Cenovus Energy Inc. (CVE) Q1 2016 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen and thank you for standing by. Welcome to Cenovus Energy’s First Quarter 2016 Financial and Operating Results. As a reminder, today’s call is being recorded. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. [Operator Instructions]. Members of the investment community will have the opportunity to ask questions first. At the conclusion of that session, members of the media may then ask questions. Please be advised that this conference call may not be recorded or rebroadcast without the express consent of Cenovus Energy. I’d now like to turn the conference call over to Mr. Kam Sandhar, Director, Investor Relations. Please go ahead, Mr. Sandhar.

Thank you, operator, and welcome everyone to our first quarter 2016 results conference call. I would like to refer to you to the advisories located at the end of today’s news release. These advisories describe the forward-looking information; non-GAAP measures; and oil and gas terms referenced today and outline the Risk Factors and assumptions relevant to this discussion. Additional information is available in our first quarter Management Discussion & Analysis and most recent annual information form or Form 40-F. We’ve also posted an updated quarter presentation which can be found at cenovus.com under the Investors section. The 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 update on our cost reduction initiatives and then turn the call over to Ivor Ruste, Executive Vice President and Chief Financial Officer, who will discuss our financial performance. Following that Drew Zieglgansberger, Executive Vice President; Oil Sands Manufacturing will provide an update of our operating performance. Bob Pease, Executive Vice President, Corporate Strategy and President of Downstream will then discuss refining and marketing results and our view of fundamentals. Finally, Brian will then introduce the newest member of our Cenovus leadership team Kieron McFadyen Executive Vice President, Upstream Oil & Gas, before providing closing comments prior to the Q&A portion of the call. Please go ahead, Brian.

Thanks, Kam. Good morning. As I said in February, our prime focus is ensuring our financial resilience without compromising the strength of our balance sheet. So far, 2016 has been a brutally challenging year for our industry with quarterly Western Canadian Select crude prices averaging 43% lower year-over-year and down 31% quarter-over-quarter. We entered this year in a strong financial position with $4.1 billion in cash on the balance sheet and $4 billion of undrawn credit capacity, a position that we worked hard to secure in the past year. Going forward, we will continue to focus on maintaining our financial resilience to withstand a persistently low price environment. Across the Company, we continue to make significant progress on our cost cutting initiatives, while staying focused on the safety of our people and our assets. We are on track to achieve upto $500 million in planned capital operating and G&A cost reductions that we announced earlier this year. This is on top of the $540 million in cost savings that we achieved in 2015. We continue to expect that about two thirds of these cost savings will be sustainable. This will create significant value for our shareholders over the next several years. Part of the cost savings effort has been focused on reducing our work force to better align with a more moderate pace of growth. These were difficult but necessary decisions. We have largely completed the previously announced workforce reductions for 2016 of 440 employee and contractor roles. That reduces our total headcount by 31% fewer people than the end of 2014. Following a thorough review of employee compensation and benefit programs, we reduced 2015 bonus payments and have decided to reduce allowances and benefits going forward. Our goal in this review has been to make sure that we are aligned with our peers and with market condition while also allowing us to remain competitive and attract and retain key talent. Our employee compensation structure will continue to be results driven and incorporate a pay for performance approach in the most cost effective way. Further, in an effort to control costs and given the challenging market conditions, the Board has kept 2015 base salaries for the named executive officers at 2013 levels with performance bonuses reduced and partially deferred into 2017. As I look forward in 2016 and beyond, I am optimistic about the future for Cenovus. We will continue to focus on maintaining our strong financial capacity, maximizing margins through continuing cost cutting efforts. Our oil sands extension projects remain on track to generate first oil in the third quarter of 2016 and we still have a rich portfolio of development opportunities to reactivate when the timing is right. I’m now going to turn the call over to Ivor Ruste, our Chief Financial Officer. He’ll discuss our financial performance and our balance sheet strength.

