Permian production breaks two-year record at 178 MBOEPD
Apache (ticker: APA) announced fourth quarter results and reserves on Thursday, showing net earnings of $456 million, or $1.19 per diluted share for the quarter. Apache earned a total of $1.3 billion in 2017, marking a return to profitability for the company.
Apache produced an average of 440 MBOEPD in Q4 2017, down somewhat from the 490 MMBOEPD the company produced in Q4 2016. This decrease is entirely due to the company’s sale of its Canadian properties, which it announced in July. Excluding these divested properties, Apache grew production slightly, by 1% year-over-year.
This slight overall production growth masks the significant increases Apache has seen in the Permian, where production grew by 10% from the last quarter. At just under 178 MBOEPD, Apache has set a new record for production from the basin, surpassing the company’s previous high set in Q4 2015.
Source: Apache Investor Presentation
$8.5 billion in spending over next three years
Apache plans to spend $3 billion in 2018, up from the $2.76 billion the company spent in 2017. Over 70% of this spending will be poured into the Permian, and $500 million will be spent expanding the Alpine High midstream system. The company expects this will generate about 10% adjusted production growth overall, and 9% Permian oil growth.
Apache also unveiled its three-year outlook, discussing longer-term capital and production plans. In total, Apache plans to invest about $7.5 billion in its upstream assets worldwide and $1 billion in midstream at Alpine High. The company estimates this will yield an annual production growth rate of 12% worldwide, and 27% in the Permian. Apache estimates its capital investment program will generate Cash Returns on Invested Capital (CROIC) of 18, 20 and 22 percent, respectively, over the three-year period.
Apache reports it now holds 1.2 billion BOE in reserves, down from 1.3 billion BOE last year. This decrease is primarily due to the Canadian sale, as the company replaced 124% of production through extensions and discoveries net of engineering revisions. All sources F&D costs were $11.89 per BOE.
John J. Christmann IV, Apache CEO and President, commented “We have been clear in our belief that an E&P company, over the long term and through the commodity cycles, must be able to do the three things that leading companies in mature industries do, live within cash flows, grow the enterprise through prudent investment, and return capital to shareholders through a competitive dividend and/or share repurchases. This is the path that Apache is on now.
“Our current investment programs are directed at building the optionality over the next few years to maximize the value of that portfolio. Specifically, at Alpine High we are building out a world class resource play that will change the course of Apache.
“The expanse of the opportunity in terms of acreage and hydrocarbon column will drive capital investment and very soon, free cash flow for decades to come. The capital program in short order will bring forth the capacity to deliver oil, gas, and NGLs at scale to the rapidly growing market on the U.S. Gulf Coast.
“The midstream infrastructure capital program at Alpine High is a critical piece to the story for the near term. We must strategically control the build-out of the infrastructure to meet the needs of the upstream. We do not need to own 100% of these assets for the long term though. And we are studying strategic alternatives that will ensure we capture the value we are creating and will free up cash flow by eliminating future capital.”
Q&A from APA conference call
Q: Question on the U.S. non-Permian, non-Alpine High. If I kind of take your guidance and back out what it implies for U.S. non-Permian, it’s kind of under-investment, like a decline. If I look at the Permian outside of Alpine High, it looks like you guys basically keep it flat through 2020. Is that about right?
John J. Christmann: When you look at the capital program with where we are today, Bob, yes. We are spending very little outside the non-Permian capital. I think you’re actually going to see though, that it’s – with the investment that’s come off of the last three years, it’s not going to decline a whole lot. In fact, our Mid-Continent stuff will actually grow with just the five wells we brought on in the SCOOP this year. So we’re in a pretty good spot there. But, yes, very little capital there for 2018.
Now as we get out past a couple of years and we start generating a lot of free cash flow from Alpine High, we see that changing quickly. And so we like having the optionality there in those assets.
And right now in the other Permian, it’s close, a little more than maintenance. But it’s really more designed at going at the right pace there. As I mentioned too in the Midland Basin, I mean we’ve shown – if you look at the results, the back half of 2017, as I mentioned in the script, we peaked in the fourth quarter of 2015. And then we really shut the programs down, reset the cost structure. Bottomed second quarter of last year. And then quickly in a matter of two quarters made a new production high.
So really it’s an off/on switch. It takes a couple of quarters. But it shows you the quality and the progress that we’ve made in terms of being able to apply that capital to the other Permian assets.
Q: And if you have those assets that other people would voraciously drill, at what point do you say that those belong in somebody else’s hands? Or to your point, do you keep them for future optionality?
John J. Christmann: Well, we just have to weigh the value of that. I mean we look at the portfolio. We work the portfolio very hard. Last year we made a strategic decision to exit Canada, which we’re very glad we did. I think one of the things that gets lost in there is that we eliminated $800 million of ARO, but that was a big strategic decision for us.
