Refining operations benefited from stronger realized refining margins due to our ability to run a larger percentage of heavy and other discounted crudes. Combined total crude throughput averaged 445,000 barrels per day gross, the highest quarterly average since 2007. Our Wood River refinery is demonstrating increased throughput -- increased heavy oil processing capacity and higher product yields following the recently completed Coker startup as part of the CORE project. Wood River has demonstrated rates in excess of 220,000 barrels per day of gross heavy oil processing capacity and improved clean product yield by 5%. Heading into the summer months, we expect to complete the testing of CORE processing capacity. So overall, the performance has been exceptional. We expect that until significant additional infrastructure is in place to relieve excess crude supplies at Cushing, our refineries will continue to benefit from discounted feedstock. We anticipate operating cash flow during the second quarter to range between $300 million and $400 million, excluding inventory adjustments. For the full year, we have updated our guidance to range between $900 million and $1.2 billion for operating cash flow using a $20.50 market crack spread assumption. Our refineries are expected to continue to generate strong operating cash flow for the remainder of the year mitigating the impact of wider differentials on our oil production. On the Transportation side, we continue to take a portfolio approach to accessing markets for our expanding production and diligent requirements. We support multiple pipeline portfolios that will increase takeaway capacity to markets in the U.S. Gulf Coast or the global markets via the West Coast to Canada. An example of this diversification is our firm service commitment on the existing Trans Mountain pipeline to Burnaby on the West Coast. By accessing tide water markets, we have realized higher prices for our oil. And looking forward, we are encouraged by the numerous pipeline portfolios that will increase the takeaway capacity to the coasts. I will now turn the call over to Harbir.

Thanks, Don, and good morning, everyone. Our solid operating performance has once again translated into strong financial performance. Cenovus reported cash flow per share of $1.19 during the quarter. Cash flow was ahead of the average street estimates of $1.12 driven largely by strong production volumes. We also had a timing item related to the sale of product held in the inventory at year end of about 5,000 barrels per day for the quarter, which translated to about $0.03 per share of operating cash flow. Our reported operating earnings of $0.45 per share was $0.08 per share below consensus expectation due primarily to higher noncash items such as depreciation, depletion and amortization, or DD&A, and income tax expense. Higher DD&A resulted from primarily from increased production volumes along with increased depreciation related to the CORE expansion at Wood River. We also reported higher income tax expense related to stronger operating cash flow from our refining operations, which attract U.S. taxes at a higher effective rate. During the quarter, netbacks on heavy oil were impacted primarily by the widening of the light heavy oil differential, which averaged 21% of WTI compared with 11% during the fourth quarter of 2011. Netbacks and heavy oil were positively impacted by lower overall royalties primarily due to increased capital spending at Foster Creek and Pelican Lake. Also, we incurred lower transportation costs related primarily to firm service on the Trans Mountain pipeline to the West Coast. These favorable impacts were offset by lower realized prices at Christina Lake. General and administrative expenses were $3.81 per barrel of oil equivalent in the first quarter compared with $5.04 for the same period last year. First quarter G&A expense benefited from lower long-term incentive expenses partially offset by increased office support and information technology costs. Our balance sheet metrics remain in great shape and we exited the quarter with a debt-to-capitalization ratio of 28% and a debt-to-adjusted EBITDA of 1x, both of which are at or below the bottom end of our long-term target range. This financial strength allows us to self-fund our growth plans while providing a strong dividend to our shareholders, one which we expect to place a priority on increasing in the future. I'll now turn the call back to Brian.

Thanks, Harbir. I began our call today talking about our reputation for delivering on our commitments. Cenovus is earning its reputation for predictable, reliable oil growth and the responsible development of our asset base. Our first quarter results are a continuation of this performance. I will now give a brief update on the Telephone Lake strategic initiative. This world-class opportunity was put into the market through a competitive process to bring forward the value of that resource base for shareholders and provide strategic advantage to Cenovus. This process continued throughout the first quarter and is ongoing. But we're finding the right strategic arrangement for Cenovus is our top priority and is proving a bit challenging in the current market environment. Time is on our side, and we continue to move the Telephone Lake project forward adding value for shareholders. We are enthusiastic about another successful winter strat well program along with the progress made on our dewatering pilot. We believe Telephone Lake will evolve as another cornerstone project in our oil sands portfolio. Today's results also reaffirm that we remain on track to meet the commitments that we have set for our company. Our operating and financial performance, combined with measurable progress on our development plans supports our goal of doubling net asset value by the end of 2015 while continuing to focus on increasing total shareholder return, which includes our dividend. With this, the Cenovus team is now ready to take your questions.

