Cenovus Energy Inc. (CVE) Q2 2012 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Cenovus Energy's Second Quarter 2012 Financial and Operating Results. As a reminder, today's call is being recorded. [Operator Instructions] Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of Cenovus Energy. I would now like to turn the conference call over to Susan Grey, Director of Investor Relations. Please go ahead, Ms. Grey.

Thank you, operator, and welcome, everyone, to our second quarter 2012 results conference call. I would like to refer you to the advisories located at the end of today's news release. In particular, I draw your attention to the risk factors and assumptions. Additional information is available in our annual information form and quarterly report. Today's quarterly results have been presented in Canadian dollars and on a before-royalties basis. 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 Q&A portion of the call. Please go ahead, Brian.

Thanks, Susan. Good morning. I'm pleased to report another solid quarter from the Cenovus team. We continue to deliver predictable, reliable oil growth and benefit from our integrated oil operations. We remain focused on building net asset value. This quarter we achieved a number of operational milestones. When you look at our second quarter results, you will see continued strong execution of our 10-year plan. In particular, you will note that despite substantially lower realized oil and gas prices in the quarter, our cash flow is essentially unchanged year-over-year. Our oil growth strategy is delivering, and this, combined with our downstream integration, is providing solid financial performance. John and Ivor will provide a more in-depth review of our operating and financial results, but I want to reiterate that our 2012 plans are unchanged. Our low-cost oil sands project, our strong balance sheet, our flexible conventional capital programs and our downstream integration allow us to be resilient in times of commodity price volatility. Overall, we continued to deliver on our operating and financial objectives and we remain on track with our development plans that will see expected oil production grow to 500,000 barrels per day net to Cenovus by the end of 2021. I'll now turn the call over to our Chief Operating Officer, John Brannan.

