SBOW (2020 - Q2)

Ladies and gentlemen, thank you for standing by, and welcome to the SilverBow Resources Second Quarter 2020 Earnings Conference Call. [Operator Instructions]. I would now like to hand the conference over to your speaker, Jeff Magids, Senior Manager, Finance and Investor Relations, SilverBow Resources, Inc. Sir, you may begin. Jeff Mag

Thank you, Amanda, and good morning, everyone. Thank you very much for joining us for our Second 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. And with that, I will turn the call over to Sean.

Thank you, Jeff, and thank you, everyone, for joining our call this morning. First, we hope that everyone listening is well. I would like to thank our employees and our contractors as well as our vendors and other key stakeholders for their dedication and resilience during these times. We continue to take the necessary measures to ensure the health and wellbeing of all employees and contractors. Safety strong is of paramount importance. In the face of a global pandemic and an abrupt decline in commodity prices, I am pleased to report that SilverBow delivered strong operational and financial results. The actions we took in March and April allowed the company to fortify its balance sheet, optimize its capital spend and timing and realize expense savings. Specifically, during the quarter, we generated $14 million of free cash flow and reduced our revolving credit facility borrowings by $20 million quarter-over-quarter. Looking ahead, SilverBow is favorably positioned compared to our peers, given the relative visibility we have in our cash flow and the flexibility we have in our development program. As noted in our press release yesterday, we plan to move forward with the gas development program in the fourth quarter, focused on our high rate return assets in Webb County. What's even more impressive is that we reaffirm our previously stated goal of $40 million to $50 million of free cash flow for 2020, including the additional development. The second quarter marks the low point of our quarterly production profile for the year. During the third quarter, we will complete and bring online our inventory of DUCs deferred earlier this year. In the fourth quarter, we will commence drilling in our Webb County dry gas area. Given the late timing of these projects, we anticipate the majority of the production and EBITDA benefit from this development to start in the first quarter of 2021. However, we do expect our EBITDA, inclusive of our amortized hedge gains, to return to first quarter levels for the fourth quarter of 2020. Looking into '21, SilverBow is poised to generate meaningful free cash flow and benefit from increase in gas prices, which we believe are biased higher in '21 from current levels. At current strip pricing, we plan to spend within cash flow, grow production in the high single-digits and maintain a similar EBITDA level, inclusive of amortized hedge gains. In addition to hitting this trifecta, we expect free cash flow in the range of $20 million to $40 million. We forecast the growth in our production to come from our gas assets, with oil and NGLs flat year-over-year. Based upon our current share price, our full year 2020 guidance implies a 90% free cash flow yield and a greater than 50% free cash flow yield in 2021. Furthermore, we have additional capacity in our hedge portfolio from a gas exposure standpoint. Looking at gas prices today, the curve has moved up by close to 15% in 2021 compared to pre-COVID levels. Chris will provide further detail in his comments about our use of collars to execute our risk-mitigation strategy. As we look to formalize our 2021 budget over the coming months, our strategy remains the same. Having a well-balanced portfolio provides us both drilling optionality and the opportunity to pursue accretive corporate and asset level transactions. We see oil and gas prices inversely correlated, and thus our countercyclical bolt-on activity is a key differentiator for us. Furthermore, we're optimistic about underlying gas price fundamentals and continue to manage our balance sheet to provide us with financial strength and flexibility. With that, I will turn the call over to Steve to provide an operational update. Steve, please go ahead.

