Comstock Resources, Inc.

Ladies and gentlemen, thank you for standing by, and welcome to the third quarter 2020 Comstock Resources Incorporated Earnings Conference call. At this time, all participants are in listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To ask a question during the session, you'll need to press star 1 on your telephone. As a reminder, today's program may be recorded. I would now like to introduce your host for today's program, Mr. Jay Allison, Chairman and Chief Executive Officer. Please go ahead, sir.

Thank you. Thank you for your introduction this morning. And, again, I want to thank everybody that's taken their time to listen to the story today. I know we have a lot of you we know. A lot of you are really good friends and have been forever and ever and ever. So today is an important day in our corporate life. We're all human, and we do understand the third quarter results are somewhat disappointing, quite frankly. And I can speak for me and for everybody else in the management team, we hate it. And, you know, they are disappointing for the reasons that you're aware of. I mean, they're all logical reasons. They're still disappointing. Shut-ins, curtailments related to Hurricane Laura, non-op curtailments, and there's a litany of other small reasons. You know, I think our goal this morning is to share what we see. for the fourth quarter of 2020, as well as 2021 and 2022, and to show you, our stakeholders, how we plan to deliver our balance sheet in those years by using our strength of our peer-leading high margins and low costs that we've created in the Hainesville in a period of time, quite frankly, when the outlook for natural gas is extremely bullish, really the most bullish it has been in over 10 years. Our job in the next 45 minutes really today is to avoid any disappointments in the future and show you how our high margins in the Hainesville coupled with the right size capital program over the next years can deliver the balance sheet and expand our trading multiples so that we all are winners, all based on the commodity gas price outlook that we see today. So thank you for trusting us, and if we have dented – that trust any, please know that the entire Comstock team will work hard to earn it back and even more by giving you 100% of our best as we always have. So now I'll start into our third quarter results and then we'll get to the Q&A and we'll answer any question that you have and be accountable for it. Welcome to the Comstock Resources Third Quarter 2020 Financial and Operating Results Conference Call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly result presentation. There you'll find a presentation entitled Third Quarter 2020 Results. I am Jay Allison, Chief Executive Officer of Comstock. With me is Roland Burns, our President and Chief Financial Officer. Dan Harrison, our Chief Operating Officer. and Ron Mills, our VP of Finance and Investor Relations. Please refer to slide two in our presentation to note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. If you're following this, you can turn to slide three. On slide three, we discussed the highlights of the third quarter. November is the first month where we finally exited the period of very low natural gas prices brought on by the warm winter we had as the November natural gas price closed at almost $3 after hitting a low of $1.50 this summer. The low production levels brought on by the actions of disciplined natural gas producers combined with the decline in associated gas resulting from low oil prices have caused the 2021 future natural gas prices to improve substantially. Since January this year, we have been focused on reducing our drilling activity and deferring completion activity. Those actions allowed us to generate free cash flow even with the very, very low prices we're receiving for our production. The reduced activity we had in the first half of the year combined with the third quarter hurricane activity in our region negatively impacted our production this quarter, as you see. With the stage set for higher prices later this year and into 2021, we collectively decided that we would go back to work in the third quarter. We added two additional operated drilling rigs to bring our working rigs back up to six, which is where we were at the beginning of the year, and currently have three frack crews working to catch up on the backlog of drilled and uncompleted wells. Since our last report, we have put 15 new wells on production, which have a per-well IP rate of 26 million cubic feet per day. We did have a rocky quarter, as I mentioned, on the production front, which partially was self-inflicted as a ramp-up of activity drove our shut-in percentage up to 7 percent in a quarter. The higher spending in the quarter reflects restarting a program we put on hold in the second quarter, but it is the right move as we look forward to improved gas prices that we're in. We did achieve our goal of reducing well cost to just under $1,000 per lateral foot, which is significantly lower than any other Haynesville operator. With recent changes to our completion design, we expect well cost to increase a little bit, as Dan Harrison will go over later. While it made sense to bring well costs down as low as we did with wheat gas prices this year, with gas prices closer to $3 plus now, it makes sense to invest in a little more profit as we believe the wells will have a higher return. As we will discuss more today, the wells will have a higher return. As we will discuss more today, we recently decided to increase our completion activity plan in the fourth quarter by running an additional freight crew. which moves up the completion of seven wells that we plan to complete in 2021. The additional investment will pay off in 2021 to allow us to have a little higher production to take advantage of the higher gas prices. In the third quarter, we completed a follow-on $300 million notes offering to further pay down borrowings on our bank credit facility. We reduced our outstanding bank borrowings from 57% of availability to just 36% of our availability. By freeing up the bank credit facility, we increased our financial liquidity to $928 million. The low oil and natural gas prices combined with low production in the quarter did impact the profits we generated in the quarter. Our oil and gas sales, including hedges, were $212 million. Our adjusted EBITDAX came in at $148 million, and our operating cash flow was $93 million, or 38 cents per share. We reported an adjusted net loss of 13.8 million, or 6 cents a share. With higher production and stronger natural gas prices, we anticipate returning to profitability in the fourth quarter, which is now. I will have Roland go over the financial results in more detail. Roland?

