Cimarex Energy Co (XEC) Q1 2020 Earnings Conference Call May 7, 2020 11:00 AM ET
Karen Acierno - VP, IR
Thomas Jorden - Chairman, CEO & President
Mark Burford - SVP & CFO
Conference Call Participants
Arun Jayaram - JPMorgan Chase & Co.
Gabriel Daoud - Cowen and Company
Jeanine Wai - Barclays Bank
Neal Dingmann - SunTrust Robinson Humphrey
Michael Scialla - Stifel, Nicolaus & Company
Michael Hall - Heikkinen Energy Advisors
Jeffrey Campbell - Tuohy Brothers
Brian Downey - Citigroup
Douglas Leggate - Bank of America Merrill Lynch
Richard Tullis - Capital One Securities
Good morning, and welcome to Cimarex First Quarter 2020 Earnings Call. [Operator Instructions].
Now I'd like to turn the conference over to Ms. Karen Acierno, Vice President of Investor Relations. Please go ahead.
Thanks, Nick. And good morning, everyone, and thanks for joining our first quarter 2020 conference call. An updated presentation was posted to our website yesterday afternoon. We may reference that presentation on our call today.
Just a reminder, our discussion will contain forward-looking statements. A number of actions could cause actual results to differ materially from what we discuss. You should read our disclosures on forward-looking statements in our news release and in our latest 10-K for the year ended December 31, 2019, for the risk factors associated with our business. We plan to file our 10-Q on Monday, May 11.
We are going to change things up just a little bit today. Our prepared remarks will begin with an overview from our CEO, Tom Jorden, followed by a few comments from Cimarex's CFO, Mark Burford. Also present on the call to answer questions is Blake Sirgo, VP of Operations.
As always, and so that we can accommodate more of your questions during the hour we have allotted for the call. We'd like to ask that you limit yourself to 1 question and 1 follow-up. Feel free to get back in the queue, if you like.
So with that, I'll turn the call over to Tom.
Thank you, Karen, and thank you all for joining us on today's call. It would be an understatement if I were to say that these are volatile times. Our macro environment has been shifting hourly over the past 2 months, and it has been a scramble to keep up with it. At times, this field is if operational and market updates become out of date before our update calls in. Although we hope to give you a flavor of our current situation and outlook on this call, the situation will change before nightfall.
First, I want to express our well wishes for everyone's health, both physical and mental, as we deal with the COVID-19 crisis. The dual shocks of the COVID-19 stand down and the collapse in oil prices have brought an unimaginable challenge to our company, to our industry and our nation. It is our sincere hope that you are all protecting yourselves honoring health professional guidelines and remaining in good spirits. This working remotely is wearing all of us out.
Cimarex has weathered the COVID-19 crisis well. We had an early start, and that we stood up a task force in February to make contingency plans in the event that the pandemic worsen. This included preparing our IT infrastructure for remote work, identifying key backup plans for critical personnel in the event they were to be incapacitated, ensuring that critical processes were ready for remote work so that we would not drop the ball on transaction processing, and establishing new protocols to protect our field staff as they win about their routing. Overall, we couldn't be more pleased with how our organization has responded.
Our office locations began remote work, May 18. The executive team has had daily calls to address issues as their rise. Every day is a new issue, a new challenge and a new workaround. I want to give a big shout out to our organization for the manner in which they have stepped up to the challenge. It has been humbling to be a part of such a high-performing team.
First and foremost, our field staff have gone about their jobs with professionalism, dedication and difference to social distancing and new health protocols. They are our heroes in this crisis. Our engineers have found new ways to slice and dice our cost structure in an attempt to lower our lease operating expenses and liberate precious cash. Our marketing group has been heroic in finding markets for our products. We have built new tools to analyze fixed and variable LOE in an attempt to understand our net operating income on each and every one of our properties. We have been proactive in shutting in properties that are not cash flow positive in this environment, and finding creative ways to honor our volume commitments. We have worked with our partners up and down the value chain in order to encourage cost reductions that allow us to continue to produce. Through this crisis, Cimarex has demonstrated what a high-performing team looks like.
The marketing situation has been particularly volatile. The link between WTI index prices and wellhead netbacks can be complex and rapidly changing. Our operations group has built some powerful tools to track our wellhead netbacks and we are making prudent, informed decisions on which properties to produce and which properties to shut in.
