Chord Energy Corporation (CHRD) Q4 2020 Earnings Report, Transcript and Summary

Good morning. My name is Keith, and I will be your conference facilitator today. Welcome to Whiting Petroleum's Fourth Quarter 2020 Conference Call. This call will be limited to 45 minutes, including Q&A. [Operator Instructions]. I will now turn the call over to Brandon Day, Whiting's Investors Relations manager.

Thank you, Keith. Good morning, everyone. This is Brandon Day, Whiting's Investor Relations manager. Thank you for joining us to discuss Whiting's fourth quarter results for the period ended December 31, 2020. With me today is Whiting's CEO, Lynn Peterson. Also available to answer questions during the Q&A session will be our CFO, Jimmy Henderson; COO, Chip Rimer; and VP of Commercial, Jo Ann Stockton. Please be advised that our remarks today, including answers to your questions, include forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to materially different from those currently anticipated. Those include risks relating to commodity prices, competition, technology, environmental and regulatory compliance, midstream availability and others described in our filings with the Securities and Exchange Commission, which are incorporated by reference. We disclaim any obligation to update these forward-looking statements. In addition, we may provide certain non-GAAP financial information in this call. The relevant definitions and GAAP reconciliations may be found in our earnings release and 10-K, which can be found on our website at whiting.com in the Investor Relations section. Following the prepared remarks, time permitting, we'll open the call to your questions. I would like to remind everyone that a replay of this audio webcast will be available via the company's Investor Relations page at www.whiting.com. I'd now like to turn the call over to the CEO of Whiting Petroleum, Mr. Lynn Peterson.