Thank you, Sean. Over the second quarter, we curtailed on average 57 MMcf per day of net gas production and nearly 2,000 barrels per day of net oil production. From a timing standpoint, May was the low point in production for the quarter. In June, we returned approximately 2,750 barrels per day of net oil production to sales as a result of favorable midstream partnerships. We returned these wells to production ahead of schedule, which drove our oil and NGL volumes above their guidance ranges for the quarter. We anticipate the remaining 850 barrels per day of net oil production to return to sales in the third quarter and the remaining 43 MMcf per day of net gas production by year-end. By and large, our technical teams are not seeing any degradation in well performance related to curtailments as we show on Slide 16 of the corporate presentation. We are currently performing 2 operational processes to optimize the management of our curtailed program. First, we are managing these lease obligations and other requirements to ensure compliance. Second, as shut-in wells have returned to production, we are conservatively managing chokes to optimize production rates and maintain reservoir integrity. I'm very proud of the incremental cost efficiencies our team has been able to identify. On the LOE front, we have been actively partnering with our vendors on procurement initiatives to further reduce costs on items like chemicals, rentals and other ancillary services. We have been successful in identifying and reducing operating costs on our recently acquired gas acreage, including the decommissioning of three aiming units. Additionally, the SilverBow team continues to assess the many subsurface characteristics needed to establish a development plan that meets commercial expectations for this new acreage. As a returns-driven organization, we want to make sure all new development locations meet our investment thresholds. Thus far, this acreage appears very similar to our existing Oro Grande asset and could present further cost synergies. On the capital side, we secured favorable early mover pricing on the 5 wells we plan to complete in the third quarter. This strategy reduced our expected capital spend for these projects by approximately 30% from the original AFE estimates. As noted in our earnings release, cost efficiencies and project execution have allowed us to maintain our 2020 free cash flow guidance, while also adding $12.5 million to the midpoint of our 2020 capital budget. The additional spend in the fourth quarter is for 8 of 9 planned dry gas wells in Webb County. The ninth well is the last of a 6-well La Mesa pad, which is planned to reach total depth in 2021. Outside of the La Mesa project, the remaining 3 wells in the fourth quarter are associated with Fasken Upper Eagle Ford drilling. Our revised 2020 capital budget of $95 million to $105 million implies $40 million to $50 million of CapEx in the second half of the year. We estimate approximately $20 million will be incurred in the third quarter related to completing the McMullen oil wells deferred from earlier this year. The remaining $25 million is attributable to the dry gas development expected to take place in the fourth quarter. As part of our release yesterday, we provided guidance for the third quarter and full year 2020. For the third quarter, we are guiding to a production range of 173 to 180 MMcfe per day, 72% being gas at the midpoint. For the full year 2020, we are increasing our production range from 164 to 185 MMcfe per day to a range of 176 to 184 MMcfe per day, 76% being gas at the midpoint. Our provided guidance assumes ethane rejection for the remainder of the year, although we will continue to evaluate and make monthly elections in accordance with commodity prices. As Sean alluded to earlier, we believe the actions taken to manage production and reduce costs favorably positions the company heading into the year. Our net oil production is expected to reach the high point for the year late in the third quarter. With the return to activity towards year-end, we expect to enter 2021 with a significant and opportunistic amount of flush gas production. Our goal is to repeat the timing, savings and well performance demonstrated with our first 6-well La Mesa pad. While we view oil and gas prices to be inversely correlated over the near term, our diverse portfolio allows us to remain flexible and adaptable to market uncertainties in our operations. As such, we continue to operate with a returns-driven mindset in regards to any future development. With that, I'll turn it over to Chris.

