Civitas Resources Inc (CIVI) 2020 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the Second Quarter 2020 Bonanza Creek Energy earnings conference call. (Operator Instructions) Please be advised that today's conference may be recorded. (Operator Instructions)

I'd now like to hand the conference over to your host today, Mr. Scott Landreth, Senior Director of Finance and Treasurer. Please go ahead, sir.

Thanks, Liz. Good morning, everyone, and welcome to Bonanza Creek's Second Quarter 2020 Earnings Conference Call and Webcast. On the call this morning, I am joined by Eric Greager, President and CEO; Brant DeMuth, Executive Vice President and Chief Financial Officer; and other members of the senior management team.

Yesterday, we issued our earnings press release, posted a new investor presentation and filed our 10-Q with the SEC, all of which can be found on the Investor Relations section of our website. Some of the slides in the current investor presentation may be referenced during our remarks this morning. 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 from these statements. You should read our full disclosures regarding forward-looking statements contained 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 then move to Q&A.

Now I would like to turn the call over to Eric Greager, President and CEO. Eric?

Thanks, Scott. Good morning, everyone, and thank you for joining us today for our second quarter earnings call. We appreciate your time and interest in Bonanza Creek. Those of you who have listened to our calls in the past, know we prefer to keep our prepared remarks short and leave plenty of time for Q&A. The company's performance during the quarter was in line with our expectations. So I will briefly cover a few highlights from the quarter, provide some color on the rest of the year and then open the line for Q&A.

As I mentioned, our second quarter generally came together as we expected. We guided the second quarter production being flat to slightly down from the 24.8 MBOE per day in the first quarter, and the second quarter came in at 24.9 MBOE per day. Our LOE for the quarter came in at $2.56 per BOE, bringing the year-to-date metric to $2.54 per BOE, near the bottom end of our annual guidance range of $2.50 to $2.90 per BOE.

Our recurring cash G&A dropped 21% in 2Q to $2.72 per BOE despite relatively flat volumes quarter-over-quarter.

Lastly, CapEx for the quarter of $21.7 million brings our year-to-date CapEx to $62.8 million versus our annual CapEx guidance range of $60 million to $70 million. As we have previously stated, we had expected our CapEx for the year to be heavily weighted to the first half of the year with minimal CapEx through the balance of the year. As a result of our performance year-to-date, we have increased our annual production guidance range to 24 to 25 MBOE per day, and we have reiterated all other previously provided 2020 guidance. All of our full year 2020 guidance can be found on Slide 14 of the investor presentation posted to our website. I will point out there was a typo in the guidance table included in our press release issued yesterday, which listed oil differential guidance of $4.25 to $5.25 per barrel. Our guidance remains $4.75 to $5.25 per barrel.

During the quarter, we had the opportunity to acquire working interest in over 25 wells that we operate, including interest in wells that have been recently turned to sales and are still building production. A combination of wells turned to sales in the last 6 months performing stronger for longer, and this acquired interest has led us to increasing our annual guidance range for the year. This increased working interest came to us from a financially distressed partner seeking relief on their outstanding balance. We were able to pick up the additional working interest on favorable terms and despite the capital incurred during the second quarter, that we hadn't planned for, we still believe we can achieve our previously provided CapEx range for the year. We exited the quarter with $58 million drawn on our RBL. As of today, the balance is $53 million, and our net debt balance is below $50 million. As we've consistently stated since adjusting our 2020 capital plans in March, we expect to exit the year with an undrawn credit facility.

In conclusion, we're pleased with our second order and the progress we've made toward our 2020 guidance for the year. We've increased the midpoint of our annual production guidance, and we expect 3Q volumes to once again be flat with the previous quarter.

With that, I will turn the call over to the operator for Q&A.

(Operator Instructions) Our first question comes from Leo Mariani with KeyBanc.

I was hoping you could provide maybe a little bit more information about the working interest acquisition that you all just talked about, what month did that close? And roughly how much production was associated with that? And what was the rough cost to Bonanza?

