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

Thank you, operator, and welcome, everyone, to our second quarter 2013 results conference call. I would like to refer you to the advisory located at the end of today's news release. This advisory describes the non-GAAP measures referred to today and outlines the risk factors and assumptions relevant to this discussion. Additional information is available in our annual information form and second quarter report. 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 overview of our results; John Brannan, Executive Vice President and Chief Operating Officer, will then discuss our operating performance. And Ivor Ruste, Executive Vice President and Chief Financial Officer, will discuss our financial performance. Brian will provide closing comments before we begin the question-and-answer portion of our call. Please go ahead, Brian.

Thanks, Jim. Good morning. I'm pleased to share with you some of the highlights from Cenovus' second quarter performance and our outlook for the remainder of the year. Our oil growth remains on track and our integrated strategy continues to deliver on our commitment to shareholders to build net asset value. At Christina Lake, we completed phase E, which achieved first steam on June 22, and first production last week. Christina Lake phase E represents our 10th phase of SAGD growth, another major milestone. This phase adds another 40,000 gross barrels per day. Production capacity at Foster Creek and Christina Lake, combined, now totals 258,000 barrels per day. We expect a smooth ramp up to full production over the next 6 to 9 months at Christina Lake. John will provide more detail related to our operational performance in a few moments. Our second quarter upstream results benefited from stable production, rising oil prices and a narrowing light-heavy differential compared with the first quarter. We also posted strong results from our refining operations, highlighting the benefit of our integrated model. We anticipate that the remainder of 2013 will continue to experience oil price volatility due to ongoing pipeline congestion. But I am confident that our reliable oil growth, our downstream integration and our flexible conventional programs will continue to translate into strong financial performance. During the quarter, we announced the sale of our Lower Shaunavon assets for $240 million. This transaction was completed in early July. Ivor will provide a more detailed review of our financial performance later in the call, but I want to briefly comment on the nonrecurring pretax adjustments in our Conventional business that impacted our financial results this quarter. We recognized an additional $57 million in depletion expense related to the sale of our Lower Shaunavon asset.…

Thank you, Brian, and good morning. During the second quarter, our integrated operations performed well. Steady production from oil sands and conventional were complemented by another good quarter from our refining assets. I would like to start by talking about the flooding in Alberta, which occurred in late June. The impact from the flooding to Cenovus' operations was very minor, and we estimate that we lost approximately 1,000 barrels a day for the quarter. The impact was limited to some temporary shut-ins in southern Alberta and a few interruptions at our oil sands assets. This quarter, at Christina Lake, we completed our first major plant turnaround during late May and early June. The turnaround included 11 days of full production outage, as well as a few days of ramp down and ramp up. This was slightly longer than planned, due to an expanded scope of work, but everything was completed safely as we tied in key components related to phase E and the C, D and E optimization project. The production impact of the turnaround was approximately 7,600 barrels net per day for the quarter, roughly 2,500 barrels per day more than we originally planned. Production has since ramped back up and we have been running over 100,000 barrels per day gross for the past few weeks. We expect production at Christina Lake to be in line with our full year guidance. Operating costs at Christina Lake averaged $16.83 per barrel during the second quarter, and largely reflect the impact of the planned turnaround. Lower production volumes versus Q1, combined with higher costs related to the turnaround, resulted in a higher per unit operating cost. Our full year operating cost expectations at Christina Lake are $12.80 to $13.60 per barrel. As Brian mentioned, we achieved another major milestone this quarter…

