Ladies and gentlemen, thank you for standing by, and welcome to the Fourth Quarter 2019 Bonanza Creek Energy Incorporated Earnings Conference Call. At this time all participants’ lines are in a listen-only mode.

After the speakers’ presentation, there will be a question-and-answer session [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, Daniel. Good morning, everyone, and welcome to Bonanza Creek's fourth quarter 2019 earnings conference call and webcast. On the call this morning, I'm 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 and posted an investor presentation to our website and filed our 10-K with the SEC this morning. All of which can be found on the Investor Relations section of our website. Some of the slides in the February 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 from these statements. You should read our full disclosures regarding forward-looking statements contained in our 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 for our fourth quarter and full-year 2019 earnings call. We appreciate your time and interest in Bonanza Creek. As with previous calls, we will keep our prepared remarks short in order to leave plenty of time for Q&A. The Company had a successful 2019.

And I would like to quickly share a few highlights and thank the Bonanza Creek team and our shareholders for their support. Our 4Q results came in as expected and were largely pre-released last month, so I won't spend time reviewing those, unless there are questions during Q&A.

As for highlights from the year, we saw our average production grow 48%, which led to top-line revenue growth, despite a weaker commodity price. On the cost side of the business, we continue to deliver efficiencies that further expanded our margin. EBITDA for the year was $204 million on a $222 million CapEx program.

And while we had a cash flow deficit of approximately $18 million for the year, we were actually free cash flow neutral in the second half of 2019. Operationally, we continue to report encouraging well results in 2019.

In late 2018, we turned to sales the Pronghorn B-28 pad in our eastern legacy acreage that reached peak rates in 2019 and greatly exceeded our type curve expectations. We also brought online the Whitetail well in our Northern acreage, which we believe continues to demonstrate the potential value of that reservoir.

Slide 11 of our Investor Relations Presentation shows the oil production from these wells over the first 12 months relative to our Legacy East type curve.

To this slide, we also added production results from offset wells operated by others that further demonstrate the improved well results that come with modern completion designs applied to our Legacy East and Northern acreage. With regard to our Rocky Mountain infrastructure, the Company benefited from multiple delivery points in 2019.

These delivery points provide flexibility of that, when combined with consistent low line pressures helped minimize production constraints and maximize well productivity.

We also constructed a new oil gathering system in the second half of the year that significantly reduced our use of truck hauling, which in turn reduces truck traffic, emissions, and weather-related risks, while also improving our realized oil pricing.

In 2019, we came in at the high-end of our original production guidance, below the original CapEx guidance range and below the original LOE guidance range. Cash G&A and RMI OpEx were also both within the guidance ranges we set at the beginning of the year.

Throughout the year, we updated guidance as we outperformed these metrics and we met or beat most recent guidance. I want to thank the team here at Bonanza Creek for helping to deliver these results. Finally, before opening up the line for Q&A, I would like to speak to the guidance for 2020 that we issued last month.

Despite the challenging headlines, we are excited about the prospects for the year ahead. Our expectation for 2020 is to grow average production by 17% at the guidance midpoint with CapEx that is essentially flat to 2019. Our CapEx guidance of $215 million to $235 million includes $10 million to $15 million for the start-up of drilling in French Lake.

Our LOE guidance of $2.75 to $3 per BOE compares to full-year 2019 LOE of $2.95 per BOE. Cash G&A trended down in each quarter of 2019 and our 2020 guidance of $29 million to $32 million compares to full-year 2019 result of $32 million.

We also provided 2020 guidance for our RMI operating expenses, which will include a full year of operating the oil gathering system. So, those increases are offset by the improved oil differential expressed in our $4.35 to $4.85 guidance range, as well as improvements to the RMI revenue line.

We expect our production growth in 2020 to be weighted toward the second half of the year, with 1Q being flat to 4Q 2019 on the production side and CapEx during 2020 will be weighted to the first half of the year with 1Q representing the highest spending quarter. With that, I will turn the call back to the operator for Q&A..

[Operator Instructions] Our first question comes from Welles Fitzpatrick with SunTrust. Your line is now open..

Hey, good morning..

