Civitas Resources Inc (CIVI) 2019 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the Q3 2019 Bonanza Creek Energy, Inc. Earnings Conference Call. (Operator Instructions) Please be advised that today's conference is being recorded. (Operator Instructions)

I would now like to hand the conference over to your speaker today, Mr. Scott Landreth, Senior Director of Finance and Investor Relations. Thank you. Please go ahead, sir.

Thanks, Jimmy. Good morning, everyone, and welcome to Bonanza Creek's Third Quarter 2019 Earnings Conference Call and Webcast. On the call this morning, I am 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, we issued our earnings press release, posted a new investor presentation and filed our 10-Q with the SEC, all of which can be accessed on Investor Relations section of our website. Some of the slides in the November Investor Presentation will be referenced during our prepared 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. 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 it is my pleasure to introduce Eric Greager, President and CEO. Eric?

Thanks, Scott. Good morning, everyone, and thank you for joining us for our third quarter earnings call. We will keep our prepared remarks brief in order to leave plenty of time for Q&A. Our third quarter results were in line with the expectations we communicated on our call last quarter. As was expected and due largely to the timing of wells turned to sales from our one rig program, third quarter production of 24.3 MBoe per day was essentially flat with the second quarter. Our average production through 9 months was 23.2 MBoe per day, which is up over 50% compared to average Wattenberg production through Q3 of 2018. This performance year-to-date has resulted in us raising our annual production guidance twice, once after Q2 earnings and once again with our release yesterday. Our current annual production guidance is a range of 23 to 24 MBoe per day, up from 20 to 24 MBoe per day to begin the year.

Our oil mix for the quarter of 57% was in line with our expectations. Going forward, we expect quarterly oil cuts to fluctuate in the high 50% to low 60% range, which will be highly correlated to wells that have been turned to sales in recent quarters and a higher oil cut associated with new production.

CapEx for the quarter was $46 million, bringing the total through 9 months to $173 million. We're on pace to deliver the activity levels contemplated in the 2019 budget, but we are lowering our full year CapEx guidance to a range of $230 million to $240 million from $230 million to $255 million previously. We've also tightened LOE and cash G&A guidance throughout the year. Our cash costs for the quarter and through 9 months of the year fall within our annual guidance ranges. Cash G&A for the quarter of $3.53 per BOE was down 2% from the second quarter, while LOE of $3 per BOE was up slightly from second quarter as a result of some nonrecurring expenses during Q3. We've lowered the upper end of both our LOE and cash G&A ranges as a result of performance year-to-date. Our current full year 2019 guidance ranges can be found in our earnings release issued yesterday or on Slide 16 of our Investor Relations presentation.

We've updated the production plots in the IR deck we posted yesterday for our Eastern Pronghorn B-28 pad and Northern Whitetail well. We continue to be encouraged by these results and the potential to unlock unrealized value in our Eastern and Northern acreage. We also updated the production for the I-21 pad and consolidated the 5 individual curves into a pad average to be consistent with all the other curves shown on Slide 10. We continue to be encouraged that the results at 16 wells per section are exceeding our Legacy West type curve.

As we mentioned on the last quarterly call, our new oil gathering pipeline commenced operations in late July. The investment in this new RMI asset has returned immediate results. As a result of the line, we removed over 40 truckloads per day, representing over 1,200 truck miles per day at current volumes. This reduction in truck traffic continues to improve over the next several quarters. Volumes moving through the line received an improved oil differential of $1.25 to $1.50 per barrel. Shipped volumes increase through the third quarter and will continue to build throughout the fourth quarter. Our oil differential of $4.98 per barrel was down from $5.90 per barrel in the second quarter. A portion of this change relates to the lower benchmark price during Q3, but the oil line also had a positive impact. Our oil differential through 9 months is $5.40 per barrel, and we are reiterating our full year guidance range of $4.25 to $5.25 per barrel at current oil prices.

Finally, I wanted to comment on our business plan for 2020. It's early in our budgeting process, but we expect to deliver moderated production growth in 2020 with a lower year-over-year capital program that will include some capital for our French Lake asset. We're encouraged that we generated approximately $50 million of EBITDA during the third quarter with CapEx of $46 million for the quarter. We're close to free cash flow neutrality on our operated one rig program, and we'll look to deliver a 2020 plan that builds on this momentum.