[Operator Instructions] Your first question comes from the line of Andrew Potter from CIBC.

I'll start, I guess, at the obvious question, just on the Telephone Lake, JB. I mean, if you can elaborate a little bit more about what it is in the market conditions that are making this challenging, is it more about perceptions on bitumen pricing and the volatility in crack spreads or is it the coming down more to differing views of sustainable oil prices?

Andrew, again, I'd like to start by, I guess, commenting that this is a competitive process so I don't think it would be appropriate for me to get into a great deal of detail because there'll be different concerns for various parties and we still have interest and still have folks in data room. Some of the feedback that we've been getting is that in terms of short term, as you have certainly seen in the market scene, there are factors at work that are discounting Canadian crudes which everyone's seeing in the headlines. And I guess, beyond that, probably, I shouldn't expand too much beyond that at this point in time. The big priority here is to look for something that gives strategic advantage to Cenovus, this is a project that is not currently in our 10-year plan. And we're looking for ways in which to commercially advantage that and advantage Cenovus shareholders. And as I said in the call notes, time is on our side. This is an asset that our confidence and our enthusiasm continues to build. Essentially based on every well that we drill there and we're very excited about the opportunity as it goes forward. And we are not in any kind of a rush to do a transaction, just for the sake of doing a transaction. It's really important that we do the right transaction, one that adds value for Cenovus shareholders.

Okay. So previously you guys were kind of giving goal posts in terms of expected deal -- very well, expected announcement at a certain point in time. It sounds like at this point you're just kind of more open-ended and we shouldn't be thinking maybe firm deadline to the process?

That's correct.

And then one question just on bitumen pricing in general, I mean, obviously everybody's coming under pressure with high diluent costs and pipeline constraint of -- other constraints, et cetera. And we hear a lot of guys talking about potentially ramping up railing and I think you haven't mentioned that a bit. Is there more than you can do there than you are already doing or what are the constraints on the rail side?

I'll ask Don Swystun to respond to that question for you, Andrew.

Yes, there is more things we can do and we are certainly pursuing opportunities to move our crude on rail. And we have been doing that. Particularly in Saskatchewan is kind of the start. We've actually moved in a range of about 2,000 barrels a day from, kind of our, Shaunavon and Bakken there. We're also look at some additional rail out of Alberta that we're working on as well. We're fortunate that we have a number of cars from our Kitimat diluent transportation in the past that we are looking at converting some of those cars for service for crude as well. And I think we will be looking to add some more rail capacity over the next few months.

So in terms of that, what could we see in terms of your overall rail capacity by year end, for instance?

I guess, it's relatively a small portion of what we would transport. I mean, keep in mind that we're integrated, so we're not as concerned, as long as we get it to our final locations, we're still making the money. But obviously, if we can increase it to some degree I would say -- kind of the maximum we'd be looking at is the range of about 5,000 barrels a day.

And very last question, I promise. Just on the tight oil, I mean, looks like you're getting good results as expected of the Bakken and Shaunavon. I think you've mentioned in the past that you're doing stuff in Alberta, anything you can elaborate on?

This is John Brannan, there's a couple of things we've got some properties in the Viking and Saskatchewan we're early days here, we drilled 4 wells we plan on drilling some additional wells this year. We do have some interested -- interesting plays that we're working on in Alberta, but not really ready to divulge those at this point.

Your next question comes from the line of Greg Pardy from RBC Capital.

I guess just a couple of nitty questions more. One is just interested in what you'd be looking at in terms of current taxes for this year, so just a question for Ivor. And then in terms of the realization on Christina, I hear everything you're saying around introducing a new crude and so on. How much of the impact on that was a function of just higher diluent blending given the ramp-up that you're going through.

Ivor, on the tax question?

Sure. Greg, we're anticipating approximately $250 million, $300 million of current tax in 2012.

And, Don, on Christina Lake?

