Bonanza Creek Energy, Inc. (NYSE:BCEI) Q4 2018 Earnings Conference Call February 28, 2019 12:00 PM ET
Doug Atkinson - Senior Manager of Investor Relations
Eric Greager - President and Chief Executive Officer
Brant DeMuth - Executive Vice President and Chief Financial Officer
Dean Tinsley - Senior Vice President of Operations and Engineering
Conference Call Participants
Irene Haas - Imperial Capital, LLC
Welles Fitzpatrick - SunTrust Robinson Humphrey
Phillips Johnston - Capital One Securities, Inc.
David Beard - Coker & Palmer Investment Securities, Inc.
Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2018 Bonanza Creek Energy Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will be given at that time. [Operator Instructions] As a reminder, this conference is being recorded.
It is now my pleasure to introduce Senior Manager of IR. Mr Doug Atkinson. Please go ahead, sir.
Thanks, Andrew. Good morning, everyone, and welcome to Bonanza Creek's fourth quarter 2018 earnings conference call and webcast. On the call this morning, I'm joined by Eric Greager, President and Chief Executive Officer; Brant DeMuth, Executive Vice President and Chief Financial Officer; and Dean Tinsley, Senior Vice President of Operations and Engineering.
Yesterday evening, we issued our earnings press release, posted a new investor presentation and have filed our 10-K with the SEC. All of which can be accessed on the Investor Relations section of our website. Some of the Slides in the February investor presentation may be referenced this morning during our prepared remarks.
Please be aware that our remarks will include forward-looking statements that are subject to many risks and uncertainties that could cause actual results to differ materially. You should read our full disclosures as described in our 10-Q, 10-K and other SEC filings.
Also during this call, we will refer to certain non-GAAP financial measures because we believe they are good metrics to use in evaluating performance. Reconciliations of these measures to the most directly comparable GAAP measures are contained in our earnings release and investor presentation.
We will start the call with prepared remarks and provide time at the end for Q&A. Now it is my pleasure this morning to introduce Eric Greager, President and CEO. Eric?
Thanks, Doug. Good morning, everyone. 2018 was a good year for Bonanza Creek, as we realized a number of key wins for our business. Let me run through the highlights. The sale of our Mid-Con assets allowed us to focus on and accelerate value creation in Wattenberg while maintaining very low debt.
Improvements in our cost structure helped reduce our unit LOE from $6 per BOE in the first half of 2018 to $3.27 per BOE in the fourth quarter. Improvements in completions, design and execution, resulted in significantly better well performance and has carried into our updated type curves.
We reinforced our balance sheet with expanded credit facility and more than $300 million in liquidity at year-end 2018. Our current development plan has exiting 2019, with approximately half a turn of leverage. Our Wattenberg year-end 2018 proved reserves, increased by 29% to a 116.8 million BOE, with an SEC PV-10 of $955 million. The PV-10 of our PDP at a mid-February strip is approximately $480 million.
We connected our fourth gas processors at Rocky Mountain Infrastructure, further enhancing our downstream optionality. Throughout 2018, we experienced no constraints or delays. We are currently building out an oil gathering pipeline to Riverside terminal, which will lower our oil differentials by up to $1.50 per barrel starting in late Q2 2019.
We successfully delineated French Lake and are moving forward with our partner to build out the necessary gathering infrastructure and we anticipate drilling in early 2020. We continue to be encouraged with the results of our higher density well spacing pilots in legacy west. This has the potential to meaningfully improve resource recovery, while maintaining well performance. We plan to continue applying our learnings in 2019.
Our technical and operational momentum translated to the bottom line as adjusted EBITDAX increased 97% from Q4 2017 to Q4 2018. I'm also pleased that we've rounded out the management team with the recent addition of Brant DeMuth, as the CFO. As well as adding a Chief Geologist have continue to reinforce our technical and operational capabilities.
We believe that pieces are in place for continued success. In 2019, we will remain focused on operational flexibility, so we can swiftly and prudently respond to market conditions. Our CapEx budget of $230 million to $255 million is down roughly 15% compared to 2018. Drilling and completions CapEx of $210 million to $220 million, will provide for 59 gross drilled wells and 45 gross wells turned to sales.
