2016 reserve replacement ratio 409%
Diamondback Energy (ticker: FANG) announced fourth quarter results and reserves Wednesday, reporting a net income of $26 million, or $0.32 per share. Full year results are a loss of $165 million, or ($2.20) per share. These results are far better than 2015, when Q4 and full year earnings per share were ($2.80) and ($8.74), respectively.
Proved reserves increased by 31% to 205.5 MMBOE, from 156.9 MMBOE last year. Crude oil represents 68% of Diamondback’s total proved reserves, with NGL representing 18% and gas making up 13%. Diamondback reported 2016 exploration and development costs of $376.7 million, making F&D costs $7.26/BOE. Net proved reserve additions of 64.3 MMBOE resulted in a reserve replacement ratio of 409%.
Brigham Resources acquisition to close in February
Additionally, Diamondback reported that the previously announced acquisition of Brigham Resources is proceeding on schedule, with close expected by the end of February. Diamondback expects to spend $800 million to $1 billion in 2017, to drill 130-165 wells. This drilling, combined with the Brigham acquisition, will fuel production growth of about 65% in 2017.
Diamondback is solely a Permian operator, and only has positions in that basin. In the Midland basin, where Diamondback has historically been active, the company is in the process of testing spacing pilots. The current drilling inventory represents a more conservative spacing assumption than peers, which means that success in downspacing tests has significant upside potential. After the close of the Brigham acquisition, Diamondback will hold 85,000 net acres in the Midland basin.
The acquisition of Brigham Resources will significantly increase Diamondback’s exposure to the Delaware basin. Diamondback will own 97,000 net acres in the Delaware after the acquisition closes. The company currently has one rig active in the Delaware, and expects to add another two in March. The company believes that its acreage in the Delaware has the potential to support 10 active rigs. While 2017 development will focus on the Wolfcamp A, the stacked plays provide significant future expansion potential.
FANG discusses rising service costs in the Permian
Q: The team mentioned a lot of times in their prepared remarks you’re baking in some level of service cost inflation at 2017 budget. Wondering if we can get any further quantification of what that is that’s baked in. And then maybe you could also tie that in with what are you guys actually seeing in real time, have we really seen the pressures start to build yet?
FANG CEO Travis D. Stice: Just mathematically, we’ve dialed in between a 10% and 15% total well cost increase starting in the first quarter. We’re not seeing that just yet. We actually believe that if oil stays kind of range bound between $50 and $55, the impetus behind service cost increases will be muted a little bit. However, if we continue to see commodity prices strengthen to that $55 to $60 a barrel, we believe that you’ll see these service cost increases start to accelerate in the back half of this year.
Now it’s not that Diamondback is going to acquiesce on these cost increases. We’re working diligently with our service providers and our business partners, like Mike had highlighted, to try to mitigate those costs. We know that for a healthy industry as we continue to build rigs in the Permian, we are going to have to have a service company that’s well-capitalized and ready to support increased activity. I think last week here in the Permian, we eclipsed 300 rigs and we’re adding anywhere between five rigs and ten rigs per week. And so if that pace continues, you’ll start to see some tightening.
So, we’ve not just opened our eyes to this phenomenon this quarter; it’s something we’ve been doing really since the back half of last year when all activity increased. And while we may not be insulated from all service cost increases, we feel like we’ve been proactive enough to be able to offset some of the service cost increases that we’re forecasting. So really, 10% to 15% on the total well cost, the drilling side, we’re not anticipating really much if any increase on the drilling side. All of that increase is really housed on the completion side, primarily under pressure pumping, which means we’ve dialed in a 20% to 25% increase. Again, we’re not seeing that today, but we are having conversations with our business partners that if activity continues to pick up and demand for those services continues to increase, to expect cost increases.
Q: Travis, just following up on the question just now on service costs. If they did accelerate maybe faster than what you’re anticipating, would you consider building DUCs?
Travis D. Stice: If you look at the returns that we have on these wells with those permanent savings that I just got through talking about, I don’t think that’s reasonable. I think you’d have to see a combination of rapidly increasing service costs coupled with a declining commodity price. I think that’s the only time we’d really start having that conversation again. You’ve heard me talk about dead capital or stranded capital. That’s not a good thing for our investors, and that’s what DUCs are. They’re at least deferred capital. And so as long as the industry moves sort of in lock step with an increasing commodity price, I don’t think it’s reasonable for us to start building our DUCs again.