Thanks Brian, good morning everyone. While this quarter was strong operationally, financial results were challenging given the overall commodity picture. Our hedge program proved to be valuable once again with hedge prices in the quarter being much higher than realized benchmark pricing. All totaled, we realized a $165 million in hedge gains this quarter. We exited the quarter was approximately $3.9 billion of cash on our balance sheet. Our net debt metrics at March 31, 2016 were 16% net debt to capitalization and 1.3 times net debt to adjusted EBITDA. We reported cash flow of $26 million in the quarter. Cash flow was impacted primarily by three things: First, we saw a lower bitumen realizations and higher condensate costs due to timing differences between purchasing and selling condensate; Second, we had a $31 million inventory write-down on crude oil and refined products; And finally, we were impacted by weaker refining margins. Bob Pease will discuss these items in more detail, shortly. I would like to take this opportunity to address the ratings action that was taken by Moody’s, during the quarter. In late February, Moody’s downgraded its rating on Cenovus from Baa2 to Ba2. We continue to believe that the actions we took over the past year and a half to bolster our balance sheet and secure the strong liquidity position that we have today were prudent and position us exceptionally well within the industry. There is no material impact to our business as a result of the Moody’s downgrade and we will continue to make decisions in line with that of an investment grade Company. Earlier this month S&P reaffirmed our BBB investment grade rating with a stable outlook, reflecting our robust liquidity position and the significant capital, operating and G&A cost reductions we have achieved. As Brian mentioned, maintaining balance sheet strength is one of our top priorities along with continued investment in our core oil sands assets. In this challenging business environment, it is absolutely critical that we continue to maintain capital discipline. Even if oil prices remain in the U.S. $40 per barrel Brent range through the next two years, we expect to be able to execute our planned capital program, fund our current dividend and maintain a strong balance sheet. This puts us in an enviable position to weather any further deterioration in oil prices while positioning Cenovus favorably for an oil price recovery. I will now hand the call over to Drew Zieglgansberger to discuss our oil sands operations and our focus on lowering operating costs.

Thanks Ivor. Operationally, Q1 was a strong quarter. We remained focused on executing our work and operating our facilities safely and reliably while continuing to find ways to realize efficiencies and continued cost savings. In February, I’ll walk you through some of the changes that we implemented over the past couple of years at Foster Creek to improve wellbore performance and what to expect from our operations going forward. Over the first three months of 2016, Foster Creek’s production averaged approximately 61,000 barrels per day net, down slightly from Q4 levels. This was as expected, given the number of wells we had offline at the end of 2015 and the higher declines that we saw mid last year, as a result of the better increased wellbore conformance. We’ve now brought on two of the seven new well pads, planned for this year, which is the start of a measured ramp up of volumes from Foster Creek throughout this year. We’ve also brought back roughly half of the wells that went down in 2015 and are now at a normal inventory level. As we highlighted in February, we remain on track to average between 60,000 and 65,000 barrels per day net in the first half of this year and 65,000 to 70,000 barrels per day net in the second half of the year, exiting this year above 70,000 barrels per day net. Foster Creek volumes in March were as expected, averaging just over 62,000 barrels per day net with the SOR tracking at the high end of our guidance range of 2.6 to 3, as we continue to see new well pads. We expect to see SORs at this levels through much of the year as we start up new well pads associated with the Phase G ramp up. Christina Lake continues to demonstrate top tier performance averaging an SOR of 1.9 in the quarter and it continues to produce at or near the designed capacity of 80,000 barrels per day net. Both Christina Lake Phase F and Foster Creek Phase G expansions remain on track for first oil in the third quarter of this year. We expect these phases to ramp up over a 12 to 18-month period bringing our total production capacity to 390,000 barrels per day on a gross basis. On the cost side of things, you’ll see from our results this morning that our teams have made a tremendous amount of progress on reducing our cost structures. For the first quarter, our oil sands operating cost averaged $9.52 per barrel which is nearly a 13% reduction from where we stood a year ago. These improvements include cost savings realized from the workforce reductions, supply, rate negotiations, prioritizing our maintenance and continued optimization efforts in our business. Despite the encouraging progress we have made with our cost cutting efforts, we are not done. Our focus will remain on executing our work and operating our facilities safely and reliably while continuing to find ways to realize efficiencies and cost savings. I’ll now hand the call over to Bob for some thoughts on refining and fundamentals.