Hi, Welles, how are you?.

Well, okay. [Indiscernible] I suppose, but now everything is good. The question on French Lake. I mean, obviously, it's a big part of the 2021 plan.

Any chance – any update from the operator there? And I know it's a long shop, but any chance as they rationalize their portfolio that you guys might be able to take that in-house to purchase it from them?.

It's a great question, Welles. And we work very closely with our joint development partner, very frequent partner meetings and we have these conversations. What I can tell you is at this point, both sides are really excited about developing the asset.

And as with the prior owners prior to the merger of our partner, with another partner, we continue to be really encouraged by not only the demonstrated reservoir performance, but what we can do together on this largely undeveloped, high quality oil reservoir in Wattenberg.

So, I would say that while we are eager to get started and we're certainly excited about the quality of the reservoir and would be very interested in acquiring the interest in taking 100% in an operated position, I don't know that's in the cards right now. We continue to work on that. And that would be I think a nice win.

On the – the other side feels the same way about the potential of the reservoir. And I think it represents a fair part of their ongoing development program in 2021 and beyond. So from that perspective, I don't know that they're willing to sell it..

Okay. Okay, now that makes sense. And then, I know you guys are close to it. My interpretation is that the most recent Colorado Rising push for these setbacks was kind of met with a thud. I mean, it seemed like it was on Page 6 of the Denver Post. I mean, I guess with everything else going on, it kind of sucks oxygen out of the room.

Is that a correct interpretation of what it feels like on the ground and potentially with the industry's responsibility?.

Yes. Certainly it doesn't help, but I don't know that they're really meaningful in terms of the kind of support they're going to garner. With SB 181 now being the law of the land, the operators are working really hard now that we've got a set of kind of an understanding on the set of rules.

And honestly, the COGCC is working really hard to build those rules to professionalize the commission and really codify some of what is now law into operating rules.

And I don't expect that the environmental activists like Colorado Rising are going to make a lot of headway this year in terms of gaining support except from the most extreme side of their base, simply because it hasn't – we haven't had enough time.

And frankly, the administration, the General Assembly, the operators themselves in the industry just haven't had enough time to demonstrate what SB 181 can do in terms of improving the relationships and surface culture in regulatory environment.

So, I think everybody – everyone I've talked to on both sides has said, you got to give us some time to make this work. It's too soon to be pushing for more ballot measures.

And it kind of appears, best I can tell is a little bit disingenuous because it no longer resonates as sincere interest to improve circumstances as much as it resonates as an insincere effort because it hasn't given the law time to take effect..

Yes, it makes sense. It seems kind of silly for them to go back to the setback well, especially when there was a statewide vote on that, of course. Anyways thank you guys for the time..

Welles, thank you..

You bet..

Thank you. Our next question comes from Mike Scialla with Stifel. Your line is now open..

Hi. Good morning, Eric..

Good morning..

Maybe just a follow-up on the last question with the rule-making process.

How is that going? And in terms of pace of permitting, any anticipated changes there? Once the rules get in place and the commission gets fully staffed and any permits in particular that you're waiting on?.

Yes, that's a great question, Mike. And I would say that the rules are under way. And all of that work that has to be done in writing and gathering stakeholder support by the staff at the COGCC and other kind of adjacent organizations they lean on and work with. That's taking a lot of bandwidth from the COGCC.

And I think obviously, it's a high priority and the fact that, that rule-making is taking time and it also has resulted in a little bit of a resource constraint at the COGCC and Director Robbins recognized this early on.

He knew it was going to take time to write the rules and that's why he established the Director's Objective Criteria, which kind of creates this two-track process.

If the permit has kind of nothing to see here, it's rural, maybe a reoccupying an existing surface location or you have all the right-of-way in connecting to a system, it gets fast-tracked. And the alternative to that is, if you're in a county like Boulder or Broomfield or what have you, you trip these objective criteria.

The problem is, if you combine the rule-making and the time that takes from staff and the objective criteria and the time it takes to analyze the applications, it has slowed down permit approval. There's just no question about that, but all the active operators have good regular meetings. And I'll just speak on behalf of Bonanza Creek.