Thanks, Brandon. Good morning, everyone, and thanks for joining us today. I hope everyone continues to stay safe and healthy. We filed our 10-K yesterday, and you can refer to it for detailed information, so I hope to highlight some of the significant items. Let me begin with a huge understatement. That if nothing else, 2020 brought change and as we embark on a whole new year, the company is in excellent shape, both financially and operationally. The Whiting team has done a wonderful job scrubbing and challenging every cost throughout the company. We have reduced staffing, cut salaries to reflect the current state of the industry and forged a compensation plan for the executive team that more closely aligns with our shareholders as we look to reset the company. Our results in the fourth quarter begin to reflect these efforts as shown by our free cash flow. This call marks the end of the road for the year 2020, and now we can truly focus on a future for Whiting as we are all well positioned to take advantage of a solid asset base, a strong financial position and a team of talented employees. Before getting into the financial and operating results, I would like to give a shout out to our staff for the safety record in 2020. The company reported its lowest total recordable incident rate in the history of the company. The company also exceeded the state of North Dakota's gas capture rate without any exemptions, and will continue to strive to improve in all areas. Since many of the comparisons between 2020 and 2019 numbers are not meaningful due to the restructuring and curtailment of activity beginning in April of 2020, we will try to comment on the comparisons that are significant -- have significant implications moving forward. Adjusted EBITDAX was $120 million for the quarter and $382 million for the year after adjusting for the nonrecurring items related to the restructuring and reorganization compared to $241 million and $979 million for the respective periods of 2019. Despite the lower activity level and commodity price environment, the company generated nearly $90 million of free cash flow in the fourth quarter of 2020 compared to approximately $86 million in the same period of 2019. The free cash flow generated since emerging from bankruptcy has gone towards paying down debt. On September 1, 2020, the company emerged with $425 million drawn on its $750 million facility. As of December 31, 2020, the company's debt was down to $334 million net of cash on hand, and is projected to be paid down to approximately $275 million as we exit February. We would've paid down $150 million since September 1 and as we generate free cash flow, we'll continue to reduce our borrowings as that is part of our credit facility that was set up at emergence, and is our liquidity and dry powder as we think about future opportunities. Our production for the quarter averaged 91,700 barrels of oil equivalent, of which 61% was crude oil. The company's production continued to decline through the quarter and into the end of the year. Our capital program and guidance is designed to essentially hold 2021 production flat from our December 31, 2020 exit rate, and we estimate full year 2021 production to be in the range of 82,000 to 88,000 barrels of oil equivalent per day and oil to be in the range of 48,000 to 52,000 barrels of oil per day. We spent $21 million on capital expenditures during the fourth quarter to bring 5 wells onto production and commenced completion operations on an additional 6 wells. In 2021, we expect to spend $240 million at the midpoint of our capital expenditure guidance. We currently have 1 drilling rig running in our Sanish Field in North Dakota and anticipate a second rig could be added in late 2021. We also have 1 completion crew operating in the Foreman Butte area. We plan on turning 56 wells to production in 2021, of which 13 are scheduled for the first quarter that were drilled and uncompleted wells as of year-end. Lease operating expenses were $55 million or $6.57 per BOE for the fourth quarter. The benefit of our cost-cutting measures, along with better-than-expected weather and extended ESP run times, positively impacted the quarter. I will note that winter has since returned to North Dakota in early February, where temperatures have been below 0 for the most consecutive days since 1936, with temperatures frequently reaching negative 20 degrees Fahrenheit. The operation team continues to perform well despite these harsh conditions, but we do expect operating cost to increase somewhat in the first quarter of 2021, as has been shown historically. We anticipate an active workover program throughout the year to keep production flowing on our base portfolio of older wells. Moving to some of the recent regulations of Federal Appeals Court ruling in January affirmed the district court's order to vacate the Dakota access pipeline easement and directed the court to prepare an EIS, of which was previously underway. U.S. Army Core requested a 2-month continuance of the February 10 status conference ordered by the district court to allow additional time to brief the new administration and confirm where the pipeline will continue to operate while their environmental impact study takes place. We have and will continue to secure alternative market arrangements to help mitigate the potential impact of an unfavorable outcome. We continue to believe that even with this exposure, our 2021 average oil price differentials will be similar to what we experienced in the second half of 2020, both in average and variability. There has been a focus on exposure to federal acreage as the Biden -- as part of the Biden administration. We have very limited exposure in North Dakota and expect very minimal impacts to our future plans because of any potential restriction to be put in place. To ensure our ability to fund our CapEx program and generate free cash flow, we have continued to layer on commodity price hedges. As a reminder, under our credit facility, we are required to hedge certain minimum levels of our PDP production, and we have exceeded those levels for the coming year. We currently have 70% of our total forecasted crude oil hedged in 2021 and 75% of our natural gas. We have utilized a combination of fixed price swaps and collars, which are further detailed in our 10-K. As we have guided previously, we believe we will generate over $150 million of free cash flow in 2021 at a $45 WTI crude oil price and a $2.50 NYMEX natural gas price. As a rule of thumb, for every $1 move in WTI, we expect approximately $10 million change in cash flows, but this will be affected by hedging at varying price levels. During 2020, we made a concerted effort to overhaul our internal reservoir engineering team as well as engaging Netherlands Tool & Associates as our third-party independent engineering firm. Our estimated proved reserves were 260 million barrels of oil equivalent with a PV10 of $1.2 million at December 31, 2020 compared to 485 million barrels of oil equivalent in 2019. The 2 most significant components of the reduction in the and reserves were pricing and activity level. The pricing per barrel under SEC rules for December 31, 2020 was approximately $40 per barrel compared to December 31, 2019, which was approximately $56 per barrel or a total reduction of just over $16 per barrel. Gas per Mcf decreased to $1.99 from $2.58 for the same 2 periods. The reduction in the company's activity from early 2020 to late 2020 had a ripple effect throughout the -- through the inability to book proved undeveloped locations that fall outside the SEC 5-year rule, combined with a more conservative approach to PUD bookings going forward. Interestingly, since we have experienced a significant change in WTI pricing over the last few months, we wanted to internally run our reserves at $50 per barrel and $3 natural gas to see the impact on our reserves. This pricing increased our proved reserves by approximately 20% and doubled our PV10 values. The commodity price increase also has a positive impact on our future drilling locations, expanding our economic drilling inventory to over 6 years modeling a 2-rig program. We remain steadfast in our strategy of generating free cash flow, while mitigating the impact of production declines. In the near-term and in accordance with our credit facility, we will use our free cash flow to continue paying down debt, to ensure continued liquidity. Longer term, we will look to our options of returning capital to shareholders. Lastly, one housekeeping item. As you may have seen in the prerelease, we agreed to a settlement with a general unsecured claimant where we released approximately 949,000 shares from the bankruptcy settlement pool in exchange for a release of claims, which eliminates certain obligations in our Redtail project. These shares have a lockup feature, preventing to sell more than 50% of the shares during any 30-day period. After the settlement, our share count is approximately 39 million beginning in the first quarter of 2021. With that, I'll turn it back to the operator and open it up for questions.

