Good day, ladies and gentlemen, and thank you for standing by. Welcome to Cenovus Energy’s First Quarter 2015 Financial and Operating Results. As a reminder, this 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 may not be recorded or rebroadcasted without the expressed consent of Cenovus Energy. I would now like to turn the conference call over to Ms. Susan Grey, Director, Investor Relations. Please go ahead, Ms. Grey.

Thank you operator and welcome everyone to our first quarter 2015 results conference call. I would like to refer 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 referred to today and outline the risk factors and assumptions relative to this discussion. Additional information is available in our annual information form. 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 the overview and then turn the call over to Ivor Ruste, Executive Vice President and Chief Financial Officer who will discuss our financial performance. Following are John Brannan, Executive Vice President and Chief Operating Officer who provide an overview of our operating performance and Bob Pease, Executive Vice President, Markets, Products & Transportation will provide an update and our downstream operations and transportation plans. Brian will then provide closing comments before we begin the Q&A portion of the call. Please go ahead Brian.

Thanks Susan. Good morning, my highest propriety for 2015 is preserving our financial resilience without compromising our future. In the first quarter we completed a number of strategic initiatives to help strengthen Cenovus’s financial flexibility and support this role. In late January we significantly reduced our planned capital expenditures down $700 million from our initial budget in December and nearly $1.2 billion from what we spent last year. This level of capital spending allows us to continue to invest in our high return well advanced oil sands expansions and supports the addition of 50,000 barrels per day of net productive capacity by the end of 2016. We announced and have essentially completed workforce reductions of approximately 15%. These reductions primarily impacted our contractor workforce and are aligned with our planned 2015 activity levels. We have undertaken aggressive cost cutting measures across all parts of our business and the initial impact is evident from our Q1 results this morning. We are pleased with the cost reductions we have achieved to-date and we also recognize there is more to be done and we will continue attacking cost to help preserve our financial resilience. We instituted a temporary 3% on our dividend reinvestment plant which will - which is expected to conserve additional cash. Participation is in strong at 37% and we will continue to evaluate the use of our discounted DRIP program in the context of the commodity price environment. In February, after careful deliberation with our Board of Directors we issued 6.7 million common shares for net proceeds of approximately $1.4 billion. This was a difficult decision to make. However, we felt this action provided the greatest amount of financial certainty over our three year planning horizon through 2017. Ivor Ruste will provide additional commentary regarding a bought-deal later in the call. Let me now turn to our first quarter operating and financial results. The company’s operating results were strong. Production continued to trend above the midpoint of guidance. Our upstream business is performing well and our downstream upstream operations are benefiting from improved market conditions. I expect our financial performance to continue to improve over the balance of this year. I’m now going to turn the call over to Ivor Ruste to discuss some of our important financial balance.

Thanks Brian and good morning everyone. During the first quarter of 2015, commodity prices were more than 50% lower than a year ago. Despite this we continue to generate positive operating cash flows from all our assets. Of note, our weaker Canadian dollar contributed to the $668 million net loss for the quarter as we record our unrealized foreign exchange loss of $514 million related to our U.S. dollar denominated debt. In this low and uncertain price environment, our focus is on preserving our financial resilience without comprising our future. As Brian mentioned, we made the important, but difficult decision to issue equity. We discuss the number of auctions with our board including a further reduction in capital spending, accelerating non-core asset divestitures, reducing our dividend, issuing preferred shares or increasing our leverage. The equity issue helps to strengthen our balance sheet, provides additional certainty for our current capital program and supports our strong credit ratings. We expect the net proceeds together with our operating cash flow and savings from our DRIP program to fund our business plan over our three year planning period even with low commodity prices. Commodity price hedging is an important component of our financial strategy, reducing the volatility of our cash flows and supporting our capital program. We continue to see opportunities pilot and additional volumes at prices exceeding our budget assumptions. We added to our crude oil hedging position during the quarter and now have approximately 25% of our forecast crude oil volumes for the remainder of 2015 secured at C$94 per barrel. We’ve also started hedging a portion of our 2016 crude oil volumes. Cenovus lived in a strong financial position and we’re committed to maintaining our investment grade credit ratings. We excited the quarter with just over $1.8 billion in cash and an undrawn $3 billion credit facility. With the recent equity issue, our metrics on a net debt basis are 27% net debt to capitalization and net debt to adjusted EBITDA of 1.3 times. I’ll now hand the call over to John Brannan for an update on our operational performance.