We have monthly prioritization meetings with the COGCC staff where they ask us what are your highest priorities, what are you waiting on, what are you concerned about, so that we can apply our limited resources to the right pads and wells and areas. And that has worked pretty well.

So, we don't have anything we're waiting on right now per se, but the pace of permit outputs and approvals has slowed.

I don't think that's going to carry on forever because as soon as the COGCC gets the rules in place, I think the more streamlined permit approval process that will replace the now objective criteria and all the rule-making efforts, that will allow a lot more resources to flow back into analyzing and working with the operators on the new permit.

So, that's a lot, but what I can say is right now I think we're kind of as an industry slowed down a little bit. We're not waiting on anything, but the pace of approvals has slowed. And I expect that it will speed back up again, as the rules are built and we move back into a more steady state condition..

Well, thanks for that detail. I guess an obvious one, given what's happened with oil prices, say, oil falls to $40. And it looks like it's going to stay there for the majority of this year.

How would the plan change under that scenario, or would it change?.

Yes. We preserve a lot of flexibility. We build our development programs and we build our capital commitment structures around flexibility. I talked a lot about the flexibility that RMI provides us with multiple delivery points, multiple gas processors, 11 interconnects, multiple oil connections.

We take the same approach to optionality when we talk about our capital program. So, we don't have any MVCs that are not already satisfied for years out ahead of us in terms of a banking provision.

We don't have acreage expiries that are breathing down our neck, and we don't have capital commitments either with horsepower or drilling rigs that limit our ability to ramp up or ramp down; in the case of the current environment, ramped down. And so, preserving that optionality really gives us comfort. We're watching the prompt.

And obviously, it's wildly volatile and we're watching the strip and we continue to run. As we've talked about in the past, we run our proprietary economic optimization on real-time revenue projections, real-time well performance projections, and real-time cost models.

And so, as all of those things continue to run through kind of on an hour-by-hour basis through optimization models, we will high grade where we go in the development program. And the orientation toward the returns is going to force us to make decisions. And those decisions are going to be dictated by returns and by the model projections.

I can tell you we have a lot of flexibility, Mike. And that's really good. We're not going to have to spend dollar that we don't decide to spend..

It's good to hear..

Yes..

Thanks, Eric..

Thank you, Mike..

Thank you. [Operator Instructions] Our next question comes from Irene Haas with Imperial Capital. Your line is now open..

Yes. I have two questions. Firstly, looking at your PV-10 calculation from your filing, I saw a huge improvement in both production and development cost estimate, really significant.

Can you kind of comment on this? And is it the kind of cost structure that can be maintained? Number two, looking at 2020, which is a very volatile year with probably a lot of distressed companies around, do you guys have the appetite to actually go out there and do a little bottom-feeding considering that you have currency and your share price is not single digit? Just want to check how you feel about this..

Thanks, Irene. So, on PDP and particularly the 1P reserves, we're really pleased with this. It's a tough environment. And 2019 related to 2018, the price file retreated by more than 15%. And despite that, we still managed to grow our 1P reserves and we managed to grow our PDP.

And I think that really is an indication that the business is working across the board. I think the development costs on the CapEx and well performance side, clearly is working both in terms of well performance, and in particular in terms of oil efficiency on an EUR or on a per thousand foot basis.

But also you think about just rates and the way we're driving better early time oil performance through the combination of artificial lift optimization better, more contemporary stimulation designs that are we think improving well performance and again, in particular oil performance.

So despite a 15% retreat in prices 2019 from 2018, we managed to grow the reserves by 4%. And at the same time also kind of maintain as much as we could PV-10. While we lost some value in PV-10, it was not as much as the price would have suggested. So again, I think that suggests the business is working pretty well.

Clearly, quarter-over-quarter costs continue to improve. G&A costs on a unit basis and on absolute basis as well as OpEx both RMI and LOE, those are all sustainable. We're going to keep working on them, but we haven't done anything today that impairs or hurts our ability to continue to perform in the future.

