Cenovus Energy Inc. (ticker: CVE) posted a net earnings loss from continuing operations of $914 million, or $(0.74) per diluted share for Q1 2018, compared to Q1 2017 recorded a net profit of $211 million, or $0.25 per share.
“The challenges we experienced in the first quarter had a significant impact on our financial results, but the underlying performance of our assets remains very strong,” said Alex Pourbaix, Cenovus president and CEO. “I want to stress that these financial challenges are temporary and don’t reflect Cenovus’s significant potential for funds flow and earnings growth.”
Due to market access challenges, the company said it decided to temporarily slow production at Christina Lake and Foster Creek in February and March.
Slowing down production
Steam Generators at Cenovus’s Foster Creek
“After a strong operational start to the quarter, we took prudent steps to reduce production volumes in response to wider light-heavy differentials, export pipeline capacity constraints and the slow pace of ramp up in oil-by-rail capacity,” said Pourbaix.
“When Canadian heavy oil is selling at a wide discount to WTI, we have the ability to slow our oil sands production while maintaining steam injection to mobilize the oil. We can then store that mobilized oil in our reservoirs to be produced and sold at a later date when pipeline capacity improves and differentials narrow.”
Addressing these market access challenges, Cenovus is working with rail providers to resolve a shortage of locomotive hauling capacity so that the company can more fully realize the benefits of its Bruderheim crude-by-rail facility.
Cenovus expects overall industry rail access to improve starting in the second half of the year. Should rail capacity improvements take longer than expected, or pipeline capacity tighten again, the company said it may take further steps to defer production which could result in fluctuating production volumes from month to month.
Combined production at Christina Lake and Foster Creek was 359,666 barrels per day during the quarter, nearly double the volume from the same period a year earlier. The increase was due to the company’s May 2017 acquisition, which resulted in Cenovus taking full ownership of its oil sands assets.
Oil sands operating expenses were $8.78/barrel, 2% lower than in the first quarter of 2017. Cenovus continues to expect full-year oil sands volumes for 2018 to be within its guidance range of 364,000 to 382,000 barrels per day.
Deep Basin produces over 125 MBOEPD
The Deep Basin program and initial well results have met or exceeded the company’s expectations. First quarter production averaged 127,056 BOEPD, with average operating costs of $7.36/BOE, an 18% reduction from the third quarter of 2017, Cenovus’s first full quarter of ownership of the assets.
Cenovus said it will take a disciplined approach to development in the Deep Basin, in response to lower natural gas prices. During the quarter, the company completed its 2018 Deep Basin capital investment program, bringing 17 wells on production, completing 16 wells and adding additional pipeline infrastructure – drilling 14 horizontal wells targeting liquids-rich natural gas.
New CFO
Earlier this month, Cenovus announced the appointment of Jon McKenzie as the company’s next CFO. He will succeed Ivor Ruste, who is retiring on April 30, 2018.
Conference call Q&A excerpts
Q: First question is on your production management strategy. Longer term, if we get to a wider differential scenario in the second half of the year, once we bypass this big industry maintenance, how much capacity do you have to execute on a strategy like this and how long can you maintain it without causing any reservoir issues?
EVP of Upstream Drew Zieglgansberger: So, this is the first time we’ve probably done this on a kind of prolonged period of time, like a month-and-a-half so to speak. We’ve obviously done this quite a bit when we had normal turnaround activity over the last number of years.
So, going forward here, we dial down upwards of 70,000 to 80,000 barrels a day here, over certain weeks. I think a comfortable range for us is probably better – closer to the 30,000 to 50,000 barrels a day, and – because then we can truly target different pad configurations in Foster Creek and Christina…
And so, with that we don’t see any fundamental risk in the reservoirs at all, if you just look at it from a month-to-month basis. And in that kind of volume range, we’re able to move to different parts of pads in different parts of the reservoirs to manage that type of volume for a longer period of time. But again, you’re only going to do this on a month-to-month basis in certain pads. But we think it’s a great new tool for us now to respond to different pricing environments and as did the markets move.
Obviously, we’ve proven to ourselves, and hopefully the market is realizing that, we have some elasticity here in production volume coming out of the oil sands and we’ve got a great tool now in our toolkit to use.
President and CEO Alexander Pourbaix: And just one comment I should add – when Drew is talking about that 70,000 barrels, he’s talking blend, as opposed to just pure bitumen.
Q: Alex, you have a unique perspective on takeaway and market access given your background. I’m just teasing your thoughts with the Enbridge Line 3 potentially, are you getting some resistance in Minnesota, with Trans Mountain in British Columbia… how does do you think this ultimately plays out? And from a differential standpoint, how do we think about the impact of IMO if, come 2020, some of these pipes aren’t online, particularly with some of the slippage that we’re seeing here in the U.S.?