[Operator Instructions]. And the first question comes from Leo Mariani with KeyBanc.

Just wanted to follow-up a little bit on that last comment that you guys made. In terms of the shares, the reserve for unsecured claimants out of the bankruptcy, you just talked about 900-and-something-thousand there that were issued. Are all those claims resolved? Or are there other potential issuances of shares related to unresolved claims?

I'm going to let Jimmy -- sure to address that, please.

Yes, I think we've got a good disclosure about this in the 10-K, but we reserved 3.1 million shares for these types of claims, and we still have some remaining unsecured claims to be cleaned up, and it will take some time to go through that process. This one was -- we were -- both sides were equally motivated to get it solved so that we could continue to work together going forward. And -- but we have some other legal claims that we'll continue to work through for the remainder of the year, basically.

Okay. I guess just with respect to M&A, I think you guys have been fairly vocal about maintaining just a very strong balance sheet and improving it back in order to potentially do some acquisitions at some point in time. I guess we've seen a couple of deals out of the Bakken recently. Just wanted to get a sense, are those deals that you guys have looked at? Are you very focused on the Bakken? Are you also kind of looking at other basins? Maybe just any kind of status update on M&A?

Yes. We're very familiar with the transactions that occurred. They're both a little bit unique in certain respects. So we chose, at this point, we're going to continue to look at our opportunities. Whether it's Bakken or wherever, I mean, Leo, we're looking for the right opportunity. We do know the Bakken, and that's where our focus is, and I expect it to remain. So yes, we can't comment too many items there.

Understood for sure. No, that's helpful. You guys talked about a second rig potentially late this year. Is that really just to kind of set up a 2-rig program potentially in '22? What's the thought process there?

Yes. The whole thought is to build our drill the uncompleted count up, so we can maintain our '22 production level. Otherwise, everything starts to drop around the end of the year and the first part of 2022. So I think we've got to kind of plan late third quarter, early fourth quarter time frame to bring it in.

And the next question comes from Neal Dingmann with SunTrust.

Lynn, my first question is your thoughts around Whiting's inventory. You all recently lead -- kind of laid out that showed, I think, if I recall, as many as about 432 core locations at $55. So really have one, obviously, nice increase there at $55. And so my question is, what type of -- kind of increase where we continue to see now that we're at $60, running to $65. And maybe could you talk about how -- I'm just kind of wondering, again, when they look at these locations, are they pretty widely spread throughout? Or is it a couple of the other ones that tarp on some of the others that are more centrally located?

Yes, and I'll let Chip jump in here as well. But I think, generally, we put $55. We don't want to get ahead of ourselves here. So I think you do see that inventory number growing. And certainly, as we get to $60, we see an increase as well. But Chip, you mind walking through kind of where we see all these locations in general?

Yes. So you got to -- and I appreciate the question. So of course, our core at Sanish, and we'll see probably over close to 200 locations in Sanish that we see. As we get in that $50 range for Sanish kicks in around $40 or so. And then as we get to Foreman Butte at $55, we're seeing 100, 120 locations as we go. And so as prices go up, we continue to see that -- continue to grow.