Thanks, Steve. In my comments this morning, I will highlight our second quarter financial results as well as our hedging program, price realizations, operating costs and capital structure. Our second quarter revenue was $25 million, excluding derivatives, with natural gas representing 82% of production and 73% of sales. Our realized hedging gain on contracts for the quarter was approximately $18 million. Based on the midpoint of our guidance and our hedge book as of July 31, our total estimated production is 67% hedged for the remainder of 2020. Our gas production is 69% hedged with a weighted average price of $2.60 per MMBtu, and our oil production is 93% hedged with a weighted average price of approximately $45 per barrel. For 2021, we have 67 MMcf per day of gas hedged at a weighted average price of $2.34 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 gas prices. Additionally, we have over 3,300 barrels per day of oil hedged at a weighted average price of approximately $45 per barrel. Notably, our hedges are a combination of swaps and collars with the weighted average price factoring in the floor. As of July 31, our mark-to-market value of our hedge portfolio was approximately $12 million. Risk management is a key aspect of our business, and we are proactive in adding oil bases and calendar month average roll swaps to further supplement our hedging strategy. In fact, SilverBow is one of only a handful of companies that hedged the CMA roll before the recent downturn in prices. In order to combat a sustained period of lower prices, we layered on additional basis swaps during the quarter, extending our protection into 2021. Please note, this reflects our hedge book as of July 31. SilverBow's hedges provided relief from second quarter benchmark prices. Excluding the impact of hedges, SilverBow realized an average gas price of $1.70 per Mcf, an average oil price of $23.82 per barrel and total equivalent price of $1.93 per Mcfe. Including the hedge impact of cash sale derivatives, SilverBow's average realized prices were $2.34 per Mcf of gas, $73.34 per barrel for oil and $3.31 per Mcfe on a total equivalent basis. A combination of SilverBow's hedges and actual volume produced during the quarter resulted in an uplift of $0.64 in our realized gas price and a $50 uplift in our realized oil price. As shown on Slide 14 of the corporate presentation, SilverBow continues to maintain favorable pricing on both oil and gas compared to our in-basin peers. Turning to cost. Lease operating expenses were $0.39 per Mcfe. Transportation and processing costs were $0.35 per Mcfe. Production taxes were 8.2% of oil and gas sales. Adding our LOE, T&P and production taxes together, total production expenses were $0.90 per Mcfe, continuing our trend of total production expenses of less than $1 per Mcfe. Cash G&A for the quarter was $5 million. Our lean cost structure as a competitive advantage as it allows us to remain flexible and sustain profitability during protracted periods of low commodity price. Adjusted EBITDA for the quarter was $26 million. As reconciled in our earnings materials, we generated $14 million of free cash flow. Primarily due to the effects of pricing, SilverBow reported a noncash impairment write-down of $260 million on a pretax basis. Turning to our balance sheet. We reduced total debt by $20 million during the quarter. As of June 30, we had $270 million outstanding under our revolving credit facility, $7 million in cash and $67 million of liquidity. Our cash interest expense was down 20% from a year ago as a result of lower interest rates and debt reduction. We continue to watch the interest rate market and are considering adding swaps to mitigate exposure to future interest rate hikes. Our net working capital deficit was $6 million, a $25 million cash outflow quarter-over-quarter. Given the paydown of our current liabilities during the first half of the year, working capital should be less of a factor from a cash timing standpoint for the remainder of the year. Please note, working capital is excluded from our free cash flow calculation. Capital expenditures totaled $5 million on an accrual basis, excluding acquisition and divestiture activity. During the quarter, we closed a bolt-on acquisition of gas-producing properties and a divestiture of our noncore Wyoming assets. Both of these transactions were previously announced last quarter. In conjunction with the unwinding oil derivative contracts in 2020 and 2021, SilverBow was able to amortize $38 million it received in March in discrete amounts extending from April 2020 through December 2021. The amortized hedge gains factor into SilverBow's adjusted EBITDA calculation for covenant purposes over the same time period. For the second quarter, the add-back was approximately $7 million, bringing our leverage ratio to 2.4x. In total, we received a $25 million benefit in 2020 and a $14 million benefit in 2021 for purposes of calculating our leverage ratio. At the beginning of the quarter, we completed our semiannual redetermination, where our borrowing base was set at $330 million. I would like to thank our banking syndicate for their continued support. At the end of the second 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 his prepared remarks.

Thanks, Chris. To summarize, SilverBow is set up to generate meaningful free cash flow for the remainder of '20 and '21. We hold a constructive outlook of domestic supply and demand dynamics that supports higher gas prices, particularly if oil prices remain subdued, given the natural decline in associated gas production and industry-wide limited drilling and completion reinvestment. Due to our relative balance sheet strength and cash flow visibility, we expect SilverBow to outperform other small-cap peers as our winning strategy continues to bear fruits and provides us with the staying power to potentially consolidate and operate a larger asset base. Our strategy remains intact with multiple playbooks for the future. We pride ourselves in our ability to continue producing high-quality earnings material in addition to putting out guidance for the benefit of all of our stakeholders. Thank you for joining our call this morning and allowing us to share our results. In the face of uncertainty, we find ways to step up, get creative and think outside the box. We look forward to providing further updates on our next call. To everyone listening, I hope that you and your families are staying safe, and I hope to see many of you in person in the near future. With that, I will now turn the call back to the operator for the Q&A portion of the call.

