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Bonanza Creek Energy Inc (CIVI -0.23%)
Q1Â 2020 Earnings Call
May 9, 2020, 11:00 p.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
Thank you for standing by. And welcome to the First Quarter 2020 Bonanza Creek Energy, Inc. Earnings Conference Call. [Operator Instructions]
It is now my pleasure to introduce Senior Director of Finance and IR, Scott Landreth.
Scott Landreth -- Senior. Director, Finance And Investor Relations
Thanks, Andrew. Good morning, everyone, and welcome to Bonanza Creek's First Quarter 2020 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 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 maybe 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'd like to turn the call over to Eric Greager, President and CEO. Eric?
Eric Greager -- President And Chief Executive Officer
Thanks, Scott. Good morning, everyone, and thank you for joining us today for our first quarter 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 and for you to join other scheduled calls. Much has changed in the E&P industry and throughout the world since we hosted our fourth quarter earnings call in February 27. I would like to begin today's call by thanking the employees of Bonanza Creek for their professionalism and dedication during these difficult times. I'm proud that the team has delivered another strong quarter and has been able to respond quickly and effectively to the rapidly evolving macro environment. Like many companies, we've made changes to how we work in order to help protect our employees and members of the community with whom we interact from the COVID-19 pandemic.
Most Denver based employees have been working from home for the last several weeks, and those in the field have altered their activities to limit their interactions with others. I look forward to the day when I can sit across from the full Bonanza Creek team again. But in the meantime, I'm very confident in the team's ability to provide safe, steady operations in the current working environment. From an operations perspective, we were quick to respond to the unprecedented combination of excess supply and demand destruction. In early March, we took decisive action to suspend further drilling and completion activities. Doing so, enabled us to reduce our planned 2020 capex by over 70% from $225 million initially to a range of $60 million to $70 million today. We expect to reduce capex, along with our expected 2020 volumes and a strong hedge book will generate free cash flow this year, and allow us to exit the year with nothing drawn on our credit facility.
We're off to a good start in this regard as we generated $43 million of EBITDA in the first quarter on capex of $41 million. We paid the RVL down $21 million during the quarter, exiting with $59 million drawn, $11 million in cash, over $300 million of liquidity and a leverage ratio of 0.2 a turn. Despite a relatively small size, our cost structure is among the lowest in the industry. We have identified approximately $8 million in operating expense savings that we began implementing in the first quarter. Our first quarter LOE of $2.52 per BOE is the lowest the company has ever recorded. And we have subsequently lowered our 2020 LOE guidance to a range of $2.50 to $2.90 per BOE. We made some difficult decisions on the personnel side during the quarter as a result of price volatility and reduced activity levels. Both employee and contractor accounts were reduced during the quarter.
We also lowered base salaries across the senior management team and our independent directors reduced their own retainers. Our 2019 recurring cash G&A was $32 million. And we now expect our 2020 recurring cash G&A to be in the $27 million to $29 million range. That is 8% lower than the 2019 midpoint and corresponds to $2.95 to $3.44 per BOE based on our 2020 production guidance range. RMI operating expenses for the quarter were $1.78 per BOE, but are offset by $0.71 per BOE of RMI operating revenue from working interest partners, for a net effective cost of $1.07 per BOE. It's worth noting that this revenue from working interest partners is based on production volumes, and the fees are not directly tied to oil or natural gas prices. RMI Opex per BOE guidance for the year remains unchanged at $1.50 to $1.85 per BOE. Before opening up the line for Q&A, I would like to speak to the production guidance we have provided for 2020.
Our initial guidance was 26 to 29 MBOE per day on a capital program of $215 million to $235 million. On March 12, we reacted to the quickly deteriorating price environment by reducing our capital guidance to a range of $80 million to $100 million. And reset our production guidance to a range of 24 to 25 MBOE per day. We have since further reduced our capital guidance to a range of $60 million to $70 million, and we are resetting the lower end of our guidance range. For an updated range of 23 to 25 MBOE per day. The primary driver to the reduced range is a reduction in expected nonoperated capital and production in the second half of 2020. There remains additional macro uncertainties, including potential impacts from downstream storage levels. However, our crude oil purchaser has done a great job moving our barrels, and we believe we have very little risk of forced curtailments in the second quarter.