Thank you Ivor, and good morning. We are intently focused on cutting cost and sustaining them for the future. It is important to note that our cost cutting efforts began in early 2014, and I’m encouraged by the project whereas we’ve made so far. The one thing that I’m most excited about is the commitment from all of our employees to cut cost and determine the most efficient way to operate our assets. Cenovus continued a strong operating performance from 2014 through the first quarter of 2015. Oil sands production was up 2% over the fourth quarter of 2014, while operating cost declined by 3%. Costs were down as a result of higher production volumes, lower energy cost and fewer repairs and maintenance. Oil production at Christina Lake was more than 76,000 barrels per day in net in the first quarter with an industry leading steamed oil ratio of 1.7. The reservoir continues to exceed our expectations and we are encouraged by the performance. We expect full year guidance to be above the midpoint of our annual guidance of 67,000 to 74,000 barrels per day. Total production at Foster Creek was nearly 68,000 barrels per day net in the first quarter was estimated oil ratio of 2.4. Maintenance conducted in February led to temporary reduce production levels and steam to oil ratio. Volumes return to normal levels in March. Our continued focus on well optimization has led the first production in the past two quarters. We’ve started to see some decline in these volumes, but expect them to be offset by the ramp-up of phase F. Phase F continues to ramp-up according to schedule with full production expected in early 2016. We expect full year production to be above the midpoint of our annual guidance of 62,000 to 68,000 barrels per day. Work continues at our expansion and optimization phases of Christina Lake and Foster Creek. In total these lakes are expected to add 50,000 barrels per day net of incremental productive capacity by the end of 2016. Due to your phases of growth such as Foster Creek phase H and Christina Lake phase G have been postponed until commodity prices improve. Our Conventional asset performed well in the first quarter with overall liquids production remaining essentially flat compared to the fourth quarter of 2014. As previous mentioned, these assets provide us with flexibility as developments can be more easily ramped up or down to match market conditions and we can significantly reduced our 2015 spending plans as a result. Overall, I am extremely pleased with the performance of our assets and encouraged by sustainable cost savings our teams are generating. I will now pass the call to, Bob to discuss our downstream operations and marketing initiatives.

Thanks, John. Our refining in marketing segment, we bought from a challenging fourth quarter operating at approximately 95% as capacity and resulting in $95 million of operating cash flow. If we had used last-in and first-out inventory Accounting method our operating cash flow would have been $55 million higher for the quarter. Our assets are also well positioned geographically to benefit from favorable market conditions in the second quarter. With respect to realized pricing at Christina Lake and Foster Creek, our first quarter results were also negatively impacted by a higher relative cost [Indiscernible] compared to the benchmark. Most of this impact was a result of purchase timing and inventory drive down. [Indiscernible] that was purchased when prices were considerably higher in the fourth quarter was blended into our product and sold in the first quarter of 2015. As previously mentioned, transportation cost in our Oilsands business were expected to increase to approximately $8 per barrel in 2015, this increase is largely related to strategic pipeline commitments we made to support future growth of our upstream operations and to maximize the value of every barrel we produce by moving our sales points closer to our customers. As new phases of Oilsands growth are completed, we expect the per unit cost of our transportation to Alberta market house to decrease. On a combined basis, our Oilsands transportation cost averaged $6.50 per barrel in the quarter lower than previously indicated with less oil movements than originally planned and the pattern we expect will continue in the near term. On a relative basis, Foster Creek’s per barrel transportation cost were substantially higher than Christina Lakes in the first quarter doing large part to the degree of utilization of our downstream pipeline commitments to deliver our Foster Creek barrels. We continue to see value from our strategy of moving the point of sale closer to our customers, especially from our pipeline movements to the West Coast and the U.S. Golf Coast, however the overall benefit [Indiscernible] over from continued narrow spreads between Canadian heavy crude and other North American grades has created environment in which have reduced our oil movements. Despite current real economics, this component of our transportation portfolio had allowed us to mitigate some of the impacts of pushback volumes from pipeline apportionment that we experienced in the first quarter. I will now pass the call back to Brian for his closing remarks.

