Cenovus Energy Inc. (CVE) Q2 2014 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Cenovus Energy's Second Quarter 2014 Financial and Operating Results. As a reminder, today's call is being recorded. [Operator Instructions] Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of Cenovus Energy. I would now like to turn the conference call over to Ms. Susan Grey, Director, Investor Relations. Please go ahead, Ms. Grey.

Thank you, operator, and welcome, everyone, to our Second Quarter 2014 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 and non-GAAP measures referred to today, and outline the risk factors and assumptions relevant 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 an overview of our quarterly results; and then turn the call over to John Brannan, Executive Vice President and Chief Operating Officer, who will provide an update on our operating performance. Ivor Ruste, Executive Vice President and Chief Financial Officer, will then discuss our financial highlights; and turn the call over to Brian for closing comments before we begin the Q&A portion of the call. Please go ahead, Brian.

Thanks, Susan. Good morning. In the second quarter, our continued focus on maintaining predictable and reliable operations allowed us to meet and in some areas exceed our expectations. Our upstream operations delivered strong performance with an increase in total crude oil production of 18% over the second quarter of last year. Our oil sands segment averaged nearly a 125,000 barrels per day. That's an increase of 33%. We reached design capacity at Christina Lake phase E, completed a successful turnaround at Christina Lake, began steaming phase F at Foster Creek and have been achieving high run rates at our refineries. Our financial performance is strong. Year-to-date, we have generated cash flow of $2.1 billion, which exceeds our capital expenditures and dividends on a year-to-date basis. One of our prime areas of focus is improving market access. We've recently strengthened our leadership in this area. I'm pleased to welcome Robert Pease to the Cenovus executive team. Bob joined our team in June as Executive Vice President of Markets, Products & Transportation. Bob is responsible for all commercial activities associated with marketing our crude oil, natural gas and natural gas liquids production as well as the integration with our refining operations. He brings over 34 years of industry experience in refining, marketing and transporting oil. We look forward to benefiting from his expertise and his leadership. Overall, I'm very pleased with our quarterly results. We've achieved strong cash flow and very solid operating performance. I'm now going to ask John Brannan, our Chief Operating Officer, to provide additional details on our operations.

Thank you, and good morning. As Brian mentioned, upstream operations have been strong this quarter. Both our Foster Creek and Christina Lake facilities have been running exceptionally well. Utilization rates have been exceeding the 90% to 95% normal operating range. Christina Lake continued the phase E ramp up and consistently produced near its design capacity of a 138,000 barrels per day. A second highlight from Christina Lake this quarter was a successful completion of the turnaround on phases A and B. We originally forecast an impact of approximately 1,600 barrels per day net to Cenovus for the quarter. We actually achieved the turnaround with minimal impact on total field production as volumes from phases A and B were processed through the C, D and E plant. Nonfuel operating cost at Christina Lake improved this quarter, down 39% from the same period in 2013. This was mainly due to an increase in production volumes, but also lower trucking, repairs and maintenance cost. Foster Creek also had a solid quarter. Performance was in line with our expectations. We are currently steaming phase F wells. Oil production is anticipated in the fourth quarter. Operating costs were higher compared to the second quarter of 2013, primarily due to higher natural gas prices and some higher SORs associated with the initial steaming of phase F pads. We expect operating cost on a per barrel basis to peak in the third quarter as a result of scheduled cogen maintenance in July and a facility turnaround in September. The reduction in volumes associated with these maintenance activities is included within our guidance ranges for the year. At Foster Creek, we expect the steam to oil ratio to remain within our annual guidance ranges of 2.6 to 3.0 until all major phase expansion pads for F,G and H are online. As previously indicated, the steam to oil ratio for Foster Creek is expected to be near the high end of that range through the remainder of the year due to the startup of the phase F wells. This quarter, we have made progress in our efforts to optimize steam placement across the reservoir at Foster Creek. Use of our Wedge Well Technology continues as planned. We have brought 6 wells online in the second quarter and expect another 19 new wells to be produced by the end of 2014. Use of our Wedge Well Technology also helps provide additional production with essentially no additional steam. This will partially offset the increase in steam to oil ratios we expect to see as we ramp up additional phases at Foster Creek. With respect to steam placement across the reservoir, once the pad had reached its target recovery factor, it's advantageous to move steam to pads that are in earlier stages of their producing life. This is commonly referred to as blowdown. In May, we received regulatory approval to proceed with blowdown, using methane and air on 2 additional well pads at Foster Creek. The displaced steam from these wells can now be allocated to other pads where it can be used more efficiently. Although approvals are still being issued on a pad by pad basis, we do not see regulatory approvals delaying our reservoir management strategy. A factor critical to optimal distribution of steam is the availability of sustaining pads. We have accelerated the construction of 4 new pads into 2014 to help us manage the placement of steam across the reservoir. Capital cost for the F,G and H Expansion phases are trending higher as a result of our decision to incorporate some additional A to E learnings and related scope changes. Final capital efficiencies for the expansions will be dependent on steam to oil ratio performance, costs associated with optimization activities and debottlenecking plant capacities. We expect to provide updated numbers later this year. In our Conventional business, crude oil production was essentially flat year-over-year despite the disposition of our and some of our Shaunavon and some of our Bakken assets. Those divestitures and expected naturally declines were offset by successful horizontal well performance in southern Alberta and by an increase in production from Pelican Lake. Pelican Lake production was up 4% in the quarter compared to 2013, as additional in-field wells came on stream and the response from the polymer flood program continued. Operating costs were down almost a $1 per barrel for the quarter due to increased production combined with lower workover costs. On the downstream side of our business, we had higher refinery utilization this quarter resulting in record combined crude oil runs. Compared with the second quarter of 2013, we saw a drop in the posted Chicago market crack spreads of about 37%. Combined with increased heavy crude oil feedstock cost and higher OpEx due to turnarounds in utility cost, we saw a 32% decrease in operating cash flow from refining. Turning to transportation and marketing. This quarter, we voluntarily removed from service all DOT-111 cars that would not meet the upcoming regulatory changes. In addition, we loaded our first unit train at the USD-Gibson rail facility at Hardisty. This brings our unit train total to 8 for the first half of 2014, including trains shipped from a Canexus facility in Edmonton. Currently, maintenance work is underway at the Canexus facility to tie and collate pipeline volumes. We anticipated that this work will be completed in the fourth quarter, and we will resume shipping from the Canexus facility again at that time. We remain on track to exit 2014 with 30,000 barrels per day of rail-loading capacity. Overall, our quarter was sound, and we continue to focus on delivering dependable performance. I will now pass the call on to Ivor Ruste to discuss our financial highlights.