Our focus in 2019 will be in our legacy west and central areas, where we plan to apply higher intensity designs compared to 2018. Our plan also contemplates approximately 10 wells in progress as we exit 2019.
We are guiding for production growth in excess of 30% in 2019, while exiting the year with leverage of approximately half a turn. Our 2019 plans lay the groundwork for continued production growth in 2020 of roughly 20%, while maintaining a strong balance sheet with leverage of less than one turn. Please see our investor presentation for more details.
Before we go to Q&A, I want to hand the call to Brant for two quick updates. Brant?
Thanks, Eric. Good morning, everyone. I do want to highlight two quick notes as it relates to our financial statements. First, our fourth quarter numbers were impacted by very minor post-closing adjustments associated with our Mid-Continent divestiture. For example, fourth quarter production included roughly 10 barrels per day from that asset.
Second, the Company received a $7.4 million gross ad valorem tax settlement during the fourth quarter. The severance and ad valorem tax expense shown in our 10-K, includes an estimated net amount, after taking into account the impact of prior period tax credits owed to various interest owners. There is additional information in our 10-K concerning this settlement, but I wanted to highlight it as a non-recurring benefit to 2018's overall production tax rate.
And with that Andrew, can we please open it up to Q&A.
[Operator Instructions] And our first question comes from the line of Irene Haas with Imperial Capital. Your line is now open.
Good morning, everybody. Yes, hi. So it looks like you have really a nice plan laid out for 2019 and with Rocky Mountain infrastructure adding an oil pipe, and you know with this outlook and operating on the ground, do you feel sort of any difference now that the new regime is in place, just operating where you're operating, be it permitting, speed of permitting or just a little color as to how it feels on the ground as a producer.
Yes. Thank you, Irene. The events leading up to November of 2018 were tough. It generated a lot of uncertainty in the industry. Things certainly have gotten better in terms of the mechanics on the ground as a result of the failure of Proposition 112 in November. However, there still is a pretty decent backlog and it just requires a decent backlog of permits at the COGCC, and this just requires plenty of planning and good diligence on the ground.
I think if operators have good plans and good contingencies, then we will all continue to operate effectively in the environment. But it has remained just a little challenged in terms of COGCC permitting clearance. But I know those guys are working real hard, it's just quite a lot of backlog moving into that vote.
Things continue to work pretty well on the ground, particularly for Bonanza Creek, as we have the Rocky Mountain infrastructure in place without constraints. The 1-rig program is a level-loaded operation and as far as we can see in the 2019, things feel very solid. The operations continue to gain efficiency turn by turn. So we feel very good about that.
How many permits have you secured right now in hand?
We have about a 100 permits right now in hand and that would include permits that we've got leading up to Proposition 112 and then permits that we've gained since. It also includes some permits that maybe in process, but we feel are far enough through the process that it's something we can pretty well count on. There is always a little bit of gray area, because there are a number of stage gates you have to work through with the COGCC, but when they work their way through that process, we tend to start counting them as complete because they are far enough out in our schedule to be effectively complete.
Great. Thank you.
Thank you. Appreciate that Irene.
And our next question comes from the line of Welles Patrick with SunTrust. Your line is now open.
Hey, good morning.
Good morning, Welles.
Good morning, Welles.
Congrats on the quarter. French Lake, it seems to just be continuing to really outperform expectations. Is there any chance that you partner and you all could decide to accelerate that in 2019, and if so, would that be additive to CapEx or do you think you'd offset it with something else?
Yes, it's a good question Welles. Thank you. I'm going to answer that in two parts. It sounded like a two-part question. The first part is I don't expect that we'll be able to accelerate it very much. There is a number of moving parts around design and construction of the gathering system.
And once you get, you get the two companies in a partnership having agreed on a plan in the budget year, it's a little bit difficult, particularly with the kind of difficulties we had there in Q4 in terms of commodity price to move that on a relatively short fee. So I do anticipate the gathering system build out will move according to plan through 2019 and we'll be picking up a rig and starting drilling in early 2020. But I don't anticipate that it's going to accelerate much.
Okay. That makes sort of sense. And obviously you guys have the 2019 guide out. Can you maybe talk a little bit, the kind of exit to exit or 4Q to 4Q, just kind of help us modeling how that flows through the year?
Yes, in terms of the production profile, I presume is what you're speaking to?