Thanks, Rob. My top priority this year as I said at the start of the call is to preserve Cenovus’s financial resilience without compromising our future. As I outlined earlier, we have taken a number of actions in support of this and we will continue to do so throughout the year. As John discussed and as you have seen in our quarterly results, we have made note reductions on our operating cost and expect to realize more savings throughout the year. We now expect to be near the low end of our guidance range on operating costs across all parts of our business. We have also made changes to our corporate spend and as that G&A costs to be near the low end of our annual guidance as well. Year-to-date our share price is down 3%. Our operations continued to perform well. Our focus is on total shareholder return and allocating capital or dividend, because a fundamental part of that strategy. [Indiscernible] saw on our news release this morning that the Board has approved our second quarter dividend at the same level as previously. I would like to take a moment to address this as it is obviously an area of keen interest for shareholders. I have often talked about a dividend payout ratio of approximately 20% to 25% of after tax cash flow as being an appropriate level for our company over the long term and I continue to believe that we are operate in a commodity business and are obviously at a low point in the cycle. If you got long term deal with the dividend and target a sustainable payout level. I do not want a variable dividend, ultimately the dividend is at the discussion of the Board and we will continue to reveal it on a regular basis with a view toward its sustainability as current strip pricing and market crack spreads. We have stepped up our after tax cash flow would essential cover our 2015 plan capital expenditures and our current level of cash dividend for the year. Another area of shareholder interest relates to our fee lands. We have done a significant amount of work evaluating the potential of our fee land properties, we have a data room open and interested parties are currently conducting their due diligence. We are ready to pursue a sale or an initial public offering when the timing presents itself in the valuation meets our expectation. 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 Greg Pardy from RBC Capital Markets. Your line is open.

Yeah, thanks, thanks good morning. Brian maybe just, first question is just on the decision to hedge oil in 2015, is it just as simple as risk navigation towards the relapse in the oil prices is the [Indiscernible]

Yeah, I’ll maybe start and then ask Ivor to jump in here as well Greg, but these are our assessment to fundamentals, we certainly believe earlier this year and continue to believe that there is a risk of congestion around filling storage and see the risk of lower prices here in the second quarter, which were sort of some key background to our short-term plans here, but over to you Ivor.

Thank, Brian, and certainly not much to add to Greg, I think our hedge strategy is unchanged, we do see opportunity to protect some more cash flow in this period and for the reasons as Brian mentioned in terms of the potential downdraft in Q2 we’ve had some hedges over that period that prices above our budget approaches.

Okay, fantastic. Second question is probably more for John and then the operating cost were very good obviously in the first quarter, some of that I know relates to obviously lower gas prices and volumes and so forth, but you’ve also mentioned just a little bit less maintenance and like a less replacements of SPs and things, how much of the cost reductions do you think will be more permitted nature versus that you are perhaps deferring to a little later in the year, because you are not making any change in terms of your OpEx guidance for the year?

Thank you, Greg. I mentioned in the call, it’s about a $200 million, savings that we’ve identified about $40 or so million of that has been from CapEx, about $120 from OpEx and then maybe another $30 or $40 from G&A, and clearly some of those cost reductions are associated with supplier reductions and those type of things, so if price has go up and competition is out there then potentially some of those prices may go back up and we will lose some of those savings, but we think overall but we of that $200 million, we think that cost structure changes would be about $100 million or so perhaps a little bit less than that.

Okay, and then just on, just again on that maintenance part of things, like you are going, there is more turnaround and so forth in the second quarter, there is more going on during the balance of the year, but there is really no deferral, like a meaningful deferral in terms of the maintenance that is just a part of your ordinary course of business?

Thanks correct and where we in the past I think a lot of the questions come up around are we doing things sub surface that will hurt us in the long run. And the answer to that is no, we are maintaining the surveillance in our wells at 95% or greater. We are looking to optimize some of that maintenance. So an example would be an ESP changes, typically we were trying to see how fast we could turn those around to bit of a pump change. And we got net down to less than 24 hours, we’re now saying is there a benefit to having those work over maintenance crews working 24 hours a day to be able to so to speak chase those volumes and production. And we said no that makes more sense to run those rigs daylight hours only don’t be working overtime and some of those ESP changes now instead of being in less than 24 hours and it might be two or three days before we get to allow and had them changed over, but there has been a substantial cost in our overall work over cost, because we’re not doing those, this answers we can possibly doing.

