SBOW (2020 - Q1)

Ladies and gentlemen, thank you for standing by, and welcome to the SilverBow Resources First Quarter 2020 Earnings Conference Call. [Operator Instructions] As a reminder, today's conference is being recorded. It is now my pleasure to hand the conference over to Mr. Jeff Magids. Please go ahead, sir. Jeff Mag

Thank you, Nicole, and good morning, everyone. Thank you very much for joining us for our first quarter 2020 conference call. With me on the call today are Sean Woolverton, our CEO; Steve Adam, our COO; and Chris Abundis, our CFO. Yesterday afternoon, we posted a new corporate presentation to our website and will occasionally refer to it during this call. We encourage listeners to download the latest materials. Please note that we may make references to certain non-GAAP financial measures, which are reconciled to their closest GAAP measure in the earnings press release. Our discussion today may include forward-looking statements which are subject to risks and uncertainties, many of which are beyond our control. These risks and uncertainties are described more fully in our documents on file with the SEC, which are also available on our website. With that, I will turn the call over to Sean.

Thank you, Jeff, and thank you, everyone, for joining our call this morning. First and foremost, we hope that everyone listening as well. The COVID-19 virus has impacted both the macro outlook of the economy and our day-to-day life. We continue to take the precautionary measures to safeguard our employees, contractors, vendors and other stakeholders. In response to current market conditions, including the recent outbreak of COVID-19 and the rapid decline in commodity prices and economic outlook, we made strategic decisions to optimize our 2020 operating plan. First, from a capital standpoint, we elected to suspend all drilling activity until at least the latter part of this year. We are a returns-driven company, and the commodity price outlook did not support what was originally slated to be a liquids focused development plan. We do believe superior returns exist within the industry, the highest of which will be unlocked through opportunistic A&D. Second, we have undertaken an effective production management program. We are ensuring economic returns through production curtailments and by aligning production with economically supportive prices in the future. Third, we took proactive measures in regards to our risk management program. In March, we monetized excess oil derivatives over the remainder of 2020 and 2021 to bring forward $38 million of cash proceeds to bolster our balance sheet for the near term. We decreased our net debt position by $23 million quarter-over-quarter, thereby increasing our liquidity. We have also taken advantage of the recent uplift in gas prices to layer on additional hedging into 2022. This allows us to lock in returns ahead of future development. While our budget and activity outlook has changed, our business strategy remains the same. We are building a well-balanced portfolio mix and taking advantage of the relative outperformance in natural gas prices. We are better suited to navigate near-term volatility in commodity prices compared to peers given the optionality built into our D&C program. We focus on the variables in our control and look to generate sustainable returns across our portfolio with upside leverage to both oil and gas prices. Given the current gas strip, we have the optionality to pivot to gas development late this year and early next year. Our low-cost gas acreage has always been a key lever in our arsenal. As we previously disclosed, we recently doubled our gas acreage through an acquisition, which closed just after quarter end. This provides SilverBow with further upside should natural gas prices continue to improve. We also divested noncore overriding royalty interest in Wyoming, which we expect to close in the second quarter. I'm very proud of our team's ability to execute on these well-timed transactions while working remotely. We reduced our 2020 CapEx to a range of $80 million to $95 million, a decrease of approximately 55% or $100 million compared to our prior guidance range. At current strip prices, we are targeting approximately $40 million to $50 million of free cash flow for full year 2020. Assuming no further drilling activity, we expect to generate free cash flow above that range in 2021. As I mentioned earlier, we have optionality to generate high rates of return through the drill bit on our gas acreage. Many of the opportunities we have today are the result of operational improvements and A&D transactions we have made in recent quarters. Based upon the midpoint of our guidance and implied exit rate production levels for 2020, our maintenance CapEx is in the range of $75 million to $85 million per year. In summary, our first quarter actions resulted in $26 million of free cash flow for the quarter, $23 million of increased liquidity and the well-timed acquisition of offsetting acreage in the western Eagle Ford gas window. We have established a compelling risk reward opportunity for our stakeholders over the next several years at current prices. We are in the process of ramping up our semiannual borrowing base redetermination. Based on the current state of commodity prices and constructive conversations with our banking syndicate, we expect a 15% to 20% reduction from our stated $400 million borrowing base. Despite this anticipated reduction, we have sufficient liquidity to enact our go-forward business plan. Finally, navigating near-term headwinds will require a flexible strategy that optimizes returns in real time. We will continue to assess the natural gas market dynamics including the impact of COVID-19 and lower crude oil prices on the natural gas supply and demand outlay. Currently, we see an optimistic setup of supply and demand factors that support higher rates of return within our portfolio and very favorable free cash yield for our investors. We plan to provide the market with interim updates as necessary pertaining to any material changes in our business plan. With that, I will turn the call over to Steve to provide an operational update. Steve, please go ahead.

