Oil and gas heavyweights Noble Energy (ticker: NBL) and Occidental Petroleum (ticker: OXY) discussed operations today in their second quarter earnings calls.
Noble Eagle Ford production up 60% sequentially
Noble Energy (ticker: NBL) announced a net loss of $1.5 billion, or $3.20 per share. This loss is primarily due to the company’s $1.225 billion sale of its Marcellus upstream assets, which closed in late June. After adjusting for this and other special charges, the company earned $24 million in Q2, or $0.05 per share.
Total production was 408 MBOEPD, up 7% from Q1, driven by 60% growth in the Eagle Ford. Noble reports that it has achieved a record for sales volumes in Israel, 962 MMcfe/d, where the company recently approved additional offshore gas development.
Q: Sales volumes didn’t drop off sequentially in 2Q. I mean, do you think we’re actually seeing those, or you’re seeing those secular Israeli demand trends now? And related, any color on the progress towards adding additional Leviathan gas sales agreements and progress on the exports?
A: Well, I think as you elude to, Evan, we really are seeing that demand increase showing up. You look at it quarter-on-quarter, second quarter this year versus second quarter of last year. I think as far as ongoing contracting, we’re making great progress. I think in Israel as we talked about, as they continue to push more power generation from coal to gas, that’s helpful and those discussions.
And then also just in addition, that now as a result of us having sanctioned Leviathan, they’re now in a position where they’re more comfortable sanctioning their own projects that will use more gas. I think on some of the regional discussions I think they’re progressing nicely. I think the combination of those things is what gives me confidence that we’ll, as I’ve said before, we should have solidified a Bcf a day or so by the time Leviathan comes on production.
Wider stage spacing, higher intensity completions
Q: On the DJ completions, I wonder if we could go back to a theme that is part of the 1Q call and look at these new completions that have really just continued to expand versus your type curves. Do you guys have any more developed sense now than you did a quarter ago on what you’re seeing here as far as acceleration of reserves versus incremental EUR?
David L. Stover: I think it’s probably fair to say we have a better sense and I’m not sure it’s fair to say we have a good enough sense yet that we’re commenting on it publicly yet. But I think we continue to watch these higher-intensity jobs. As you know, we had moved to 1,800 pounds per foot as our standard job in the DJ which was higher than we had historically pumped and we’ve tested some jobs higher than that.
We had put out some results on some Wells Ranch wells I think it was last quarter that were as high as 2,500 pounds. And we’ve got plans late this year to test some additional wells higher than our standard jobs. So we’re continuing to gather data. Some of those wells have still been on kind of six to nine months at most. And so we’d like to get a bit more data to really feel comfortable with where we’re at. But got to say I haven’t seen anything that discourages me yet.
Q: Back to the DJ. You mentioned – I think you mentioned wider spacing on some of these completion techniques. Can you just walk me through what that accomplishes? I know the cycle time’s quicker. But were you getting – were the, I guess, the cluster’s too tight before? Can you just talk about that process?
Gary W. Willingham: Yes. David, this is Gary. We haven’t actually changed the cluster spacing, we’ve just been testing wider stage spacing. So you can still have the same cluster spacing, the same effectiveness of the frac, frac it with the same efficient but have wider stage spacing, then you can reduce the cycle time, the completion time of the well quite a bit. So we’ve tested some of that. We like what we’ve seen so far. I think we need to see a bit more data to convince ourselves that that’s something that can be repeated. But if it is a situation where we can have the same number of clusters, the same cluster spacing, the same efficiency of fracking those clusters but with wider spacing and shorter times and less cost, then that’s obviously something we’re going to continue to pursue.
Oxy talks Permian technology
Occidental Petroleum (ticker: OXY) announced net income of $507 million, or $0.66 per diluted share, up from the $117 million in income from Q1 2017 and the $139 million loss in Q2 2016. The company reports 601 MBOEPD of production in Q2, compared to 584 MBOEPD in Q1.
Oxy announced a shuffle of its Permian basin assets in June, with a series of transactions totaling $1.2 billion. The company increased its interest in several CO2 source fields, and tertiary recovery oil operations. This trade has given Oxy the opportunity for a significant amount of oil at low development costs, as the company reports that it added about 100 million barrels of resource potential with less than $6/BOE future development cost. In total, Oxy’s enhanced oil recovery operations in the Permian have over 1 billion barrels of resource potential with future development costs below $6/BOE.
Q: Couple of questions on the Permian. You highlighted the shift in – the coming shift in rigs into New Mexico. And wondered if you could talk a little bit more about the decision to do that and the implications on the returns there versus the returns elsewhere in the Permian portfolio like the Southern Delaware and Midland basins. And also given that it’s topical, can you speak to how you see the risks associated with navigating drilling horizontal wells around areas where there are legacy vertical wells particularly in the Midland?
A: Yes. Brian, the reason for the shift to New Mexico is really kind of grounded in our capital intensity calculations. New Mexico, because of the stacked pays and very good stacked pays. It’s not like you have a primary bench and then three or four secondaries. There’s three or four primary benches that compete very well, very high returns. And so it’s that nature that drives us toward more New Mexico. Kind of second in the tier would be the Texas Delaware and then Midland basin. I mean, they’re not – those two aren’t that different, but they just have different production profiles with the wells as we drill them. That’s why we’re more dominated with our activity set over on the Delaware side.
The risks of drilling with vertical wells, a lot of the areas we’re developing are not historical vertical development or they were done in a way that you still have a lot of room between those vertical wells for not having any collision areas. A lot of our New Mexico development that we’re going to is clean acreage and very little historical development, and if it was, it was in shallower reservoirs. We’ve got a long history of this. You’ve got to remember, we’ve been in the Permian for a long time at 25,000 wells, a lot of experience dealing with both vertical and now horizontal activity.
We’re doing more horizontal activity in our legacy EOR properties and on the central base and platform. So it’s something very manageable for us, and I think the properties that we have set themselves up well for continued horizontal development.
Q: And then on the technology side, can you give us an update of some of the technology solutions that you’re deploying such as I think multilateral wells, one that you highlighted in the past? And if there’s more to say on some of the predictive analytics slide than you already said, that would be great. But, specifically, what the impact is on production or capital costs today?
A: Yes. I mean, we’ve got a great – a number of slides in the appendix that lays out the different projects that we’re working. We’ve made a lot of progress here recently in one around reservoir management of our injectants. So both in Ken’s business in Mukhaizna with steam and then Northern Oman with the water flood. And then in our EOR business with C02 floods, we’re deploying kind of the early versions of those tools that combine, essentially, low-fidelity reservoir models with the statistical models so that we can make changes in where our injectant goes on a greater frequency.
And so what that does is, it allows us to get the biggest bang for the buck for every molecule of injectant that we put in the ground. So those are starting to get rolled out. And from a technology standpoint, that’s all being done in the cloud. So from an IT standpoint, we’re able to do this work from Oman all the way back here to Houston. And again, that’s our starting point, but that technology applies to all three geographic areas.
On the drilling side, we’re pushing out our bit trajectory data analytics tools. So we’ve been through our earlier round of validating where the bit is based on surveying equipment being 45 or 60 foot behind the bit. That’s now starting to – will start beginning to get penetrated across multiple rigs. And what that does is it, again, it keeps you in zone. It allows you to build your curves more accurately because you know where you are instead of projecting where you are. And that results in better wells if you stay in zone longer. So that’s a couple of examples, but there’s a long list that we continue to push forward on the technology front.