Okay, that’s great. Last question Brian. This comes back to your commentary around the dividend. I know you’d mentioned many times the 20% to 25% of after tax cash flow. Can you give us any idea of what kind of oil price that would mass towards, I suppose I can back into it by doing the mass, but I’m curious is to how you’re thinking about that.

So 20% to 25% payout of our after tax cash flow dedicated and committed to our dividends means that by definition we are reinvesting 75% to 80% of our after tax cash flow with our business. I think that’s a good balance. I really believe that our dividends really is a capital allocation decision and I do it is as a form of capital discipline for us. With regard to pricing, obviously one of the things and John just responded with regard to how we’re really focusing on driving down cost structure in a sustainable way and we do expect that we are going to be at the lower end of the guidance for both OPEX and G&A this year. So it’s a little bit dynamic in terms of the price that we would sell for, as well as the production growth. So as you’re aware we got 50,000 barrels a day net which is about a 25% growth in our oil production by the end of 2016. So I think if we’re going to add $70 to $75 WTI range that probably gets us back into the range where we’re back in that 20% to 25% payout as I mentioned and just to reiterate that the discounts on our dividend reinvestment program is a temporary cash conservation measure.

Okay, that’s great Brian. Thanks a lot. Thanks a lot.

Thank you Greg.

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

Hi, good morning. First question is just on the committed capital, you’ve talked in the past about what committed capital looks like for 2016, 2017, just wondering if you have any update on that and I was just hoping may be you could break out how much of that committed capital will be required to maintain flat production versus, what would be committed capital to finish off the current phases of Foster Creek and Christina Lake?

Yeah, thanks for the question Phil, Brian Ferguson, so once we completed these current expansion phases of Foster Creek, Christina Lake, we estimate there is about a $1 billion in capital to sustain that level of oil production. As you know our natural gas business is a financial asset not a production asset, so we are not in any way attempting to sustain our gas production, we’re focusing on how we optimize free cash flow that comes of that. We also require approximately $200 million annually in maintenance capital on our downstream business and there is another color about $100 million in G&A or corporate type capital, in addition, once we completed the phases. With regard to your question about what the capital is to complete the phase F at Christina Lake and G at Foster Creek, it’s about $800 million in aggregate, the bulk of that has spent here in 2015, little over $500 million and the balance in 2016.

Okay, very helpful and does that factor in any idea of you’ve talked about potential cost reductions beyond this over the next several years I think $400 million to $500 million I’ve seen that it’s a mix of CapEx and OpEx in there and so, is any of that factored into the sustaining capital number or any other deflation that you might be able to achieve?

No, we expect to improve on that, that’s one of the key objectives here, that’s at kind of current run rate.

Got it, okay. And then just on future growth projects beyond what you’re executing on, how do you think about restarting those types of projects in the future, I know obviously the prices are [Indiscernible], but is there a specific IRR you’re looking for or just how should we think about that?

Yeah, so we continue to believe that the future phases at Foster Creek, Christina Lake, Narrows Lake are all very high return projects and they all clear more normalized price environment, our economic thresholds very handily, and the decision to that to defer those projects is entirely around cash conservation, not rate to return on them - just remind you again, that we are adding 50,000 barrels a day in net capacities and all those between now and the end of 2016. Our capital plans continue to remain in net $1.8 billion to $2 billion range for this year, which is unchanged. I do not accept the change 2015 capital programs further at all this year, what I am looking for is really a clear sign on the direction of oil prices, I expect it will have a lot more information on that during the second half of this year and then what we will do in terms of the very orderly and thoughtful capital plan is to assess that as part of our 2016 Budget Program. I do expect that we will continue and we are very much focusing on how we take advantage of this downturn in terms of how we can look at redesigning, how we can look at sustained levels in terms of improvement on supply chain, those sorts of thing. So our focus is on how we improve even further to supply cost on these other projects.

[Indiscernible] just one last clarification, as you said the conservation issue, so you raised the equity, you’re talking about monetizing the fee lands and in the release you mentioned that the equity rates gets you through your capital plan I believe for next several years, I think it was the phrasing of it. So what that mean if you actually got cash from fee lands you might start of rethinking about the [Indiscernible].