Thanks Drew. For the first quarter of 2016, Cenovus’s refining and marketing operations had an operating cash flow loss of $23 million compared with an operating cash flow of $95 million in the same period a year ago. Cenovus’s refining cash flow is calculated on a FIFO accounting basis. Using the LIFO accounting method employed by our U.S. peers, Cenovus’s operating cash flow would have been $37 million higher in the first quarter. Operational performance at both refineries was very good with minimal impacts other than those resulting from industry economic conditions. Overall, refining margins were negatively impacted by lower average crack spreads which were nearly $7 per barrel lower than Q1 of 2015 in our operating region, primarily resulting from high storage levels for refined products. Refining profitability tends to be weak in the first quarter and is not reflective of full-year margins. In the first quarter of 2016, the Chicago 3-2-1 crack spread averaged about $9.50 per barrel as a result of higher global refined product inventory and the narrowing of the Brent to WTI differential. More recently, Chicago 3-2-1 crack has improved to an average U.S. $15.60 per barrel, following a typical profile on higher seasonal demand. We expect the product cracks to remain healthy through Q2 due to high seasonal demand and refinery turnarounds. Further, WTI’s currently trading nearly 30% higher than where it averaged in the first three months of the year. If sustained, these seasonally stronger refining crack spreads combined with the upward movement in prices should lead to stronger returns across our downstream business. Additionally, the Wood River debottleneck project remains on track for startup in Q3 of this year. This light-ins processing project will add 18,000 barrels per day of gross crude capacity with added flexibility to process more light or dilbit heavy type crudes. With respect to realized pricing at Christina Lake and Foster Creek, our first quarter results were negatively impacted by a higher relative cost of condensate compared to the benchmark. Most of this impact can be attributed to timing of condensate purchases and inventory draw down. In a falling price environment, like we saw in Q1, condensate that was purchased in the fourth quarter when prices were considerably higher, was blended into crude and sold in Q1 at lower prices. This negatively impacted our realized bitumen pricing and was similar to what we saw in the first quarter of last year. These effects are amplified by the higher blend ratios we typically see in winter months. Additionally, when compared to years prior, we are not seeing significant uplift in blend sales pricing by marketing barrels to the West Coast and the U.S. Gulf Coast. That being said I would like to stress that some of these bigger factors on condensate are transitory in nature. We expect overall bitumen realizations to improve in the second quarter as we benefit from blending less expensive condensate into our product and selling into a rising price environment. I will now pass the call back to Brian for some closing comments.

Thanks Bob. As you’ve heard, first quarter was strong from an operational and cost perspective but it was incredibly challenging from a pricing and financial results standpoint. I want to reiterate that we are committed to maintaining our financial resilience. We will continue to demonstrate discipline on capital spending and look for further improvements in our operating and G&A cost structure, all while maintaining a focus on safety and executing on our business plan which includes adding another 100,000 barrel per day of gross production capacity including the Foster Creek and Christina Lake extensions as well as the Christina Lake optimization. I believe these changes will make us a cost and efficiency leader, so we can drive sustainable value for our shareholders. Before I open the call to questions, I want to take this opportunity to introduce the newest member of the Cenovus leadership team, Kieron McFadyen, Executive Vice President and President, Upstream Oil and Gas. Kieron will be responsible for the upstream oil and gas operations and will oversee our partnership with ConocoPhillips and our relationships with third-party contractors and service providers. In his 30 years in the industry, Kieron has acquired an impressive breadth of experience and has a noteworthy track record in value creation and leading change, safety and environmental programs, and stakeholder management, all of which I’m confident make him an excellent addition to our leadership team. Kieron?

Thanks a lot, Brian. Firstly, I’m delighted to be here, absolutely delighted. I spent the last two weeks getting to know the Company and I can already see that I’m very impressed by the quality of the asset base and people, really top class. I’m also very impressed by the Company’s focus on safety leadership and cost leadership. Over the coming weeks, my focus will be on implementing the changes currently underway in the Company, so changes to further drive cost efficiencies, changes to further drive organizational integration to ensure that we steer the course on the major steps I have already been taking during this period of great extreme price volatility. So, in short that encouraged. I’ve seen a lot of good things in my short term here and I look forward to being a key player in Cenovus going forward. I’ll leave it there from here. Over to you, Brian.