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

(Operator Instructions) Our first question comes from Irene Haas with Imperial Capital.

My question for you is French Lake, in light of the recent reorganization that happened with Oxy taking over Anadarko. Sort of any color on when the project would start? And roughly when you should expect spending money and roughly how much? And when should we expect the production impact?

Yes. Thanks, Irene. We're thinking right now based on our best intelligence from the Oxy organization that we'll be picking up a rig. It will be a 50-50 operated rig operated by Oxy, 50% net CapEx from Bonanza Creek starting in late Q3. So I think kind of mid- to late September. And that rig would start its one rig level-loaded operation moving continuously throughout the balance of the subsequent years. That's the current best intelligence we've got. So what that means is we would have half a rig for one quarter at the tail end of 2020. And you could anticipate, because these are big pads, we'll be drilling 8 wells east and 8 wells west of what might be a single pad, and these are XRLs. It's going to take probably 4 or 5 months to release off the first pad and another month or so to begin stimulation. So it's going to be well into 2021 before the first well's IP.

(Operator Instructions) Our next question comes from Welles Fitzpatrick with SunTrust.

Whitetail A-4 continues to fit that 830 curve. Can you talk to how you guys are thinking about that area now internally? And how much capital you might be willing to push up there in '20?

Yes. Thanks, Welles. We are encouraged by the Whitetail A-4, and we think it continues to derisk the reservoir in that area. So the way we're thinking about it is our 2020 budget is going to take a shape around working to achieve best we can with the challenging price environment, free cash flow neutrality. So that is sort of the focus and the objective is working toward that. The Whitetail A-4 is a great-performing well, particularly considering the reservoir performance in that area was expected to be challenging. So we're very encouraged by it, but it's probably, given the fact that we don't have a lot of infrastructure out there, the best we could do into 2020 budget would be to continue delineating perhaps with one well a couple of miles away from the current Whitetail. What we'd be thinking there is, it's going to be challenging for a single well to compete with the kind of economies we can put together on larger pads and particularly in a place where we don't have a lot of infrastructure -- existing infrastructure to leverage. And so the best we could do in a challenging price environment we expect to see in 2020 is perhaps one delineation well, and that's likely to be closer to the end of the year, perhaps in the back half. And so that's the way we're thinking about it at this point.

Okay. And you said you'd push it. Would you want to -- if you were to drill one, would you want to be pushing it east or north? I mean which do you think would be sort of less informative?

Yes. I think we'd probably want to push it north. And it might even be north and west. And the reason for that is because we've got good acreage ownership to the north and west, and we can easily connect to rights away to get us back to the Whitetail. Again, it's ease of infrastructure build-out and really lowering the burdens on that single delineation well. So learn as much as you can, delineate as much as you can, but don't create an unnecessary burden on the well or the 2020 budget.

Okay. And then you guys obviously -- you have more midstream control than most. But can you talk to more recent NGL pricing in the basin? To my understanding, fracs and White Cliffs are taking line filled now. Has that moved up the price of the heavies at all?

It hasn't really impacted the realized pricing for us at least at this juncture. We're certainly encouraged that more inch miles of pipe are going to improve access. Most of us in DJ are exposed to Conway, and the Conway pricing has -- realized pricing has just been terrible. And I think there's some hope that, that can continue to get better. I don't know that it's going to be this quarter, but I think it's going to be perhaps in the -- early in 2020 as we continue to see capacity open.

Our next question comes from Ray Deacon with Petro Lotus.

Following on the last question about NGLs, would you think that the current level would be a conservative place to be for 2020 in terms of realization? Or it sounds like you're hoping things improve?

I do think it's a conservative place to start. And I would anticipate that NGLs will continue to improve as particularly the propane element of the NGLs in this part of the country is weather-sensitive, and we're moving into the colder season. So I think you'll see the propane element continue to improve in terms of realized pricing. And as the last conversation pointed out, we do see just a little bit more fractionating capacity coming on at the end of the NGL pipelines as well as more capacity, and we think that will help exposure to -- perhaps to Mont Belvieu, which is the ultimate goal, but the access will improve the pricing regardless. So I do think it's a conservative place to start, Ray. Thank you.