Not in 2015, as I said, we are going to take the opportunity now in a lower price less inflationary environment. In fact a deflationary environment to reassess design, supply chain, all those things to make sure that we can capture and sustain cost improvements as we go forward. So the intention here in terms of the timing of disposition or IPO or other alternatives with regard to the fee lands is really driven around how did we crystallize value for our shareholders on an asset class that the market clearly describing a higher valuation and what is currently embedded inside Cenovus today. So this is a value creation strategy for Cenovus’ shareholders and that is what is going to drive the timing of that as when we think that market conditions are appropriate to proceed with the transaction that realizes fair value for our shareholders. So it is somewhat independent of decision in terms of the timing of what we are going to do around reactivation of additional phases.

Okay, thanks a lot. I appreciate it.

You’re welcome.

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

Hey, good morning, guys. Just a few quick questions, I just wanted to clarify this standing CapEx number. You just mentioned that $1 billion sustaining CapEx, is that after you get to the $195,000 net production, but that’s after the few phases?

Yes.

Okay and then just a quick question on the optimization that you got lined-up for Christina Lake in 4Q. Can you just walk us through what’s exactly is involved in that? Or just give us some color on that and it seems like that that production ramps up in a more faster fashion than your typical growth projects?

Yeah, get Harbir Chhina to respond to that one, Amir?

Yeah, so on that one, what we’re doing is, adding [Indiscernible] boilers, before we used to have four boiler packages we have started to put in five [Indiscernible] packages. So that’s a very small addition to the whole plant and we do not expect, we have wells that are already gone through the ramp up. So we expect the production to pick-up a lot faster with the extra steam on that plan.

Okay and just on the royalty business monetization, so can you - I am just trying to figure out the timing for the next. So if you could just let us know when you are expecting the bids to be deal on the package [Indiscernible] out there?

Hi, it is a competitive process so I don’t want to get into specifics with regard to timing. Our timing is going to be based on assessment of market conditions. I will confirm that there is substantive interest by substantive parties and as I say, we are on multi-track process, competitive process.

Okay and then just one final question on the [Indiscernible] program, so right now I think you are guiding towards, basically a free cash flow neutral with the drift in place. What take you back away from the [Indiscernible] to you the cash dividend with it, once you get the positive free cash flow is that once you get the wealthy business sold?

It will be driven by I guess greater clarity on the direction on oil price. It is what I would say in terms of the macro environment. And as I said, my prime objective right now is to maintain our financial resilience without comprising our future, they just kind of the [Inaudible] is entirely a temporary short term measure here and once we have got a clearer view on the direction on oil prices then we will make a decision on whether or not we continue with the discount for a short period of time.

Thank you.

Our next question is from Arthur Grayfer from CIBC. Your line is open.

Good morning. Thank you for taking my questions, a few of them for you. The first one is in regards to just say, if you have some non-core asset dispositions as you had last year, and noting that you have free cash flow neutral budget [Indiscernible] up. How do we think about any proceeds, our user proceeds from a non-core asset disposition?

So thanks for the question Arthur. At this point in time given the volatility and the market around us, we would choose to use to further bolster our balance sheet and continue to monitor the macro environment.

Okay. Can you talk a little bit more about the downstream or market access initiatives. You’re going to be adding 50,000 barrels a day net by the end of the next year and so your bitumen mines in heavy length on the increasing. Can you talk a little bit about the perspective and any desires that’s how would you address that.

I’ll ask Bob. Do you use to respond to that?

Yes Arthur. Thanks for that question. We’ve had a strategies accompany for our existence to try and maintain a balance between our bitumen production and our ability to achieve global product pricing and refinery capacity has been a core component of that. And yes you’re right we are seeing that we’re now getting a little out of balance of where we have been as our production increases. So we are watching those markets looking for opportunities whether it’s in refinery acquisition or partnership or other means, we stay tune to those markets, just it’s been an important part of our strategy, it’s one that’s provided good re-terms force. So we do stay up rest of the market.

And can you talk a little bit about that market specifically our valuations reasonable is it cash price have been a quite favorable so far this year. Can you talk little bit about that environment?

Yeah, we wouldn’t be able to talk about any specific opportunities out there. You are right in general margins have been little above their rock fourth quarter and we’re started this year have returned to more typical levels, but valuations are kind of one-on-one discussion and we’ll just - we’ll keep on track to track of that.

Great. And the last question for me despite the dividend when I think about the comment you made Brian about that our free cash flow neutral when you look at the dividend on the cash basis. Do we think about that 20% to 25% in this period of trough oil pricing as reflective of the drip adjusted basis cash divided or do you think about it as the entire $900 million give or take for that 20% to 25%.