Not as much in Pronghorn, Chip, anything down? I'm just wondering if you're going out there?

No, Pronghorn's going to be a lot -- has to activate a lot higher.

And all of our focus in on just the core area there, Neil.

Yes. Got it. Got it. And then just one more for Jimmy. Jimmy, can you remind...

Neil, just let me add one comment. I mean we did state that these are economic conditions at these dollar prices. It's important to know. There's obviously a lot of locations out here, given certain levels of oil pricing.

So yes, this hurts our rate of return level. And also, there's a little bit in Redtail that takes off also in that $50, $55 oil.

No, I think we all appreciate that, Lynn. That I think it's a number that I don't want to say before we didn't trust, but it's a number we could definitely hang out hat on now. I really appreciate that, Lynn. And then, Jimmy, just a follow-up is, can you remind me post kind of when you came out of restructuring, I think there was some sort of stipulations in there regarding your RBLs, what the repayment needs to be? Is it before you can do shareholder buybacks or other shareholder returns or different things like that? I just -- I'm not sure if I'm clear on that.

Yes. And our RBL that our exit facility, if you will, does have a requirement to get to basically September. And so as the history of free cash flow before we would be able to make dividends or buy back stock. I think if we were in a position and desire to, we could probably push on that a little bit, but that's kind of what we've been adhering to. And we wanted -- as we've said in the script, we want to continue to pay down debt because that is our liquidity to pursue opportunities going forward. And so that's still our preferred use of free cash flow at this point. For the short and medium term, I'd say that's a -- that would be our focus.

Yes. You'll -- you show them, Jimmy, when you get down to 0 debt, you can't do much better?

No. We're not there. But we'll get there pretty quick. We hope to not get to that point because we hope opportunities present themselves that we can reinvest this liquidity. But at some point, with just going status quo, you get there pretty quick. You guys have done the modeling and kind of think everybody knows the pace of our ability to pay down that debt.

And the next question comes from David Deckelbaum with Cowen.

I wanted to follow-up real quick just on the fourth quarter. In the ops update that you guys put out before you reported the quarter, you highlighted that production was a little bit better-than-expected on a more favorable base decline. Can you elaborate a little bit on that? Or is this a case of just having more uptime? Or are you seeing some improved reservoir performance? And I guess, what would you attribute to that to?

I'll let Chip address. I mean, generally speaking, I think we had some nice weather in the fourth quarter, and we are a little bit ahead on our activity pace, but Chip?

Yes, I appreciate the question. So we created a base management team here. I guess, it was just coming out of Chapter 11 there and wound up. They've really been focusing on downtime. And so part of that is good weather. We had our lowest downtime in 3 years in the fourth quarter, which really helped us going forward. So some of our run times also extended. So we manage our run times on our -- see how long our artificial lift is going. And those extended almost 7% over -- year-over-year from fourth quarter to fourth quarter. Some of the runtimes going longer, you've got the downtime better and then you get better oil.

And just to ask on activity. I know you're working down some of the DUCs in the Foreman Butte Hidden Bench area. And I know you had some DUCs in the Sanish partial area. Should we assume that, that second rig kind of floats around? Or is this going to be mostly a Sanish partial field program?

I think we'll initially move it into the Sanish area, David. That where our goals are right now, at least.

That's correct.

Okay. And Lynn, I just wanted to follow-up on some of the M&A discussions. I know you can't say a lot, but I guess, one, can you characterize, I guess, how many opportunities are out there now? And you all can just elaborate a little bit on the pipeline. And I guess I would wonder as well as you've evaluated some of the deals, we note that many of the deals, especially in the Bakken, have a very heavy PDP component. When you look at value creation for Whiting right now, are you looking for something that has a bit more of an undeveloped tail to it?