Thanks, John, and good morning, everyone. Ongoing project execution, combined with solid performance from our integrated operations, allowed us to maintain our strong financial position in the second quarter. Cenovus reported fully diluted cash flow per share of $1.15, compared with consensus estimates of $1.19 per share. As Brian mentioned, this quarter we recognized a pre-exploration expense in our Conventional business of $63 million or $0.08 per share, which accounted for the cash flow variation. Our reported operating earnings of $0.34 per share were below consensus expectations of $0.51 per share. The variance relates primarily to 3 items: the $63 million pre-exploration expense, the $57 million of depletion on the sale of our Lower Shaunavon asset; and the $46 million exploration expense on the conventional tight oil play. These 3 items totaled about $0.22 per share. Commodity prices remained volatile during the second quarter, as light-heavy differentials tightened in June. The narrowing differential positively impacted our netbacks during the quarter, but this also had a negative impact on our refining results as heavy oil feedstock was more expensive and contributed to lower refining margins. Refining operating cash flow was $316 million in the quarter. Using a LIFO inventory method as is done in the U.S., our operating cash flow would've been $33 million lower. General and administrative expenses were $3.54 per barrel of oil equivalent in the second quarter, compared with $2.51 per barrel of oil equivalent for the same period last year. G&A reflects higher workforce and office rent costs compared to last year. Our balance sheet metrics remain strong, exiting the quarter with a debt-to-capitalization ratio of 33% and a debt-to-adjusted EBITDA of 1.2x, both at the bottom end of our long-term target ranges. Our financial strategy remains unchanged. Our plan continues to support our growth plans in oil production and also -- while also providing a dividend to our shareholders. I'll now turn the call back to Brian.

Thanks, Ivor. Our operating performance, strong refining business and a reliable oil growth profile position us well. The stability of our cash flow gives us confidence in our long-term growth objectives, allowing us to maintain our focus on increasing total shareholder return, which includes paying a meaningful dividend to our shareholders. The completion and first production from Christina Lake phase E and the recent announcement of the C, D and E optimization project at Christina Lake is a continuation of our manufacturing approach to oil growth. We expect to deliver a new 40,000- to 50,000-barrel per day phase of oil sands growth every year for the next several years. The outcome is an oil production profile that we anticipate will reach 0.5 million barrels net to Cenovus by 2021. We are on track to achieve our cash flow guidance for the full year. Wherever we have provided an update to our guidance document, it reflects changes to a few individual items. Overall, our integrated operations continue to perform well, and we continue to build on asset value. We are committed to total shareholder return, which includes growing our dividend. Our teams are focused on a strong second half for this year. With that, the Cenovus team is now ready to take your questions.

[Operator Instructions] Our first question is from Arjun Murti with Goldman Sachs.

Brian, 2 questions. The first is, one of the possible solutions if there's pipeline congestion or permitting or regulatory delays is, obviously, rail. And no question, it's a very tragic and unfortunate situation that happened in Québec. Can you provide any comments on how you see rail progressing in light of that very unfortunate situation for industry and/or for yourself?

Thanks, Arjun. As you pointed out, it is truly a very tragic situation. There was tremendous loss of life, which is never, never supposed to happen in these kinds of situations. There is an ongoing investigation into the root cause of the accident and why it was so catastrophic. We continue to believe, for Cenovus, that we can safely move crude by rail. We are targeting to have 10,000 barrels per day moving by rail later this year. We have committed to some medium-term leases on additional railcars, which will see us in a position to move up to 30,000 barrels a day by rail next year. We continue to believe that crude oil can be moved very safely by rail. And what it does is give us access to a variety of niche markets that will help us to be able to optimize our overall realized pricing.

I guess -- and again, I certainly appreciate the sensitivity of the issue, but at least, up to this point, the plans you have are on track, you guys are going to be as safe as possible, but you haven't had to slow down or face any other issues in terms of what you're doing today and/or your future plans?

That's correct, Arjun. Safety in all of our operations is of paramount importance to Cenovus. And we will continue to make sure that we do absolutely everything that we can to ensure that every barrel that we produce and every barrel that we transport is done in a very safe fashion.

That's great. And then a second unrelated question, I can't remember if it was last quarter or 2 quarters ago, you talked about blowdown on a portion of Foster Creek. Has that started? And where are you in that process? The production numbers certainly look very much in line or as expected. So I just want to see if you are already seeing the impact of that in the numbers.

I'll ask Harbir to respond to that one, Arjun.