Good relationships with some marketing counterparties have borne fruit during this time, and allowed us to lock in fixed-price contracts where appropriate. We have also added to our hedge position, further strengthening our confidence in our marketing and production decisions. Mark will provide more detail here.
Cimarex has always valued flexibility, and once again, we are reminded why. We do not have services under long-term contracts nor are we burdened with onerous minimum volume commitments on volume delivery. Our prior caution in entering into long-term commitments has paid off. Allowing us to react quickly to market signals. As I mentioned previously, we have scrubbed our cost structure to lower our lease operating expenses. The creativity that our organization has shown here has been amazing. Although only a partial list of initiatives, we have renegotiated saltwater disposal fees, renegotiated gathering and compression rates on third-party gatherers, reconfigured facilities to lower electricity costs, reengineered compression systems to release unnecessary compression and scrubbed and minimized our chemical expenses.
As our activity levels and drilling, completion and facility construction and midstream construction have declined, we have released contract labor and redeployed company personnel to take in many of these jobs. In what was either tremendous foresight or blind luck, we initiated an early retirement incentive program in January of this year. In aggregate, our early retirement program has allowed us to reduce over 10% of our headcount on a purely voluntary basis. We enter the second half of 2020 with a lower cost structure and a better, higher-performing organization.
We are also quite pleased with the trend of our drilling and completion costs. In the second quarter, we are seeing total well costs for 2-mile Wolfcamp wells at less than $900 per foot. These are actual costs, not projections or targets. They include all drilling, completion, facility and flowback costs. We look forward to resuming active drilling and completion operations in the near future and taking further advantage of these cost savings.
Any outlook for the future is, at best, murky. We have learned 2 lessons from past downturns. First, these downturns in our business never come pre labeled and how long that will last. They never less forever, and the recoveries are as unpredictable as the downturn itself. Thus, if you are managing a company in a balance sheet, you must be inherently conservative financially as if the downturn will last a long, long time.
The second lesson is that 1 must be very careful making long-term decisions in the emotional funk of the downturn. Patience is a virtue at times like this, for patience may prevent 1 from making decisions that will linger long after the downturn has passed. We have the flexibility to significantly increase or decrease capital in the remainder of the year. We have contingency plans for both.
Our base plan includes bringing additional rigs back mid-summer and continuing to drill but deferring completions to 2021. And on the downside, we can forgo this second half drilling and conserve cash. To the upside, if conditions improve, we can bring the rigs back and stage completions in the second half of the year.
All of these contingencies generally fall within the capital guideline range previously communicated. We will watch the pace of restart of the world economy and its impact on oil, natural gas and natural gas liquid prices. We have the flexibility to respond accordingly. We will also be staging our organization back into the office sometime in the latter half of May. We will return to the office in phases, keeping the health and safety of our workforce our top priority.
Finally, we remain optimistic regarding the long-term prospects of our industry. There will be an effective treatment or vaccine for COVID-19. The world economy will restart and respond in ways we do not anticipate. Fossil fuels power our world and will continue to do so for decades to come. As in prior crises, we will look back on the prognosticators and marvel at how much they got wrong. We can't be certain what the future looks like, but Cimarex will be there to respond to it.
With that, I'll turn the call over to Mark for a few comments before we go to Q&A.
Thanks, Tom. As Tom discussed, our capital guidance has significant flexibility in bringing back activity both rigs and frac crews. We will continue our focus on ensuring that we make decisions during a return on investment and preserving our financial strength to generating free cash flow. Our 2020 hedges do provide us with some shock absorber on our cash flow. Our hedges generated cash settlements of $43 million in the first quarter, and we estimate generating $230 million of cash in 2020 based on an April 30 strip price. You don't, however, do our hedges as justification for investment or production decisions.
We have seen continued improvement in our well cost per lateral foot and have an excellent inventory of drilling opportunity. Our production forecasts are highly dependent on when we bring back frac activity. If you refer our fracking activity over the remainder of the year, we will be declining. Once we bring back frac activity, we'll begin to grow. As we discussed in the past, our expectation to establish a consistent drilling and completion cadence. It allows us for some growth and free cash flow generation efficient for our dividend and greater with stronger commodity prices. We want to position ourselves as the commodity markets stabilize, to build cash in our balance sheet, to increase our liquidity and that options to reduce our debt in the future.