Pourbaix: I’ll talk a little bit about the pipeline situation, and then I’ll let Keith to comment on IMO. But I think from the pipeline perspective, and I’ve said this from the start, I remain an optimist that ultimately most, if not all of those three major pipeline projects would go.
I think, clearly, a bit of a complication has been thrown into the Line 3 project with that decision from the administrative law judge. It’s a really big decision. We’re taking a look at it, and I know that Enbridge is taking a look at it, and I don’t understand at this point what their response would be.
But I would just say that the logic of replacing an old pipeline with reliability problems with a brand new state-of-the-art pipeline with state-of-the-art leak detection seems to be a very prudent thing for the State of Minnesota, and I hope that there’s a win-win resolution.
We’re obviously in the middle of a process with TMP and Kinder Morgan. I remain in close conversation with both Kinder Morgan Canada, the Alberta Government and the Canadian Government and I take a lot of comfort that I think those three parties are all very committed to finding a resolution that will allow that project to proceed, and once again, we’re just waiting to see where that gets to.
And then, on Keystone XL, it obviously continues to proceed, and I know the company is acquiring land on the new right-of-way.
So, I do ultimately believe that that project is going to proceed also. In the interim, as production grows in Alberta, we obviously are going to need rail to balance production and take away, and as I said in my remarks, there has been a bit of a slow start in getting this oil moving.
I think that is overwhelmingly attributable to the lack of spare capacity that the rail companies had when faced with this issue, probably earlier than I think everyone anticipated. But I’m really confident that as we move into the second half of this year and into the first half of 2019, we’re going to be seeing very material volumes of oil moving by rail.
And I would expect, once that situation prevails, we would expect to see WTI/WCS differentials probably persist in the high-teens being reflective of the cost of rail to get oil from Alberta down to the Gulf Coast.
But why don’t I have Keith just talk about the IMO issue.
SVP of Downstream Keith Chiasson: Just building on kind of Alex’s comments, obviously, Line 3 timing could then bring back in the differentials. So, if that gets pushed out past kind of the third, fourth quarter of 2019, we could see some pressure with regards to widened differentials associated with the rail transportation as well as the IMO coming in.
But specifically on the IMO, there are still a lot of questions with regards to the implementation and the response to the changing regulation. Whether or not refineries will have sufficient capacity or how much sufficient capacity they will have to increase coking utilization, how fast the shipping industry can respond to putting scrubbers on their vessels, as well as how well the regulations will actually be enforced and even if the timing of the regulations sticks to the 2020 implementation.
So, still lots of unknowns. We are obviously watching that space. We do have our heavy oil integration with our Wood River and Borger refining capacity. But we’d also look at do we want to bring new production growth into that market if we start seeing kind of Line 3 deferred and delayed, as well as kind of the IMO impact coming.
Q: My follow-up question is, as you think about rail and the negotiations that are going, recognizing those commercial sensitivities – what do you think are really the stumbling blocks in terms of getting this to the finish line, it is conversation around margin, it is conversation around duration?
Pourbaix: I’ll kind of maybe talk at the strategic level and Keith may provide some color on specifics. But my perspective on the rail, I have been closely involved with Keith in dealing with the rail companies really for the better part of a few months now.
And my experience with the rail companies, and I might have said this earlier, but I don’t detect there is any philosophical concern on the part of the rail companies about moving the product. I think they feel that the last time they ramped up their capacity to move oil, I think they felt they spent a lot of time and resources and then they lost that business in very short order once the pipeline solutions became available.
So, I think I’m not surprised nor distressed by the pricing that we’re seeing. I think it is – I think we’ll be able to achieve fair pricing. I think that there is going to be some term to these deals to deal with this issue that the rail companies have.
And I think there is going to be – they’d probably desire to have some element of take-or-pay, which might have been lacking in the past. So – but I don’t – as I said, I mean our discussions with the rail companies are very productive.
From our perspective, I mean, we really see the importance of getting a rail deal more towards the end of this year, and that’s where we’re targeting to start seeing our barrels move by rail. But there is – I’m not seeing anything that is significantly worrying me that we’re not going to be able to achieve that goal.
Chiasson: We’re actually starting to see increased rail capacity happening in our conversations with the heads of the two rail companies. It’s evident to us that they’ve hired the crews. They are just going through the training process now to get them competent and capable.
They’ve indicated that they’re reactivating a fair amount of locomotives. So, we do see that capacity picking up. There is a fairly heavy turnaround activity happening in the province, and with the new coker startup – upgrading startup this year as well.
We do see the timing for that rail deal to be in the fourth quarter as being more necessary, and we’re taking a very disciplined approach to make sure we get the right deal for us and the rail companies.