Thank you, Brian, and good morning. I'm pleased to say that our momentum continued during the second quarter. Our oil sands operations posted strong production volumes with net production at Foster Creek and Christina Lake averaging more than 80,000 barrels per day at an average steam to oil ratio of 2.0. At Foster Creek, we safely completed our plant turnaround as planned, while maintaining the production impact to approximately 7,400 barrels net, or 14,800 barrels gross per day for the quarter. Production volumes have ramped back up and we hit a new daily production record of just over 129,000 barrels per day gross in June. We expect production volumes at Foster Creek to be in line with our guidance for the year. Construction on the expansion phases at Foster Creek continues. We are now just over 50% complete at Phase F, with offsite module assembly and facility construction progressing. At Phase G, piling work, offsite steel fabrication and major equipment procurement continues. And at Phase H, design engineering work is underway. We have also started public consultation for an additional phase at Foster Creek. This 9th phase is anticipated to add approximately 50,000 barrels per day, bringing total expected gross production capacity to 295,000 barrels per day. With ongoing optimization work over time, we believe total gross production capacity at Foster Creek will reach 310,000 barrels per day. Gross production at Christina Lake averaged more than 57,000 per barrel -- 57,000 barrels per day in the quarter. We reached a new daily production record of just over 64,000 barrels per day in June, exceeding our nameplate capacity of 58,000 barrels per day. This demonstrates the high reservoir quality of our Christina Lake asset and our industry-leading startup processes. Steam injection at Christina Lake Phase D began in June, approximately 3 months ahead of schedule. We have commissioned about 90% of Phase D and production ramp up is expected to begin in the third quarter. We will continue to move forward with the completion of Phases D and E and plan to further updates on those projects in the coming months Phase E is currently more than 50% complete and all major equipment has arrived at site. With additional expansion phases and optimization work at Christina Lake, we believe total gross production capacity has a potential to reach 300,000 barrels per day. Operating costs at Foster Creek declined slightly from the first quarter, averaging approximately $12.50 per barrel, including turnaround cost and higher staffing levels for future phases. With Christina Lake production averaging close to design capacity per unit operating cost continued to decline, also averaging approximately $12.50 per barrel in the second quarter. Our emerging oil sands projects had positive developments this quarter as well. In May, we received regulatory approval for our Narrows Lake project. This approval includes the use of our solvent-aided process or SAP, which will be the first large-scale commercial development to use butane as a solvent in combination with the steam. This project will have a total expected gross production capacity of 130,000 barrels per day. The production from the first phase of 45,000 barrels per day expected to start in 2017. Currently, we are working on detailed engineering for the first phase at Narrows Lake and anticipate project sanction later in 2012. At Telephone Lake, we continue to progress the dewatering pilot and anticipate starting water removal and air injection in the next couple of months. Prior to water removal, we think Telephone Lake steam to oil ratios will be in the range of 2.5. If we are successful in removing the non-potable water above the reservoir, we should be able to further reduce steam to oil ratios. We are encouraged by what we have seen so far in our strat well drilling program at Telephone Lake and we will continue to collect data from the pilot and additional wells as we plan to drill -- in additional wells that we plan to drill over the next year. Clearly, Telephone Lake will be an industry-leading SAGD project with or without dewatering. At Pelican Lake, we are seeing incremental volumes associated with our infill well and polymer flood program. Production averaged approximately 22,400 barrels per day in the quarter. Current production is in the 23,500 barrels per day range. The start of our production ramp-up was delayed as a result of temporary production decreases associated with lower operating pressures from injector shut-ins that were required as we drilled and completed our infill program. Overall, production growth is now proceeding at anticipated rates and we expect to be within our guidance range by the end of the year. Our plan to grow Pelican Lake to approximately 55,000 barrels per day remains unchanged. Conventional operations continue to perform well with oil production growing in both Alberta and Saskatchewan. In Southern Alberta, we continue to be encouraged by early success from some of our emerging tight oil plays. We have added 3,500 barrels per day of light oil production in Alberta so far in 2012 and are currently producing over 29,000 barrels per day at that -- in that asset. Oil production from the Lower Shaunavon and Bakken and Saskatchewan averaged approximately 6,200 barrels per day. During the quarter, we completed the battery construction for the Bakken and expect to complete facility construction in the Shaunavon area in the third quarter. We also recognized a $68 million pretax non-cash exploration expense in the quarter primarily related to a small piece of expiration land in the Roncott area outside of our core Bakken acreage. Based on the results of our first 6 wells, we decided not to continue exploration work on this asset. Activity in our other areas of the Bakken continues as planned. In terms of overall capital expenditures, we remain on track to complete our 2012 program within the guidance range. We aren't seeing significant changes in inflation and still forecast about a 5% increase in oil sands and conventional costs. We continue to minimize capital spending on our natural gas assets in the near term. Excluding the divestiture in the first quarter, our natural gas production declined about 5%. Despite low gas prices, we still earned a healthy netback due to our hedges, low operating cost of approximately $1 in McF and mineral taxes on our fee lands of only 2% to 3%. Natural gas accounted for only 11% of total operating cash flow in the second quarter. At Wood River, we continue to test heavy oil processing capacity following a start-up of the coker at the CORE expansion late last year. Performance during the quarter was very good, with total crude throughput of 451,000 barrels per day at Wood River and Borger combined. At Wood River, crude runs average 327,000 barrels per day gross in June. This included approximately 213,000 barrels per day of Canadian heavy crudes and set new record high monthly averages for both total and Canadian heavy throughput. With the capacity to use additional heavy crudes as feedstock, combined with an improved clean product yield of about 5%, Wood River is well positioned to take advantage of what we expect will be a good refining market in the PADD II area over the next couple of years. In closing, Cenovus posted another solid quarter in terms of our operations. We continue to show predictable oil production growth. Our teams remain focused on safe and reliable execution of our projects and our operations as we strive to meet our near and long-term goals. I will now turn the call over to Ivor.