Regarding the blowdown, you're absolutely right. We do have 3 pads ongoing, one is on complete blowdown. We do transition from steam injection to full blowdown. We turn off the -- there's a transitioning phase where we slow down on the steam injection and ramp up on the gas injection. And so we have 2 pads that are in that mode, which we call kind of a ramp down mode. So really, we only have one pad. So we're -- right now, a very small percentage of the field is on blowdown, and that's why you're not seeing any effect on total project SOR yet.

Got it. And then when you're done with those 3, you continue to progress? Or this just happen to be the oldest portion that needed it right now? If there's a -- kind of an update on how blowdown would progress across the rest of the complex?

Right. So the main metric that triggers when a well goes on blowdown is really the recovery factor. Once we start to get to somewhere around 50% to 60% recovery factor from a pad basis, we start to go on blowdown and blowdown will keep going on that pad for about 10 years. And then we'll continued to add more pads on blowdown. So as FGH comes on, we put new wells on and new pads on, but we start to retire the old ones to the ramp down and the blowdown phases with time. And so over the years, you will start to see our steam-oil ratio start to come down to close to that 2.0 level.

The next question comes from the line of Paul Cheng with Barclays.

A set of quick question. First, Brian, that -- related RIN, what's new exposure at your refining joint venture? And do you have an estimate of what is your share of the RIN purchase cost for 2013?

I'm going to ask Don Swystun to respond to that question on RINs.

RIN is a very topical issue these days. I guess, the Renewable Identification Numbers, the cost we put into our -- that was built into our guidance are -- certainly have escalated from what we initially put in. The challenge, I think, that we have in terms of setting sort of what that cost is, relates, of course, what the upside is for the refiner. And the fact that we see some of those costs being reflected in the price of transportation fuel. So, in fact, it's negative, kind of passed on to the consumer in terms of gasoline or diesel prices going forward. So we believe that, going forward, RIN is, to some degree, bit of an unworkable system for -- particularly for the refiner, and we expect that some changes will result, going forward, particularly in 2014. In the interim, like you said, I think it was, to some degree, was built into our guidance for this year. Overall, the impact, I think, could be in the range of 5%, maybe 4s at this point. But again, I think we reflect some of that in the go-forward guidance.

Don, can you tell us that -- based on your branding requirement, are you -- need to buy RIN for 50%, 40%, 30%? Any kind of rough number you can share?

I don't have that number as to what the percentages of RINs we're purchasing at this point. Yes, I don't have that number quite yet.

Okay. And you're saying that you believe that part of them is being pushed through into the -- into your customer, the additional RIN cost. Any rough idea that you would be able to reconcile back and say, "Okay, I think I've been able to pass through 50% of the cost or 30%." Any kind of number that you can share?

No, I can't really say that. The one thing you could understand is that there's a bit of a lag here, because these prices are going up when the RINs cost is not truly reflected initially, right away, in the actual kind of crack spread or in the gasoline price, but it's coming more and more as we continue to see escalation in the RIN price.

Okay. Brian, you guys just did a full turnaround at Christina Lake, as you mentioned, that took it down for the whole time [ph], for 11 days. Looking at both Christina and Foster Creek, on a going forward basis, how should we view the occurrence of this full-time turnaround, how often that it may happen? Say, once in 5 year, once in 10 year? What kind of number that we should be using or assuming?

I'll ask John Brannan to comment on that. We would basically schedule a maintenance on an annual basis.

Yes. Thanks for that call, Paul. Clearly, these facilities, both at Foster Creek and Christina Lake, our large facilities. And we have, generally, annual turnaround requirements, one, to meet regulatory requirements, some to clean up vessels, do maintenance and those type of things. You generally can plan for about a week of full-time outage on an annual basis and 2 or 3 days on either side of that to bring the field down and bring it back up.

So at a year we should assume about one wave of full-time downtime?

That would be correct.

Let me just comment, Paul, that we do take into consideration plant turnarounds when we issue our guidance. So that's already taken into account in our guidance document.

Sure. And that for Foster Creek that you guys have just raised the steam-oil ratio for this year, the target. When we're looking out, should we assume that this is the new norm or that you think, ultimately, still coming back down into the 2, 2.1 level over the next couple of years?

Harbir will comment on that.