That's right, yes.
Yes. Yes, so the way we're thinking about this is, if you look back at 4Q 2018, we invested about $100 million in CapEx in 4Q 2018 and you would anticipate that begin to show up in kind of the sequential quarter and in fact that's about what we're expecting.
We're looking at 1Q 2019 mid-teens growth over 4Q 2018 and then you can expect that to begin to decelerate kind of in Q2 and decelerate down into maybe mid-single digits, sequentially, Q2, Q3 and Q4.
And then of course as we pick up the half of net rig in French Lake in early 2020, you would anticipate that beginning to build again, but most of it – most of the results of that continuing drilling and completions investment in 2020 rolling on into 2020, basically into 2021 as you see more of the production uplift flow in. Is that kind of get at the question?
Yes, that's great detail. That's perfect. And I might just sneak one last one in here. I know you guys are more plugged in most up there, almost a follow on to Irene, but any thoughts on what we might expect from the omnibus bill? I mean obviously there's been some [indiscernible] media reports out there?
Yes, the conversations, I have with peers and others in the trade groups seems to indicate to me that we can expect maybe two dimensions to an omnibus bill. It's always a little risky to speculate on legislation, while it's still pending. But there seems to be two common themes in all the conversations that I'm having with peers and others.
The one element is around the COGCC posture and maybe nuance changes to the language of the Act. I think there's going to be perhaps a little less emphasis on fostering of oil and gas development in the mission of the COGCC and perhaps a little more emphasis on balancing development of oil and gas resources with the impacts on the community vis-à-vis environmental safety and health.
That as you recall, was the key pillar to Colorado Rising's arguments leading up to Proposition 112. And so that also flows into kind of the second element, we would expect to see and that is an element of local control.
And we think that local control is going to have a sub part to it, that probably allows for very small municipalities to opt out and defer back to the COGCC because it's a sophisticated agency with lots of technical and on the ground expertise and a lot of these small communities, 1,000, 2,000, 5,000 people, they just don't have the resources for undergoing significant and/or sophisticated citing evaluations.
So I would expect those kind of two or three major parts to come out. But again it is a little risky because it's not out yet and it may still be undergoing modification, but that's what I'm hearing now.
That's wonderful, very helpful as usual. Thanks again.
Thank you, Welles.
Thank you. And our next question comes from the line of Phillips Johnston with Capital One. Your line is now open.
Hey guys, thanks. I wanted to ask you about your oil mix. It crept up to 62% in the fourth quarter, which I think is the highest spend since late 2014. I think your guidance for this year, calls for 76% liquid mix, but I am wondering if you could give us some color on the expected oil mix for the year on average as well as how that might trend throughout the year?
Yes, thanks Phillips. It's a good question and we benefited particularly in Q4, but throughout 2018 from the reservoir pressure management system that we've put together, you hear us refer to this in a number of different ways, but essentially what we're doing is, we have essentially a pressure flow and composition dashboard, that we tune into essentially every day and we used that dashboard to manage moment to moment reservoir pressure.
So we hold back the reservoir to ensure, this is a solution gas drive environment and in solution gas drive environments, you want to ensure that you get as much benefit from the gas, that is very deep within the reservoir to sweep as much oil as you can out before you have delivered the energy. So you want to make sure, every unit of solution gas drive delivers as much oil as possible.
And as we continue to evolve that control dashboard and continue to see better performance, we implement those practices back into the business. So that's really is the enhanced recovery flow back or managed reservoir pressure practices that is resulting in that higher oil yield. And it also results in better well performance across the curve.
So that's one of the things that both benefits early time oil yield, but also long-running oil performance in conjunction with greater SRV, stimulated reservoir volumes and better fracture complexity and so on. These things all work hand in hand. In terms of 2019, what I would expect is continue to carry forward these improvements.
It's a percentage point or two, but it's pretty meaningful with the value differential between oil and the other commodities. So what I would say is between 60% and 62%, to continue to carryforward in 2019 and beyond, but we're going to do everything we can to continue the upward pressure on those yields.
Okay, that's really good color. Thank you. And then last year you drilled, I think 36 more wells when you completed. I think this year, the plan is to drill about 40 more wells, then you turn to sales, and I think you're exiting the year with a DUC inventory of about 40 to 45 wells that seems to be fairly high, just given that you're only running a 1-rig program.