[Operator Instructions]. And your first question comes from Jeff Grampp with Northland Securities.

For Sean, or maybe Steve, on the well cost front, I know you guys have a couple of slides talking about some of the efficiencies and cost reductions that you've seen. Was hoping to dig in a little bit more, I guess, as we think about second half well cost for you guys. Can we kind of compare that to maybe what you were seeing at the start of the year? How much of a reduction have you seen? And if you had to kind of bifurcate that out in terms of kind of internal efficiencies versus maybe some attractive pricing you've seen from service companies, what that split might be?

Hey Jeff, this is Sean. Steve and his team have done a great job driving down costs on top of capturing many efficiencies even coming into the downturn. So why don't I turn it to Steve and let him give you more details on what him and his team have been able to accomplish?

Yes. Thank you, Sean. Jeff, what we've done is we've been able to capitalize on some level loading opportunities with some of the service companies that have commitments with some of the larger companies later in the year in order to fill some of those spaces early on in the year. That's what caused a slight acceleration of the DUCs. Most of that drilling -- most of that being on the completion side. That said, more specific to your question, we're seeing about a 30% reduction from where we were at the end of last year and earlier this year as a current price basis. Much of that discount is coming from the service providers. And I would basically say about of that 30%, about 65% to 70% is coming from the service side and another 25% to 30% is coming from our increased operational efficiencies. As we advance through the year, we're looking for much of that price position to hold through the end of the year. That said, going into '21, we're estimating about maybe a 3% to 5% price increase in our AFE estimates by midpoint '21. Hopefully, that answers your question, Jeff.

Got it. That's really good. I appreciate that. My follow-up was just kind of wondering, I know you guys had a slide on some of the, I guess, a little bit of an improvement in performance from these wells that you guys had shut in. Was curious how you guys are kind of building in the expectations for the performance of those wells? Do you guys think there's some longer term improvement? Is that just kind of a shorter term bump that kind of normalizes over time? And how you guys are effectively, I guess, kind of planning for some of those dynamics.

Hey Jeff, yes, again, this is Sean. From a guidance standpoint, we're modeling, assuming that those wells will return to previous historical decline trends. But we are monitoring and watching reservoir performance, both production and pressures to see if we can get a sustained longer-term uplift. So that's kind of my high-level overview. And again, maybe I'll turn it to Steve if he wants to provide some more color.

Yes. Thank you, Sean. Jeff, as you know, we have a strong weight in our production profile our mix to gas. And so as a gas company, you never know when you have potential for interruptible service. On our oil side, we've got storage capabilities. So when we go back and originally complete these wells on their initial completion, we take a very manage graduated choke strategy in terms of conservatism when we not only flow the wells back, but when we bring them online. That happens to benefit us very well by preserving our fracture conductivity in our frac pack so that when we do have interruptible gas service, to the extent that we can, we go through that same protocol on very managed shut-ins and very managed returns to production. And through that conservative practice, we've been able to see not only flush gas production, but for a period of time elevated gas production that we then continue conservatively to model back to the original decline, even though in some cases, the wells continue to do better than the original decline. We extend that same mentality, Jeff, over into the higher GOR areas for our oil properties. And lo and behold, we see somewhat of the same similar effects, both flush, some early better performance and in some cases, some continued better performance.

And your next question comes from Dun McIntosh.

Looking for maybe a little more color on bringing the rig back in the fourth quarter and obviously going to focus on those 9 wells down there in Webb. As we think about the program for next year, you've talked about increasing your exposure to gas. But I mean, what is that program -- I mean, are you really going to -- is it exclusively kind of a dry gas program? Or do you think that you'll mix in some more liquids wells to maintain a little exposure to that side if you do get more of a recovery on the NGL and oil front as well?