Thanks, John, and good morning, everyone. As Brian and John mentioned, our operations continued to deliver solid results in the quarter, and our financial performance reflects that. Through the first half of the year, we experienced higher, commodity prices compared with our guidance. As a result, we've seen stronger-than-expected year-to-date cash flows. At this time, we've not adjusted our guidance but expect to revisit it in the second half of the year. One item of note this quarter was the significant variation in cash tax. Cash tax expense in the second quarter was $68 million lower than in 2013. This is primarily attributable to a one-time favorable adjustment related to prior tax years and the relative mix of the sources of cash flow, with lower U.S. cash flow partially offset by higher Canadian cash flow. We do not anticipate that this will impact our effective tax rate guidance for the year. Our financial strategy supports our business strategy and this quarter was no exception. We added incremental oil hedges for 2015 in the form of both fixed price instruments and collars. We now have 28,000 barrels per day of our projected 2015 oil volumes hedged at attractive Brent prices. In addition, we elected to file a new $1.5 billion Canadian debt shelf and a new $2 billion U.S. debt shelf in the second quarter in order to replace the prospectuses we had filed in 2012. These shelf prospectuses are a normal course of business and were completed in order to provide flexibility and maintain efficient access to the debt capital markets. We continue to manage our balance sheet conservatively, and we remain well within the target metrics we've set for ourselves. As with our operations, we are pleased with our financial performance so far this year. I'll now turn the call back to Brian.

Thanks, Ivor. We've been able to deliver predictable, reliable performance through the first half of the year, and we continue to look for opportunities to add value for our shareholders. I've been asked numerous times this year if we intend to create a separate oil and gas royalty company. As I mentioned previously, we owe it to our shareholders to evaluate the options to increase the value of our own royalty lands. Specifically, we've been focused on ensuring that we understand the potential that exists on our lands and the impact to the company of any actions taken to crystallize value. It is important to remember that our fee lands give us a competitive advantage. We hold 4.5 million net acres of fee lands, accounting for 50% of our conventional production, and providing significant free cash flow to help fund the growth of our oil sands operations. We are continuing to evaluate the opportunities to maximize shareholder value. Our projects continue to deliver strong results, and we will continue to work diligently to ensure this performance continues. The Cenovus team is now ready to respond to your questions.

[Operator Instructions] Your first question comes from Greg Pardy with RBC Capital Markets.

Just one question, Brian. I guess is how should we be thinking about the path of steam-oil ratio of Foster Creek. I think you've outlined it well for the balance of this year, but what about 2015 and beyond?