So my question is what do you consider to be a normal amount of inventory there? And as we look out to 2020 where you expect around 20% production growth. I know that assumes of 1.5-rig program, but does it assume that the DUC inventory is drawn down at all?
It really doesn't make an assumption on deliberately drawing down the DUCs. And I would say as a corollary to that, we're not deliberately building DUC inventory. What we're doing is maintaining flexibility. We want to maintain a highly efficient level loaded drilling operation because we think that's the best way to carry through, when you pair that against a pretty solid hedge book, you've got efficient operations on the capital side and you have got a solid hedge book on the commodity side. And you pair those up well and then you build as much efficiency as you can into your operational practices, then we think that results in the best performance.
So on the one hand; it's a continuous 1-rig program. We think that yields level loaded efficiency. In terms of turning wells to sales and in particular stimulations, what we're doing is looking for – at any given point in time the maximum efficiency. So at some points in our program, there will be gaps where we won't have a crew at all, frac crew. At other points will have one because one pad is ready and all the stars line up in terms of capacity around the system in CPF upgrades and facilities and all the rest and we'll accelerate that stimulation through.
In other cases we may have two pads and we may bring out two frac crews and we may stimulate two pad simultaneously with two frac crews. And again it's around managing our efficiency and maintaining just as high efficiency as we possibly can. And that is really a theme that we pushed throughout the entire organization, whether we're talking about work overs and well interventions or we're talking about managing capital allocations and capital deployments over time. It's less about a deliberate DUC plan and more about maintaining flexibility so that we can be as efficient as possible with our CapEx.
Okay, makes sense. Thanks.
Thank you. [Operator Instructions] Our next question comes from the line of David Beard with Coker & Palmer. Your line is now open.
Thank you. Good morning, gentlemen.
Good Morning, David.
Just a question, a little bit bigger picture on the regulatory impact. First, do you noticed any difference in the actions between your big company neighbors and some of the smaller companies with regards test activity with the regulatory overlay?
That's a great question. We sit with the big operators at COGA, sit on the Board of Directors at COGA and in terms of their interests and our interests they're perfectly aligned. They're great people. They're very smart. They bring a lot of resources. We don't see much difference in the way they're looking at the surface, political and cultural environment from – in terms of correlation between size of the company.
Where we do see the difference is, in terms of their exposure to – for example, lots more municipal or urban exposure versus a lot less, for example Bonanza Creek has no overlapping municipalities with our acreage. And so, that really seems to be where the difference is in the way companies view their posture.
But one of the things I was really pleased to see was the solidarity leading up to November and the vote, and really that's solidarity and alignment of interest has carried through right up to today. When we have these conversations, there is not much bifurcation between the companies. It's really a strong alignment of interests and solidarity within the companies to ensure that we do as good a job as we possibly can, because we think that's going to allow the industry arrive at the right outcome.
Okay. That's helpful. And then, a follow on would be relative to the M&A environment into some of this overhang, shake some property loose or at least create more discussions relative to M&A, small parcels, big parcels?
Yes, that's a great question. It does both. It increases or encourages more activity because there is more pressure, right. People are more perhaps under more pressure to act, when the multiples are depressed the way they are today in the DJ. And that's largely a function of the political and cultural overhang.
The problem is, it's difficult to do, when you're talking about public's and privates because of the bid-ask spread right – the public's are mark-to-market and the privates tend to have a much higher value on their assets, that feels more like an NAV. And so there's a big spread between, how the seller who my value his asset and the buyer might be willing to pay.
And so that provides a constraint on it. What we really do believe the environment is right. There's no question that scale benefits the efficiency of an operation and we care a great deal about scale and efficiency. It really is something we spend a great deal of time and energy and attention on working to maximize. When we think about scale, we think scaled means cash flow and so you know that informs the way we look at that the universe.
All right. Good. That's helpful. I appreciate the color. Thanks.
Thank you, David.
Thank you. And I'm showing no further questions at this time. So with that, I will turn the call back over to CEO, Mr. Eric Greager, for closing remarks.
Thank you, Andrew. And thank you for joining us everyone. Have a nice day.
Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you may all disconnect. Everyone, have a wonderful day.