Thanks, Kieron. With that the Cenovus team is now ready to respond to your questions.

[Operator Instructions] We will now begin the question-and-answer session and go to the first caller. Your first question comes from Neil Mehta from Goldman Sachs. Your line is open.

Brian, just wanted to start off here with the housekeeping question. In the press release, you indicated that the CapEx this year is going to be $1.2 billion. I think in the last February release, it was $1.2 billion to $1.3 billion. Are you guys guiding to the bottom end of the range? And if so, what’s the delta?

Yes. We are now tracking to the lower end of that guidance range. As Drew mentioned, we have not yet exhausted we believe the possibilities in terms of continuing improvement, not just in capital but in our operating and G&A as well. So, we’re going to continue to focus on improving that cost structure, as we continue to go forward.

I think can you just talk about the pricing environment you’re seeing in April? Thanks for the comments on the first quarter, clearly condensate and bitumen pricing were a headwind as we’ve seen WTI lift here in April. Are you seeing that flow through in terms of the bitumen pricing in the realizations?

I’ll ask Bob Pease to respond to that.

The answer is yes. Obviously it’s early in the quarter to draw conclusion but generally speaking in an upward market we see benefits, both on the fact that we are pulling condensate inventory from a previous period that tends to help us in periods like these, plus the overall realization just on WCS is better and then for our sales to destination locations which tend to be later, we tend to benefit from that as well. So, yes, we would expect second quarter to be a stronger quarter.

And then last question from me is that, at what oil price do you guy consider resuming dividend growth once again? Obviously you had to make a tough decision earlier this year but at what point are you looking for from both either from a pricing standpoint, spot basis or the forward curve to start thinking about growing the dividend once again?

One of the things we’ve ensured, despite our focus in what we’ve been able to achieve in terms of cost reductions, very difficult but very necessary decisions on reducing workforce, what we have ensured is that we have retained that core nucleus of talent that we can quickly and efficiently reactivate projects whether that’s in the oil sands or in our tight oil in Southeast Alberta. So, we’re positioning ourselves to be in a position to react quickly there. I’m actually not looking for a price signal. It’s a kind of market where given the balance sheet strength that we have, given the sustainability of the cost structures, and that’s one of the big focuses for me is ensuring that the cost achievements that we have delivered so far are in fact, the majority of them sustainable that we can choose to reactive because we’ve got -- we have the financial capacity to invest counter-cyclically into the organic portfolio when we think the time is right. The other piece to the equation here that I’m watching carefully is for fiscal and regulatory clarity out of Ottawa, I expect to see that in the next few months, I would say that so far all indicators I’ve seen are positive there. We now have the clarity and the certainty that we needed from the Alberta government around royalties and fiscal regime here. So, we’re positioned to respond quickly when we look at all of those indicators together.

Next question comes from Benny Wong from Morgan Stanley. Your line is open.

Just notice you guys had laid at Southern Alberta light-oil assets in your presentation. Just wondering if you could provide some color around the assets and maybe some field economics there. And I guess what kind of crude price would you need to see before spending makes sense in that area?

It is one of the areas that -- our decision to reduce activity on our Southeast Alberta properties wasn’t in any way, shape around the economics, the returns, present value because they are high return and relatively short payback. It’s all been around cash conservation in the short run here. So, we continue to see very positive economics. I would observe that during the first quarter our conventional business, both conventional oil and natural gas had positive operating cash flow before hedges. So, it is a strong and it is a robust business. As to specific economics for individual plays, we’ll get into that more when we get into our Investor Day part of our budget process 2017.

Your next question comes from Greg Pardy from RBC Capital Markets. Your line is open.