Thanks, John, and good morning, everyone. Strong project execution and very good operational performance, combined with our integrated strategy, allowed us to maintain our solid financial position in the second quarter. Cenovus reported cash flow per share of $1.22 compared with consensus estimates of $1.13 per share. Once again, our integrated strategy proved valuable in the quarter, with downstream operating cash flow making up for the lower upstream pricing. The reported earnings of $0.37 per share were $0.16 per share below consensus expectation due to 3 noncash items. Approximately $0.07 per share related to the exploration expense that John mentioned and about $0.06 per share is for additional tax related to true-up adjustments arising of the filing of the prior year's tax returns. The remainder of the difference can be attributed to higher upstream DD&A in the quarter. As you know, oil prices came under pressure in the second quarter and light heavy differentials remained wide. The average price of Western Canadian Select benchmarked Canadian heavy crude to up approximately $11 per barrel from the first quarter, consistent with the decline in WTI. This negatively impacts our upstream results, but has recovered as our refineries are able to source these discounted crudes as feedstock. U.S. midmark -- U.S. Midwest market crack spreads remained strong in part due to the Brent WTI spread and averages over $28 per barrel in the quarter compared with approximately $21.50 per barrel in the first quarter of 2012. Refining operating cash flow was $344 million in the quarter. Using a LIFO, or last in first-out inventory method as is done in the U.S., our operating cash flow would have been $95 million higher. While current market crack spreads remained strong, plant turnarounds are scheduled at both Wood River and Borger in late Q3 and early Q4. Based on an average $21.50 per barrel oil crack spread for the second half of 2012, we anticipate full year refining operating cash flow to be nearly up or end of our guidance range of $900 million to $1.2 billion in 2012. General and administrative expenses were $2.51 per barrel of oil equivalent in the second quarter compared with $2.65 per barrel for the same period last year. Lower long-term incentive expenses were partly offset by higher staffing, training and development and office support costs. Our balance sheet metrics remain strong, exiting the quarter with a debt-to-capitalization ratio of 27% and a debt-to-adjusted EBITDA of 1x, both still at or below the bottom end of our long-term target ranges. Supplementing our strong financial position is the financial flexibility provided by our conventional programs. The scalability of these programs allows us to adjust capital expenditures as appropriate in periods of volatile commodity prices. With low oil sands supply cost of USD 35 to USD 45 per barrel, we're not making any changes to our SAGD development plans at current prices. Our 2012 guidance and 10-year plan remain on track. Our financial strategy also remains unchanged. Our plan continues to call for the investment of our cash flow to support our growth plans and oil production, while also providing a dividend to our shareholders. I'll now turn the call back to Brian.

Thanks, Ivor. Our low cost operations, financial strength and our refining assets position us well in the current environment and for the long term. 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 a meaningful dividend to our shareholders. With the regulatory approval now in hand at Narrows Lake, we have 10 more phases of SAGD oil sands growth ahead of us. This represents about 220,000 barrels per day net to Cenovus and essentially locks in our growth through 2017. John talked about the progress that we are making on our emerging plays. In our news release this morning, we also indicated that we have chosen to conclude the formal process of looking for a strategic partner at Telephone Lake. The process generated a tremendous amount of interest and confirmed the world-class scale of our resource. However, current industry joint venture activity is focused on near-term production and cash flow. I am happy to move forward on 100% basis, and I believe that Telephone Lake has the potential to be another cornerstone asset for Cenovus like Foster Creek and Christina Lake. Our team remains on track for a strong second half of the year and we look forward to achieving the remaining milestones we have set for ourselves to continue to build net asset value. The Cenovus team is now ready to take your questions.

[Operator Instructions] Our first question comes from the line of Greg Pardy from RBC Capital Markets.

Three quick ones for me. I'm just curious as to -- from a technical standpoint how you'll be approaching Telephone and just what timelines might look like? Second, just with respect to Christina, realization there surprised me as to how low it was in the second quarter, but I'm still curious as to what fraction of that has to do with the diluent cost versus the introduction as a crude stream? And the last question is, what was your expected recovery on butane to be as a solvent?

I think, I'll turn the first question about the development plant at Telephone Lake over to Harbir.

So, Greg, what we're currently doing at Telephone Lake is started our dewatering test over the next -- we'll be starting production on the water there in the next month or so. And so we're going to prove that up and we want to proceed with getting our application approved, we put that in December. We expect that to take about 1.5 to 2 years. We are currently doing feed engineering on that project. And so we're not slowing this project down. We're going as fast as we can, given that we don't have the regulatory approvals for that. But we will be ready to go once we do have the approvals in place and we're going to keep proceeding down the engineering route. So the timeline will be somewhere towards the end of this decade timeline. The other question that probably belongs to me is the butane recovery you asked about. So we have proven that we can recover butane in the 85% to 90% range. And so we need more than 80% to be accretive to SAGD. And so we've already seen that and proven that in the 3 pilots that we've done to date. So that's the end recovery. We expect it to be plus 90%.