First of all, we believe Foster Creek is a great reservoir, and I think we got a -- it's one of the lowest steam-oil ratios, highest returns, 22% to 25% IRR. One of the lowest supply costs, $38 to $40, so it's a great reservoir. We think these reservoir metrics will stay for the next -- up to until we get to about 300,000 to 350,000 barrels a day. With respect to changing the guidance on the SOR, what we've said over the last 7 years, with respect to Foster Creek, is it's nameplated 120,000 barrels a day, but we also said that the instantaneous steam-oil ratio would be 2.5%, and that we'd get to 120,000 barrels a day at a steam-oil ratio of 2% when we have full blowdown, when our wells start to go into full blowdown mode. So what happened over the last 5 years is the Wedge Well technology dropped our steam-oil ratio from 2.5% to 2.35%. Last year, at this time, the reservoir pressure dropped below the initial reservoir pressure. And so we had a substantially higher production than our nameplate, but we still feel that we can deliver 120,000 barrels a day at a steam-oil ratio of 2% with blowdown, and that is going -- will be here to stay for the next 10 to 20 years, until Foster Creek gets to 300,000 to 350,000 barrels a day. So fundamentally, this is just a short-term blip in terms of the 2.2% to 2.4% SOR. And we expect, by the end of this year, Foster Creek to be running towards the high end of the range that we gave you, the 110,000 to 120,000 barrels a day range and the steam oil ratio, as we put more wells on blowdown, will get -- start to go down to the -- closer to the 2% level.

The next question comes from Phil Skolnick with Canaccord Genuity.

Two questions. One, how much of the OpEx increase, both in this last quarter and the increase in guidance, would you say is onetime in nature, percentagewise?

Thanks. John Brannan will comment on that.

Yes. Phil, talk -- particularly like at Foster Creek. When you break it down, we almost had $2 of -- over our budget and, basically, that was associated -- about $0.40 was natural gas, about $0.60 was electricity associated with the cogen being down. We had to end up buying that additional electricity. And then as we've been talking about, we've got a higher-than-normal workover activity, so we're about $1 over our planned budget. So I would expect that you would see just, non re-occurring, about $2 on -- at Foster Creek. Christina Lake, similar to that, we had longer turnaround than expected, so there's volumes associated with that. We had about $1.10 over on our fluid and trucking costs, most of that was related to the turnaround. So some of those things are generally onetime pieces.

Okay. And a second one, do you have a downstream guidance, at all, for Q3?

Yes. Phil, we continue to have our annual guidance, which we have not updated. Do expect that there's going to be a fair bit of volatility on pricing, particularly on the feedstock side here, as you see some new demand come on and also some new supply on the heavy side as we go forward. So some volatility in differentials here in the second half.

The next question comes from Mark Polak with Scotiabank.

Actually my questions have already been answered.

Next we have the line of David McColl with Morningstar.

Just wondering if you can provide any indication, perhaps, as to whether Cenovus has any long-term capacity commitments on TransCanada's Gulf Coast connector or the COA pipeline?

Don Swystun?

We have, I guess, a number of commitments on various pipelines. We've been pretty proactive in terms of moving those forward. I think, as far as -- like we like to say to the West Coast, we're moving -- we've got commitments, about 175,000 barrels a day. To the Gulf Coast, we're looking about a 150,000 barrels a day and, certainly, with the open season on TransCanada East, we were a participant in that and more information will be coming shortly, but we expect to be -- have a good commitment on that line as well. And generally, within most pipes, in a lot of those particular markets, we split between things, such as on the West Coast it would be between Gateway and Trans Mountain expansion, or the Gulf Coast it's, obviously, Keystone XL or Enbridge in the Gulf Coast line as well. So I think we try to have a real portfolio approach to our marketing of -- on pipelines.

Next is the line of Peter Ogden with Bank of America Merrill Lynch.

I might have missed it, but on the $63 million pre-exploration expense, I was wondering if you could provide a little bit more color. I mean, to my recollection, I can't remember something like that being a cash expense and I understand it's part of pre-licensing or whatever it is. But, I mean, how do you prevent that from happening again? How was $60 million spent, to begin with? And, I mean, maybe you can share where or how that was incurred and how it, I guess, doesn't -- or controls on how it doesn't happen again?