Good morning. Brian, I wanted to come back to what you’d said just about the projects that you still have in the half that you can resume. You mentioned before that cash is king. One of my former colleagues mentioned to me today that some of these longer term bonds are trading at like $0.75 and $1. Given the cash position you have, does it make any sense to start to think to tender for some of that? And then just as a follow-up to that is there any update on the Fitch process?

I’ll ask Ivor Ruste to respond to that, Greg. Thank you for the question.

Thanks very much, Greg. We continue to look at debt repurchase opportunities, given where are those bonds trading. The spreads have tightened. We don’t have any debt maturities until October 2019. So, it’s not in our specific plan, as we --it’s really dealing with the capital allocation question, where should we use some of that cash that we’ve accumulated, and we’ll be looking at that through next several months as well. And with respect to Fitch, to date in 2016, our focus has been on managing our existing rating agencies relationships with S&P, DBRS and Moody’s. And as noted earlier, S&P just reaffirmed our investment grade rating here in April, and we’ve elected not to pursue an additional rating at this point in time.

Just on the operating cost side, I think the numbers look really strong there. Certainly looks as though you are tracking below guidance this year. So, is there potentially some good news to come a little later in the year from that standpoint?

I’ll ask Drew to respond to that Greg. It is still early in the year but we continue to see a very clear focus inside the Company on our unit operating cost. Drew?

As noted in the Q1 results, the teams have done some amazing work and continue to do great work on our cost structures. Just to note that the current production levels -- I mean obviously we’ll continue to probably show some good headway at unit cost basis as production continues to ramp up particularly at Foster Creek but today as Brian mentioned, it’s still early in the year, but we’re very pleased with the progress the teams have made. And so far considering all the kind of business environment we continue to believe that trend will continue for us. So, we’re going to stay focused on it and we’ll just continue to update as the year progresses.

And just the last one from me, Brian that hedging in 2017 -- or Ivor, hedging in 2017, And you said before, you’re repositioning Cenovus for a volatile $50 world. So, is that kind of what’s going into the hedging plans; could you just outline a little bit about how you’re going to think about hedging going forward?

Sure, Greg. So, we’ve had a very consistent hedging strategy since the Company was created in 2009. And the objective has always been to have certainly around 25% to 30% of forecast cash flows. Given a more volatile world, what we’re looking at there is opportunities where we can gain certainty on 25% to 30% that hasn’t changed. In terms of our cash flow, we thought it’s appropriate to certain layering in a very programmatic like fashion some hedging for 2017.

Your next question comes from Phil Gresh from JP Morgan. Your line is open.

Hi there. First question, just a follow-up around the cash is king commentary. I was just wondering with the options that you’re thinking about the cash, if you can maybe just remind us how you think about minimum cash that you’d like to have on the balance sheet.

Thank you for the question, Phil. We don’t actually have a minimum cash target. We continue, as Ivor mentioned to strive to manage the company to investment grade status. So that’s very important to us. I think in this environment where we’re seeing a lot more volatility on pricing that we will tend to run a leaner balance sheet than we otherwise would. And the forecast that we’ve done some modeling at lower prices as we mentioned $40 Brent. If we saw $40 Brent flat through the next couple of years to the end of 2017, we would still have over a couple of billion dollars in cash on the balance sheet and we would have funded all of our capital, our existing dividend, and we’d still have a net debt to cap that would be in mid 20% range.

And in terms of go forward sustaining capital requirements, are you still thinking kind of 1.1 to 1.2 range or with the progress you’ve been making on the cost reductions, is that coming down as well?

We’re going to be reviewing that as part of our planning process over the next quarter but directionally that’s correct. I would expect that unless we choose to reactivate new phases or some additional rigs in Southeast Alberta that the trend line will be downward on our overall capital in 2017.

Last question is just on the downstream side. In the MD&A, you called out weaker currency as a factor that has weighed on the operating costs, north of $200 million. I was just curious how we should think about the run rate on operating cost moving forward. I think in the past you’ve kind of talked about an $8 to $9 bell range but we’ve been above that for a couple of quarters now, so any color there would be helpful.

I’ll ask Bob Pease to respond to that.