All right. Thanks, Jay. On slide four, we summarize our financial results for the third quarter of this year. Our production for the third quarter totaled 103 BCF of natural gas and 354,000 barrels of oil. Total production of 105 BCFE was 4% higher than the third quarter of 2019. Our oil and gas sales, including the realized hedging gains, were $212 million, which was 15% lower than 2019. And this was all driven by the lower oil and gas prices we had in the quarter. Oil prices in the quarter averaged $33.52 per barrel, and that's with the hedging gains we had in the quarter. And our realized gas price, including hedging gains, was $1.95 per MCF. Our natural gas price realization overall was down 14 percent, which offset the production growth that we had in the quarter. Adjusted EBITDAX came in at $148 million, which was about 22% lower than the third quarter of 2019, and operating cash flow of $93 million was about 35% lower. We did report a net loss of $130.9 million for the third quarter, or 57 cents per share, but most of that loss is attributable to the $155.6 million unrealized loss on the mark-to-market of our hedge positions, and that is all caused by the substantial improvement to future natural gas prices since the end of the second quarter. Our adjusted net income, excluding the unrealized mark-to-market hedging loss and then certain other unusual items, was a loss of $13.8 million, or six cents per diluted share, for the quarter. Slide five, we summarize our financial results for the first nine months of this year. Production for the first nine months totaled 349 BCFE, including about 1.2 million barrels of oil, which is 90% higher than our production for the same period in 2019. Of course, most of this increase is due to the acquisition of Covey Park Energy, which we completed in July of 2019. Oil and gas sales, including realized hedge gains were $716 million, 40 percent higher than the same period in 2019. Oil prices so far this year have averaged $39.84 per barrel, and our gas price is $1.96 per MCF, both including the hedging gains we had. Overall, this is 18 percent lower than the prices we had for natural gas in the same period in 2019. Our adjusted EVA DAX came in at $511 million, which was 35% higher than 2019. Operating cash flow was $367 million, and that's 31% higher than 2019. We did report a net loss of $160.9 million for the first nine months of this year, or 77 cents per share. Again, this was due to the mark-to-market loss, the unrealized mark-to-market loss on our hedge book. Mark-to-market loss. loss, the unrealized marked market loss on our hedge book. Adjusted net income, excluding the unrealized hedging losses and other usual items, was $12.9 million, or a net income of six cents per diluted share. Third quarter production was adversely impacted by a higher shut-in level than normal, as you can see on slide six. Seven percent of our natural gas production was shut in in the third quarter, as compared to 4% in the second quarter. Much of that shut-in is due to offset frac activity, either by our simultaneous operations or other Hainesville operators. But we also temporarily shut-in a portion of our production over the course of about a week due to the impact of Hurricane Laura that caused widespread power outages in our region. And then also in September, for a good part of the month of September, and then carrying over really into the first, you know, 12 to 14 days or so of October, we did experience wide differentials in the daily cash market at Perryville and in other indexes in our kind of region in the southern kind of Gulf region. And this was all due to concerns that the natural gas market had over the high storage levels as we exit the period of storage injections. So the only gas that's really impacted by these daily prices is what we call our swing natural gas that was not sold during bid week and is not part of our base load sales. So we chose to restrict some of the new wells that were coming on in September and then given this very low price that this extra swing gas was getting. And these high differentials in the month of September and also the declining overall index prices in that volatile month did cause our overall differential in the quarter to widen by 10 cents in the third quarter. This situation did continue into October, really only the first couple of weeks of October. And then we took an action in the very first part of October to actually curtail, for price reasons, $300 million a day of our production. And overall, we did this for about 11 days. That action, along with the startup of LNG facilities, coming back after the hurricanes, really helped reduce the concerns about storage filling up. And then we saw... Now, about mid-October, we saw the daily cash prices go back into a normal relationship and differentials narrow, and then we put all that gas, you know, really back into the market. So I think as October has finished out and as we enter November, we've seen a very healthy situation, which has been supported by – you know, very favorable kind of injections to storage and even today a withdrawal. We also saw that, you know, obviously our non-operated oil production, which is primarily located in the Balkan region, also has continued to experience substantial curtailments, which carried through in the third quarter. We had about 12% of our oil production that was shut in by the operators that operate it due to the very low oil prices or other issues in the Balkan region. On slide seven, we cover our hedging program. For the first nine months of this year, we had 50% of our gas volume hedged, which increased our realized gas price to $1.96 per MCFE from the $1.60 that we actually received from selling our production. We also had 86% of our oil volumes hedged, which increased our realized oil price to $39.84 versus the $30.35 per barrel that we actually received. Overall, during that period, we had realized head gains of $133 million. But with the improvement in future natural gas prices, we also took that opportunity to continue to add to our hedge book, but really at higher levels than we'd hedged before, and then also using collars. So we've added about $10 million a day of natural gas for the fourth quarter since we last reported earnings, and we added about $38 million a day of natural gas collars in 2021 and about 12 million a day of collars in 2022, which gives us a good protection level but