Yes, I'll give you a little insight into Christina. And -- or -- CDB blends that were put now. And one of the things that we looked at -- so for the -- if you look at roughly Canadian dollars price, we're at that kind of $103 West Texas and we're kind of a differential in both between $1 to WCS and then CDB was getting an average discount of about $11 on top of that. That has narrowed and even now we're pushing now in the range of more like $6 and $7 a barrel and then hoping to shrink that even further. But -- so that would've taken us down to kind of that $72 number and then with our blending, we took that down by another $20, about almost $20 a barrel, so that's where you get that realized dry bitumen price in the range from our supplemental in the range of $52 -- $52.58. But going forward, I think, as we get through the start up and we start moving forward, I think, there will be Q1 is a bit of an anomaly and I think we will have better prices on Q2 -- from Q2 going forward.

Okay. That's great. And maybe just the last question, the power outage at Foster, are there any plans then to -- in terms of addressing that longer-term with cogent or any other thoughts around that or is this just sort of part of the business in the area that you're located?

Yes. This is John Brannan, I can address that. There were a couple of power outages, one was an external power outages and we're working with our third-party supplier on that. And we do have cogents at Foster Creek and we had a transformer that overheated and burned up. So a bit of maintenance and replacement there. Some of the insulation coming into that transformer just over time it had worn out and shorted through. So those are kind of one time occurrences and hopefully we've investigated that and resolved that so we shouldn't have that on the way forward.

Your next question comes from the line of George Toriola from UBS.

My question is around the way you look at the heavy oil business particularly with the differential and the challenges we've seen here. Granted that this is somewhat offset by your downstream exposure, but just wondering if you're completely comfortable with the growth projections that you have without completely hedging that on the downstream side, and if any of what we have seen in the differential market here is changing your views to the long term?

Today, in 2012, Cenovus is 100% integrated on all of our bitumen production with the startup of the CORE project at Wood River in the fourth quarter of last year. So we are in fact, 100% integrated. We started to become a little bit long bitumen as we bring on another 40,000-barrel a day phase at Christina Lake in the fourth quarter of this year, and another 40,000 barrels a day 12-months later. So we're in a situation where we will brought on 120,000 barrels a day of new production over a 24-month period. With regard to your question about are we confident in the bitumen growth, yes, absolutely, we are. And what's at work right now is a series of pipeline bottlenecks in and around the Cushing area and there's a tremendous amount of infrastructure activity that is underway to address that. You've seen many announcements on that in the U.S. by both U.S. pipeline companies and Canadian companies. And there are short-term solutions such as railcars, which we already talked about. So there is a temporary dislocation and we really do view it as being temporary. It's going to take some period of time here over the next 12 to 24 months to resolve fully. But I think it's absolutely short term and have a great deal of confidence in our ability to grow our heavy oil and our conventional oil production at a pretty good pace over the next decade.

Okay. So your views right now haven't changed, but would you then be, sort of a flip -- just a different way of asking the same question, is would you be looking for lock step growth in your downstream exposure from here just based on everything you've seen now?

One of the strategic decisions that we are assessing is the range of integration that we do have. As I mentioned, we're 100% today. We've become long bitumen in about a year's time, not dramatically, but somewhat. And we are looking longer term strategically at a variety of possibilities that would give us greater assurance around the light-heavy differential. And that could involve, for example, added exposure to coking in terms of refinery expansions. We have identified, for example, a project to further de-bottleneck the CORE project at Wood River, as an example, one of our existing assets. There's a variety of other marketing arrangements that we can look at which would include pipeline transportation to different markets, supplier engines. So quite a portfolio of things that we are looking at. This is my opportunity to state that Cenovus is strongly in favor of additional pipeline capacity and access to the West Coast both on Northern Gateway and on Trans Mountain. Certainly we are strongly in favor of access through Keystone XL down on the U.S. Gulf Coast and a myriad of other alternatives down to the U.S. West -- to the U.S. Gulf Coast. So there is a tremendous amount of industry activity on the infrastructure side recognizing the growth that we see here in Western Canada.

Your next question comes from the line of Justin Bouchard from Raymond James.

I got 3 related questions. One, what are you doing differently for the startup at Christina Lake phase C. And then the second part would be are these new techniques that you're employing are they broadly applicable across SAGD reservoirs or is this something that's Christina Lake specific? And then the third part is, when you compare the ramp-up here of phase C to phase A and B, how much of the improved performances is attributable to reservoir quality and how much is attributable to these accelerated techniques?