Sure. And just one follow-up is, in terms of the mix of XRLs versus SRLs, it seems like a fairly big shift next year, I guess. Does that -- what's the reasoning there? And I assume it helps your cycle times in terms of getting wells tied on quicker, I guess.

Well, the mix of SRLs and XRLs will be -- is very much a function of the shape of the acreage, the DSUs, and that's -- which ones come on throughout a various budget year, Ray, is more dependent on our maximizing both our surface efficiencies and our subsurface efficiencies. So I wish we had just a wide-open whiteboard where we could just take advantage of any piece of acreage we wanted to. But the truth is we've got varying working interest, and we've got varying shapes to our DSUs. And we also are very careful about minimizing frac impacts in the subsurface. And so it constrains the number of options we've got. And so the mix is governed by maximizing the profitability of a budget year. So you try to develop in areas where you have the highest total return at the pad level, whether that's an XRL or an SRL. So it's going to continue to be dependent on a number of factors, including both surface and subsurface efficiencies.

And to be clear, Ray, we're still in the budgeting process. So we have not guided the mix of those different links yet.

Got it. Got it. Great. Yes. And just one more, Brant. Did you -- one of your peers had their RBL reduced or elected a lower level on a call yesterday. I was just curious, have you already gone through that process?

I appreciate the question because it's a good one. We are right in the middle of working with our syndicate. In fact, we have our meetings next week. So very early indication is, I think, we'll be fine. But it's probably too early to give you a definitive reaffirmation, but I think with the reserve growth and the production growth over the last several quarters. I think we're in very good shape.

Yes. Fundamentally, well -- cash costs have been reducing over time, well performance has been improving over time, reserves growth has been consistent quarter-over-quarter, and our utilization rate of the RBL is pretty low. In fact, we will draw and repay in -- periodically through the quarter throughout a year. So we really do use it like working capital. So I think all of those things will point to a pretty healthy redetermination. But again, as Brant pointed out, it's early.

And our next question comes from Noel Parks with Coker & Palmer.

Just a couple of things. One of them, I have to ask about consolidation in the basin. And I was wondering if you've seen, among the feedback folks out there, any more kind of coming down-to-earth as far as their bid-ask expectations on transacting in their assets?

Yes. Thank you. That's a great question. I'll tell you what we have observed is that over the last couple of quarters, rather than testing the market through kind of a broad process that involves a big VDR and inviting everyone to come take a look and make a bid, what we've seen is an evolution toward targeted kind of rifle shot strategic conversations, and we're happy to participate in those. It -- the challenge really is, as you know, our upside, our 1,000 gross well SRL inventory doesn't bring a whole lot of share value or component to our share price today. RMI really doesn't provide us much value in our share price. What really does in our share price is our PDP. And so if we look at -- or we imply our valuation on a potential target, it would imply we could pay a fair price for PDP. And most of these PE-backed firms are really light on PDP, and they can't possibly afford to sell at that price. But there continues to be interest in the idea that PDP for PDP is beginning to make a lot more sense as the strip remains constrained and access to capital gets tougher and tougher. So I don't know that they're currently at the point, just generally speaking, across the companies that I speak with. I don't know that they're currently at a price that makes our bid makes sense to them, but I think it's certainly moving in the right direction. I think there's plenty of therapy to continue to migrate in that direction.

Great. And one other thing. Things have been so tough for the service guys that we are really not hearing anybody worried about any sort of cost inflation over, say, the medium term. Do you see any scenario where -- I mean, I guess, the only thing I can think of withdrawing equipment from the basin or just getting rid of older equipment. I mean do you see any scenario that could give you any cost inflation in 2020 or maybe beyond that?

