Earnings Transcript for ROCC - Q1 Fiscal Year 2021

Operator: Ladies and gentlemen, thank you for standing by. Welcome to the Lonestar Resources First Quarter 2021 Financial Results Conference Call. At this time, all participants are in a listen-only mode. [Operator Instructions] Please note this conference is being recorded today, May 12, 2021. I would now like to turn the conference call over to your host, Frank Bracken, Chief Executive Officer. Frank, please go ahead.

Frank Bracken: Good morning and thank you for joining us as we review our first quarter 2021 results and get you caught up on operations. As always, I will refer you to Page 2 to review our disclaimer and forward-looking statements then ask you to turn to Page 3. Over the past year, Lonestar successfully restructured its liabilities, simplified its balance sheet and further reduced debt by utilizing free cash flow. At March 31, 2021, net debt of $239 million provides $36 million of liquidity and a debt to adjusted EBITDAX ratio of 2.1. Lonestar continues to target a debt to EBITDAX ratio of 1.5 within the next eight quarters and the combination of continued high performance of our drilling and completion program and price certainty afforded us with our hedge book leads us to be highly confident in achieving those goals. Let’s touch on some highlights from the recent quarter. Current production is up 22% from first quarter levels. While we did report a 29% decrease year-over-year, that really is a function of the fact that we went for an extended period of time without bringing new wells on stream. I would also remind you that, that production stream in the current quarter, it’s comprised of 75% crude oil and NGLs on an equivalent basis. Resumption of development activities has increased production at current rates of 12,500 barrels a day. And I’d also note that Lonestar expects further growth in production in the second half of the year and for rates to average between 13,400 and 13,800 barrels a day during the second half as we see the more fulsome benefits of our capital program. Adjusted net income was $1.05 a share and the company is on track to continue to report strong earnings on an adjusted basis. Adjusted EBITDAX was $22.9 million while discretionary cash flow was $19.1 million, which was nearly in line with last year’s results. It’s worth noting that 1Q discretionary cash flow was negatively impacted by $5.4 million in hedge losses realized in the quarter, while 1Q ‘20’s result was positively impacted by $8.2 million of realized hedge gains. Improved wellhead price realizations and reduced cash expenses are what balanced those two out to yield essentially flat results. As a result, after spending a little over $11 million, Lonestar reported free cash flow of $7 million in the quarter, which is a sharp about faced from the negative $15 million from the prior year. The returns of our capital program are outstanding ranging from 79% to 112% at $55 oil and $2.75 gas and we will continue to focus our program on our high return extended reach laterals at Cyclone, Hawkeye and Horned Frog. Company continues to expand its drilling inventory in an environment where I think the industry is becoming increasingly inventory poor. Lonestar boasts a robust inventory. At December 31, 2020, we had 109 proved undeveloped locations and an additional 115 probable undeveloped locations per our third-party engineering report. At 2021’s currently projected pace of well completions of 10 per year, our PUD locations alone represent 11 years of inventory. Over time, Lonestar has been especially successful at increasing its drilling inventory on its core assets of Cyclone, Hawkeye and Horned Frog, where its well returns are outstanding. Recently, Lonestar concluded a series of primary term leasing, dispositions and acreage trades that increased our acreage position at Horned Frog and in doing so nearly doubled our inventory of extended reach laterals. I will discuss that deal further in our operations update. As it relates to 2021 guidance, as production increases as the – through the year as we bring new wells on, we expect to continue to register improvements in total cash cost per BOE. With production and discretionary cash flow ramping up, our current budget would generate $30 million to $35 million of free cash flow, which equates to a free cash flow yield of 35% to 40%. At this moment, Lonestar intends to principally focus this free cash flow to continue to reduce long-term debt and associated interest expense. Now, turn to Page 4 please. Before we take a dive into the performance of our capital program, I would like to recap the net results of our restructuring and acquaint you with the robust asset value that underpins the equity within that current capital structure. Our restructuring, which was completed on November 30 as of last year, was value preserving and consensual. Through that process, $250 million of unsecured debt and $100 million of preferred equity were exchanged for common equity, while free cash generated in the second half of 2020 reduced bank debt by $45 million. The net effect has been to streamline our balance sheet and reduce net debt to $240 million, which consists of an RBL and an amortizing term loan. Reduced long-term obligations and increased revenues, reserves and commodity prices, puts the equity at an extremely undervalued position today. At year end 2020, the PV-10 of our PDP reserves alone sit at $361 million at $55 oil and $2.75 gas. That means our PDP value, less debt, equals $121 million, or $11 per diluted share. It’s also worth noting that internally, we see continued ramp up in net PDP PV-10 as we bring on our 10-well program. Now, please turn to Page 5. The graph on the top right indicates the reduced long-term