I'll ask Harbir to respond.

To answer your question, the start-ups. They're going well because of 3 different reasons. One is, intentionally Christina Lake A and B are not -- were not put in the best part of the reservoir because we wanted to learn about this reservoir and we've done -- and we learned a lot on how to -- whether it's drilling and operating and how to complete these wells. So partly, the ramp-up at Christina C is due to the quality of the reservoir. Partly it's due to the lessons that we learned from phases A and B on a medium type reservoir and partly it's because of the 2 startups. The other question is whether these startups will be applicable to other reservoirs, and I think they will be applicable, but every reservoir is different when it comes to the oil sands, and so we'll have to learn to what -- how well it works for them.

Your next question comes from the line of Charles Maxwell from Weeden & Co.

I am curious, a question that only would come from a U.S. analyst, which is what relationship that you use during this quarter for the loonie and the dollar? And I think it might be one-to-one, but that might be for you, Ivor.

Charles, and you're correct it was almost one-to-one.

Okay, sounds good. And, Ivor, one other quick one. Page 10 of the piece that we have. You speak about a drop of 18% in the first quarter was general and administrative expenses. That's a heck of a drop. And you say it's primarily due to longer term incentive expenses, but I wouldn't know what an incentive expense was, what is it?

Well, those are longer-term incentive arrangements, stock option prices that we mark-to-market, if you will through the quarter.

Stock options.

Exactly. Yes. And so last year there was a pretty significant increase during the quarter. This year, not quite as much. And again, it's a function of what the expected price is by the end of the quarter, the actual price was at the end of each respective quarter.

If it goes up, it puts the earnings down a little bit, right?

That's correct, yes. So we reflect in our earnings charge for increasing stock option, stock-based compensation expense.

Your next question comes from the line of Robert Bellinski from Morningstar.

I was just wondering if you could give a little bit of additional color to the well pair that was drilled at Grand Rapids pilot?

Harbir?

Yes, Robert. So we've been working on the first well pair for about just about 14 months, 15 months type. And so the key learned -- the objective -- the key 3 objectives that we have for the Grand Rapids was to learn how to start up long well pairs. We don't have any well pairs except in the Grand Rapids that are like 1,200 meters long and we want to test even longer wells. The second objective was how the reservoir is going to react to the steam. The third was what the peak oil rate's going to be. So for about the last year, we've been focusing really on the first 1 and 2 objectives. And so now, as of the last month or so, we made pretty good progress on how do we think we can start up these things. So the second well pair is really set up now. We should have it operating towards the end of the second quarter. And our objective is to apply all the learnings that we have plus apply the things that we've learned from Christina start-up on 1C and also Foster Creek start ups and apply them to the second well pair. And perfect the start up with the second well pair. So this is just normal progress in piloting. We knew we'd have a challenge with this one, that's why we're doing a pilot. Overall, we still believe that we're going to deliver on the steam oil ratios and the calendar oil rates that we predict for this reservoir that we submitted our commercial application for 180,000 barrels per day. So we're still in line with what we put in to the application.

Okay, great. And then last, I just wanted to ask, you mentioned 5% to 7% cost inflation. I just wondered how does that break down in terms of labor versus materials?

This is John Brannan, I can answer that, Robert. We said 5% to 7% overall for the oil sands projects. We have seen labor probably has increased a bit more than that, so that's one of the things that's probably gone up higher than the 5% to 7% average. Our equipment delivery times have stretched out a little bit, so they've taken us longer to get, but the cost on delivery of equipment that's only been in that 5% range. And then there's some other things that have -- chemicals and those type of things have actually kind of been in the flat range.

[Operator Instructions] And we will now open the question-and-answer session to members of the media. Your next question comes from the line of Jessica Chipman from Tudor, Pickering, Holt.

I'm definitely not part of the media, but just a couple questions. First, on the capital budget for this year, and I know there's $900 million of capital this quarter. How much of that is related to really strat well drilling or other seasonal capital expenses that were unique to Q1?

This is John Brannan. Out of that overall $900 million that we spent in the first quarter, we spent about $196 million on new resource plays and the pilot at Grand Rapids would fit into that and also the work that we're doing at Telephone Lake to set up that pilot. But the 450 or so observation of strat wells were all part of that.

Okay, so I mean, I'm just saying guidance CapEx is within that previously guided range, so I just wanted to make sure on that.