Yes. I would tell you that we'll continue with our strategy of investing in projects that generate the highest returns for us. So we'll continue to monitor near-term pricing. We usually like to look 12 to 24 months out in front of our capital program and even lock in some of that pricing before we take actions in the field. Right now we do see strong gas prices in '21 and into '22. So our view is to start with the 9-well program. That's all in place, and that will actually start moving a rig out in the early fourth quarter, so not too far from today. So we're committed to that. We then believe that we'll take a pause on our capital program towards the end of first quarter, early second quarter of '21. And being that that's still 9 months out, we have in our playbook a combination of some dry gas drilling as the program picks up in the end of second quarter of '21. But we also have some liquids drilling rolled in there, mainly in our southwest LaSalle County area that has kind of a equal blend of oil, NGLs and gas.

All right. Great. And then calling kind of more macro-based, I guess, we've been seeing more and more about exports to Mexico picking up and given your location in the southern Eagle Ford, I'd have to imagine you're paying close attention to that as well. What role does that play kind of in your thesis of really leaning on gas harder going forward? And kind of just what your thoughts are on that scenario in the next 12, 18, 24 months?

Yes. A key investment thesis for SilverBow is our location in premium markets, both on the gas side and on the liquids side. And so what you described in terms of activity picking up flows into Mexico increasing, we are seeing that. We're encouraged also that NGL -- or LNG takeaways are starting to pick up as you look out into September. So we believe prices or demand will return where it was first and foremost, and that's in the Gulf Coast area. So yes, our thoughts around investing in gas as we move into the end of the year is supported, we believe, by the premium markets that we have and the early indications from uptick in Mexico as well as LNG is really supportive of our thoughts.

And your next question comes from Neal Dingmann with SunTrust.

So my question is you guys continue to see nice improvement just on well economics. I'm just wondering -- given efficiencies and cost advantage, I'm just wondering could you kind of give us an idea now on kind of sensitivities, how you're looking at some of your natural gas well economics today? And if your just thoughts are, can those continue to improve? Just -- I'm trying to get an idea of just how much that -- those economics have improved, let's say, in the last 6 or 9 months, given these costs and efficiencies? And is that at a $2 level, $2.50 to try to give us a handle on the sensitivity?

Yes. No, thanks for the question, Neil. We've always said that, especially in our Webb County gas area, $2.50 pricing is really the threshold where we start to get to returns that we like. And typically, we target D&C returns in the 30% range. As we move north to $2.75, that moves closer to 45% to 50%. And then above $3, they get even stronger. So we've always said we like our gas business at $2.50. We'd like it even more at $2.75, and we love it at $3. So we're still of that mindset. And then on the capital side, really, we probably see at least a 20% reduction in CapEx costs that Steve and his team have, I think, long term embedded into the system late last year and into early part of this year. And we may see even stronger reductions depending upon if some of these service costs hold at least over the near term.

And then just lastly, just on cost. I guess would you all walk into longer-term cost here you have in the past? Or I guess, would you lock in and do you all anticipate costs going much lower from here?

Yes. No, I think we really think keeping flexibility and optionality is a critical part of managing the business. And so I would say, no, near term, we'll probably -- I don't envision us locking in any longer-term contracts. Some of that is, as we look into '21, having some cadence in our capital spend, where we ramp up activity, increase cash flows and then scale back to ensure that we spend within our cash flow. So we're probably not set up at the current scale to do long-term lock-ins and it just fits our strategy for now. It is something that we desire to potentially get to as we get to be a larger company and have more scale.

And your final question comes from Josh Young with Bison.

So I guess just high level, obviously, your stock at this point is trading essentially as an option, I guess, on some combination of gas prices and your guys' ability to survive. In that context, how do you think about essentially sustaining the business and extending either the longevity of that option or kind of increasing the payoff, right, with $470 million, what, or so of debt versus a $40 million market capitalization? Obviously, it's pretty lopsided. And looking at this giant write-off that you guys just had to do, it would be interesting to get your guys' thoughts at a high level in terms of how you're working to extend or improve the value of that option.