Additionally, while our first quarter differential was higher than expected, mostly due to a onetime revenue adjustment, the majority of our crude oil is not subject to spot differentials or other basin specific price risks. In conclusion, our first quarter 2020 volumes came in as we expected at 24.8 MBOE per day. We had guided to the first quarter being relatively flat with 4Q 2019 on our last call. And they were up 2% sequentially. We expect second quarter production to be relatively flat to slightly down from 1Q. And as a reminder, we have an eight-well pad that was completed in March and waiting to be turned to sales later this summer to help stretch our flat production profile as far into 2020 as possible. All of our full year 2020 guidance can be found in the press release we issued yesterday, and on slide 16 of our investor presentation.
With that, I will turn the call back to the operator for Q&A.
Questions and Answers:
Operator
Thank you. [Operator Instructions] And our first question comes from the line of Steve Dechert with KeyBanc.
Steve Dechert -- KeyBanc -- Analyst
Hey guys. Just had a question on the comment around low-cost opportunities from the release. I just want to see if there's any detail that you guys could provide or where you guys are on that?
Eric Greager -- President And Chief Executive Officer
Yes. Thanks, Steve. We've really been deliberately patient over the last couple of years, and we think that deliberate patience has benefited us. We've talked about PDP for PDP exchange and our willingness to engage in something like that over the last couple of calls. And we remain open to that. The way we think about scale, and certainly, we're focused and have been focused on efficiently achieving scale. The way we think of scale is cash flow, and we think of scale as cash flow net of debt. And so when we think about any low-cost opportunity, we have to consider that most opportunities or many opportunities have a significant upside component to them, and we simply can't pay for upside. No one can today. And that's why we like the idea of a PDP for PDP exchange. This is the way we think gaining meaningful scale is going to work for us, but it's got to be net of debt.
Steve Dechert -- KeyBanc -- Analyst
Okay great. I appreciate the color. Thanks.
Eric Greager -- President And Chief Executive Officer
Thank you.
Operator
Next question comes from the line of Irene Haas with Imperial Capital.
Irene Haas -- Imperial Capital -- Analyst
Hey, good morning.
Eric Greager -- President And Chief Executive Officer
Good morning, Irene.
Irene Haas -- Imperial Capital -- Analyst
Congrats on the debt reduction, you'd probably be the first one in the whole sector to go to 0 debt, so great job. And my question specifically for this quarter is really the natural gas liquid dynamics. It seems like pricing is kind of low. So can you give me a little comment as to what caused it? Because typically, first quarter, you have some help from cooling I mean, heating and all that good stuff.
Eric Greager -- President And Chief Executive Officer
Yes. Thanks, Irene. It really I think our oil our realized pricing on oil came in, as you suggest, just about in line. NGLs are at historic levels. And in the past, we've talked about the difference between Conway and Mont Belvieu, and most DJ operators, us included, have more exposure to Conway than Mont Belvieu. But natural gas liquids across the space and in particular in DJ, have been at historically low levels. Recently, we've seen a little bit of an updraft on ethane pricing, but I don't think it's going to be enough to change the overall NGL basket. And so for us, fortunately, we're dominated by oil pricing. But you rightly point out, and I don't think it's something that's unique to Bonanza Creek. It's a difficult pricing environment on the residue gas side. A little bit of our natural gas liquids from the tailgate of one of our processors is trucked, and so that tends to cut in just a little bit on the value of those liquids. And that might explain a little bit of a differential, but I think you'll look across most of the E&P's operating in DJ this quarter, and you'll see soft, both residue gas and NGL pricing.
Irene Haas -- Imperial Capital -- Analyst
Good. Thank you.
Eric Greager -- President And Chief Executive Officer
Thank you, Irene.
Operator
And our next question comes from the line of Mike Scialla with Stifel.
Mike Scialla -- Stifel -- Analyst
Yes. Good morning. Just want to see if I get a sense for your thoughts on heading into 2021 based on where strip prices are right now. What you might spend there? And what kind of capex would you need to spend in order to keep production flat with, say, the fourth quarter?