Thank you, Sean. As we reflect on the first quarter, it has been one of extremes as we work to ensure the safety of our employees, contractors and their families. At the same time, we are adjusting our field operations to meet the economic impacts and to deliver best-in-class results. Before commenting on our quarterly highlights, we will share some key actions we took to protect our balance sheet and maximize cash flow. In mid-March, we enhanced our work protocols to ensure we maintain a safe work environment for our office employees as well as our field personnel that are the front line of our operations. We elected to curtail existing production and to defer bringing on new production. We view this as a prudent action to preserve the economic value and our resource base. We have curtailed approximately 50 million cubic feet per day of net gas production and 2,000 barrels per day of net oil production. We plan to bring this production back online with improved pricing currently forecasted during the latter half of this year. We also elected to defer turning to sales 5 DUCs and previously -- and 3 previously completed wells in the McMullen oil area, for a total of 8 wells that we intend to bring online in the third quarter of this year. Our updated production guidance of 115 million to 140 million cubic feet equivalent per day for the second quarter and 164 million to 185 million cubic feet equivalent for the full year reflects an increasing mix of gas. As illustrated on Slide 11 of our corporate presentation, we have demonstrated the ability to bring on a significant amount of oil or gas production in a short time frame. Since the beginning of 2019, we brought online 4,000 net barrels per day over the next -- over the span of 6 months as well as 50 million cubic feet per day in as little as 45 days. This further supports our ability to pivot our development program between oil and gas locations, especially as we view the potential for gas development in late 2020 and early 2021. We continue our industry-leading focus on reducing operating expenses through drilling and completion efficiencies, contingency schedules and workflow optimizations. We value the relationships we have built with our service providers and continue to work with them as partners to ensure our mutual success. As it relates to the first quarter, we drilled 11, completed eight and turned to sales five net wells. Our drilling results demonstrate an improvement in drilling efficiencies of more than 300 feet per day, or 48% over 2019. This represents a cost reduction of $80 per lateral foot, which is a 28% decrease over 2019. Our completions team continued its improvement trend as well. They successfully increased completed lateral length footages per day and routinely placed 9% more proppant per day than 2019, while maintaining similar per well cost. In our McMullen oil area, we drilled eight, completed five and turned to sales two net wells. The two well pad purchase sales yielded a very strong choke-managed rate of 1,700 barrels of oil equivalent per day at 84% liquids across two 10,000 foot laterals. As we look toward the latter part of 2020, we are preparing to initiate a capital program aligned with materially higher natural gas prices. We have the optionality for developing additional Webb County dry gas where we have ample inventory, deep technical experience and predictable returns. Given the updates to our operating plan, we are now targeting roughly $10 million in operating expense reductions this year across LOE, T&P, production taxes and G&A. We expect to realize further cost savings as a result of working closely with our vendors, implementing improved efficiencies and further leveraging our area expertise. Finally, we are in the process of integrating our recent Eagle Ford acquisition, which adds incremental PDP production of approximately 10 million cubic feet per day across 8 wells at no additional overhead costs. We expect to realize operating expense synergies on these assets as they are immediately offsetting our existing acreage. We are now assessing the best development strategy of this large acreage position, which could include seeking a partner to fund the development with higher gas prices in the future. With that, I will turn it over to Chris.