So, you can continue to see incremental and sequential progress on all of those dimensions, as we apply more and more technology in the ground and on the surface for efficiencies. With regard to M&A, we're absolutely maintaining an active posture. It is really hard, given valuations.

And the rate of change with regard to both oil price and also valuations makes it really tough because it's hard to pin down a valuation upon which you can transact. But you're right. It is creating a lot of opportunities.

And we have a good balance sheet and we have good performance and a strong team that we think gives us some advantage on some acreage, particularly when it allows us to sort of benefit from fixed cost absorption and really drive synergies whether industrial logic synergies or synergies related to costs and people.

So we're in the market, we have the appetite, we have the public currency, although our valuation means it's a little bit more difficult. We won't go out and do something that implies a value on someone else that we're not getting for our own assets.

One of the things we're really proud of, Irene, is that we've been patient for two years and that patience has paid off.

It's allowed us to focus on blocking and tackling on maximizing the value of the acreage we already own and really focus on kind of three-quarter cycle performance without going out and buying new acreage, but we are absolutely in the market and we also have an appetite. We just have to make sure we're not going to do anything silly.

We're not going to pay too much. And when we think about scale, we think about cash flow. So, we're very oriented toward business improvement focus, efficiencies, and cash flow..

Okay. So, it sounds like if the right opportunity arise and the math works, you do have the capacity for this..

That's exactly right, Irene. Thank you..

Great, thanks..

Thank you. And our next question comes from Noel Parks with Coker and Palmer. Your line is now open..

Good morning..

Hi, Noel..

Hi. Just had a couple questions. On the slides, you updated the production curves for the Pronghorn pad and the Whitetail well. And I remember months ago, they were outperforming the type curve.

And I just wondered when you did reserves this year, did your engineers give you any credit for type curve improvements in those areas?.

They did. We absolutely got some positive uplift with regard to our recent well performance, not only in these areas, but across other parts of the acreage.

So, I think because these have been on long enough and have demonstrated in a real way whether you talk about implied flowing bottom hole pressures or rates relative to expected performance, we've definitely gotten an uplift. So, I think you'll see the performance on the cost and the well performance flowing through the 1P reserves..

Great.

Can you give sort of a ballpark of maybe what sort of improvement you got with EURs?.

A ballpark on improvement in EURs. I'll tell you, Noel, we just went through the reserves process, and then we updated the deck. I don't think we've changed our area-by-area type curve. So when you go to Slide 12, what we think is Legacy Central, French Lake, Legacy East and Legacy West.

While we've got some improvement particularly in and around the Northern Block and in and around the B-28, we like to be pretty conservative in terms of how we generate these type curves. So, we left Slide 12 unchanged. But certainly, the performance flows through in terms of our 1P reserves performance.

There I see a 1.4 million BOE improvement in PUD revisions and also a substantial PDP revision as well. So, both exist. Wells that were online saw an upward revision in terms of volumes. And this is corrected for the 2019 price as well as did our PUDs. So, we're definitely seeing it flow through.

I just wanted to point out that while we're updating the actual performance slide for the Northern Block and B-28, we didn't make changes to our type curves because we'd like to keep those more – a little bit more conservative, but give you some leading indication of where they might be going..

Great, thanks.

And thinking also about looking ahead and the SEC five-year rule, did you assume any trend at all in service costs going forward, flat, down, or inflation?.

While we saw – we certainly saw some improvements in our 2019 1P reserves performance related to costs. In terms of the five-year future, those – we think those are probably flat to down, but we had two significant upward revisions in our 1Q reserves. We had a significant upward revision in PV-10 related to the oil gathering pipeline.

And you can imagine that, that pretty dramatically improves to the basis differential the economics of the 1P reserves. We also saw a pretty significant improvement as a result of – and we did three rounds of RFPs leading up to about Christmas time. We're continuing to put to refresh those RFPs in today's environment.

And so, I would say flat to down over the five-year period is very reasonable today, given what we're seeing right now in the strip..

And Noel, this is Brant. Keep in mind our reserve report is based on a four-year program, not a five-year program..