No. No, we see no scenario. In fact, throughout the course of 2019, we've seen factory input cost to our D&C operations consistently declining, and we've been able to take advantage of that to further optimize our stimulation designs and really maximize PV and IRR based on those factor cost improvements. We've seen that happen throughout '19. And as we kind of stress test through RFPs and test the market into 2020, we see continued improvement. And so throughout 2019, we've seen about a 10% reduction in factor cost inputs to our D&C operation. We've been able to take advantage of that. And even beyond that, relative to current pricing, our current RFPs are pointing to nominally 15% to 20% reductions into 2020. We don't see a scenario where, for example, a major supplier of frac horsepower withdraws capacity out of DJ. Although I've read a lot about it, I don't read about it happening or have any sense that it's taking place for DJ and I think -- because the market is really pretty well balanced today, and DJ has been under pressure because of the political environment for a couple of years. And so we've had time to sort of get right with the activity level as an operator and supplier environment, whereas some of the other basins that were a lot more active up until the recent couple of quarters have really had a high rate of change. And so I think they're much more sensitive to the oversupply in capacity.

Got you. And I mean, have you seen things like people looking at closing or combining service centers just to kind of help with their overhead in the area?

I certainly anticipate that there will continue to be rationalization of costs on the service side and efforts made at every level to reduce the overhead and some of the burdens on the business because their margins are tight, and that's a difficult place for them to be in. And we, as an operator community, all of us continue to put downward pressure through competitive tension and round after round of RFPs.

Great. Great. And just one last thing. From a bigger picture, just like a flat strip in a pretty constrained phasing range don't do wonders for dealmaking, is it fair to say that if we are looking at a fairly long-term $50 million to $55 million price, that's not a -- really a bad long-term operating environment for you guys, assuming we can continue with the same sort of efficiencies that hit the markets so far?

Yes. I think we've got adequate high-quality inventory. And that inventory is effective at this price environment. We also have good liquidity. And as I mentioned earlier in the remarks, we're certainly flirting with today and working hard to continue to be a self-funded operation. And that would imply that if we're not drawing on the RBL and we're not increasing our net debt at these price points, we can weather time, and we can weather this price environment perhaps longer than others can. And that should create some opportunities for us. We're certainly focused on a disciplined capital program. We're going to continue to be focused on lowering our cash costs over time and really working to rationalize anything that doesn't really improve our business and the profitability of our business. But we also recognize that there are a lot of benefits to scale. And so when we think of scale, we think of cash flow. And so that's the way we look at consolidation from our perspective. But today, we remain patient because we think this is an opportunity where patients will continue to benefit us in terms of the number of opportunities that we get a chance to look at.

And we have a follow-up from Welles Fitzpatrick from SunTrust.

I just had a real quick one. Just to kind of sanity-check my reading of the COGCC new mission change white paper, it didn't seem to me that anything was terribly new or onerous in there. Is that -- I know you guys are close to it. Can you talk to your interpretation of that document?

I feel exactly the same way, Welles. I think it was a reaffirmation of Senate Bill 19-181. And I think the point really was to continue to reinforce the mission of the COGCC. So I don't think the white paper was meant to announce any incremental changes or new emphasis. I think it was really to reaffirm 19-181 and to ensure that, as the operator and environmental communities continue to talk about how we provide energy for people in a state like Colorado, how do we balance that? And what is the legal mission of the COGCC? I see it as a reaffirmation of that. And frankly, I think it's good. The whole conversation today related to CDPHE and COGCC is a -- is in a lot healthier place than it was a year ago. And I think several people can disagree on points. But I think everyone recognizes that the middle of the fairway has gotten wider. And if you've got an opportunity to do good work and be sensitive to the stakeholders' needs, I think you can continue to do good work and provide good jobs in a state like Colorado. And I think we saw that during the press conferences at the CDPHE and COGCC press conferences during the health study rollout. I think there was a balanced view as to what that study did and did not accomplish. To me, it was frankly a healthy indication of the balance that the regulatory bodies are taking when it comes to evaluating the impacts of oil and gas development.

Yes. No, that's great. And I agree. When you pull this and even Becker kind of lined up the same way to have a quick response to that study it points to the state being in a much better place.

And I'm showing no further questions in the queue at this time. So I'd like to turn the call back to Eric Greager, President and CEO, for any closing remarks.

Thank you. Thanks for your interest, everyone. As a reminder, we're going to be attending the Capital One Energy Conference in Houston on December 10 through the 12. We hope to see some of you there. And with that, we'll end the call. Thank you so much.

Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.