Eric Greager -- President And Chief Executive Officer
Thanks, Mike. That's a great question. It really does depend on how pricing looks. But if we could maybe just reflect on the strip pricing, we've got opportunities to invest D&C capital in our best acreage that will return above hurdle rate returns deep into the 30s. And with the factor cost inputs on the services side having come down as sharply as they have, we expect that there's going to be a time in 2021, whether it's the first quarter, the second quarter or so on, that will allow us to make incremental investments. We also have about 30 DUCs. That's a working DUC inventory that we carry, as you know, and because we stopped drilling and completions activity fairly swiftly in March, we have those DUCs, which have a relatively low non-well capital requirement.
So they just require completions. And when you take the low-cost or low oilfield services, factor cost input environment into consideration, I think we can probably stimulate a number of those DUCs or number of those pads and maintain that exit rate throughout 2021. As far as capex is concerned, I think the best way to look at it is probably something in the range of this year. I think because we have DUCs and because the prices have come down dramatically, we could probably carry year-over-year with something in the range of the capex we have forecasted this year throughout most of next year. And maintain something close to a flat production profile.
Mike Scialla -- Stifel -- Analyst
That's helpful. And I guess to clarify, you mentioned the 30 DUCs. You also mentioned that eight-well pad. I think that eight-well pad that you I assume that's baked into the 2020 production forecast for second half. You plan on bringing that on? And then the, I guess, incremental 22 DUCs would be price more price dependent, possibly this year, but more likely next year. Is that the right way to think about that?
Eric Greager -- President And Chief Executive Officer
Well, you're right about the T-19 being baked into our second half production for 2020, but the 30 DUCs we talk about does not include that pad. So there's 30 additional DUCs. That are that T-19 pad is completed, and we're drilling it out with a coil unit right now. So it's excluded from the 30.
Mike Scialla -- Stifel -- Analyst
Okay. And then the 30 is not baked into anything this year, so you're thinking more likely that would be a 2021 investment?
Eric Greager -- President And Chief Executive Officer
That's exactly right, Mike.
Mike Scialla -- Stifel -- Analyst
Very good. Thank you.
Eric Greager -- President And Chief Executive Officer
Thank you.
Operator
And our next question comes from the line of Noel Parks with Coker & Palmer.
Noel Parks -- Coker & Palmer -- Analyst
Good morning.
Eric Greager -- President And Chief Executive Officer
Good morning, Neol.
Noel Parks -- Coker & Palmer -- Analyst
Just had a couple of things. Talking about drilling and completion costs, what with the recent cost cuts we've seen, what's kind of that proportion of the total BNC dollar that's now for the drilling component versus the completion component? And is that different from say a year ago?
Eric Greager -- President And Chief Executive Officer
Well, I think the two are both coming down hard. And I would say, relatively speaking, they're coming down in proportion. So if a year ago, drilling was 25%, maybe 25% to 30% of the total AFE and stimulation was perhaps 60%, and then the balanced flow back oil tubing drill out plugs in the balance of things that aren't in stimulation, but are in completions, make up the difference. I think they've all come down pretty hard. You've seen the rig count drop, and we get a lot of we see a lot of press on the precipitous drop in rig count. And that really affects day rates and all the ancillary components around the drilling spread. But we've also seen frac horsepower come off really hard. And so that's going to put a lot of downward pressure on horsepower pricing. And then normally, we see oil and gas kind of factory input costs move in different directions from the general economy, which sometimes puts us at a disadvantage with regard to labor costs. But right now, labor costs are crashing as well across the entire economy.
So I think what we're going to be able to do as an E&P space is if you've got activity, we refresh our RFPs on a very regular basis. In fact, so far this year, we've refreshed RFPs three times, leading up to where we sit today just in 2020. And that allows us to continue to bake in these improvements over time, and stay up to speed on what we think the returns will be based on both commodity price environment and also the factor cost inputs environment. So I think the succinct answer is I think they've come down roughly proportionately, but they've both come down or all components have come down pretty dramatically in the last couple of months.
Noel Parks -- Coker & Palmer -- Analyst
Great. I guess I'd just ask as far as the sand component, has even that come off harder? It's already come down so far from the peak.
Eric Greager -- President And Chief Executive Officer
Yes, it has. And it depends on where you go. We've been expanding our use of infield kind of brown sand, low compression lower compression strength proppant because our closure stresses allow us to do so. But I think if you're bringing it down the Mississippi River and then by rail, you're going to be subject to all the diesel pricing, which hasn't moved down as much as other fuels. But if you're doing if you're using more infield proppant like we are, it has really come down a lot because it's a very it's locally demand driven. And there's as you know, in DJ, there's been a precipitous drop in activity, both drilling and completions.
