CNX Resources Corp (CNX) 2020 Q2 法說會逐字稿

Good day and welcome to the CNX Resources Second Quarter 2020 Earnings Conference Call. (Operator Instructions)

Please note, this event is being recorded. I would now like to turn the conference over to Tyler Lewis, Vice President of Investor Relations. Please go ahead.

Thank you and good morning to everybody. Welcome to CNX's second quarter conference call. We have in the room today, Nick DeIuliis, our President and CEO; Don Rush, our Chief Financial Officer; and Chad Griffith, our Chief Operating Officer.

Today, we'll be discussing our second quarter results, and we have posted an updated slide presentation to our website.

Also, in conjunction with Monday's announced transaction of CNX acquiring all of the outstanding common units of CNXM, we released a prerecorded video where Nick and Don reviewed the investment thesis of CNX and why we believe we are a non replicable, best-in-class E&P company. If you haven't had a chance to see the video, please feel free to access it on the homepage of the cnx.com website as well as on the Investor Relations portion of the company website.

To remind everyone, CNX consolidates its results, which includes 100% of the results from CNX, CNX Gathering LLC and CNX Midstream Partners LP.

Earlier this morning, CNX Midstream Partners, ticker CNXM, issued a separate press release. And as a reminder, in light of the recently announced transaction, CNXM has canceled its previously announced earnings call, which was originally scheduled for 11:00 a.m. Eastern today.

As a reminder, any forward-looking statements we make or comments about future expectations are subject to business risks which we have laid out for you in our press release today as well as in our previous Securities and Exchange Commission filings.

We will begin our call today with prepared remarks by Nick, followed by Chad and then Don, and then we will open the call up for Q&A.

With that, let me turn the call over to you, Nick.

Thanks, Tyler, and good morning, everybody. I'm going to start with my comments on Slide 3 of our slide deck. Slide 3 highlights the philosophy and approach of how we go about managing the company. Intrinsic value per share, that's the true north that we employ. It's the metric that our decision-making looks to optimize. And to really do a good job of optimizing intrinsic value per share, you have to do a couple of other things. You have to be a sound capital allocator to be able to do that. You have to be applying reality, I'll say, to assumptions to do this and the assumptions and the reality that needs to be affixed to them are in 2 broad buckets. One are external assumptions.

The most obvious example of that is gas prices. So we apply the NYMEX Forward Strip, not a different or an inflated gas price, even though we made this higher net price, we're always using the Forward Strip on external assumptions for gas pricing. And then there's the bucket of internal assumptions. A good example there would be things like capital efficiency and making sure that our capital efficiency assumptions are basically anchored in fact, in reality, versus something that's more aspirational that we want to get to, but haven't yet demonstrated in the future. You also need to be able to build a flexible and strong balance sheet. In particular, you need to do that at the bottom parts of the cycle to really have this approach work well.

So we think that we've obviously done that as well. And we do all these things at CNX, and that's not just what drives our decision-making, but it's also what drove the 7-year free cash flow plan that we laid out last quarter and updated on Monday. We feel CNX is nonreplicable. The way to sum this up perhaps is across a range of items that peers in the Basin can't do, that we enjoy. So peers can't copy the upstream/midstream strategic combination that CNX now levers. The peers can't shed liability commitments like substantial unused FT that CNX is not as heavily burdened with. The peers can't repeatably execute in the field at maintenance production levels at the low capital intensity levels that CNX brings to bear. The peers can't decide today to hedge at where our hedge book sits for the coming years. And the peers can't apply the water infrastructure that we employ to optimize activity pace and reduce costs.

Last but not least, the peers can't protect the cash flows and the balance sheet to the extent that we can, if lower gas prices brought on by a weak start to winter, start to materialize going into 2021. All this means that it's going to be tough for others to post CNX's cash costs, certainly, our cash margins, our free cash flow and of course, the opportunity that our intrinsic value per share presents to investors. We believe the company is best-in-class when you look at those cash costs and as capital efficiencies and those cash margins, largely driven by our cost and the hedge book that I mentioned, in our free cash flow profile. And last but not least, best-in-class when you look at our lowest risk to delivering and executing on those metrics.

Let's jump over to Slide 4. Slide 4, it's one, I think, that's crucial to what we really unveiled and discussed in depth on Monday. Tyler mentioned the video that dives deep into the investment thesis for CNX across 6 investment reasons that are shown on the slide. That is on our website, as he's mentioned, it's also on our YouTube, Twitter and LinkedIn company accounts. I encourage you to view it and follow up with a call or e-mail to go over any areas of interest that you want to explore more in depth. We're happy to do that.