Leo, it's Brant. So in the financial statements, you'll see it as a supplemental item on our cash flow statement, but it was approximately $8.3 million marked at fair value. And it really was mostly working interest in recently completed wells. And so if you want to think about it as a balance sheet adjustment, where the receivables went down and the approved properties went up, that's how it was handled. It closed May 1. And so it added a little bit to the quarter, but more importantly, those -- the recently completed wells are still building. So it did enable us to take the low end of guidance up, that's why you saw the adjustment in production.

Okay. So I guess that 8 well pad that you guys brought on in June, part of it was interest in that, it sounds like?

In a few of the wells there. Yes.

Okay. Got it. And is there like a -- I know it's a moving target, but is there like a rough estimate in production? Are we talking just a couple of hundred barrels a day? Or what are we talking about here to (inaudible)

Yes. You saw the guidance increase and the bottom end going from 23 to 24. So across the entire year, it's 500 per day.

Okay. All right. That's helpful. And maybe just to kind of segue that, obviously, not a huge deal as you guys talked about $8 million. Just wanted to get a sense of what else is kind of brewing on the M&A front? I know there's certainly a number of distressed players up in the DJ, and your balance sheet's clearly pretty clean at this point in the cycle. How are you guys kind of feeling about the potential for maybe other deals over the next several months going forward? Do you feel like there's opportunity and potential willing sellers there?

Thanks, Leo. It's Greager here. I think we continue to remain focused on efficiently achieving scale. And so clearly, our objectives and our timing with the balance sheet is working to our advantage. We remain focused on figuring out where those best opportunities lie, and scale is extremely important to us. And we think scale equals cash flow net of debt. So production net of debt is what we're looking for. And that -- fortunately luck favors the prepared, and we came into this opportunity pretty well prepared with the balance sheet. And there are some opportunities. And we're certainly looking at all of them, all of them that you would expect us to be looking for.

The G&A synergies and the DJ make it much more attractive for us than other opportunities that might be outside of DJ. So clearly, there's a bias for us to take maximum advantage of those cost efficiencies. So yes, we're absolutely looking. But we want to reiterate, we're focused on doing it the right way. It's got to be a low cost basis, it has to improve Bonanza Creek in all of the metrics. We have to be a better company on the other side of any transaction. It's got to be cash flow accretive. It's got to be improvements in terms of cash cost structure and all the rest. All the things you've been hearing us speak to the investment community about that are important to us. And we'll remain disciplined in how we approach these things. It's been 2.5 years of capital discipline and sort of transactional discipline that have led us to where we are today, but it's not wasted on us that this is a good opportunity for us to flex the balance sheet. We've worked so hard over the last couple of years to really get into the shape it's in.

That's very helpful color for sure. And maybe just lastly, I know there's not really much in the way of operating activity, I guess, I think 0 planned the rest of the year. Just wanted to get a sense the -- whether or not you kind of hit the ground running in the first quarter and start kind of fracking DUCs in order to maintain production? How you're sort of thinking about it in kind of a $44-ish strip world next year in '21?

Thanks, Leo. The way we're thinking about it is there's a good opportunity between now and the end of the year to start having proactive conversations with our oilfield service providers, particularly on the completion side and make sure that they understand we intend to get-go and -- very early in '21. And I would say that you're right in concluding, and we've reiterated this a couple of times, just we're going to carry through the balance of 2020 with this $60 million to $70 million CapEx guidance range, and this 24 to 25 MBOE a day production guidance range. We feel really good about that. We're going to take advantage of the oilfield services' price structure as it stands today and try to get those prices pulled in and sort of firmed up for the beginning of 2021. And then we intend to carry forward in 2021 with more DUCs. We carry a DUC inventory at 30 going into 2021, and those will be sufficient to hold our 2021 production flat on a year-over-year basis. And that's our plan. So we are -- I guess, we're reiterating essentially what you teed up in summary.

Our next question comes from Michael Scialla with Stifel.

I guess just to follow-on the last comments you had there, Eric, is there any chance you would pull some of that activity forward? Say you got some price concessions from your vendors, would you consider pulling any of that into 2020? Or you're pretty set on getting the balance sheet debt-free before you go back to spending some more money?