So that the 20% to 25% targets payout ratio relative to after tax cash flow is based on a more normalized price environment, it’s not based on drop pricing where we are today.

And so the DRIP has really little influence on that perspective?

Correct.

Thank you for your time.

Thank you.

Your next question comes from Chris Feltin from Macquarie. Your line is open.

Good morning guys. My question is primarily focused on some of the realized pricing evidenced in the quarter. I guess it’s a bit of a two part of here, I guess, first of, it looks like the realize condensate or [Indiscernible] was extremely cheap which was great. I guess the first part of the question would be where are you sourcing that, is that Canadian source [Indiscernible] or would that be something more linked to the United States? Second part of the question is, I guess we would have expected with the combination of the cheaper [Indiscernible] cost and improved access to the U.S. Gulf Coast that we could have seen higher bitumen realizations than what was posted, just curious how we should be thinking about that I guess bitumen differential to TI going forward, is that something that we expect will contract or if these absolute differential are kind of where that’s going to flattening out there?

Yeah, Chris, well, I’ll get Bob Pease to respond to that, but I just need to make a comment, the condensate cost were actually higher because of being purchased in Q4 and running through in Q1, but Bob will explain.

Yeah, Chris, but what Brian indicated is correct, in the marketplace today, so when we are up buying today for condensate, condensate prices relatively cheap in the market just as the price accrued and other products have fallen, but our condensate cost that went into our realized pricing as Brian said we are higher because most our condensate works through a [Indiscernible] and it’s kind of a weighted average pricing works similarly to the first in, first out, but because of the length of the supply chain, most of what you run off in the quarter of those into your blend value as what’s purchased in the previous quarter or in the first part of the current quarter. So most of our first quarter really when it was actually quite high relative to few adjustment of the benchmark price, the Alberta benchmark price for the quarter and that is why the realized prices on our blended product was down quite a bit, the vast majority of that was the higher condensate price. So yes, you’re correct, what we buy today is lower price that will show up in future quarters blending, but it’s, but that’s not what you saw on the first quarter. As far as sourcing goes, we’ve taken the strategy similar to our placement strategy which is we want to have a spread of options, we want to not be exposed entirely to one market, so we do some acquisition in Alberta and we do some all the way back as far as the U.S. Gulf Coast and the relative valuations of that change over time, but it general, it is a wide portfolio of sourcing which is benefit to us over the long-term.

Okay, and I guess in terms of pricing realizations at the Gulf Coast that was being specific, it’s still fair to assume that you’re getting in line with or in the ballpark of Mia down there?

Yeah, again that also swings, but generally speaking Mia is a good comparative crude, so the types of crude we produce every refinery season definitely and pricing conditions changed, but that’s really reasonable approximation for a lot of heavy grades.

Okay, yes, that helps me, thanks.

Yeah.

Our next question comes from Menno Hulshof from TD Securities. Your line is open.

Thanks and good morning. I’ll start with a question on SORs, they were quite low in Q1 at both Christina Lake and Foster Creek, but if you look at the guidance, which is just they turn higher in the coming quarters, so the question is, it’s not your expectation and if so, can you give us a sense of what the profile for both projects would look like?

Hi, Menno, Harbir here, so Foster Creek, we laid out about 15 to 18 months ago our six strong strategy in how to improve the production at Foster Creek and so that got implemented in 2014 and so we’re seeing a lot of flush production, lot of optimization going on, a lot of the conformance in the wells has improved, so all of those things are adding to the reduction as so far, but we do have ramp up still occurring in Foster Creek F, we’ve got G starting next year, so that does chew up extra scheme [ph], so we’re maintaining our guidance of that 2.6 to 3 for Foster right now, Christina is also performing very well and so we’re doing about 1.7 right now, guidance is about 1.8 to 2.1, so I think just because of the startups coming in the other ones we want to maintain that guidance that we’ve laid out so far, but things are working really well and we’re going to continue to keep the SORs and both the projects at the low end of the guidance.

Okay, and then in terms of the just to take that a step further, you have Foster Creek F still ramping up, still early days, you’ve got flush production starting to little lower I think, so what should be expect from a Foster Creek through year end given that Q1, production was at the very top of the full year range?

Yeah, so you are absolutely right, we’ve got flush tapering of a declining and after ramping up, so expect Foster Creek to be within that guidance and most probably you will be at the high end of that guidance range.