Yes. So, the view is still we’re going to be in that $8 to $9 range, yes, the currency does impact that but from what we’re seeing currently in this environment going forward, we still expect to stay within that range. There’s a lot of work that continues to go on, on the ground to lower overall cost structure. So, I think that $8 to $9 target is still accurate.

Your next question comes from Amir Arif from Cormark Securities. Your line is open.

Good morning, guys, just couple of quick questions. First, just on the new redesigned well pad construction that you’re talking about, starting in the third quarter of this year, I think you mentioned that it could reduce your capital cost by about 30% to 35% for the well pads. Can you help me translate that to what it would mean in terms of capital efficiency improvement from the current run rate of about 30,000 per barrel.

I’ll ask Drew to respond to that please.

Sure, thanks Amir. So, we look at the zero based module design that we had started working on here just about two years ago now, where we’re currently sitting in on the new slides that we just updated on the website today shows a good visual of that difference. We anticipated to see 30% to 35% reduction just from the design change, happy to report that we’re actually seeing a better cost estimates come in on our actual,, now that we’re actually starting to fabricate them. We won’t be going to the field until the end of Q3 into Q4 this year to actually start to install them and they won’t be the first ones to have come on to operation until early 2017. But so far the work that the teams have done and now that we’re getting some actuals that they’re coming in as expected or even somewhat better, obviously this will help the overall F&D cost come down and getting us into single digits. This is just one component of many things that we’re working on. So, we expect it to continue to add better value in the future.

But I’m guessing some of the other costs will still be fixed, so the 30,000 per firm barrel number probably doesn’t drop to 20,000; is that fair? This is just for the well pair, right?

Yes. The capital efficiency we previously used was really for growth and additional capacity. So what we’re referencing here is really about the longer turn sustaining capital and the overall F&D, so those two aren’t necessarily related.

And then in terms of the downstream business, the FIFO has been a headwind for you and just curious how long of a inventory lag do you see on the crude oil side in terms of will FIFO become a positive tailwind by 2Q?

Amir, this is Bob. So, again, at the current prices, at the current pricing levels are sustaining, yes the expectation is we would actually see a FIFO benefit in Q2, much as we did in Q2 of last year. So, I mean it is heavily tied to the direction of crude, the lag time between acquisition and processing is not as long as it is for example on the diluents [ph] supply side to the upstream but there is a lag. But Q2 at this point would look to be positive from a FIFO impact basis.

Your next question comes from Paul Cheng from Barclays. Your line is open.

Hey guy, good morning, couple of questions. Brian do you have a -- I know it’s early days, do you have a range that you currently expect for 2017 CapEx?

We haven’t got into our 2017 budget process. As I mentioned, if we don’t reactivate additional oil sands projects or reactive additional rigs in our Southeast Alberta light oil, then the trend line would be lower in capital in 2017 than where we see it today. We certainly have the capacity as I mentioned and we’ve ensured that we’ve retained that core nucleus of talent inside the Company that we can reactivate, if we choose to. And I would expect order of magnitude in terms of direction that you would -- we could conceivably very easily add 200 million, 300 million, 400 million in next year, if we think the timing is right. You wouldn’t see us double our capital in 2017.

And you guys have done a great job in the cash cost and is already at a pretty low level in the first quarter in that unique cost on a per barrel basis. And it sounds now you actually think that you can push it down further. Over the next 12 to 18 months, do you have any number you can say in terms of you think it could be down another 10%, 15% or 5% comp number?

Paul, we’re not in a position to give a specific target. I guess the observation I make is that increasing volumes will have an impact -- positive impact on the overall per unit operating cost. We’ve got a lot of fixed costs both in the oil sands and in our conventional business. So, as we continue to see volumes added in the oil sands because expansion of Foster Creek, Christian Lake, the trend line there because we simply got a larger denominator will be -- should be favorable. On the conventional side, we’ll continue to look at all aspects of that business, again fair number fixed costs, so higher volumes would translate the lower unit costs.

On the condensate, you just mentioned that because of the timing gap, the cost is -- the actual purchase cost is higher than the spot. Can you tell us -- I mean how many days of the inventory typically you keep for the supply to the upstream for condensate.