So with that, Nick, I'll turn the call back over to you for Q&A.
[Operator Instructions]. The first question comes from Arun Jayaramaram of Retail.
This is Arun Jayaram from JPMorgan. This is testing everything you've learned in your career in business school and such. But I wanted to ask you about the D&C cost savings. You're currently -- it looks like at leading edge, all-in cost at $900,000 -- pardon me, $900 per lateral foot. Can you talk about the improvements that you're seeing? Maybe give us a little bit more color in terms of what is driving the improvement? How much further can you push? And your thoughts on capturing these savings, particularly as you move down to lower activity levels over the balance of the year?
Well, I will say this. We really love this drilling and completion cost per lateral foot marker because it's easier to calculate, it's easy to compare, and it's transparent. But I want to remind you, and you won't be surprised to hear me say this, Arun, it's about return on capital. And so during the year, we actually tried lowering our completion effort on a few projects and realize that, no, that wasn't the right answer. So we are back increasing our completion effort. So it's not always about cost. I would love to be able to tell you that I can make the ideal well at the lowest cost structure possible, but that's not the way it works. So that current number, less than $900 a foot, is a completion style that we're quite happy with go forward.
The reductions we've seen internally, I had a conversation earlier this morning with our Permian business unit manager, and we were talking about how much of it is cost reduction from vendors and how much of it is engineering. And he told me that internally, in their discussions, they think about 80% of that cost reduction is coming from just service cost reductions and about 20% of it is engineering. So my answer is it's going to -- as activity picks up and demand for services picks up and the service sector recovers as they must. And I want to underscore that point, we need a healthy service sector in our industry, and they're seeing the pain of this as much or more than anyone. So if prices recover, activity recovers, service costs are going to inch up, and I don't view that as a bad thing.
Great. Great. And my follow-up, Tom, you articulated your base plan that assumes bringing back some rigs mid-summer and perhaps, restarting some completion activity in early 2021. In your update, you didn't provide a lot of outlook comments given all the uncertainty. But I was wondering if you could perhaps, give us some -- maybe some thoughts on if you went to your base plan. How could oil production trend next year? I don't know if you can offer maybe an exit rate in '21 versus this year? But maybe just some thoughts on what '21 could look like as you restart completion activity next year under your base plan?
Yes, Arun, I'll as best I can and then turn it over to Mark. We're not trying to be coy here. The honest answer, Arun, is that there are so many things we don't know that giving a projection would have to -- we'd have to point of a set of circumstances that we just don't have confidence in. And it's not just drilling and completion activity, it's also shut ins. This situation is so volatile we had a situation earlier within the last few weeks, where at 1 point, we thought we were going to be shutting in massive amount of our oil production. And then in the very last minute, we got a call from 1 of our marketing counterparties, who said they were short oil for the month of May, and they offered us a premium to produce more oil. And so it's a function of drilling and completion investments and how we stage them. It's a function of shut ins, all of which is tied in to the pace of the restart of the world economy.
Now I am hopeful that we're going to be back to a growth trajectory in 2020, not just 2021. I'm hopeful that we'll be bringing completion activity back in the second half of the year. But we -- the band is so wide on what it could look like that we just decided not to give that degree of granularity at this point. Mark, you want to bail me out here?
I think you said it well, Tom, I think trying to evaluate what our outlook could be with the variability of our shut-ins, the timing of our potential depletions, no completions but basically if we don’t complete wells in the remaining of the year we have talked about a decline rate in our production. We will decline as I said in my remarks through the year and we have historically talked about decline rates of 40% annually in all over volumes so we are not trying to be coy on the fact that we do have declines. We expect to have declines before we start and our primary focus is when we start staging activity back in and make sure we get a return on investment, and we're prepared to start bringing on volumes as we have a better visibility in the market. But at this point in time completing wells in the low 20s is not a logical thing for us to do, as the market stabilizes we get some more confidence and the stability, [indiscernible] balance then we will be ready to start in making those investments in [indiscernible] additional volumes at this point in time, in this market it doesn’t seem a logical set and there is so much volatility.
The next question comes from Gabe Daoud of Cowen. Please go ahead.
I hope everyone's doing well. Tom, maybe just with curtailments, you mentioned you eased up on curtailments given the marketing company asking for more oil, but how should we think about, I guess, June? And I guess, generally, would you comment on maybe what price you need to see to start flowing some of these curtailed wells?