obligation, limited interest expense and dividend payments totaling $37 million annually, with 2021 expected interest expense of $14 million. I’d note that we expect to reduce interest expense each quarter as we further reduce debt with free cash flow, which will also reduce our average LIBOR spread on our RBL further cutting interest costs. The graph on the bottom right summarizes our guidance, which we’ve already covered, but drives home the significant level of free cash flow we expect to generate in spite of hedge losses, which at the strip will exceed $30 million in 2021, but then decreased dramatically as the price in our book escalates in ‘22 and ‘23. Please now turn to Page 6. As we mentioned, Lonestar reported net oil and gas production at 10,377 BOE a day. I would note that we did experience modest reductions in oil and gas sales as a result of temporary shut-ins related to winter storm Uri. 1Q production consisted of 54% oil, 21% NGLs, and 26% gas. Resumption of activities have boosted current production as is noted by our little Longhorns there as a comparison and current rates are 12,500 barrels a day. Lonestar expects further growth in the second half of the year, which should boost rates to somewhere in the mid-13,000 barrel a day equivalent ranges. That will also serve to establish a more profitable higher margin base upon which to run our business. Now turn to Page 7 please. Lonestar assets continue to deliver favorable wellhead realizations, with 1Q ‘21 wellhead prices of 42.63 of BOE, that’s up 47% over the prior quarter. Lonestar’s wellhead crude oil realizations were $55.74 that reflects a $2.10 discount to WRI. Our NGL price of $21.96 equated to 38% of WTI, a substantial improvement over a year ago. Lastly, in the quarter, our wellhead natural gas prices price averaged $5.35, reflecting $1.79 premium to Henry Hub. Ordinarily, that discount is about $0.10. The first quarter natural gas dips were positively impacted by the effect of high realizations achieved in February, resulting from increased gas prices during winter storm Uri. On the expense side of the equation, Lonestar initiated an aggressive cost reduction measure starting in the second quarter of 2020, which continued to deliver a lower operating cost structure for the company, both on an absolute dollar basis and a per unit basis. The graph in the top right shows that our lease operating expenses, which do include work-over expenses and are shown in black, were 44% lower on an absolute dollar basis and were cut 22% on a unit basis from $5.81 to $4.55 year-over-year. The graph on the bottom left shows that our total cash expenses, which include the cash portions of lease operating, gathering, processing, transportation, production taxes, G&A and interest, were reduced 18% from $20.28 per BOE to $16.70 per BOE. It’s only logical that our unit cost structure is poised for further reductions as production ramps up over the course of 2021. Please now turn to Page 8 where we will start to dig into operations. The cornerstone of our central region operations are our Cyclone and Hawkeye assets, which continue to perform extremely well. On today’s call, we will discuss three sets of wells, which are highlighted on the leasehold map on Page 8. Now, turn to Page 9. Our joint venture with Marathon was kicked off in 2020 with the Hawkeye 14-16 pad. These wells were augmented by a trade we did with EOG which not only elongated the laterals, but got us into some better rock. These wells averaged nearly 1,500 BOE a day in their first month on stream and have outperformed based on Von Gonten’s Hawkeye base case type curve by 55% cumulatively as you can see in the graph in the top right quadrant. Based on this outperformance, our third-party engineers upgraded their EURs by 27% to $900,000 BOE per well at year end. And you can see that these wells continue to perform very well compared to that upgraded forecast. The economics associated with these wells is summarized in the bottom right quadrant and are at 123% currently and needless to say we are pleased. Now, please turn to Page 10. In February of ‘21, Lonestar began flow-back operations on three gross 1.5 net wells, the Hawkeye 33, 34 and 35. These wells recorded initial rates over a 30-day period of $938 BOE a day, 91% of which was crude oil. Recently, Lonestar introduced artificial lift operations on these wells and they have responded favorably, with current production rates still averaging over $800 BOE a day. These 11,000 foot laterals were completed for $6.5 million, which is a nice saving compared to the Hawkeye 14 pad, which were completed for $7.7 million. The production graphs on the right side of the page show a high degree of conformance to our third-party type curve and our completed well costs, our new Hawkeye wells are on track to earn 77% internal rates of return at $55 and $2.75. Lastly, I’d add that we have in fact initiated drilling obligations on our next 3-well pad in the Hawkeye area and we expect those wells to come online late in the third quarter. Now, please turn to Page 11. We will now move to our central region, where our recent activity has been focused on our high return Horned Frog asset in La Salle County and we will discuss flow-back operations on our recent 2-well padded at Horned Frog West and drilling activity on newly acquired acreage on the Alderman 1 and 2 wells and some excellent news regarding continued ongoing lease acquisition activities. Now, please turn to Page 12. In March 2021, Lonestar began flow-back operations on a 2-well pad involving the Horned Frog West #1 and #2. Lonestar has 100% working interest and a 78% NRI in these wells. These wells commenced flow-back a little over 2 weeks ago and to-date have registered initial production rates averaging