Paul, I don’t the exact number. It’s actually in the process of decreasing; we’ve been reducing some of our inventories in the condensate supply chain at principally non-commercial locations, but still a large percentage is acquired in the previous months or in some cases the previous quarter. It’s a rolling cost structure that works through the accounting system. But on average, it has probably been in the 45 to 60-day kind of range but I honestly don’t have a number on how many days it currently is.

I’m just curious because I noticed that seems to have the impact on that on the condensate price, seems to be bigger for you guys than some of your peers. Is that because that you guys keep a -- due to maybe conservative reason or whatever is the reason that you keep a longer supply day inventory or that you think that you’re actually about [indiscernible] to the rest of the industry?

I don’t know the average length of supply chain for our competitors. I mean there are number of elements in our cost structure. We do purchase condensate from multiple locations, so not just in the Edmonton market that we do have long haul commitments, kind of diversified strategy on supply, so we do have barrels coming from the U.S. and over time that price can be higher or lower than Edmonton price, recently it’s been the higher on a delivered basis. There are costs going from the hub out to the field and back, and we did expand that pipeline capacity last year. So, there’re several elements, but again the principal one is that length of supply chain and whether the market is moving upwards or downwards, and that does come back in different periods.

Bob, can you tell us that what percentage of your condensate purchase is from the long haul supply?

I don’t have those numbers, again, we keep a fairly balanced supply sourcing and we have multiple points within Alberta and from the U.S. but I don’t have a percentage breakdown.

Two final questions, one, with the write down, Brian, should we assume that 800 million you decide to increase spending, they probably would be one of the last one to receive any capital? And second one, on Conoco, your partner, I suppose that right now you guys are in sync in terms of the capital investment plan which is essentially not for the new face. But when -- do you have the same expectation or the criteria that you use to determine when you’re going to go for the next phase of the expansion in the Foster Creek and Christina Lake between you and your partner?

So, with regard to Pelican Lake, we’re currently -- it’s currently generating free cash flow. We don’t have plans to reactivate much activity there, we’re continuing to focus on cost. Costs that would absorb are down meaningfully there in the first quarter on a unit basis. It is an area where we can choose to allocate capital. But the first call on the conventional side will be into Southeast Alberta on the late tight oil that we have there on the conventional side. With regard to the relationship with ConocoPhillips, it continues to be a very good partnership from my perspective. We have been very strategically aligned since the partnership was created in 2007. They are looking to us as the operator to do all the things that we are doing in terms of trying to be more or less cash neutral in terms of cash generation versus cash in. And all the things that we’re doing in terms of the cost improvements there obviously have positive impacts on rates of return and present value as we go forward. They have approved the budget for 2016. And I continue to believe that we will continue to be strategically aligned as we go forward. And their expectations of us are going to be that we are a great operator for them and a great partner for them.

Your next question comes from Joe Gemino from Morningstar. Your line is open.

Hi. Thank you. As you look to bring on new production in Q3 and into 2017, how do you think about transportation? Will you have the pipeline capacity for it or do you see yourselves transporting it by rail?

I’ll leave that for Bob please.

Thanks for that question, Joe. First of all on getting it from the field to hub, we’re well positioned on capacity there, and it will actually contribute to bringing down our overall cost per barrel on that component of the transportation. On moving it into market, the majority of our crude is still marketed in Alberta. We do have capacity to the Gulf Coast and we have capacity down Trans Mountain to Vancouver but that’s a relatively small percentage. Rail, we will use it incrementally as economics dictate. So, if it’s not attractive, we will sell volume in Alberta; if movements via rail increasing attractiveness, we do increase those volumes. At the current price levels and differentials we are seeing a little bit of an uptick in attractiveness of rail but we expect that to remain small unless the differentials widen further.

Your next question comes from Nima Billou from Veritas. Your line is open.

Yes, just on that subject of transportation cost, clearly we’re looking at Foster Creek, these economies of scale in the $8 a barrel range now. But as your production normalizes, what’s the long run steady state cost for this? It seems that these costs are trending higher over time because of constrains. So, this is in the 5 barrel mark. Just wanted to get a sense of the what the long run cost us. What have you factoring into your assumption?