Well, June is the topic of the day, we'll be having to do nominations here for June. It's -- there are -- we've all learned more about marketing in the last couple of months than we ever dreamed we would know. Maybe you follow it carefully, but the WTI price is a starting point and then from that, you have either the mid cush differential or the WTL deduct, which incorporates the mid-cush differential that WTL being West Texas light, but then you also have the NYMEX role, which is a function of the behavior of the out months. And then you have against that, various other elements to get your wellhead netback. And we're making these decisions based on our wellhead netback. And it's been remarkable to us how volatile every 1 of those markers I just laid down have been. June looks pretty good to us today.
I think if we could waive the checker flag today on June, we'd probably be producing the great majority, if not all of our volumes and be very lightly curtailed or perhaps not even curtailed at all. The challenge is, all right, when we go to nominate, we're locking in and committing to produce those volumes. And just how bold we want to be. What we've seen is the near month has been a bit of a mirage. Like when we looked at April and May, it looked really good until the very end of the month and then the bottom fell out. That was what happened with trading, that was the headline. And so we've secured a lot of our June volumes, our May and Jume, we're talking about pre-sales at a fixed price. Right now, I'd say June looks pretty good. But the game is still being played for June.
Understood. That's helpful. And then just a follow-up on the curtailments. Could you maybe just talk a little bit about timing to get the wells back up and running? And just how you think about that from a -- like I said, just from a timing perspective, any color there would be helpful.
Yes. I would answer that, Gabe, I would say we think we can get the production back pretty quickly. And I know every company will have a different answer, and every company has different reservoirs. But we think for the great majority of our reservoirs that the reservoir response will be just fine. We did a lot of work on that, it feels like forever ago, it was probably 4 or 5 weeks ago. We had quite a technical session. Looking at our reservoirs and the response of the reservoir to shut in based on the age of the production. Should we worry more about shutting in an old well versus a brand-new well. Should we worry more about shedding in a well that's sustained production versus one that's just recently fracked and then early flow back. And we think we're in pretty good shape with our reservoirs to shut them in and then bring them back when we need.
Next question comes from Janine Wai of Barclays. Please go ahead.
[Technical Difficulty] to anticipate generating free cash flow on the current strip. Can you clarify whether this is after the dividend? And if so, can you quantify how much free cash flow you're forecasting? And I know it's kind of a moving target because pricing moves around, but just whatever your estate is now.
Janine. Yes, we do expect to generate free cash flow after the dividend. And I guess, we would say, at a recent strip price, it's probably in the $50 million to $100 million range.
Okay. Great. That's really helpful. And then my second question, maybe just following up on Arun's earlier question. In terms of 2021, we've been a bit surprised that just how much base declines are expected to improve next year based on some of the commentary from your peers, even given the magnitude of the CapEx cuts we're seeing this year. So can you discuss what kind of improvement you anticipate in Carex base decline for next year? I know you said historically, you're at about 40%. And any commentary on what this plus maybe the backlog of your wells in progress could mean for capital efficiency in '21?
Sure. Janine. We have looked at that. And looking at our -- right, our base decline has been typically in that 40% range. As we look at a plan where we have limited completions through the balance of the year, our base decline does moderate, and it could be down to close to the 30% range and coming into '21. So that definitely does help us as we look at -- as we stage back activity to have some sequential growth. So we will have that going forward. Plus, we do, as we disclosed in our presentation, 47 wells in progress that we will be -- have in the backlog, and we can start evaluating the pace at which we bring those wells in the completion and depending on the environment. So we do have some things that will be setting us up to help into '21 and resuming more normalcy and we hope in '21.
And then maybe just a quick part two on that one. In terms of the normalized level of wells in progress, I know that will move around with activity. But we've heard others kind of comment that it's about 10 operational per frac crew. And is that a good rule of thumb for [indiscernible]?
Frac crews to the rig count, Janine, is that what I heard you say?
Frac sites. The number of operational wells in progress that you just see normally. And so we've heard that the ratio of that is kind of like 10 of those to every 1 frac crew, is that you would kind of want to run?
Janine, I'm going to turn that question over to Blake Sirgo, who's joining this. So Blake, why don't you take that?
Unidentified Company Representative
Yes. Janine, I want to make sure I understand your question. The -- in general, we can run about 10 drilling rigs with two frac crews. That's kind of our distribution to keep up. Is that what you're asking?