also gives us exposure to the higher prices. As you look ahead for the fourth quarter of 2020, we have 663 million cubic feet of our gas and about 2,800 barrels per day of our oil hedged. The weighted average floor price of our remaining 2020 gas prices is $2.61. And for 2021, we have natural gas hedges covering about 836 million cubic feet of our 2021 production. So we're on target to having 60% to 70% of our 2021 production hedged, and we'll also work as we have this improving gas strip to work with, to hedge our 2022 volumes appropriately. On slide eight, we detail our operating costs per MCFE produced. And overall, these were pretty comparable to the second quarter. So our operating costs averaged 55 cents in the third quarter as compared to our second quarter rate of 54 cents. Gathering costs were 21 cents. Production ad valorem taxes averaged $0.09, and field level costs were $0.25. The one thing we did do this quarter in order to improve the comparability to us and other producers was to reclass our ad valorem taxes that used to be showed as part of just lifting costs and include those in production taxes. So you'll see that if you're kind of tracking the old numbers. And so it's really about $0.01. So not a big change, but we think that just makes us more comparable to our peers. On slide 9, we detail our corporate overhead for MCFE, and our cash G&A costs were $0.07 in the third quarter, which is slightly up in the second quarter, but that's mainly due to the lower production level in the quarter. On slide 10, we detail the depreciation, depletion, and amortization per MCFE produced. Our DD&A averaged 95 cents in the third quarter, which was about 8 cents higher than the second quarter. And then most of that impact is due to the much lower kind of SEC-type prices that are kind of backward-looking that we used to do amortization with. On slide 11, we recap our third quarter and the first nine months of 2020 capital expenditure program. So we spent $110 million on development activities in the third quarter, and $94 million of that was related to our operated Hainesville shale properties. For all of 2020 so far, we spent $316 million, including $259 million on the operated Hainesville properties. We've drilled 36 or 28.6 net operated horizontal Hainesville wells so far this year. and we also completed 9.6 net wells that we drilled in 2019. We've spent $56 million on non-operated activity and for other activity so far this year. We generated $367 million in cash flow for the first nine months of this year, resulting in free cash flow of $30 million after we paid the dividends on the preferred shares. After dropping our operating rig count to four rigs in April, which was down from six back in January, we've increased our operator rig count back to six rigs. In the fourth quarter, we expect to spend about $150 to $170 million this year to drill 17 or 16.4 net operated Hainesville wells, and then to turn to sales 22 or 17.6 net Hainesville wells. We made the decision recently to keep a third frat crew busy in the fourth quarter, which we originally planned to release and then bring back, you know, in early 2020. This does add about $30 million to our 2020 spending, and the reason for it was to accelerate the completion of seven wells before we planned to complete in 2021. And this is in order to take advantage of the higher gas prices, especially that, you know, we see for the first quarter of 2021. And it was just a decision based on if we kept our original schedule, We compared that to keeping this third rig, which was performing well for us, and operations asked us to look at that. And we said, you know, we actually make $15 million more by accelerating that completion into kind of the prime, the highest gas price months on the futures curve. And so we said that's the right thing to do. If you look at the full year for 2020, if you combine the fourth quarter with that, we now expect to spend about $450 to $500 million this year, which would have drilled 53 or 45 net operated Hainesville wells this year, which would have drilled 53 or 45 net operated Hainesville wells and turned 55 or 42.2 net operated Hainesville wells to sales. We also participated. We also plan to participate in 18 or 1.3 net non-operated Hainesville wells and, in turn, 3.8 net wells to sales. At the end of this year, we now expect to have about 16 or 15.4 net ducts or drilled and uncompleted wells. So as you look ahead to 2021... We expect to increase spending a little bit over the 2020 level in response to these higher natural gas prices that we see. And we expect to spend between $525 to $575 million and drill 70 or 56.5 net operated Hainesville wells and turn 65 of those wells or 56.6 net wells to sales in the year. Our initial plans right now are to add a seventh operated rig, and we would do that in the second quarter of next year. Obviously, as we get to that point, we'll assess, you know, the natural gas market in our region and decide if that's still a great course of action. If not, as we've shown in the past, we don't have long-term commitments for drilling or completion services or any kind of volumes to meet. So it's clearly an economic decision on when we spend the CapEx and what And we can react, as we did this year, we can react to the market and adjust our level of spending as is appropriate. But we still remain focused on generating significant free cash flow, and we see next year as having a bounty of that, you know, with the plans we have. And we target to have a minimum of at least $200 million of free cash flow as we plan for any future capital spending. On slide 12, we show our balance sheet at the end of the third quarter, and during the third quarter, as Jay mentioned, we issued $300 million of new unsecured notes to term out a portion of the borrowings outstanding under our credit facility. So we ended the quarter with about $500 million drawn on our credit facility, and we do expect to continue to pay that down with free cash flow generated during the rest of 2020 and into 2021. Okay. With a quarter-ending cash position of $28 million, our current liquidity now stands at $928 million. We have just over $2.25 billion of senior notes outstanding, and that's comprised of $619 million of our 7.5% senior notes due in 2025 and $1.65 billion of our 9.75% senior notes due in 2026. So I'll now turn it over to Dan to cover the third quarter drilling results in more detail.