Thanks, Steve. In my comments this morning, I will highlight our first quarter financial results as well as our operating cost, hedging program and capital structure. Our first quarter revenue was $53.4 million, with natural gas representing 79% of production and 59% of revenue. Realized pricing for the quarter was 98% of both NYMEX WTI and Henry Hub and 27% of WTI for NGLs. Although our realized prices have seen a slight pullback in recent quarters, Gulf Coast markets consistently trade at a premium to other basins and our asset base benefits from its competitive advantage. As shown on Slide 13 of our corporate presentation, we realized higher pricing on both oil and gas versus in-basin peers. Our realized hedging gain on contracts for the quarter was approximately $13 million, not including the $38 million from the hedge monetization Sean previously mentioned. Based on the midpoint of our guidance, our total estimated production is 64% hedged for the remainder of 2020. Our gas production is approximately 67% hedged with a weighted average price of $2.63 per MMBtu. And our oil production is approximately 81% hedged with a weighted average price of $57.40 per barrel of oil. For 2021, we have 66 MMcf/d of gas hedged at a weighted average price of $2.33 per MMBtu, inclusive of floor prices for our gas collars. Our gas collars next year represent approximately 85% of our hedge position and have a weighted average ceiling price of $2.91 per MMBtu, preserving material upside exposure to natural gas prices. Additionally, we have over 2,000 barrels per day of oil hedged at a weighted average price of $51.85 per barrel. Please note, this reflects our hedge book as of May 4. We have taken advantage of the recent strength in gas prices to layer on additional downside protection over the next 24 months. Inclusive of the changes made to our budget, we now have $60 million in gas revenue secured for the remainder of 2020 and $56 million for full year 2021. The risk management is a key aspect of our business, and we have been proactively adding oil basis and monthly roll hedges. Turning to cost. Lease operating expenses were $0.28 per Mcfe. Transportation and processing costs were $0.32 per Mcfe. Production taxes were 5.6% of oil and gas. Adding our LOE, TMP and production taxes together, total production expenses were $0.74 per Mcfe. Cash G&A for the quarter was $4.7 million. Our cash operating expenses, including G&A, totaled $0.97 per Mcfe compared to $1.01 a year ago. We proactively managed G&A to maximize our efficiency and maintain our low-cost structure. Our cost structure allows us to remain profitable at low ends of the price curve, and we believe gives us a distinct competitive advantage to our peters. Adjusted EBITDA for the quarter was $46 million. As Sean noted earlier, we took prudent measures towards the end of the quarter to protect our balance sheet and maximize free cash flow. Inclusive of the cash proceeds from the hedging line, we generated approximately $26 million of free cash flow for the quarter. Given the uncertainty surrounding macroeconomic factors in commodity prices, we are temporarily suspending our cost guidance on a per unit basis. Finally, turning to our balance sheet. We reduced net debt by $23 million during the quarter. As of March 31, we had $290 million outstanding under our revolving credit facility. Approximately $36 million in cash and a liquidity position of approximately $146 million. We reduced our net debt leverage from 2.3x to 2x year-over-year. This better positions us to offset the impact of lower pricing on our adjusted EBITDA in the near term. Starting in the second quarter, it is important to note that for covenant calculation purposes, we will be able to recognize the $38 million of cash proceeds from the unwound transaction in the month they would have settled as if they had not been unwound. This provides us with $25 million in 2020 and $14 million in 2021 to be added to our adjusted EBITDA for the purposes of calculating our leverage ratio. As Sean mentioned earlier, we expect our borrowing base redetermination to be finalized in the next week and believe we have sufficient liquidity to meet all our obligations. I would like to thank our banking syndicate for their continued support. At the end of the first quarter, we were in full compliance with our financial covenants and had significant headroom. And with that, I will turn it over to Sean to wrap up our prepared remarks.

Thanks, Chris. To summarize, SilverBow is set up to generate meaningful free cash flow for the remainder of 2020 and 2021. We estimate that for every $0.10 per Mcf increase in gas price, we will realize an incremental $4 million of annualized free cash flow. Our team continues executing our strategic objectives and optimizing our go-forward plan. As a result, we are prepared to pivot to gas development later this year and we hold a constructive outlook of domestic supply and demand dynamics that support higher gas prices. As always, we are returns focused. Additional spending in today's environment will be supported by a strong hedge position and improving capital efficiency. As the year unfolds, we will make further improvements to our plan that generate the highest rates of return for our stakeholders. We believe strategic A and B will play a critical role in our future success and we will continue to bolster our portfolio with favorable opportunities. Thank you for joining us for today's call and for allowing us to share our results. We look forward to providing you further updates as the year progresses. To everyone listening, I hope that you and your families are staying safe and well. I look forward to seeing you in person in the near future. With that, I will turn the call back to the operator for the Q&A portion of the call.