I think she's asking with having 47 win progress, how many crews would you do have per location in progress? Is that what you're asking, Janine need?
Yes. I can take it offline if it's not appropriate. Just kind of -- the thing is that everybody has been talking about these wells in progress are DUCs as tailwinds for '21, but we're just trying to figure out what the normal level so that we can figure out how much is actually a tailwind versus what you really need.
Unidentified Company Representative
Yes. I mean, there's a lot of elements that go into that, Janine. Again, maybe off-line would be better. Staging in the number of frac crews is a function of water availability, labor availability, facilities construction, midstream. I mean, there -- it's a really complex system. And it's not just driven by the frac crews. It's driven by a lot of the follow-through and what's the right pace of field activity to get it done prudently in its lowest cost structure.
Our next question is from Neal Dingmann of SunTrust.
My first question, Tom, just wondering, you've hit on this quite a bit, but wondering when you think about between the curtailments and then just the sort of, I don't know, I guess I'd call it D&C suspensions or slow down. How different do you -- are your requirements or margins or rate of return requirements on each of these to bring these back?
Well, we look at full cycle return on every investment we make. So as Mark said, we had some drilling in progress, and we'll have some uncompleted wells. To start a new well today with WTI that has a 2 handle in front of it, doesn't make a lot of sense. Now the completion decision is a go-forward some cost, so that's a little different decision. But we would generally, for our program broadly, like to see a 3 in front of the WTI price before, I think a lot of new drilling completion gets interesting to us. Is that -- am I answering your question?
That's spot on. That's exactly right, Tom. And then really just a second parter is you guys have taken a bit more of a -- just -- I don't say conservative but a slower pace, both in the mid-con over the last several quarters as well as even, I'd call it a very stable pace in the Delaware versus some others. With that, I'm just wondering how you all think about PDP decline, I would think, potentially might be potentially slowing down a little bit here, but I'm just wondering, any comment you could make on how you view the current PDP decline in either of those assets.
Well, I'll let Mark comment. The way I think about PDP decline is I hate it. I mean, I wish we didn't have a PDP decline. But this is -- these are strange times. And I've learned a few things in my career, and that's the 1 thing you want to focus on first is survival and making sure that you preserve your balance sheet to the extent you can preserve your assets, preserve your organization. And so we're making decisions, first and foremost, to make sure that we're healthy when the things inevitably recover. And a lot of things that I don't like are secondary priorities in terms of survival decisions. Mark, do you want to comment on that?
Yes, Neal. So the PDP decline, it's definitely going to be declining, decreasing with lower activity as we go into the '21 period. And we are just managing our investments and looking at our investments, making sure that when we get to an environment, we want to continue completing and drilling new wells, and we have a visibility for a full cycle return on an investment. And I think you'll start off on production shut ins. That's definitely a challenge on what we look at for cash flow return.
Obviously, we're clearly looking at our cost structure, all the elements that go into the NOI or net operating income of each well. We've done a lot of work to -- when we look at the valuation of our shut-ins and curtailments, we want to make sure we're getting positive cash flow off those wells. So that's a little bit different. So you're on to making sure you can be positive cash flow on what you're producing and not setting yourself up for potentially negative cash flow on that production. So definitely the drilling investment, full cycle returns and then on that kind of curtailments, we're scrubbing every well and making that our base and even the whole base of looking at every well seen if we can get positive NOI on those productions.
Yes. I'll also add to that, Neil. Right now, I will say that we're really pleased to have those mid-continent assets. They're generating really good cash flow. As the strip firms up on gas, they're looking better and better. We have some investment opportunities there when we get back to work that will compete nicely with our Permian assets, particularly if oil prices stayed depressed. And then finally, to the extent that we've had bottlenecks, it's just nice to have a diversity. So we're really glad we have those mid-continent assets.
The next call is from Michael Scialla of Stifel. Please go ahead.
Tom, you mentioned some of the changes you made to lower lease operating expense. And I guess, other than slowing activity and curtailing production, can you talk about any of the changes that you've made operationally, if any, to respond to the lower price environment. I'm wondering if anything in terms of well design or spacing has been changed to respond to the lower prices.