Okay, that’s it from me. Thank you.

Your next question comes from Nick Lupick from AltaCorp. Your line is open.

Yeah, hi guys. Thanks for taking my questions. I just had a quick question on the pipeline apportionment that you mentioned earlier on that you saw in the quarter getting out of your Oilsands. I was hoping you can give us a little bit of sense as the magnitude of impacts on that in terms of the price realization seen may be Christina Lake specifically and also if it is [Indiscernible] and we won’t to see that going forward?

First part Pease is to respond.

Yeah, so the apportionment is primarily on the mainline, which heads down to the U.S. it reduced our access to our plan again in South pipeline space. You made a peers just on the nature of how nominations are handled on that system that it swings in magnitude overtime that I suspect it will be a continuing issue. As far as the realization between Foster Creek and Christina Lake, again the primary issue, the overall though our realized price was the [Indiscernible] cost as opposed to any amount of proration. Proration actually decreases the total volumes we sell on a destination thereby decreasing our transportation cost and our potential for top lift on those destinations, but it was a relatively small factor relative to the higher compensate that we had to blend off. The big swings you sometimes see between Foster Creek and Christina Lake [Indiscernible] another depends on which volumes which crews ended up being sold at Alberta versus which ones we chose to put into the pipes or into the rail to go to the various destinations and that swing quarter-to-quarter. So you will see variations between each individual field and what we do is we optimize the whole across the total [Indiscernible] which field it is.

All right, thank you.

Your next question comes from Fernando Valle from Citi. Your line is open.

Hi guys, thank you for taking my question. Just a follow-up on the cost cutting changes that you’re expecting $400 million to $500 million. I so [Indiscernible] understand that you talked about $100 million already realized in this quarter. I wanted to know if this $400 million is incremental and also I have a bit of ballpark estimate of how much to as much of that is OpEx? How much of that is internal versus external with suppliers [Indiscernible]? Thank you.

John Brannan will respond to that.

Yeah, thank you Fernando. The $100 million generally we said overall about $200 million that we have achieved at this point and the $100 million that would be sustainable, would be part of that $400 million to $500 million net on the way forward, but we have also got lots of other things that we are doing that we just haven’t been able to realize the savings associated with that. We got zero base modules that we plan on putting in for our sustaining well pads and those types of things and we kind of have to use up the existing things that we’ve had before we go into being able to go to the new design. So with time and supply chain management and other things, we think that we will achieve those kinds of numbers that $400 million to $500 million is on a combination of CapEx and OpEx and if generally – the current levels of about $2 billion a year, perhaps if prices recovered our capital expenditures would be a bit higher than that, but then on the OpEx is somewhere in that $2 billion range annual basis at this point. So, that $400 million to $500 million is generally on say $4 billion to $5 billion worth of combination of OpEx and CapEx.

Great, thank you very much.

Our next question comes from Fai Lee from Odlum Brown. Your line is open. Q – Fai Lee: [Indiscernible] here. Just a quick question in terms of the increase in hedging in the short-term I guess to protect against, I guess potential drop in pricing due to storage concerns. Can you please comment on the condition of your brand fixed price contracts and suppose to say may be as opposed to say maybe WTI?

So I ask Ivor to comment on that.

Thank you. Certainly we look at where we can [indiscernible] margin the using brand fixed price contracts allows us to success something closer [Indiscernible] global pricing in the situation that we’re probably looking to maximize optimize [Indiscernible].

Okay, next.

Our next question comes from Sameer Uplenchwar from GMP Securities. Your line is open.

Good morning, guys. Quick question on the cash on hand you have and if you are successful in selling or IPOing of the royalty interest. Trying to understand what have you planned to do with that cash? One is, are you looking for any acquisitions and if so, are you looking within Alberta itself or you’re looking outside? What’s the plan on that end, or is it organic? Thank you.

Thanks for question, Sameer. It is Brian Ferguson. The decision to raise equity was based on an assessments of our three year business plans 2015, 2016, 2017 and our organic investment opportunities, what we wanted to do was to have the highest level of certainty. If prices remain lower at the time, we were looking at $52 WTI and price is staying in 50s 2016 and creeping into the low 60s in 2017. So three years of sustained low prices and the decision was what was the minimum amount of equity that will give us the certainty to be able in that sustainable growth environment to continue to be able to invest these high return organic projects of Foster Creek and Christina Lake. So that continues to be our focus and we have no acquisition plans.