Thanks for the question, Peter. So we decided to take a conservative approach. We have fully written-off in the quarter the entire obligation related to a farm-in on our conventional oil operations. Due to the contractual nature of the farm-in, I am not at liberty to give any additional details on it. I can tell you, and you have my assurance, that there is nothing else to come on this.

Next question comes from the line of Fai Lee with Odlum Brown.

Just wanted to clarify something. There seems to be a general outlook for operating costs to decline for the remainder of the year, for most -- for Christina Lake, Foster Creek, Pelican Lake. Is that largely related to reduced workover activity? Or is there something else driving that?

Yes, I think, particularly at Christina Lake, we will be ramping up volumes and we do not have any additional turnarounds planned. At Foster Creek, we do have a 1 week turnaround in September, and we are continuing to work off the backlog of these workovers and re-completions and things that we're doing. So I expect you'll still see some of that into the third quarter and then as we get our volumes up on a per-barrel basis then the cost should start coming down in the fourth quarter.

Okay. And the electricity in Alberta seems to be pretty volatile. How -- I know you mentioned Foster Creek, but how sensitive are the -- is the impact on Christina Lake and Pelican Lake?

Yes. So on a per-barrel basis, generally, our electricity runs -- let me just look here real quick, $0.88 to $1.50, somewhere in those kind of ranges, depending on volatility associated with the price. When we are able to run our own cogens at Foster Creek, we take that variability out of it and can keep that below $1-type numbers on a BOE basis. We are -- also at Foster Creek, as we do these additional expansions in F and G, we will be putting in cogens there so that should stabilize electricity prices for that facility on -- at Christina Lake on the way forward.

Next question comes from the line of Menno Hulshof with TD Securities.

I've just got a quick follow-up question on the RIN issue. You mentioned 5% impact, and I was just wondering if you could give us some more clarity on what that's in relation to?

Yes. Sorry, yes, this is Don. Yes, that would have been -- overall operating cash flow is the way I'd characterize that in terms of what that impact has began. It's hard to take that, if you want to take RINs as a higher cost, you have to also reflect, potentially, the higher value you would get on some of your products in terms of how that's going to be priced out in the marketplace in terms of refiners trying to recover some of that cost. So, as I said, there's a lag created in there where you may not see it quite coming back in the short-term, but we expect some of that, certainly, will get passed through to the consumer.

And that was in relation to 2013?

Yes.

[Operator Instructions] The next question comes from Paul McRae [ph] with Tower Bird [ph] Advisors.

Yes, my question, actually, was partly answered. It had to do with the $63 million pre-exploration expense. That was a bit of a surprise to me and I'm wondering, for example, will we hear more about this with more clarity in the future? And maybe what kind of expense this was? Would it be G&G, for example?

The -- this relates -- it is onetime, there is no further expense to come on this. We took a conservative approach and have fully expensed this quarter all of the costs associated with this particular farm-in opportunity. So with regard to that, don't want to get into specifics, I'm not allowed due to the contractual nature of the farm-in.

The next question comes from Dan Healing with Calgary Herald.

I just had a couple of questions about tight oil plays. I believe John mentioned that $35 million more would be spent at the tight oil play in Southern Alberta. I was wondering where that is? And then also the $46 million exploration expense, I wonder if you can tell me where that is? And give me a little more color on that one.

So then -- the $35 million increase in investment here is in our existing lands in Southeast Alberta. And a lot of that is on fee lands that we have. And with regard to the $46 million, as we indicated in the news release, it has to do with a tight oil opportunity in Saskatchewan, but we're not going to get more specific than that because we do have other lands in Saskatchewan.

Okay. And then on the Alberta part of it, can you say what formation or what specific area?

No. I prefer not to get into that detail due to the competitive situation.

There are no further questions in queue at this time. I'll turn the call back over to Mr. Brian Ferguson, President and CEO.

Thank you for joining us today on this call, and the call is now complete.

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