Well, we have not changed any well design is facing and mostly because we have not configured a new project from drawing board to go forward. I don't anticipate our spacing are well-designed to change materially. But in answer to the first part of your question, 1 of the things that we didn't give much detail on in preamble, was our project that we undertook to replace our contractor workforce by redeploying employees. As we lowered our drilling and completion activity, we found we have a lot of employees that are engaged in drilling and completion that suddenly had idle time. And what happens at Cimarex, what happens with all of our peers, is because our capital expenditures tend to be elastic, you end up with a pretty good field contractor workforce. And so we embarked on a very systematic, comprehensive project to release our contractors and redeploy company employees to these contractor positions. And that, on a gross basis, that savings was over $40 million a year. Now that's gross, not net, but really tremendous effort on the part of our operational team to look at that workforce and find a way not only to keep our own people deployed, but to lower our overall cost structure.
But throughout our organization, it's just been humbling for me to watch the innovation and creativity that our operating groups have brought to the task of keeping our production on by lowering our cost structure. And I wish we could provide more detail, but it's been fun to be a part of. And that, quite frankly, it makes me want to work that much harder to earn a spot on such a high-performing team.
That's nice to hear. You also mentioned -- I appreciate the uncertainty here, but you said you'd probably need to see a $30-plus price before you can really make economic sense of new drilling and completions. I'm wondering, in terms of -- can you say even just broadly, what kind of price you'd need to see before you go back to growing production?
Well, if you give me a little wiggle room, I'll answer the question. I think today, if you told me that there was some sign in the heaven that said strip was what we're going to see. I think there's a high likelihood we would bring some completion crews back in the second half of the year and get after it. The challenge is with what's happened, we don't have much faith in strip. The strip holds up until you get to the near month and then it falls off from under you. So we're kind of looking for some signs that the macro environment is moving substantially to recovery. I think if we saw the world economy restarting, however sluggishly, however slow burn on restart. But if we just saw the momentum moving in that direction and thought the strip is probably a reasonable indicator. I think we -- as long as oil was, I would say, WTI in the mid-3s, we'd probably be willing to lean forward. Mark, do you want to comment on that?
Yes. Sure. Mike, I think of it in terms of -- we're obviously baking ourselves a lot of flexibility in second half of '20, not knowing, especially through this summer period. Still uncertainty on the economy what demand growth would we establish. And when we get into the fall, if you see some stability. I think as Tom said, we'd like to bring back some of that activity. And if we have some of that confidence to do that with the underlying commodity and inventories, we'd expect to do that. And as we go into '21, if we have continued north of $30 oil, we'll have a program. We could probably be in a similar level of $500 million to $600 million of capital going into '21 at $30, low $30 strip, which where it's at now. And we could start seeing sequential growth in our quarter-to-quarter growth. And it's just going to come back to when we start bringing back activity and when we start bringing additional new wells on.
Our next call question from Michael Hall, Heikkinen Energy Advisors.
I guess, Mike, kind of hit on some of what I was hoping to ask about. But I guess, maybe thinking a little near term about the completions pace. I was a little surprised to see the 2Q completions be where they were relative to the rest of the year. Is that just a function of kind of carryover activity that spilled into April and those completions are already happened? Or is there ability maybe to smooth out the back half of the year with some of those completions? Or just trying to get a little bit of a thought process or insight into your thought process around that shape.
Yes, Michael, those are pads that are in progress that we had started in March, and they were just carrying over into April. We basically just finished up with things that were already in progress. They'll be counted in first production starting in the second quarter essentially in April, as our presentation shows? Michael.
Michael, one of the things we didn't talk about, the lease obligations are a factor in what we're doing right now. I know there's been a lot of talk about some of our regulatory bodies, giving the industry broad relief. We still have individual contracts, and to the extent that lease obligations require first production we're going to preserve our assets. So some of that is involved in lease obligations.
Okay. That's helpful. That makes sense. I guess maybe as a another question here on the 2Q period. I'm just curious, as it relates to the curtailment that you've outlined, has any of that been a function of true inability to flow? Or has it really all been just purely economic, economically driven decision-making? Just trying to get...
It's purely economic. We've had flow assurance. We've got good relationships with our counterparties. And every curtailment we've made decision on has purely been economics and market forces. But there's -- we don't want to produce any well and loss. I mean, that's -- but we certainly have the opportunity to.
[Operator Instructions]. Our next question is from Jeffrey Campbell of Tuohy Brothers.