We've talked about pulling it forward, Mike, but we're pretty firm on making sure we exit the year debt free. We think that's a real advantage, and it really differentiates our company and the strength that we can bring forth at this point in the cycle, our relative strength. And making the working interest acquisition in Q2 really helped reinforce that belief. So we're pretty firm on exiting debt-free with several quarters of sequential flat production and then getting started beginning of the year. I would say that as a consequence of that, we do expect Q1 to dip a little bit. We expect 2021 to be flat relative to 2020, and nominally flat to even 2019. But I do want to point out that as a consequence of 6 months of no activity in the second half of 2020, we do expect a little bit of a production dip, but we want to reiterate that 2021 will be flat to 2020 on that DUC activity.

Got it. And I want to see how French Lake fits into '21. I know you'd kind of gone back and forth on -- and it's a nonoperated property. But is that likely to be part of the '21 plan? And would it be a meaningful part of the '21 CapEx? Or -- and any production contribution contemplated in '21 plan from French Lake at this point? Or is it mostly going to rely on those -- pulling down the DUC inventory?

Yes. It's a draw on the DUC inventory that's going to maintain the production, Mike. And our view on '21 French Lake is that it's going to be weighted to the back end of the year, if it happens at all. And it's going to be drilling capital, no contribution of production and probably even no completions capital is the way we're thinking about it. Based on -- yes, based on our conversations with OXY and our read -- our read-through of their public commentary is, if it happens all, it's going to be in the back half. And frankly, Mike, we're not beating on their door to tell them to get after it, if -- they're making economic decisions. We're making economic decisions. We use WACC and return on invested capital to guide our incremental economic investments, and I'm sure they do the same thing. And so we're reading, I think, the signals from the marketplace the same way. So what's good for them is good for us. It's just a good alignment of interests. Neither of us are overly perverted to go one direction or the other, we're equally aligned and I think making decisions on economic value accretion.

If it were to slip into '22, I guess there's enough inventory there if you wanted more activity you could just pull down the DUCs a little bit further than what you're contemplating right now. Is that kind of the way to look at it?

That's exactly right. We've got a flexible development plan. We've got the DUCs that are attractive in the low to mid-40s price environment we're talking about here. We've got a good operated plan with great opportunities in legacy if we need to flex that, which I don't anticipate we will, but we could pick up a rig and flex that because we've got great opportunities there. And then, of course, French Lake. So what we've done is created a flexible development program over time that allows us to operate 2020 and 2021 on relatively low CapEx and maintaining flat, we can flex up. And if French Lake moves out, we can swing in our own operated program just about on any kind of flexibility necessary to augment or replace French Lake. So it's a really good position for us to be in at this juncture.

Our next question comes from Welles Fitzpatrick with Truist.

Can you talk at all to -- I mean, you guys held in on a better in 2Q on account of the API differentials that hit the basin and obviously hit the lighter barrels harder. And so you guys fared better than your competition. Can you talk to what that API discount looks like now and what you might think it looks like going forward?

Sure, Welles. This is Brant. So as you know, our differential is essentially very formulaic. And we are exposed -- 20% to 25% of our production is led -- is considered a light barrel to DJ common barrel. That is exposed to the White Cliffs discount, and that did expand during the second quarter relatively dramatically for 1 month. It's back down to what we would consider normal levels. And I think it was just posted under $1 again. So it did expand out to over $6 in May, but it's come right back in. So that's why we're reiterating our differential guidance for the year.

Okay. Perfect. And any updates on potential midstream consolidation? And how that might affect you guys going forward in the basin?

No. We haven't read of anything that is affecting us. And our view of RMI remains essentially the same as it's been in the past. We're not inclined to consider or -- well, we'll consider anything, but we won't -- we're not inclined to act on something that feels like a sale leaseback that's going to burden our upstream entity with fees that are -- that essentially are a burden in perpetuity. We remain interested in willing to discuss more creative solutions that kind of lean into eastern flank consolidation, Welles, to your point, if there's something that looks like it might be an aggregation of eastern flank midstream, and we could contribute RMI on some equity basis that would then result in both economies of scale and G&A synergies along with some multiple expansion as a consequence of that consolidation.