Noel Parks -- Coker & Palmer -- Analyst
Got you. That's helpful. And it has been a topic of some debate as companies have been talking about the quarter and the outlook around whether these service cost improvements are going to be durable or not. And I guess the question I have thinking about the DJ is, the most biggerish comment I've heard said that they thought this is actually somebody in another basin, but saying that the service providers, things have gotten so lean for them that they actually are getting more inclined to lay down equipment rather than try to keep up their own scale, but just barely breaking even on larger fleets. And I just wondered if you had any sense of that. Has it finally gotten to the point where the service companies are on the verge of not being able to give any more? And whether you've seen any shift of equipment availability in the basin as a result? I don't know stuff might be coming over from other basins where things are really dropping even more dramatically.
Eric Greager -- President And Chief Executive Officer
Well, we really haven't we haven't seen a shift in either direction. So recently, we RFP-ed one lease retention well that we needed to stimulate. And the frac horsepower, we look to two of the several key providers in DJ, and both were willing, enables to provide very competitive proposals for that work. I think in the past, what has happened, again, is the general backdrop of economics has been counter cyclic to oil and gas, and that has put a floor in some of the oilfield services companies ability to push back through their supply chain. Labor costs in Colorado, the unemployment rate was running in the high 1.9%, 1.85%, 1.9%, low 2s percent for quite a while, running right up here in early 2020, that has obviously dramatically changed in just the last few months. And what that means is now if you've got a frac crew that you want to put to work, you don't have to pay against a 2% unemployment rate in the Greater Denver area. So they've got downward pressure they can push on wages.
Water contracts are flexible as well. And local sand contracts are flexible. And to the extent that they have to maintain activity in their fleet to keep the fleets functional to make sure this capital equipment will function and be ready to pull back up when we see an updraft in pricing and activity. They've got to operate the equipment, and they'll do so at costs that are as close to breakeven as necessary. I don't think they'll operate negative, but what happens is because their supply chain has seen a little slack in it. We've been able to push down more on the oilfield services, and they've been able to push more on the array of their supply costs and gain incrementally. There's not a lot left. And whether or not it's durable will depend entirely on the available supply on an updraft, and that is something I worry about. But it's not something I'm as acutely worried about as I am about ensuring the very lowest factor cost input prices for our D&C activity.
Noel Parks -- Coker & Palmer -- Analyst
Great. Great. And just the last one. On the non-op side, you were saying that was a sets a little bit of variability of what you had for activity levels. I'm just curious, I don't know if your non-op of your operating partners there are public or private. But are you seeing among the private companies operating in the basin sort of similar behavior shut ins and lay downs as we're seeing among the public?
Eric Greager -- President And Chief Executive Officer
Yes. By and large, we are because it's just it's driven by such limited availability to capital. Many of the private equity-backed, sponsor-backed portfolio companies had already experienced meaningful tightening to their availability of capital through 2019 and many were pursuing things like term loans and such. And if you're taking a term loan to drilling complete wells in this price environment, only to decline off again, you're stuck with the debt and the PDP isn't significant enough to make a difference in how you flip the assets. So what we're seeing is most of the privates pulling back on activity dramatically as a result of the price environment, the oil and gas price environment.
Noel Parks -- Coker & Palmer -- Analyst
Great. Thanks a lot.
Eric Greager -- President And Chief Executive Officer
Noel, thank you.
Operator
Thank you. [Operator Instructions] Our next question comes from the line of Philip Johnston with Capital One.
Philip Johnston -- Capital One -- Analyst
Hey, thanks and happy Friday Obviously, the planned activity for French Lake in the back half of this year is off the table, and that asset isn't exactly front of mind right now. But assuming some sort of reasonable oil price recovery in the back half of the year and into 2021. What do you think is realistic in terms of the timing of when you guys and Oxy stand up a rig to develop that acreage?