over 1,500 BOE a day. Productions currently comprised of 77% crude oil and NGLs on an equivalent basis. And the chart on the top right reflects a high degree of conformance with our type tight curve. The chart on the bottom right reflects that these wells are the oiliest yet in our Horned Frog area and early indications are that they maybe our most productive on a per foot basis. These wells were placed on stream at a cost of $6.1 million, which is a striking savings over our last pad of identical lateral length, which costs $8.6 million. At these completion costs and production at the type curve, these wells will generate over 100% internal rates of return. Now, please turn to Page 13. Page 13 depicts our leasehold position and associated development locations in our year-end reserve report, with proved reserves totaling $30.4 million BOE and PV-10 of $193 million at $55 and $2.75. Page 14 updates that position and associated development locations from that result from a series of transactions we have executed year-to-date. Now, please turn to Page 15 to discuss the details of our ongoing efforts to build inventory on our highest return asset. Through a combination of primary term leasehold acquisitions, leasehold dispositions and an acreage trade, Lonestar has meaningfully enhanced its position on its Horned Frog asset. The net effect of these transactions is to increase our leasehold by about 15% to a roughly 7,300 acres. Much more importantly, it reconfigured that acreage in terms of development geometry, to not only accommodate significantly more drilling, increasing the number of drillable locations exceeding 5,000 feet in lateral length from 11 to 20, all of which are owned by Lonestar at 100% and increased the average lateral length across the Horned Frog position from just a little under 9,000 feet to a little over 10,000 feet, which impacts reserves and returns on a per well basis. Most importantly, the transactions increased our proved reserves at Horned Frog from 30.2 million barrels equivalent to 40.1 million barrels equivalent and increased PV-10 on the asset from $193 million to $280 million. As the graph in the top right quadrant demonstrates, Lonestar has been able to generate consistent organic growth over a significant period of time and we expect to continue the strategy moving forward. Lastly, Lonestar also completed drilling operations on two 100% wells in our Horned Frog South property, the Horned Frog Alderman #1 and #2. These wells represented a step out from our Horned Frog South block in terms of well controlled and to assist in optimizing these results, we use a new suite of petrophysical logs derived from a new pilot hole and a recent completed pre-stack depth migration to assist in reservoir characterization and geosteering. Because we have the benefit of through bit lateral logs on these two new completions, we have a lot of data on these wells that most operators wouldn’t have at this point in time and our analysis of this log gives us optimism that these laterals have been drilled at rock, that is among the best we have completed at Horned Frog to-date in terms of effective porosity. At current projected well cost, our two new wells would generate IRRs exceeding 100% if they can form to a type curve. Fracture stimulation operations on these wells are scheduled to commence later this month, with first production anticipated in July. Now, please turn to Page 16. Not to go into too much detail this page provides a lot of detail on the timing of recent wells and future wells and summarizes it in terms of timing on drilling and completion operations as well as working interest in lateral lengths to give you some assistance in tying your models to our guidance. Please now turn to Page 17 to wrap things up. I would like you to think of 1Q ‘21 as a stepping stone as it should represent a trough for production costs and profitability. Drilling and completion operations have already lifted production by 22%, which will drive revenues higher in the second quarter. This factor, combined with benefits of stringent cost control and our restructuring, have cut cash operating costs by 18% or 350 a BOE. Again, we would expect to see further improvement in our per unit cost structure as production ramps up. Our long-term debt and associated interest expense are now at very manageable levels and facilitates significant free cash flow. We will focus our capital program on areas where we have demonstrated years of excellence in terms of technical acumen and returns and recent results are yielding returns ranging from 79% to 112%. Our 2021 program has very little susceptibility to increase service costs as we locked in all the high dollar items. Our program is expected to increase average daily production for the second half of the year to a range of 13,400 to 13,800 BOE a day. We keep building inventory in our core area at costs that are barely a blip on our capital budget, which drives further growth in our proved reserve base. I think, the best way to summarize our 2021 guidance is that we are on track to use free cash flow to repay bank debt to a level of $230 million at the midpoint of guidance, which at year end would yield a debt to unhedged EBITDAX ratio of 1.8x, I think the best way to summarize our 2021 guidance is that we are on track to use free cash flow to repay bank debt to a level of $230 million at the midpoint of guidance, which at year end would yield the debt to unhedged EBITDAX ratio of 1.8x, which I think would represent excellent progress toward giving the company the flexibility it needs to position Lonestar for growth through drilling and asset consolidation in the Eagle Ford shale. That concludes our prepared remarks. And I will now turn the call over to the moderator.