Tom, you mentioned needing macro data points to have increased investment confidence. And you spoke about, I guess, broad economic recovery. I'm just wondering what relative importance do you place on more, I guess, oily markers, such as the very high inventories that we have in both crude oil and gasoline currently?
Well, I worry about it. I worry that the amount of oil in storage is going to put a dampener on the recovery because we'll have to bleed that storage down. I don't have any particular insights on that other than what you and I both read. But I also want to remind listeners that we produce a lot of gas and natural gas liquids as well. And it's nice to see the firm up in natural gas prices. That has a significant impact on us. So it's not all about oil. It's really a 3-phase sale. But yes, I do worry about what impact the storage situation will have on oil demand.
Yes, you kind of anticipated my follow-up question, which was assuming that nat gas price improvement materializes the way we're sort of prognosticating now. How would this influence your capital allocation in 2021? I think you mentioned something about the Midcon earlier, but I was just wondering, are there also parts of your Permian acres that could benefit from those better nat gas prices as well?
Well, I mean, yes and yes. Our mid-con production looks quite a bit better, particularly in our broader cana asset, we have some opportunities in that eastern margin that they're just tremendous wells, really amazing wells that are low decline. But natural gas prices also greatly benefit us in the Permian. And it's not NYMEX. It's been really nice to see that Waha firm up and that flows right back to our wellhead netbacks. We spent too much time this year with almost 0 netbacks on our Waha. And it's really been nice to see greater than $1 Waha. And to the extent that, that holds in, that's going to have -- that makes our Delaware Basin assets look down better from an investment standpoint as well.
Jeff, on a $0.10 change in our gas price realization, that's anywhere from $20 million to $25 million additional cash flow. So definitely, the gas price improvements are positive to us in both our cash flow and our economics.
The next question is from Brian Downey of Citigroup.
Most of mine were taken, but just had a quick 1 on the Mid-Con as a follow-up. I realize it's not a huge part of the oil production base and you've had minimal recent turn in lines. But I was curious on the sequential oil declines, in particular there, they were a bit higher than we had assumed on a base PDP decline sequentially. Just wondering if there's anything one-off there in either of the 1Q or 4Q '19 mid-con oil production numbers that was leading to that large sequential decline?
Yes, Brian. We -- there isn't anything that we -- that's unusual in the numbers. That's just a reflection of some of the wells we had brought on and a decline in not only ours, but there's a fair amount of nonoperative production in our Mid-continent base, which there's some wells it had that type of decline in it.
Yes. If you want to -- we can look into some detail on how this offline. We just don't have that in front of us.
The next question is from Doug Leggate, Bank of America.
Tom, I apologize. I was a little late going on because there's multiple things going on this morning, as you know. So I apologize if I'm repeating on an earlier question. I wanted to just kind of revisit a high-level question that we've been asking all your peers, frankly, in this -- in light of everything that's going on with the text of a road commission and everything else. And the question is that when we come out the other side of this, companies like yourself, bulletproof balance sheets, tremendously conservative strategy over the years, consistent focus on returns, all the good things that have been part of this business. What does the strategy look like longer-term in a recovery scenario? And I'm not asking when do you go back to work, so to speak. It's more about what is the right balance of growth, cash returns in the context of, I guess, the signal from Saudi that they're not going to tolerate 1 million barrels a day of growth out of the U.S. How do you think about that?
Well, there are a couple of questions there. Our approach is going to be what it's been. We're going to be very prudent in the investments we make. We're not going to be growing for growth's sake, but we're also deeply committed to our dividend, and our capital structure going forward will include honoring our dividend.
Now I don't know what happens with the global price war and what the Saudis do. I suspect there'll be some consolidation in our industry. And I suspect that better operators will survive, better balance sheets and better operators. We're going to see some shakeout here in the U.S. E&P sector. We're not expecting things to go back to 2019 levels for some time, but we're going to manage our balance sheet we're going to deploy capital prudently. We're going to return cash to our investors, and we're going to try to be the best operational company in the business, and that's our outlook. Mark, you want to comment on that?
Tom, I think you said it well, I just say that we've never been about growth. As Tom said, it's always been about return on our investment. That will still be a key to how we think about moving forward. I would say that we have probably as Tom said, we want to make sure we generate free cash flow to return cash through our dividend. I guess, I got a little bit more on top of that. I think we want to have a little bit more free cash flow above that, even. So we can have some more liquidity in our balance sheet, and have the outlook to be paying down some debt with that additional free cash flow.