These are the 6 that matter. And although these 6 are important and drive the future of the company, I want to point out that they're not just aspirational. These 6 are steeped in data. They're quantitative so that they can be tracked, managed and evaluated robustly over the coming years. We try to deliver tangibly to the capital markets on those often overused -- you'll hear them a lot -- yet rarely backed-up terms of transparency and following the math, being IR-driven and being a low-cost producer. If we say it, we feel a duty to prove it. That's something that excites us and we run toward.

Now all 6 of the reasons, of course, they work in concert. One builds off the other and vice versa. Today I just want to focus on 2 of the 6. One that's misunderstood and one that's not on the radar of the markets, but should be. I'm going to start with reason #2, which is the low capital intensity. That's the one, I think, that's understood by many in the market.

Now there's a lot of historical reasons, from accounting rules to the rapid rate of improvement that we've enjoyed, that make our low capital intensity today and in the coming years, an easy thing to miss. But this is a crucial point to the investment opportunity that CNX represents. And the good news is that to accurately understand how efficient we have become and will be on capital, you need to look at really only 3 drivers. The first driver is our current and future capital efficiency on drill and complete activity, it's much lower than what our history has been. So the current and future capital efficiency on drill and complete is evidenced by our finding and development costs, which, as we show in the core Marcellus, is about $0.35 today and dropping to $0.30 for 2021 and beyond.

And the CPA Utica should be as low if not lower due to that play's done in EURS. But GAAP rules dictate financial statements apply historical look back DD&A that is about $0.68 per Mcf for D&C. That historical D&C, DD&A metric, it's not accurate for current and future D&C capital efficiency because it's a collection of sunk PDP capital under very different and less prolific well profiles and capital costs. So the world has changed drastically and in a good way for CNX on drill and complete capital efficiency. And we want to ensure that our stakeholders capture the efficiency of today's and tomorrow's $0.35 and $0.30 finding and development, not the $0.68 per Mcf DD&A that is a historical look back. The second driver to understand our capital efficiency is the non D&C.

This is the land in the water in the midstream. It's a fraction today and in the future, compared to what it was in the past few years. And that build-out is completed and behind us. So what was a $510 million investment in 2019, it dropped to $155 million this year. And it drops to $70 million annually for the 6 years following this year. $70 million annually, that equates to about $0.13 in Mcf. And then the third driver of our capital efficiency for us to hold production flat at the 560 Bcf. And in the 2022 to 2026 time period, we need about 25 TILs on average per year in our core Marcellus and/or the CPA Utica fields. That's about $230 million of drill and complete CapEx annually, and that assumes no further improvement in operating efficiencies or well profiles that Chad is going to talk about in a couple of minutes.

Now if you'd like to further discuss these 3 drivers of our capital efficiencies. Again, please give us a ring or an e-mail, and we'll be glad to walk through you with them in more detail. As I said, they are crucial to understanding not just the capital efficiency, but our investment thesis with CNX. Now the second investment reason I want to cover today is reason #5 on Slide 4, which is the low-risk business model. This is one that I think isn't even on the radar of most of the capital markets today. So I just want to spend a minute on it. There's a number of drivers of why we're low-risk when it comes to delivering over $3 billion of free cash flow in the coming years. The first driver is we're substantially hedged for the coming years, which is perhaps the 1 driver of the low-risk that most of the market gets today.

The second driver is that we apply the NYMEX forwards on all open volumes that we project into the future. It's a reality-based plan. It's not an inflated gas price deck, which would be a hope-based plan. The driver, you would think is understood by the markets that I'm talking about, yet everywhere one looks these days, all you see are $2.75 and $3 gas price footnotes in decks supplied on projections. And it's not just industry companies doing this. You see the banks, the ratings agencies and a host of other stakeholders doing the same thing. And what can go up can also go down. We don't get the constant and consistent optimism on pricing being a given when it comes to the next years in this industry. We remain tethered to the forward price curve. When that changes, we'll change with it.

Third driver of low risk is the 7-year plan to deliver over $3 billion in free cash flow. It's effectively 1 frac crew setting up shop in our core fields. We don't venture beyond the core areas to deliver the plan. And we don't need to ramp up to deliver on what is effectively a maintenance production plan. The inventory we enjoy in these core fields extends far beyond 7-year inventory, and it's going to be consumed in the activity pace that we've laid out. Fourth driver of low risk, we don't need to access any of the capital markets to execute this plan. We don't need to issue debt. We don't need to issue equity. We don't need to do major asset sales. This is a huge derisker in a world where E&P's access to capital markets, it's becoming more and more volatile and suspect.