Great. Thanks for clarifying that. And just the last thing, if we turn back to thinking of a little bit more bullish scenario, we get past the coronavirus, maybe OPEC will keep some production discipline. Looking ahead, I suppose when we saw prices go up nicely and suppose we got $60 for a while.

How much higher do you think, I guess, crews to staff it is available in the DJ at this point? I mean, just I guess in terms of what could the industry realistically put off as far as additional rigs, and I don't know what six-month period or one-year period sort of best-case would you think?.

I'm not entirely sure I understand the question, Noel, but I think you are asking if oil prices gain some support and perhaps TI is around $60, what kind of development do we expect on the whole in and around DJ?.

Well, I was thinking as a practical matter for adding rigs, as you've – as the trend has been down for so long, are there other rigs – and more importantly, are there crews, so that even in a best-case scenario, you would really able to add rig? I'm assuming it couldn't happen too fast, but I just wondered what you thought about that..

Yes, I can tell you from Bonanza Creek's perspective. We really like operating in efficiency channels. And we think a one rig level loaded program offers us a great deal of flexibility. And you can slow down, you can gap out the program, so it's not quite as level, but you maintain the efficiencies because you keep the whole spread together.

And the same is true on the frac side. So, when things are a little slower like they are today, you can gap it out and you still have the economies of scale around stockpiling in big pads and that sort of thing.

But when things heat up and I think hypothetically $60 a barrel TI would probably still lend itself to a fast fully leveled one-rig program and a fully utilized one frac crew program.

For us, I think we've got to see something, perhaps a little higher than that to dive into the second channel, which would be a fractional rig or even a full-time level loaded second rig.

And the reason for that is, we just – we think, right now, we're fully anticipating French Lake – here, we are talking about Q4, but even if under the circumstances with commodity price the way it's moving around that happens to be in early 2021, we are running half a net rig there on the non-op program.

And we're running a full gross operated rig on our own legacy, which gives us a great deal of flexibility in how much – how many wells we can spud and turn to production. I think this range of where we are today, up to $60, it's still a one-rig operated program.

It just – it's a matter of how much you gap it out between locations or how much you really put the coals to accelerating that one rig..

Okay, great. Thanks a lot..

Thank you, Noel..

Thank you. [Operator Instructions] Our next question comes from Mike Scialla with Stifel. Your line is now open..

Eric, just a follow on your last thoughts there. If you say, looking ahead – I realize you just put your 2020 plan out.

But looking into 2021, if you stay at the one operated rig, one non-op, what is – assuming you have a say decent $50 oil price or thereabouts, what kind of growth would you anticipate for 2021? And is there an inflection point there or – I know you had some free cash flow at times here.

Do you get to a sustainable free cash flow level at some point in 2021 or is that further up?.

Yes. I think 2021 is going to be pretty challenging.

I mean, if we're talking about the current pace of development that we are involved in today, and let's say the price stabilizes and we don't exercise options to slow down, this 1.5-rig program that we've talked about over the next couple of years, we definitely have to draw on the revolver and spend excess CapEx in 2021.

And then – because that's primarily a drilling program with completions lagging by perhaps six months. And then, you're spending completions dollars that don't have revenue associated with them until about 2022. Now 2022, as the revenues start flowing out of French Lake, those lines cross. And then in 2022 and into 2023, you do just quite the opposite.

The revenues and the cash flow overwhelmed the CapEx. And then moving forward from there, the Company clearly paying back the RBL and then generating unlevered free cash flow. You're basically from that point forward, as we continue to operate that level-loaded program. That's all modeled that strip. And so, well, strip from maybe 10 days ago.

So, we feel really good about the robustness of that program. And what – we really like the fact that French Lake is absolutely excellent rock. And it's a great – we have a great operating partnership there.

And if it starts in early 2021 instead of Q4 of 2020, we're fine with that because the truth is, we've got a great operated program with a ton of flexibility to ramp up or ramp down and smooth this out. But even at – even with low-50s kind of price strip out for a number of years, our leverage ratio is still even under kind of a $50 flat price file.

We're still less than a turn of leverage even at its peak. And so, this is a really robust program. And that doesn't contemplate betting on the comments in terms of efficiencies, which I think we've built a track record of creating.