[Operator Instructions] The first question will come from the line of Duncan McIntosh with Johnson Rice.

First off, thanks for the detailed guidance for both second quarter and 2020. I know it's a tough environment to guide in with so much uncertainty out there right now. So I really appreciate you kind of giving us an idea of how you're looking at the rest of the year. My question is, the ranges you provided, both in the second quarter and '20 are pretty wide and understandably, obviously. So if you could maybe talk about some of the scenarios that would kind of put you maybe towards the lower or the higher end of that range, if -- what's kind of baked in there with assumptions around curtailments and bringing those volumes back on? Any color there would be appreciated.

Dun, and the comments as well. Definitely difficult environment to provide guidance, but we felt that we understand our business enough that we wanted to at least get some ranges out there. Specific to the ranges and the guidance, what we are anticipating is continued curtailment through the second quarter, both with the oil that we've commented on in our release as well as the gas. For now, our guidance anticipates that we'll return those volumes back to production at the start of the third quarter. Of course, we're going to maintain flexibility, and we'll adjust that plan, either up or down, relative to our net realized wellhead prices. As you know, not only our top line price is lower, but also differentials and gathering fees are lower as well. So we definitely are looking at the net realized wellhead prices to make our decision.

And then as we kind of look out into next year and the end of this year, as you shift your focus back on to gas, kind of any color how you're thinking about a '21 program? In the opening remarks, you mentioned the possibility for maybe a drillco on the newly acquired positions. So just maybe a little more color there would be great.

Yes. No doubt, 2020 is going to be a year that, at least for the second and third quarter, will be viewed as almost last quarter. So our objective is really to position the company as we get into '21 and through '21 to be at a position operationally, financially than it was prior to coming into the current macro environment. We do anticipate potentially picking a rig up towards the end of this year and then drilling into next year. And as we mentioned, we would do that on our gas position. In terms of the amount of gas acreage that we now hold, we would look to bring a partner in. Over the years, we've built relationships with a number of players, both domestic and international, that have expressed interest in SilverBow's gas assets, and with the move towards higher gas prices as well as the expanded position, we're looking forward to restarting those discussions as we expect there will be interest. Our plan is to continue to only drill with a capital program that's supported by cash flows. One thing Steve and his operational team have done is become so efficient that we can drill 30% to 40% more in terms of footage in wells each year. And so in terms of living within cash flow, that's where we envision bringing in a partner to help support that very capital-efficient program.

The next question will come from the line of Neal Dingmann with SunTrust.

It's Jordan Levy calling in for Neal. Just looking into the curtailed volumes, just trying to get a sense of what sort of drove the decision as it relates to both the gas and, obviously, we've seen a lot of operators on the oil side, but less so on the gas shut-in and what -- maybe what component of that is -- are we talking about both dry gas window and oil window wells or kind of just the associated two stream production from some of the mixed volumes?

In terms of curtailment, we shut-in both oil wells that reduced some gas production. But we also did make the decision to shut-in some dry gas production. So of the 50 million a day, I would say probably 80%, 85% of it is associated with dry gas wells with the remaining 15% plus or minus associated with oil-producing wells. And we did that just looking at the economics and the economic position of gas prices being low. And we anticipate gas prices will be low over the next couple of months, but do see a significant strengthening in prices and the strips already bearing that out. As the shut-in on oil and the reduction in capital investment by the industry, these oil wells will really bear out over the latter half of this year. And we're anticipating really coming out of next year's withdraw season, being at very low withdraw or inventory numbers, that should really set gas up well strong for the whole part of '21 and even into '22.

And just one more, if I could. Just thinking more broadly about kind of the M&A environment, knowing that it's definitely challenged right now. But if you could just highlight some of the things that -- some of the characteristics you guys liked in the last deal you all just executed on? And what sort of characteristics would fit the bill for you guys going forward as it relates to accretive deals?