In fact, our generation of the $3-plus billion in free cash flow, it not only removes our reliance on capital markets access, it's going to allow us to reduce our exposure to the capital markets. We'll hold substantially less debt into the coming years as we continue on the march to delevering, and we'll likely have less shares outstanding in the coming years if we don't close our intrinsic value per share gap. The fifth last driver of low-risk, it's the nature of our cash flows. It's not just upstream E&P, but it's also lower risk midstream. The pro forma CNX after the CNXM taken is a blend of an Appalachian upstream and midstream entity. With midstream cash flows being lower risk and lower cost of capital than upstream, that means on a weighted average basis, CNX is a lower risk and will have a lower cost of capital, and will enjoy premiums in debt and equity markets versus the upstream peers over the long term.

Now I'm going to wrap up with Slide 5 before we turn the mic over to Chad Griffith. And what this slide tries to (technical difficulty) [communicate is that] investors should have confidence in our ability to execute into the future because we've delivered in the past. The most recent example of that is Monday's announcement of the take-in of the remaining interests of CNX Midstream that CNX does not currently own. The transaction, it's a catalyst for the 6 investment reasons we discussed. And it bolsters each and every one of them. The transaction is also an exemplar of value-accretive M&A versus what may become a theme in the Basin, of desperation M&A to address looming challenges.

The simplest way I can articulate the transaction is that CNX acquired about $100 million of annual free cash flow under a conservative set of assumptions for about $357 million in equity. That's a sub-4x multiple on true free cash flow, for a business on top of it that we know inside and out and that works hand in glove with our upstream business. And besides picking up free cash flow for less than 4x, we also picked up lower-risked free cash flow than upstream free cash flow. So pro forma, as I said earlier, our cost of capital and risk profile is declining. And besides picking up free cash flow for under 4x that's lower risk than our upstream free cash flow, we also are now going to enjoy any upside that will be created if and when prices or CNX activity pace and/or the Basin's activity pace increase.

Under that scenario, the $100 million of free cash flow will increase along with those metrics. So I'm very pleased that we're able to add that last bullet to the 2020 box that you see on Slide 5.

So with that, now, I'm going to turn things over to Chad Griffith, who's going to dive a little more in depth on some of these performance metrics.

Thanks, Nick. There are 2 broad things that differentiate CNX from our peers, which lead to many tangible competitive advantages. First, while our peers have been jumping from 1 one-dimensional metric to the next, we continually stay committed to creating long-term value per share. And while the one-dimensional metrics do often relate to the creation of long-term value, they're only 1 small part of the picture. And our broader analysis has led many different decisions over the years that have compounded into a material competitive advantage over our peers. The second difference is our team and their approach to our business.

We could not be where we are today without their dedication to CNX and absolute refusal to accept conventional thinking in any aspect of our business. So I do want to thank them for their tremendous contribution. The first major category where these 2 factors have made a difference is in capital efficiency, and we get there by continually asking the most fundamentally basic question that all E&P producers should be asking about their drilling program. How do we generate the best value for our shareholders from our undeveloped reserves? We're not trying to grow production for the sake of growth. We're not trying to fill FT. We're not trying to hit arbitrary dollar per foot metrics at the cost of risk-adjusted rate of return. And we're not trying to drill the longest laterals just for the sake of drilling long laterals.

We try to generate the best risk-adjusted rate of return for our shareholders by focusing on the overall long-term value creation of the D&C investment and by the team continually challenging conventional thinking to innovate and improve our capital efficiency. Longer laterals are a great example. We agree that they can lead to a more efficient capital. But only if they do not simultaneously increase your risk profile. So we've approached drilling long laterals, sort of like trying to get to the moon.

You don't want to get off the ground and have a problem when you're 20,000 or 25,000 feet underground. Things can get expensive fast. So we're methodically increasing our lateral length over time as we solve the various challenges to the longer lateral lengths create. We've done things like adopting QMS and adapting it to the E&P space.

QMS is a globally recognized process for ensuring high-quality products and services that's extensively used throughout automotive, health care and aerospace manufacturing to ensure the delivery of highly reliable products and services. We've [adopted] that philosophy and process to the E&P space, have begun working with our service partners to extend that process upstream through our supply chain. We've also refined a number of design criteria with our well completion designs in order to deliver a more predictable drilling and completion process. Evolution's all-electric frac fleet has also contributed to this improvement in many ways, including reduced fuel costs and significantly more flexible horsepower deployment.

These improvements have all contributed to more productive uptime and reduced downtime, which has resulted in the decreased drilling days and frac days shown on Slide #6. The economic benefit of these improvements are demonstrated by recent all-in capital results, such as our Shirley 38 M1 pad, which we brought online for an all-in dollar per foot of $680, and our more recent Richhill 99 pad, right in the core -- right in the heart of our core SWPA field that we brought online for $720 per foot. And it's important to note that in our capital per foot numbers, we include everything except for land and permit costs.