Yes. Yes. We've always been firm believers that, hey, you run the business the way it's supposed to be run, and the market should reward you for long-term performance. We've always struggled to understand the market's undervaluing of SilverBow. With that kind of as a backdrop, I would say that the -- extend the runway through this challenging period is, first and foremost, on our minds. We took actions early on to shore up our balance sheet, ensure that we had liquidity, right, cash being king when there's great times of uncertainty. We managed that we thought -- we believe very effectively. The next step then is how do you start to reinvest into this lower-priced commodity environment that we find ourselves in. So we've set up to where we have sufficient liquidity to start the capital program up. We believe that we have clear visibility through '21 and into '22 to keep favorable liquidity and leverage metrics. And we believe that what you're going to start to see over the next 12 to 24 months is the necessary consolidation within each of the key basins in the United States. And we believe the Eagle Ford is one of the key and most primary basins to do that. And at this point, there's really not a basin consolidation champion. SilverBow wants to play in that environment. We think extending the runway and doing that while demonstrating very efficient operations, a low-cost structure and prudent capital allocation is the way to win that consolidation environment.

Okay. Great. And as a follow-up, can you talk about -- so you guys talk about service cost savings, that those are kind of found money because there's a oversupply environment. Can you talk about overhead changes to the business that are kind of in your guys' control? And then also how your guys' operations benchmark versus your peers. So there was a prior question about that, and you guys did address kind of operating costs and efficiencies to some extent. But looking at kind of third-party literature, it looks a little different from how that's represented. It'd be helpful to understand how you guys see it. And then also kind of what changes you guys are making to kind of get your drilling and completion cost structure kind of, I guess, more competitive.

Yes. What I would tell you is at SilverBow, we came into this downturn what we believe is in a peer-leading position in terms of operating expenses and capital. We were in that environment, as are many of our gas -- natural gas peer companies. It was necessitated because we had a low commodity price that we had to deal with and we have been dealing with for a number of years. So unlike many, many of our oil peers that really had to tighten their belt instantaneously to survive, we were already at a peer-leading cost structure, again, both on the expense side and capital side. We've always looked to try to have an all-in operating cost around $1. We continue to do that. The second quarter doesn't represent the long term just because we shut in so many of -- so much of our volume. There is a fixed cost component in our expense that drove our unit costs up. But when you look at the long-term picture and take out the second quarter, we're not just a top-tier company in the Eagle Ford, but throughout most of the U.S. So we see, hey, prudent actions coming into it. We'll continue to take prudent actions going out of it and just stay very focused on being a low-cost operator.

Got it. That's really helpful. And I do think that it was fantastic that you guys monetized some of your hedges and were able to get bank credit for that monetization and shut in some production. I think that was industry-leading activity. And obviously you have the benefit of a lower debt amount from that. I guess just a last question in terms of gas prices and kind of -- and again, prior questions address this to some extent, but the kind of macro guys and industry consultants are all talking about potentially a higher than strip price for gas going into next year in an undersupplied environment potentially. How well positioned are you guys to capitalize on it? Obviously, your hedges are set up in a way where you can get some extra cash flow from that. But like how much does this company change in potentially, let's say, a $3 or even higher gas price environment?

Yes. So as we look out into '21, we agree that gas prices probably move higher and hopefully significantly higher than the current strip. We currently have 50% of our gas hedged next year. So we're being patient as we think about the -- so other 50% of the -- our view of our production next year to look to hedge that at higher prices than the current strip. We'll look to probably use collars again to capture -- lock in when we think it's prudent, but still be exposed to further upside. Then on top of that, our goal is to manage growth as well as deliver free cash flow. So if prices move up even higher, mid-$3s, pushing $4, we'll probably revisit our capital program and assess if it warrants -- at those prices, our returns will more than warrant additional capital expenditures. And what's great about our business is we can bring on a lot of gas in a short period of time. Last year, within a 5-month period, we acquired a nice block of acreage and from acquisition to first production was that 5-month period, and we brought on 100 million of gas a day. So where we think our strategy is to lock in a piece of it, which we currently have, remain exposed on our current plan and lock in that when it's prudent, but then also be ready and flexible to invest into even higher price if it supports it.

And there are no further questions at this time.

Okay.

Thank you.

Yes, Jeff, if you want to wrap up the call?

Yes. Thank you, everyone, for joining today and look forward to providing you a further update towards the end of the year in November. Thanks again.

Thanks, everybody.

That does conclude today's call. You may now disconnect.