Thanks, Greg. So as John has mentioned, our guidance range for this year is 2.6 to 3.0. And in our second quarter, we're actually at the low end of that 2.6. We will see some fluctuations inside that range or as we continue bring on new phases F,G and H. And as we're steaming the new phases when they cut, start to come on in about a year's time, we expect to trend upwards towards the upper end of that range. We do expect to be within that range fairly consistently over the next couple of years. Ivor, perhaps I can ask you to just comment on perhaps the mid- and longer-term expectations for SOR at FC, at Foster Creek.

Yes, Greg. So Brian -- so like Brian said, we're going to be 2.6, 2.9 (sic) [3.0] over the next 2, 3 years. We're going to go from the high end of that range to the low end of that range. And once FGH has all started up, then we'll start to see the steam-oil ratio drop again below that 2.5 mark. So we still think -- Foster Creek ran at 2.35 for quite a few years. We still think we'll be able to get back to that longer term.

Your next question comes from Mohit Bhardwaj with Citigroup.

Brian, I just wanted to talk to you about the increased capital expenditure pressure that you're seeing at FGH and Foster Creek that you mentioned in the press release. If you could just talk to us about that and tell us exactly what you're seeing and how that's playing out going forward and what happens in 2015, 2016 capital expenditures.

Okay. Thank you for the question. We continue to believe and expect that we will be able to deliver top quartile capital efficiencies for F,G and H when it's fully optimized. What we've done is taken the opportunity based on the learnings we've had on phases A through E, and we have very specifically decided to make some scope changes that we believe will enhance the reliability, so the run rate that goes very much to profitability; safety; and also things that we believe are going to reduce our OpEx, particularly looking at how we can continue to reduce SOR. All those things taken together, as I say, we continue to believe that it'll be somewhat higher than what we originally guided to. We continue to believe that fully optimized, we will deliver top quartile capital efficiencies at F,G and H.

Is there a guidance number that we can use in terms of what your initial expectation was and what percentage higher you would be just from the initial CapEx standpoint?

Not at this point. We will be providing more fulsome update on this later this year. We are well advanced on F obviously, but also G and H. We just need a little more time here to make sure that we've got full -- more fulsome complement of the cost and in particular, the volumes when optimized. So we will be providing a more fulsome update later this year.

Okay. And just one more from me, just wanted to understand the exact -- I don't know if you have a timeline for the startup of the optimization phases at Christina Lake and phase G for Foster Creek in 2015.

Ivor, can you comment on that?

Yes. We expect that production to start in the second half of '15. The optimization, which we're adding a blowdown boiler.

And for phase G?

Phase G for Foster?

Yes.

Okay Foster will be about 12- to 15-month from -- so we started up F and started steaming in May this year, production we expect in Q4 of this year. So approximately about a year delay for G and H.

[Operator Instructions] Your next question comes from David McColl with Morningstar.

Just a quick question going back to Foster Creek here on the blowdown. I understand that in pads, D and A have entered blowdown now. I'm just wondering if they are in fact, I guess, under blowdown. And if you were -- if you expect to see the results kind of similar to what we've seen already with pad C, and maybe if we can use that to extrapolate production going forward as you commence blowdown. And I guess related to that, how long do you think it will take before you effectively stop injecting steam?

David, I'll take the question. So normally when we start blowdown, it's coinjection like you said, combination of gas injection and steam. That depends on the recovery factors. Normally, it takes us minimum 12 months. It could take us up to 24 months of coinjection, and then we'll shut off the steam totally. We tried to shut off the steam when we reached a recovery factor of close to about 60%, after the 60% of the oil has been recovered.

Ladies and gentlemen, today's question-and-answer session is now open to the media. [Operator Instructions] Your next question comes from the line of Menno Hulshof with TD Securities.

I just had a follow-up question on higher capital efficiencies for Foster Creek F,G and H. Is that expected to negatively impact full cycle returns? Or is there some sort of an offset in the form of higher expectations on reliability? And then lastly, is it possible that we see similar capital efficiency increases for expansions outside of Foster Creek?

I will ask John Brannan to respond to that, Menno.

Yes, Menno. Let me you guide you [ph] with the last part of your question first, is that Foster Creek and Christina Lake are clearly different reservoirs, and any other reservoirs we develop outside of that, we probably need to look at those independently. In particular with the overall returns at F,G and H, very minimal impacts to our overall economics with the slightly higher capital efficiencies.

Were you able hear that?

Yes, that was fine.

The only thing I might add, Menno, is that FGH at Christina, we already incorporated the learnings from C, D, E. So we don't expect any scope changes on FGH because those have already been incorporated.

And there are no further questions at this time. I will now turn the call back over to Mr. Ferguson.

Thank you for joining us today. That concludes today's call.