Well, we think that's probably pretty good business. We think that makes sense. And we've got an idea about how that might work. And because it would allow for not only synergies and economies of scale, but also for third-party volumes to flow through our equity contribution to something like that. We think about that, and we think that's probably the most reasonable potential. But to your point, specifically, there's nothing working as far as we can see, reading the same kind of public commentary you read, nothing that works.

(Operator Instructions) Our next question comes from Noel Parks with Coker & Palmer.

I just have a general question. In the event we do sort of turn a corner on some of the macro COVID worries and we see prices keep creeping up in the strip, do you have a sense of -- I hate to say a particular price that you get more active. But I guess, since you've been such active hedgers, sort of like -- do you anticipate that we can wind that up back in the situation with sort of a backwardated curve that would sort of change your hedging strategy from what you've been doing recently with a lot of success actually?

Noel, this is Eric Greager. I think what -- if we see COVID-related demand side pressures that begin to manifest themselves in a strip that is much more attractive, my read -- and I'm going to get pretty macro on this, but my read is that OPEC is going to act in a way that defends their market share. And frankly, I think we've seen it already as North American unconventionals have begun to talk about putting shut-in production back on, and we've talked about bringing frac crews back, and there's been more active conversation around activity increases. You hear the saber-rattling. You see the saber-rattling in the defense of the market share that OPEC has taken such a big black eye to gain. I think they'll do whatever is necessary to maintain that market share. And so I like -- my personal view is I think the modest contango we're in today is about reflective of the dynamics that are necessary.

And unfortunately, it's going to put a lot of stress on North American unconventionals because the structure doesn't work across the board. It works in certain pockets. But it doesn't work across the board. And I think that's exactly by design. So I -- again, what I'm saying is if COVID and demand pressures result in upward pressure on price. I think that's going to force action from OPEC, and they're going to immediately act. And given the sensitivity of the price to that surplus, it'll put it right back where it needs to be in order to suppress U.S. shale.

So that's a lot of speculation by Greager. So I just want to preface that. And that's why we think our systematic hedging strategy -- we're arranged around, not only oil and gas hedging with swaps and collars, but also in minimizing any long-term contract risk on the operations side of the business, ensuring strong capital allocation according to economic value accretion, WACC and return on invested capital. We think those are all the right mechanisms to allow us to respond quickly and correctly to the signals as opposed to trying to name prices because if you name a price, you're only talking about one side of the D&C economics. There's always the cost side of that, too.

And so I also -- I just -- it just -- it's tough on the industry when across the board, we start talking about a lot more activity because I guarantee the folks that have a lot lower cost of production are listening to that chatter, and they don't like it. And it just brings additional pressure on the supply side. And so let me stop there, Noel, and just see if that answers your question. If not, please clarify.

No. That's great. Just to sort of hear how you rank the likelihood of the various factors, geopolitical, supply and demand. It's just what I was looking for. And it does feel like despite the challenges with the bid ask, sort of like we're on the verge of maybe some pretty serious consolidation, long overdue consolidation happening in E&P. And it was encouraging to hear you say, despite having high standards for what you'd acquire that it's not lost on you that this is a -- maybe a particularly good window of opportunity for picking up assets given your balance sheet. So I guess, thinking about the different basins and maybe with some of the regulatory fear about Colorado, hopefully, ebbing -- in contrast with many new fears of -- on the federal side. As far as property and acreage valuations, do you think we've kind of maxed out maybe the DJ's discount to other basins and thinking, especially the Permian at this point? Do you think that's maybe gone as far as it's going to go and maybe might start, basically to DJ relative to the Permian might be hitting upward in value?

That's my view. And I think the multiples would show that the -- the multiples have compressed disproportionately in Delaware and Midland on both sides of the Permian, more than our multiple has expanded. So you could say that the DJ multiple has stayed compressed while other basins have compressed toward the DJ, which is not exactly what you'd like to see. But in terms of relative performance, we know that DJ can generate returns that are comparable to any basin in the U.S. It's not so much on the well performance side as it is on the cost side, right? The Niobrara drills like butter, it treats really well, and we're well piped, and we've got consistent access to very good, low cost supplies, both of labor and also of oilfield services.