This is Don Swystun, just replying on your oil price realizations. I guess a couple of things. Maybe we'll start with Foster Creek, as an example, we moved a good 2 shipments on Trans Mountain with Foster Creek and that provided an uplift to our price of about $6 to $7, so that joint looks quite good compared to Christina Lake. On Christina, through that entire period of the quarter, obviously prices were quite volatile both on West Texas and condensate pricing. With Christina, we'd probably sell about 70% of that as a new bitumen blend or CDB, and so you look at that -- probably the only liquid price you can try to match to that would be Access Western Blend in the marketplace, the other 30% of Christina we sell in a pool as part of Western Canada Select. So it gets a little difficult to set the price. But in fact, we did have some higher -- you're right, we did have some higher diluent charges in the quarter that led to a slightly lower price realization. But I think it is difficult to get the -- to try to match the market price on Christina based on the amount of purchases of condensate throughout that -- through the quarter.

In terms of how you market Christina, would you make any changes from the way you're doing it today or is it just something that just needs to settle out and it will eventually drift up with time?

I think that's -- what we're doing now, we've moved a lot of volumes to a number of different refineries currently. So both in the Midwest and even into the Gulf Coast, so we're getting more long-term clients associated with it. So we're working diligently on that. So I would expect, as time goes on, we would expect that the -- that CDB would move a little closer to Western Canada Select. I think on a market basis it's come down from -- initially, it was kind of pushing at that $10 discount to now more like $5. So it's come down a bit. I think we're going to continue to do that as obviously the volumes increase. It's trying to find good markets for us both in the Midwest and potentially in the Gulf Coast. We are sending a lot through the Wood River Refinery as well. That's actually -- we've come up substantially. So some of these are little higher asset number crudes. If you can run them, it's a great benefit to be integrated and run the CDB blend at Wood River in particular.

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

My question is around the steam oil ratio at Foster Creek. It seems like the implied steam oil ratio, once you backup the wedge wells, is about 2.4. So the question is, do you see this as starting to creep or you think this would remain in the 2.4, 2.5 type of range, Harbir?

So George, when we first designed Foster Creek, our instantaneous SOR after the first year, we designed it for a steam oil ratio of 2.5 without the new technologies like wedge wells and reborders and things like that. So you're absolutely right. Your math is right. So it's because of the wedge wells, we're sitting at about 2.1. We still do not have significantly any wells on blowdown and gas injections, so I expect once we start to do that, that would -- that steam oil ratio would steadily come down with time from the 2.1 to sub-2s. But really, the plan's working just as we expected. There's no negative things. It's all positive. And the other thing is -- that good key thing about Foster is because of these steam to oil ratios, you're seeing us ramping up our production volume on the future phases and having more optimization projects going in at a cheaper capital efficiency. So it's all good news.

[Operator Instructions] We are also now taking questions from the media. Your next question comes from the line of Jeff Jones from Reuters.

I just wondered if you could provide a little bit more on the Telephone Lake partnership search? What were potential partners unable to bring to the table for you?

I guess just to remind you in terms of our overall objective, this was never a financially driven process. This was all about bringing forward in time longer dated barrels and looking for something that adds strategic value to Cenovus overall. And in particular, that could potentially have been something to help perhaps manage light heavy differentials. One of the things that has definitely transpired over the last 18 months is the macro environment has changed substantially from when we began process. I think as you can clearly see by recent announcements that the market transaction or JV market, however you want to describe it, is now really focusing on near-term producing assets. There were occasionally some expressions about concerns over transportation outside the basin. I would say that we did receive several expressions of interest, bids, but overall, when we look at the combination of cash and what I would describe as strategic advantage, there wasn't what I would view, given the truly world-class into this asset, what I would perceive at this point to be compelling value. What I would say is that based on the drilling results that we have seen over this past winter season that we're really convinced we can create a tremendous amount of value for Cenovus shareholder by proceeding on 100% basis now. We're also in a position where with the Narrows Lake approval now in hand that we are turning our efforts on the regulatory side to approvals at both Telephone Lake and the Grand Rapids. And those approvals, just to remind you, the number will represent another net 270,000 barrels a day of production to Cenovus from those regulatory approvals. So we're now focusing on both Telephone Lake, Grand Rapids in terms of moving those projects through the regulatory queue. And we're in, I think, a very strong position because we've already got regulatory approval, as I mentioned earlier, for the next 5 years growth. And so we already got 220,000 barrels a day that we're currently moving forward in terms of construction and approvals.