Eric Greager -- President And Chief Executive Officer
Thanks, Phillips. We're the good news is French Lake remains some of the very best oil reservoir in DJ, and it remains one of the very few, if not the only, remaining greenfield large-scale greenfield development. And as a consequence of those two factors, both the high-quality reservoir and the greenfield development opportunity, it rises to the top of our returns and of our working interest partner our partner's returns. And so we're confident that when the price supports meaningful development activity, we're going to get there. So the joint development agreement is great. We really do enjoy a strong relationship with our partner. And in terms of realistic start-up times, I think the best thing to think about now is, I don't think anyone is going to rush out on a January one spud.
So it's probably reasonable to think about mid 2021, maybe if there's a substantial updraft in price and it looks sustainable, then that could be Q2. But I really think kind of mid-Q2 to mid-year is a reasonable and realistic expectation. But again, because this is really good rock, and it's a really great opportunity to build a highly efficient development program for us and our partner. It's going to rise to the top of any portfolio of opportunities.
Philip Johnston -- Capital One -- Analyst
Okay. Thanks, Eric. That's all for me.
Eric Greager -- President And Chief Executive Officer
Thanks, Phillips.
Operator
Thank you. And our next question comes from the line of Mike Scialla with Stifel.
Mike Scialla -- Stifel -- Analyst
Eric, you had mentioned in your prepared remarks some small force curtailment of the DJ. I wonder if you could quantify that. And just wondering your thoughts on have you looked at any voluntary shut ins? And if so, how much there as well?
Eric Greager -- President And Chief Executive Officer
Yes. Thanks, Mike. Our shut ins have been limited to low rate intermittent wells and low rate continuous wells, but these tend to have higher variable costs. And in this price environment, you would fully expect that, that would be the tranche of wells or the portion of the distribution, we would shut in first. It's a meaningful number of wells, but it's not a meaningful production value. We're talking about a couple of hundred BOE a day in terms of the total production contribution. And that's a combination of wells we've deliberately shut in at the surface and wells that, by virtue of the fact that they may have needed an intervention to maintain their uptime. And that intervention, we deemed as out of the money. We would have we would just forgo that intervention. So it's something like 20% of our total wells, but it's a couple hundred BOE a day. So it's not a meaningful rate. And that, obviously, allows us to cut those variable costs off immediately.
Mike Scialla -- Stifel -- Analyst
Okay. And then did you happen to mention I thought you mentioned that there were some minor force curtailments as well out of the DJ?
Eric Greager -- President And Chief Executive Officer
We haven't seen any. I think what we were talking about in the prepared remarks was we don't anticipate in the future being forced to curtail, and we haven't been forced to curtail. In fact, even in the darkest month, given the low cash costs of the company, we were able to keep almost all other than the intermittent wells we just discussed on production and generating positive cash flow at the wellhead. So we haven't been forced to shut anything in. We've shut in voluntarily as we discussed just a minute ago, but haven't been forced, and we don't anticipate being forced to. In fact, our oil purchaser is successfully moving our future nominations already through cushing.
Mike Scialla -- Stifel -- Analyst
Okay. Good. And then I just want to get your thoughts on the I think you're going through a borrowing base redetermination right now and then your plans for the balance on the revolver over the course of the year.
Eric Greager -- President And Chief Executive Officer
Yes. So as far as the RBL is concerned, we don't know anything yet. We've got ongoing conversations with our lead bank and there's no indications whatsoever of stress with those guys. I mean they've got stress in other names. We've got $59 million drawn, and we're going to be paying that off over the balance of 2020. And I just I don't anticipate any meaningful stress.
Mike Scialla -- Stifel -- Analyst
Very good. Thank you.
Eric Greager -- President And Chief Executive Officer
Thanks, Mike.
Operator
And I'm showing no further questions. I would now like to turn the call back over to CEO, Eric Greager, for any closing remarks.
Eric Greager -- President And Chief Executive Officer
Thanks, Andrew. Thank you all again for joining us this morning and for your continued interest in Bonanza Creek.
Operator
[Operator Closing Remarks]
Duration: 31 minutes
Call participants:
Scott Landreth -- Senior. Director, Finance And Investor Relations
Eric Greager -- President And Chief Executive Officer
Steve Dechert -- KeyBanc -- Analyst
Irene Haas -- Imperial Capital -- Analyst
Mike Scialla -- Stifel -- Analyst
Noel Parks -- Coker & Palmer -- Analyst
Philip Johnston -- Capital One -- Analyst