And follow up on the takeaway side, I’m just trying to understand you had ordered the railcars before if I remember correctly 825 coiled railcars, if they kind of looking at not just Cenovus, but everybody else in the industry. Production doesn’t seem to be ramping up as we got a year ago. So is there a need for the railcars and how are you thinking about takeaway from that perspective? Thanks.

First, Bob Pease to respond to that?

Yeah, thanks, Brian, yes, that number was correct on our railcars, we are still receiving those. Today, we have not received all of them yet, our view as at this point that’s the right amount for us that doesn’t mean we’ll be using them all at all times, again we see opportunities to utilize rail even in these relatively compressed Alberta, the Gulf Coast spreads their opportunities that makes us sense for us. And we see opportunities going forward and because of the lead time associated with railcars it’s essential to have some in stock. So we said before, we expect rail to remain a core part of our business with the potential to grow more in the future. If we find opportunities to put them to use so, no, I don’t see that we have too much, I think we are well-positioned and could even grow in the future.

Okay, thank you.

[Operator Instructions]. Our next question comes from Ashok Dutta from Platts. Your line is open.

Hi, thank you. Bob I had a few questions for you and I would quite appreciate it if you could just explain these to me if I heard you right. So the transportation cost you said will increase to $8 per barrel in 2015, that’s the anticipated increase. Did I get that right?

No, we had originally forecast our total average transportation to be $8 per barrel in 2015.

Okay.

And the first quarter was $6.50.

Okay, good. And what has brought about that decline?

So a small portion of it has been the fact that we are producing more from the field than we expected, which reduces our per barrel cost of moving barrels to the hub that the vast majority has been decreased transportation to the Gulf Coast both from proration that has reduced our availability to get to the Gulf Coast, but the biggest component has been our reduction and our use of rail economics on rail what we need much less than we had forecast at that time. So rail is the largest component and then somewhat reduce total pipeline movements.

Okay, good and in terms of how much you have reduced via rail. There is a figure that’s out in your release today, but how does that compare with Q1 of 2014?

Well it’s up from Q1 of 2014, I don’t recall what that number was, but we moved about 13,000 a day in Q1 of this year, which is more than Q1 of last year, but I don’t have the number handy.

That’s okay. And in the following quarters is that expected to decrease further the transportation costs?

Actually, I hope not, because my hope is that we had more and more opportunities to move product to the Gulf Coast and to the West Coast where we see a higher realized price above those transportation costs. So our desire is to get us much pipeline capacity as we can economically justify. Again rail at these kind of spreads between Alberta and Gulf Coast pricing, it’s likely to remain similar. We’ve got the capacity to go more, but at this point I don’t foresee that coming in the near future.

Okay and just one last question, if I may. So is there is shift from your side of transporting more by pipelines than by rail [Indiscernible] it is still a portfolio that you would prefer?

When we look strategically at it, still a portfolio, we believe rail will be a sustained component of our portfolio, but again part of what we’re doing is to create a structure to guess us the ability to move locationally and by transportation means whatever is best at that time and we will adjust on a short-term basis as market opportunities did take.

Okay. Thank you very much.

Our next question comes from Jeffrey Morgan from Financial Post. Your line is open.

Good morning. Thanks for taking my question. Wanted just to ask you [Indiscernible] targeting a dividend payout ratio of 20 % to 25%, and I think if I heard you correctly at WTI prices, I think you said between $55 and $60 per barrel you’ll be able to achieve that. My question is over the first quarter, we’ve given that oil prices were below that level was your dividend payout ratio above that 20% to 25% or how is that compare relative to that 20% to 25% target?

Yeah, thanks, for the question Jeff. I just need to clarify the price that I mentioned would be in the $70 to $75 WTI equivalent range,

Right, my apologies…

Generate that kind we were clearly above that, this is a trough, look at the dividend, board looks at the dividend based on the sustainability in a more normalized price environment and that is one of the reasons why we took the step for temporarily putting in a discount on our dividend reinvestment plan.

Right, so with oil prices being below that $70 to $75 level range or if your dividend payout ratio at the moment higher or above that’s 20% to 25% target?

Yes.

Okay, thank you very much.

Thank you.

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

Thank you for joining our call today. The call is now complete.

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