Okay. So then, presumably, that would mean somebody with -- you would've, ideally, been looking for somebody with probably some refining and upgrading capacity along with a lot of patience.

Well, there could be a number of things that would be brought to bear that would distinguish some, but I think -- I've always said all along that just cash doesn't distinguish the successful joint venture partner. And I would say that over the course of the last 9 months, our view of this asset, as John Brannan mentioned, we're absolutely convinced this is going to be one of industry's leading projects.

Your next question comes from the line of Aaron Clark from Bloomberg.

Can you give a sense for how much the fall turnarounds at the Borger and Wood River Refinery, how much crude that will free up and where you might send it during that -- those 2 maintenance turnarounds?

So I'll leave that for Don Swystun.

Yes. One thing we do is obviously we're trying to take down the inventory there as we get into the turnaround time, so we will be building inventory. Some of that -- others will, other lines will course, we'll be moving some of -- if we can move off the West Coast, some are we're going to be moving to other PADD II refineries, as well as PADD III. We also continue to do realize Rio as well in terms of where we move our crude, but at the refinery, the biggest way to alleviate some of that is build inventory.

Can you give any just any color as far as how much -- you talk about how much the combined they ran in the second quarter, I mean, is that going to reduce it -- this turnaround is going to reduce it by 15%, 20%, 30%.

In both cases, yes, it'll -- through turnaround period, you will reduce substantially for a period of time. But it's -- it all depends on how fast you can get through the turnaround and how efficient and what you discover through the whole process.

Your next question comes from the line of Dan Healing from the Calgary Herald.

Brian, I'm just wondering if you could talk a little bit about what role the pipeline debates or the lack of clear pipeline takeaway capacity might have had in finding a partner on Telephone Lake?

I think the key item here has been the change in the marketplace and industry attitude towards near-term production and cash flow. It wasn't in the last quarter sort of driven any way primarily by transportation constraints. I would say that was more of an issue 6 to 9 months ago with some concern about it. But as I said, you can clearly see and based on some recent announcements that there is right now, a big focus on near-term production, near-term cash flow. And again, from Cenovus' perspective, this is not a financial-driven transaction. I see absolutely no reason why Cenovus would want to share any of our crude production volume. So I'm really quite excited about proceeding on 100% basis as we go forward here.

Does it change your overall target? I think you said earlier the target was 500,000 by 2021 net to Cenovus. Does that number go up now?

No. Currently, Telephone Lake is not in our 10-year plan. And again, that was one of the fundamental objectives was that we would bring the project inside the 10-year plan. One of the things that we will be looking at here as we continue to progress with regulatory approval and the pilot projects over the next couple of years, is building this big inventory. And for example, with regulatory approval on Grand Rapids, the Telephone Lake will would have about 500,000 barrel a day under regulatory approved project net to Cenovus by 2015. So that puts us in a really strong position to actively manage our own portfolio in terms of projects and pick and choose a timing on various phases. So that gives us just a huge amount of flexibility. And what I would say is stay tuned. I think you're going to continue to hear more good news on both Telephone Lake, Grand Rapids as we go forward.

Okay. And just so that I understand. Cenovus is committed now to doing it 100%. There's no chance of another partner emerging in the future?

We are focusing right now on moving to the regulatory process on 100% basis. I think it's fair to say that there are several parties in the data room that would really like to reengage, but I'm not going to open the process. Process is closed for now.

But it might be open later?

I can't comment on that, but we'll evaluate as we go through the regulatory process.

We have no further questions in queue. I turn the call back over to you, Mr. Ferguson.

Thank you for joining us today on our conference call. And that now completes the call.