So all of those things contribute to the returns profile in the DJ. And so I think if you think about all of that in the context of your first question or your first comment, which was the regulatory and surface political environment might be getting incrementally better for us, and potentially incrementally worse across other basins. I do think that tilts towards the DJ. At the same time, there is a limited number of operators in the DJ that are capable of flexing up in a $40 price environment. So you combine all that stuff, and it does create for a pretty interesting, long, overdue consolidation dynamic.

I'd also point out, Noel, that our exposure to federal lands is, I think it's less than 5%. So we have very, very little exposure to federal changes...

Which reinforces the whole story.

Yes.

Great. Yes. No, it's good to hear that [spread sit]. It seems like that's the perpetual question that everyone's getting is people kind of want an update on what their federal exposure is. So it's great to hear that's low. And I guess just the last one, just as housekeeping. Right up top, you mentioned what your oil differential was. I just wanted to double check. What did you say that it actually should be in the guidance?

Yes. Thanks, Noel. We're reiterating $4.75 to $5.25 as the range. That's our full year base range. We just had a typo in the press release. It was right in the Q. It's right in the IR deck. It just -- there was a typo in the table that was lifted into the press release. So we wanted to reiterate that.

Our next question comes from the line of Michael Scialla with Stifel.

I just want to follow-up on the -- obviously, the regulatory environment does look -- it's getting better. But just curious with the COGCC Board now in place, have you seen any change in the pace of permits and any new proposals coming out of the agency that could have -- impact you either way?

This is Dean, Mike. Yes, thanks for the question. We are seeing steady progress. I think that the agency is working through their process, and we're working to integrate those changes into our internal process. And so just in the last couple of months, we've seen steady progress on getting both location and well commenced. Does that help?

Yes, it does. I guess, Dean, relative to the pace previously, is it -- any change there? It looks like it's -- I guess, could it be a bottleneck going forward? Or do you think it's speeding up?

I think it's certainly speeding up from what it was 3 or 4 months ago. Realistically, I don't think it's going to be a fast process or a faster process. We just need to incorporate the new changes, the new rules. And I think that given our rural setting and given our infrastructure in place, we don't anticipate it being an evolvement for our operation.

Yes, I don't -- Mike, this is Greager. I agree with Dean. I don't think we're going to see it snap forward. I think the best way to describe it is deliberate. It's a very deliberate process with the COGCC and the other regulatory bodies, whether you're talking about Weld County. And of course, you're familiar with all of this. But for those who aren't, you've got the counties and the municipalities, not on our acreage, but you have municipalities that the COGCC has to consider. And so they're very methodical. I am encouraged, though, the professionalization of the Board and particularly that Director Robbins is now the Chair of the new professional COGCC Board of Commissioners. That is all encouraging.

And Julie Murphy, she's the new Director. She was a lieutenant, I think, directly reporting to Director Robbins. All of this is good because there's no change in the tone. There's no change in the thesis. It is -- it remains constructive. And I think most recently, Governor Polis's position. This is something we've been saying for a while in both our earnings calls and in other conversations with the investment community. We've been saying it's in Governor Polis's administration's interest to see Senate Bill 181 work, and to stabilize and kind of allow things to go through rule making to be sort of deliberate, methodical and work at a steady pace. And for a while, we were saying, and he wasn't, but now he's saying the same thing. Look, let's let SB 181 work. We have rule making, we have professional Commission. We have willing and capable operators. And let's give this some time to stabilize. And I think it's good for everyone. It's going to be good for the people of the state of Colorado, and it's going to be good for, I think, the economy in general. So we're encouraged by the professional commission, and we're encouraged by the tone and the deliberate nature of the process.

And that concludes today's question-and-answer session. I'd like to turn the call to Eric Greager for closing remarks.

Thank you, Liz. We appreciate everyone's interest in Bonanza Creek. Have a nice day. Thank you.

Ladies and gentlemen, thank you for participating in today's conference. This concludes the program, and you may now disconnect. Everyone, have a great day.