Operator: [Operator Instructions] We will take the first question from Charles Meade with Johnson Rice. Please proceed with your question.

Charles Meade: Good morning, Frank and thanks for all of this detail that you’ve you put together in the presentation.

Frank Bracken: Good morning, Charles.

Charles Meade: In particular, Pages 13 and 14, I like the ability to flip back and forth there and see what you guys have done at Horned Frog so far this year? The question for you if you were to kind of how would you characterize the opportunity set not just here at Horned Frog, but also in other parts of your portfolio? If you kind of break it up by how much of it is leasing? How much of the opportunity set is trades? And is there – are acquisitions or kind of small acquisitions, like I guess you could call leasing the type of acquisition, but maybe with acquisitions with some PDPs, is that in the mix at all?

Frank Bracken: Yes, I would say yes to all the above, Charles. We have been at both of these areas for over 5 years now. And it’s kind of funny, you talk to investors and say, well, can you keep doing it. And each year, we keep doing it. And it’s not – its hand to hand combat. These are areas that typically are largely HBPed. And we will use all means necessary to continue to grow those positions, but I would tell you that the same environment that has persisted for the past several years at Horned Frog and Cyclone and Hawkeye still exists, and maybe more advantageously for the company. So, we have we have our eyes on more leasehold in these areas. And I think – and so it can take a lot of different forms, it can take – we have bought an asset out of bankruptcy in the Hawkeye area, for example. So we have lots of tools on the Swiss Army knife. I think the thing to emphasize is that we have always been able to do these kinds of things at really minimal costs. Continuing to use that free cash for the highest return purposes is really important. And we have not tied up a lot of money nor created any really significant drilling obligations out of any of the activities that we have used to grow these positions. So, that’s an important point. But in short, yes, there is more to do out here. We have got identifiable targets. And they don’t always drop in your lap when you want them to. They take a lot of work in some patients, but we are confident that we can continue to do this kind of thing and build the position out further.

Charles Meade: Got it. And then on your – I got your comments about the second half rate being 13.4 to 13.8, do you care to kind of give any indication of where you think your year end exit rate would be?

Frank Bracken: Look, I think – I don’t think it would be too off – too far off from that range. It really depends on well timing as it relates to both getting the Alderman wells on at Horned Frog and then the 910-11 pad on. So I’d rather be a little more circumspect at this point. And suffice it to say that not only will we produce in that range for the second half of the year on average, but it will even be dependent upon when we decide to get rig back up for the 2022 program.

Charles Meade: Got it. Thanks, Frank.

Frank Bracken: Thank you, Charles.

Operator: [Operator Instructions] And we have no further questions in the queue.

Frank Bracken: Alright, everybody. Well, thank you for joining. Thanks for the question and we look forward on building on the results of the first quarter and look forward to getting back together with you in the next 90 days.

Operator: Ladies and gentlemen, this concludes the Lonestar Resources first quarter 2021 financial results conference call. Thank you for joining us today. You may now disconnect your lines.