So, we feel pretty good about it, but we – because you can't see the future, we preserve the optionality and flexibility on both the capital side and elsewhere in the program to pivot hard if we need to..

And on the growth side, is that still kind of mid-teens growth you'd be looking at for the next couple of years?.

Yes, I think it's not going to. Yes, go ahead..

No, I would classify it, Mike, as modest growth. I don't know, if we want to refine it to a specific number yet..

Yes, I think it's where we stand today. Brant's exactly right. Mid-teens is probably the best thing we could say for – we're talking about 17% in 2020 over 2019. And that same kind of progression until you get a little bit more of the French Lake slog of production contributing. So, 2022 and 2023, that starts to happen.

So 2020 and 2021, I think you can look for mid-teens is probably a reasonable thing to sort of expect..

Okay. And then, just one last one from me.

I wanted to see – does the oil mix change much for you this year at all? And if so, how do you see that playing out?.

I think we actually guided 57% to 60%. And we feel pretty good about that range. It really does depend – on any given quarter, it depends on the number of pads we've turned to sales in the previous quarter or two. And the reason for that is, you understand and we've talked about this as well in the past. DJ is a solution gas drive environment.

So when you put wells on production, particularly in the oil-prone rock like ours, if you manage the reservoir pressure well, you can coax a lot more oil out early in the curve which we do.

And that holds back the gas, but eventually, as you draw down the SRV, eventually you're going to get closer to the vapor pressure of the fluid where the bubble point. And then, you'll start to see the GOR come up. Naturally, that's happening on all the wells we've put to sales.

And as you build a larger and larger base inventory, more and more of those wells are going up in GOR. So, it gets a little bit harder for the pads that you turn on to move that ever growing base that's growing in GOR. So, I think what you're going to see is less volatility in our oil cut.

And it's going to kind of continue to converge in this 57% to 60% range, kind of high-50s if you like..

Got it. Thank you very much..

Yes. Thanks, Mike..

Thank you. And our next question is a follow-up from Welles Fitzpatrick with SunTrust. Your line is now open..

Hi, guys. Thanks for let me hop back on. Obviously, a lot of talk on M&A and whatnot in the basin. But what about – there is a lot of private equity-backed guys. It might be a little bit below critical mass on the midstream side.

What about any kind of roll-up of those types of systems that might involve RMI? Is it the low commodity environment? Is that putting any pressure on moves like that?.

It is, Welles. It's creating opportunities, but it's also creating paralysis. As you can imagine, when things move this fast, the gathering companies and midstreamers look around and say, maybe there are opportunities to buy systems like RMI and take advantage of the difference in the two multiples, which we could benefit from as well.

We're not interested in a sale-leaseback, something that will hurt our upstream business with fees.

And we think our balance sheet allows us to be patient in that regard, but there are opportunities, I think, and something we've given a little thought too, which is participating in something that really creates scale and true economic efficiencies on the gathering and midstream along the eastern flank.

Again, the problem really is midstreamers are looking at their inch miles of pipe capacity, and then they're looking at the stress in the E&P business and they are trying to forecast how is that stress going to play through in terms of volumes and fee revenue for them.

And that contributes to paralysis on their site because they're not sure how to model it. On the other side, there is a huge opportunity, particularly, if you think about RMI as a wholly owned entity within Bonanza Creek and the fact that we could probably unlock some value there. And there are others like us.

So, we continue to have those conversations. But again, I think the strength of our balance sheet and the patience of our leadership team and our Board gives us time to really make good decisions in an environment where there are going to be lots of opportunities I think..

Okay. It makes sense. It's a unique advantage. Thanks for let me hop back on..

Yes. You bet, Welles. Thank you..

Thank you. Ladies and gentlemen, this concludes our question-and-answer session. I would now like to turn the call back over to Eric Greager for any closing remarks..

Yes. Thank you, operator, and thanks again for everyone joining the call and your interest in Bonanza Creek. I just want to remind those who will be unveil early this week at the Credit Suisse 25th Annual Energy Summit, we will be there. We'd love to have conversations with you, and we'll look forward to seeing you then. Thank you..

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