So, first of all on Foster Creek, it’s always difficult to look at just one field in any given quarter because it depends heavily on where those barrels do get sold. In the case of Foster Creek, in the quarter, more of our sales are on a destination basis. So, more of our sales into the gulf coast, more of the sales are by rail were of the foster Creek volumes than of the Christina Lake volume. So a higher percentage of Foster Creek’s transportation costs were those revenue generating side of the equation. But yes directionally, the cost of moving the barrels from Forster Creek down into the hub locations and ultimately Narrows Lake which will move through the same line will decrease due to the fact that we have a relatively fixed cost on a number of those transportation components, so as the volumes increase that number goes down correspondingly.

I appreciate the clarity. You guys did a great job by the way explaining the pricing mechanism and condensate because I was looking at the bitumen pricing and it seemed abnormally low. So thanks for walking through that. A longer terms question on the supply and demand dynamics. Are you guys obviously constructive with respect to U.S. or your own refinery demand for bitumen and for heavy oil going forward given the investments made in refining complex to be able to process more of these crudes? Do you see better pricing and narrower discounts structurally longer term?

As a Company, we believe in an integrated strategy and like to maintain a presence with our heavy crude processing and refining. Directionally, the project at Wood River C5, C60 bottlenecking project does add about 18,000 barrels a day of capability to run more dilbit or other crudes as economics dictate. And of those joint venture sites are operated to the maximum value creation for the sites. So whether they actually run more or less will be determined on their economics. Directionally yes, we’d like to see as much upgrading capacity and conditions that favor keeping the spreads tight between the WCS and WTI as a company that favors us. So we’re hopeful for additional pipeline takeaway capacity; we’ll utilize rail as need be. But as far as overall market conditions, at this point, we still think we’re going to see a continuing widespread $14 to $15 is where it is now or could go even wider if we don’t see additional pipeline capacity come on stream because production does continue to grow. As a Company we’re working actively to keep a balanced exposure but to work hard to keep those differentials tight so that we realize full value for our crude production.

Your next question comes from Dave Winans from Prudential. Your line is open.

My question was already answered regarding the Fitch rating. Thank you very much.

Ladies and gentlemen, at this time, we will take questions from the media. [Operator Instructions] Your next question comes from Shawn Fulser [ph] from Mergermarket. Your line is open.

Hi, I was just wondering what some of the priorities are for the cash that you have on your books. You’ve currently got $4 billion. Give any thought to maybe investing in infrastructure, acquiring pipelines or maybe real capacity.

As we mentioned our focus is on preserving the strength of our balance sheet in this more volatile world. We did purchase a unit train loading facility at Bruderheim last year, we currently don’t have any plans to purchase additional facilities. We do have the opportunity to invest to expand that, if we think that’s the right thing to do, going forward into the future. Beyond that, our focus is on our organic portfolio, continuing to drive the organic opportunities and improve our cost structures as we go forward, so that is our prime focus. As I mentioned earlier, given the volatile environment we’re in, we’re going to run a leaner balance sheet than we otherwise would and probably run a little higher cash balance than we otherwise would in a more normalized price environment.

Okay, quick follow-up, is there any thought to maybe expanding joint ventures or selling down some of the interests in your oil sands properties to third parties, maybe Chinese or U.S. private equity?

No.

Your next question comes from Nia Williams from Reuters, your line is open.

Hi, there. You talked about needing more fiscal and regulatory clarity from market before reactivating projects. Can you talk a bit more about what you mean by that?

Yes. So, there has been discussions around the pipeline review process at the National Energy Board, so any additional clarity on that. There’s currently four working groups that are working on climate policy, they’re due to report later this year. And then in terms of the fiscal clarity, it would be around any potential changes to income tax rules, all sorts of things. I expect that we will get clarity on all of these items over the next several months.

We have no further questions at this time. I will turn the call over to Mr. Brian Ferguson.

Thank you for joining us today. Our call is now complete.

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