Yes, that would be great.

My other question is just following up on the flow of transportation questions. The first question, just I've heard some rumblings around the reversal of cap line pipeline. I was wondering if you'd be willing to just share what you think of reasonable cases for that occurring, if you do think it has a reasonable chance of occurring. If you would be willing to secure FT on that pipeline?

I'll just give you a quick comment, Jessica, I guess cap line is certainly underutilized currently and from everything we know. So without knowing anything particular, you would suggest that there could be an opportunity to reverse that line.

Okay. And then third question, just following up on the rail side of things. Are there also additional opportunities for small floods of bitumen on securing refining capacity either locally or even in the Gulf Coast. Or is there still some sort of FT arrangement that has to be taken by you guys in order to do that particularly in the Gulf Coast?

I'm not sure if I fully get your question, Jessica. I think you're looking for -- can we have real access from some of our locations to the Gulf Coast, is that. . .

Just -- sorry, just to secure a refining agreement, if a refiner wants to take on long-term supply, could you do that with a Gulf Coast refiner? Are there opportunities to do that locally just for smaller pieces of bitumen?

We already delivered volumes to the Gulf Coast on the Pegasus line to this point. So we're at -- we're looking at -- we already have moved out Foster Creek productions to the Gulf Coast. We actually moved some Christina over this last quarter as well. So we do continue to move volumes. Obviously not as much as we'd like to, but to the Gulf Coast. As well as we have third parties actually even railed to the Gulf Coast also.

Okay. And what is the size of that? I mean just in aggregate to the Gulf Coast?

In Pegasus we have roughly 20,000 barrels a day available to us. So that's what we move on pipeline. Rail, it would be kind of month-to-month and we don't always know where it's going sometimes we'll sell to a third party and they'll move it potentially there. So we don't know the details, but it's relatively small volume on rail.

Your next question comes from the line of Menno Hulshof from TD Securities.

I just have one question on the watering pilot at Telephone Lake. Maybe you could just talk us through the scope of that pilot. What you're hoping to achieve at the end of the day and then how you would expect to apply any learnings on a commercial setting?

Menno, it's Harbir. Yes, we drilled about 9 horizontal wells, one gas injector, some horizontal producers and then water disposables. What we're trying to do is produce the water because there's consistently tap water at Telephone Lake and varies in thickness a lot. And that's going to -- the negative part about having tap water is it increases your steam to oil ratio. We can dewater this thing. We can reduce our steam to oil ratios anywhere from about 10% to 30% depending upon the thickness of the water. And on a commercial scale, we believe dewatering is only an extra 4% adds to the capital cost, so saving your steam oil ratio by 30% of 40% with only a 4% uptick on the capital cost on the big commercial project is a good value add initiatives. And so we'll have this pilot operating in around May, June time period. And we -- 80% of what we want to achieve we'll know whether we can do that or not at -- within the first 12 months. We think it's very easy, achievable to dewater this thing and -- but we are doing it in a very unique way in fact we have a patent pending. It's something that somebody hasn't done before, so we are looking forward, but what we think we got a very high probability of success in this pilot working out.

Okay. So the -- like commercial development is not necessarily contingent on success of that pilot.

No, it's whether your steam to oil ratio being like 2.2 you'd have a steam to oil ratio 2.5, which would still be top quartile steam to oil ratio and a top quartile project in our industry.

Your next question comes from the line of Ben Hopwatch [ph] from Argus Media.

I had a question about the sale of about 250,000 barrels a day to China via the Trans Mountain pipeline. I'm wondering if you still have volumes heading to Asia and how regularly would that be occurring and what type of vessel would you be using like a Panamax or so forth?

This is Don Swystun. We continue, obviously, now that we have firm service we are able to move approximately 11,500 barrels a day to the West Coast. And at that point, we'll sell to a number of different parties. Our vision is more like those volumes will tend to go to the -- to California as the prime market. We fill a Panamax ship. That's where you get kind of the full month of 11,500 that's roughly where it comes from. But that's not to say that we do have some sales potentially to Asian customers. But at that point, we can't always guarantee where they will take it. So potentially it could move to Asia, but often they -- if they see the value of California, they can move it to California as well.

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

Thank you, everyone, for joining us today. That concludes this call.

Thank you, everyone, for joining us today. This call is now complete.