Like we've always said, we're a returns-driven company, and we'll look to capture returns, be it through the drill bit or through A&D transactions. So the recent deal that we did was essentially a PDP purchase with tremendous amount of acreage and upside optionality associated with it. And the returns we felt like on a PDP basis competed favorably to our drilling capital. So that model will be one that we continue to employ in this environment. And what we're excited about and what we've been working hard on over the last couple of years is a single base and low-cost strategy that really sets up well in the current environment. It's a margins business and the companies that keep their margins high continue to at least be profitable in these low-price environments. And we think that a number of competitors will unfortunately not be in that situation and will be forced to liquidate. So we'll continue to look for A&D opportunities that compete for capital head up or even their drill bit capital.

[Operator Instructions] Our next question will come from [indiscernible].

A couple of quick questions. So one, there's been some debate out there in terms of the downhole impact to unconventional wells when they're shut-in. Can you talk a little bit about the analysis you guys did? And what your view is on the well productivity when you turn these wells back on?

Yes, I can start and then Steve you're welcome to weigh in as well. There is some history track record of shutting wells in, in the business, both horizontal and oil shale wells as infill development has occurred and you shut-in wells to protect against frac interference. So we've had history of wells being shut-in for 30-plus day days. It will be interesting to see if shut-in periods extend significantly beyond that. The industry really hasn't been in an extended shut-in period well over probably 15, 20 years. It was more common back in proration times in the 80s and early 90s, of course, different environment where there are more vertical wells. So what we're doing to monitor and help us understand the reservoir is looking at shut-in pressures, how those pressures are building. And we'll monitor those to assess. It will be a great opportunity to assess reservoir performance, enhance our EUR estimates, but also look to make decisions when it's appropriate to open back up. The time will tell in terms of impact to long-term productivity. We feel very comfortable on the dry gas side, a little bit more caution, I think, on the oil side. Steve, I don't know if you'd like to add to any of those comments.

Just a couple of points. One, we've been seeing very strong progressive buildup pressures. Secondly, I kind of remind everyone, we're in the higher energy part of the basin. So we have, obviously, dry gas and then we also have oil that's associated with gas, in some cases, retrograde. So the high energy part of the basin helps us out with respect to return to production. And then lastly, just like Sean mentioned, we've had some cessations where we've had to do some RTPs. And in returning those production volumes back after anyway, 30 to 45 days of shut-in, some cases a little bit longer, we were pleasantly surprised with very strong cost reductions for the better part of the week. But it does look favorably because right now, it appears that they're tracking back to the EUR position that they were prior to the curtailment. So favorable so far, and we're modeling that accordingly.

And then for a second question. It's been interesting seeing the gas strip rise and the gas rig count actually fall, including you guys. I guess at what point do you see the strip as stable enough? Is there a particular price that you'd target where you'd essentially go lock in more gas on the forward curve for locking the price and bring a rig back on potentially ahead of that Q4 schedule? Like was there a price that you'd be looking for that would make that make sense for you guys? Or are you pretty set in terms of waiting until kind of late Q4 to bring the rig back on?

In terms of pricing and associated returns, we did add a slide to our corporate debt that looks at gas plays across the country, our position in Webb County competes very favorably. We show a full cycle, 15% return at 270. Would tell you that our corporate threshold is higher than that. We typically like to drill in the 30-plus rate of return projects. So, we're looking for really probably $2.90 to $3-plus environment to start locking in prices in advance of the development program. And based upon our macro view and reviewing and assessing a lot of the different folks out there that have put views forward for '21 and into '22, we think that $3-plus is going to be a realistic target. And for now, we're holding off waiting to get to that level before we start hedging in anything. But what we will do is continue and we take a very logical progression in how we lock in our hedges. We'll start with PDP first, probably lock in those at the sub-$3 level. And then look to lock in the development program in stages as gas prices improve, and that's the strategy we've employed in the past and have been very successful with it.

With that, we are showing no further audio questions at this time.

Okay. Jeff, you want to wrap up the call?

Yes. Thanks, everyone, for joining our first quarter call and look forward to providing an update for the second quarter in August. Thanks again.

That concludes today's conference call. We thank you for your participation and ask that you please disconnect your lines.