It's a good question, David. And we're trying to look at everything, I guess, I'll start there. You're right, the basin is older. It's one of the more mature basins. So most of these do have a very high component. Frankly, most of them don't have a lot of inventory going forward. So I think that's one of the challenges we're faced here is how do we try to get both of those situations. Location of the acreage is also important. Do we want to be on the reservation? Do we want to be off the reservation? These are questions that we have to ask ourselves. So it's a myriad of questions. And I think we look at every PDP deal and we are trying to find some pockets of undeveloped. But again, I think we're all probably limited in this, call it, 5- to 8-year range of inventory here and depending on what oil prices do. I mean we look at a $55 oil price. I think every package you look at is kind of similar in nature.

Yes. I guess it would stand that with so many of those types of deals out there, there's nothing that really jumps off the page that would incentivize you to chase because it looks too similar to what you already have?

Yes. No, it's an interesting environment. But again, I also think if we can find the situation to double where we have today, we're better shaped because, again, some of this will be to the cost. We can work on overhead costs and these type of things, which will be -- bring value to the bottom line. So I think there's definitely merit in looking at all these. And I do believe size and scale matters. I haven't changed my mind there at all. We've got to grow here. And we've got to figure our path forward here.

And the next question comes from Noel Parks with Tuohy Brothers.

I just wanted to touch back on the workover program that you're putting some capital into this year. Can you just talk a little bit about the cost of what sort of productivity or returns you think you might get out of them? And how you come up with the priority of which areas or which wells to tackle first?

Yes. We think it's our best dollar spend, and I'll let maybe Chip walk through our focus and how we go about this process.

Yes, Noel. Let's start it. We have two meetings a week on the production side with all our operations. And we're looking to see what the best opportunities are out there in all of our fields. And so we have a team that manages our workover rigs. We have about 25 plus or minus rigs that work out there. That team goes to our most economical wells. They are our best returns. And so that's what we focus on. The guys will look at it and where do we need rigs do we need rigs up in Williston or down in Watford City or where that might be. And that is on a daily basis. That wasn't always the case a couple of years ago. And now I love the way the teams are working, they operate together, managing their business. Our team inside here down in Denver manages -- runs economics, which wells to go. And then we focus on those. We focus on the cost, managing the cost across the board to make sure we're getting the best bank for the buck.

It's also an area where the weather hits us. This February, the weather is pretty tough. A workover rig is not protected. So the workers are out in the exposure, so.

Yes, to your point, the weather, it was brutal in February. The joined rig doesn't lose a beat. The completion is just a little slower. So the workover rigs just can't work in that. And so we're going to pick up a couple of additional rigs to manage that, but it's easily managed.

Great. And just from an accounting standpoint, will most of what you do this year wind up as CapEx? Or will it wind up in LOE?

Get a component of both. It just kind of depends on what the work is involved. Generally, you can -- if you're improving reserves or adding reserves, then we would call it capital, but for the most part, these are repair type operations, so primarily going to be in LOE.

Yes. Of the 25, probably 20 of those are work in LOE.

Yes. In our prepared remarks, Noel, we mentioned that we expect LOE to increase from the low levels that we saw in the last part of 2020, and a lot of that is due to increased work we've experienced just keeping these wells maintained and up and running.

Ladies and gentlemen, there are no further questions at this time. I'll turn the floor back to management for closing remarks.

All right. Thank you, everyone. We'll be attending some virtual conferences over the coming quarters. I sure hope at some point we can have some face to facing. For now, everything will continue to be virtual. I'd like to thank everybody for joining us this morning, your interest in Whiting. Once again, I want to thank the staff here at Whiting for the work that's gone on over the last 12 months. It's been certainly a change of working remotely in a large part of this, so just a huge shout out to the staff for what they've done here. And we're really looking forward to 2021. We think we're starting the year in a great spot. Certainly have seen a nice boost of oil the prices here, and we're excited with lies ahead of us. So thanks, everybody. Stay safe, and enjoy your day. Thank you.

This concludes today's teleconference. Thank you for attending today's presentation. You may now disconnect your lines.