We also unloaded some acreage that we felt like we got some very – prices for. And is exactly that. Something that somebody placed a high enough premium on that we felt like it would be better in their hands. So you’re always looking at those things and weighing those things. And we continue to do that in the future.
Q: On the multi-year plan, you mentioned the 10% service cost inflation. Can you talk through some of the other assumptions, specifically what commodity prices you’re underwriting? And if you’re including any expected efficiencies or productivity improvements?
John J. Christmann: On the service side, yes. We have most of our big ticket items – rigs, frac crews, sand – under contract and tied up for the foreseeable future. So we feel good about the main services.
But we are seeing the smaller things that drive the day to day, trucking, simple as the backhoes, pads. Everybody is wanting to raise costs everywhere. So we did bake in, in general, a 10% rise. Now when you look at some efficiencies at – and then we kind of took each play, play by play. As Tim told you, in 2017 we were able to reduce our Midland Basin well cost by 20% on a treated lateral foot basis and increase productivity by 17%.
So we’ve taken those kind of play by play into account. The greatest efficiencies we’ll see at Alpine High is we’re early in that play and really starting to move into pads. And then less in the more mature plays, where we’ve drilled more wells.
And so we’ve got a pretty conservative forecast on the capital side going into this year. And what I don’t want to be is in a couple quarters, having to raise my capital, because I assumed that we could keep things down when the reality is there’s a lot of pressure out there on a lot of different fronts.
Q: I appreciate that detail. And then I guess on the commodity price assumptions through the three-year timeframe. Just trying to get a good sense of what’s under-written, when Steve talked about cash flow neutrality and the upstream piece this year, for example, and just how that might evolve over time.
Stephen J. Riney: So obviously, there’s lots of conversation out there today about cash flow neutrality and pricing assumptions and what pricing assumptions people ought to use. And obviously I think that the last few years have demonstrated how important we believe cash flow neutrality is. And we’ve said that many, many times that we ought to be able to live within our means.
I think it’s important that we actually acknowledge there are lots of different definitions out there about cash flow neutrality. There are lots of different methods that people use to talk about that. Some include dividends, some don’t include dividends. Some actually go so far as to include asset sales. And some have some capital structure changes, all contributing to cash flow neutrality.
Just to be clear, we take a very, maybe extremely pure approach, because we believe cash flow neutrality means that with no asset sales and with no changes to debt or equity, that you should end the year with the same amount of cash on hand that you began the year with. And that’s a very pure definition. I’m not sure there’s a more accurate definition of cash flow neutrality. If there is, I’d like to know what that is.
So with that said, our plan for 2018 and beyond, what we talked about today around – or I talked about around 2018, is so the midstream is obviously operating at an out-spend, about a $500 million deficit. That doesn’t – that’s regardless of what price assumption that you might use. And there’s obviously – there’s some reasons that some of that might go away.
And what I talked about is that the upstream, which is everything else in Apache, including dividends, that that would be cash flow neutral at current pricing is what I said, which is about $60. $60 $61, WTI’s current pricing I believe, unless something’s happened on the call.
So we would be cash flow neutral at around that type of price assumption. We believe we could also be cash flow neutral down into the upper $50s. We’re working on a number of things that could help us do that.
In terms of pricing in our plan, we’ve actually run numerous price scenarios, all of them lower than $60. We’ve reviewed many of these with the board. And just a couple weeks ago, we actually agreed our plan for this year with the board, and that was at a price of $58 WTI. Obviously at that price there would be a small cash flow deficit in the upstream to go with the midstream deficit.
And I think that – I think with the information that we’ve now provided around the plan and with the supplement around price sensitivity, around the hedge positions, we’ve given you lots of details. You understand cash flow sensitivity relative to movements in oil price or gas price. You see the details on our hedge positions, which obviously affect cash flow sensitivity as cash flow – as price moves down.
And I think – so I think most of the data there, to meet any modeling requirements that you might have, to understand how cash flow changes as commodity prices move up or move down.
The only word of warning that I would give you on that is that if you start moving too far off of this, our plan at $58 or current pricing at around $60, you start moving too far off of that either to the upside or the downside, then the current plan, all of the other elements of the plan actually begin losing relevance. Number one, we have our hedges in place, so you’ve got that.
Number two, I think the simple math on cash flows due to price isn’t really adequate. Because when you start moving well below that $58 or $60 current pricing or well above it, then all of the other assumptions inherent in the plan begin to change. All of the things around cost inflation assumptions that we’ve made, the actual activity set that we would engage in, the actual capital allocations that we would make, all of those change as you move far off of that plan.
So we set ours at – we set the plan with the board at $58. And we think that’s actually somewhat irrelevant. The current pricing, $60 to $61, we would be cash flow neutral in that upstream or everything outside of the Midland – or the midstream, which is about a $500 million deficit.