Guys, I know it's a tricky one to answer. If you don't mind, I'm just going to put a little bit on this because I understand the issue about the dividend and so on. But for the volatile commodity environment, a big dividend has never been an ideal part of an E&P strategy for obvious reasons. The bigger issue is how much of the total cash flows reinvested versus returning to shareholders, whether it be a variable dividend or a buyback or something like that. And that's kind of really was the root of my issue. Protecting a relatively small dividend still implies you're reinvesting an enormous amount of cash flow and a normalized oil price environment. My question is, why not shift that to something, for example, the a percentage of cash flow that gets returned to shareholders as an ongoing commitment. Because otherwise, the industry ends up with too much growth. And that's kind of what I'm getting a little bit of cash flow for a dividend, living -- that last still doesn't really get us to a point where the industry has been more conservative in its growth outlook in absolute terms. So any comment on that, Mark, or you and I have talked about this before.
Sure. Doug. That's something that we -- at the tension that we all are looking at with the amount of return we can generate from our drilling programs, which is still important to us. We think we have a great asset base, great returns. So the amount that we divert away through dividend and/or debt repayment or other cash build on the balance sheet does take away from that returns. But I think this market is evolving, and we are also evolving our thinking to where a percent more a larger percentage not being to be set aside for dividend, other returns to shareholders is prudent and the amount that we invest and making sure we get reinvested in the high rate of return projects is it's always been just a part of how we think about the business.
Let me just do a quick follow-up. Your question is a good one. You're asking about really our philosophical capital structure and investment structure going forward. And I think there have been some good white paper is written on that topic on should the industry view itself differently and not invest every penny they can. But we live in a marketplace. And if you told me that we were dealing with a $50 WTI price, that's 1 discussion. If you can tell me, we're dealing with the $30 WTI price, that's another discussion. The challenge is, if it's the latter, and we're at a $30 WTI price, and you say, well, why don't you just invest 3 quarters of your cash flow or whatever the number is, we're liquidating. And I think that's a difficult position for any E&P company to be in is have part of their long-term philosophy involve liquidation. And so in a higher price environment, it's a different discussion than in current prices. But it's a good discussion, nonetheless.
I won't waiver the point, Tom. I guess what I'm really getting at, and you've framed it brilliantly, to be honest. But what I'm really getting at is that the returns that Mark's talking about requires an oil price assumption. And that oil price assumption has been subsidized by Saudi for 4 years and the U.S. grew 50%. My point is that relying on a subsidized oil price to justify a business model is maybe not the right balance going forward. And I just wanted to see how you guys were thinking about that. But I take your point, and you're right, there's a lot of debate around this is going to continue for some time.
Our final question comes from Richard Tullis of Capital One.
Just a quick question for me. Everything else has been asked, I believe. But looking at the number of wells completed in the first quarter, I believe it was 20 net, and you also had about a dozen completed at the very end of the fourth quarter. Could you kind of sketch out how the cadence of the completions for the first quarter? And also what contribution did you get in the first quarter from the late 4Q completions?
Yes. Richard, I guess, the contribution we got from the late 4Q completions, by the way, that's a contribution from those. And the first quarter completions are fairly muted on the contribution that we saw in the first quarter completion. So you're right, we do have some carryover from the first quarter to the second quarter, but so the most affective activity has occurred and through April, and they were just out being brought on. And they're part of the overall evaluation. And when we look at May and the curtailments are part of that evaluation.
This concludes our question-and-answer session. Now I'd like to turn the conference over to Mr. Tom Jorden for any closing remarks.
Yes. I want to thank everybody for joining us, and I'll finish where I began I just want to wish everybody well through this COVID crisis. I know it's been tremendous strain, and there's a lot of loss out there. We've all felt it, some more than others. And it's a good time for us to reflect on what we're grateful for. And I wanted to tell you, I'm deeply grateful for Cimarex and the position we are in. I'm deeply grateful for our employees and our tremendous workforce. I'm grateful for our owners, and I'm also grateful for our industry and the world we play in this world economy. And so I just really want to express my appreciation to everybody for your good questions. Wish everybody well. And we look forward to seeing you on the other side. So thank you.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.