That means we include pad construction, road construction, surface facilities, wellheads, drilling, casing, cementing, completions, et cetera. So when comparing our E&P dollar per foot metrics, we encourage the investment community to challenge our peers on what all is included in their cost bucket, to ensure that you're comparing apples-to-apples across the industry space. And we've not made these improvements in dollar [per] capital efficiency at the cost of well productivity. Again, we're solving for long-term value creation for our shareholders. So our well designs and completion designs are focusing on maximizing risk-adjusted rates of return. We continually assess our well results and tweak designs in pursuit of the best risk-adjusted rates of return.

Slide 7 shows 1 example of this in action. Our most recent CPA Utica well is by far our best-performing deep Utica well, trending towards 4.5 to 5 Bcf per 1,000 foot EUR. The net result of this effort is a continual year-over-year improvement in dollar per foot capital costs and improved well productivity. We're getting nearly twice as much out of the ground for just about half the capital.

As shown on Slide 8, this has driven our finding and development costs from $1.20 per Mcfe back in 2013 to an estimated $0.35 today. And we expect those F&D costs to continue to improve further and average $0.30 per Mcfe over the 2021 through 2026 forecast period.

Slide 9 illustrates that following the recently announced midstream transaction, we have the lowest production cash cost in the Appalachian Basin. Again, this is a feat we've achieved by challenging assumptions and focusing on true value propositions for our shareholders. For instance, when the industry was focused on the one-dimensional metric of production growth, we were often asked, how will you grow without firm transportation. Well, the team challenged the conventional thinking and realized it could achieve the same basis protection, but in a much more narrowly tailored manner by adding basis hedging to our hedge strategy.

And later when the conventional thinking shifted to NGLs and the subsidy they appeared to provide to upstream economics, we stayed measured in our approach, concerned by the significant downstream logistical challenges and lack of effect of hedging. And as many of our peers were divesting or farming out their gathering systems, we retained control of our midstream and recently reached an agreement to buy back the remaining public interest in our midstream. The value spread here will only widen as the core Marcellus areas have existing gathering systems with long-term contractually long -- with long-term contractually locked in gathering rates, which by the way, were established at a level to generate a return on the original midstream capital investment.

Now that those systems have been paid for by the first round of pads, those gatherers are ready to harvest cash as dedicated producers come back to [our] infill wells or neighboring pads. Our lease operating expense also benefits from our approach. We asked ourselves why on 1 hand, do we pay a supply fresh water to our fracs, while on the other hand, we're paying to dispose of large quantities of produced water. And once we determined the reuse of produced water is all upside, we asked ourselves what the most efficient means of moving that water around in order to recycle it. Once we made that assessment, we again went against the grain, when many of our peers were slashing capital expenses during 2018 and 2019 trying to hit calendar year and near-term term metrics, we focused on the long game and made a significant capital investment to build a water management system that now allows us to reduce our disposal water volumes by over 90%.

We've also improved our lease operating costs by finding more cost-effective ways to operate our stations, pads and pipelines. We believe this difference in approach to gathering, processing and transportation and to our lease operating expense has created a sustainable competitive advantage for CNX. Our peers who have made large long-lived firm transportation commitments or long-term commitment to third-party gatherers will have that burden on their books for many years to come. And yes, there is some ability for our peers to unload some of this excess FT onto third parties. But the companies who play in that space are extremely savvy. And I'm not sure a lot of those firms will pay a premium, let alone face value, for firm transportation that's largely under water.

Building off our production cash cost. Slide 10 illustrates how we expect fully burdened cash costs to improve over the next several years. As we discussed on the call on Monday, if we allocate all of our free cash flow towards paying down debt, and with conservative assumptions on all other line items, our all-in fully burdened cash costs fall below $0.90 over the next couple of years.

Moving on to revenue. Our different approach has also positioned CNX at a distinct advantage to its peers. Instead of expecting or hoping for gas prices to improve, we think continuously about what the various factors are that influence price. More often than not, we conclude that regardless of how smart or perfect our micro/ macroeconomic analysis is, prices end up just coming down to the weather and how warm or cold each winter ends up being. So we began program (technical difficulty) equity hedging in earnest a few years ago. And now, as illustrated on Slide 11, we possess an industry-leading hedge book that predominantly hedges more volumes and for longer time periods than any of our peers.

As Don likes to say, no matter what industry you're in, if you can presell your product and know your price before spending capital or operating to produce it, how could you not take advantage of that?

And on Slide 12, we revisit the production timing we've been talking about for a couple of months now. We came out of last winter with slightly higher-than-average storage inventories and a lot of associated gas coming out of the Permian. Gas markets were already strained when COVID-19 had a dramatic impact on the entire global economy. Summer 2020 gas prices plummeted, but the huge reduction in rig activity created some real bullishness for supply reductions and for improved prices this coming winter and beyond. For the first time in several years, the winter-summer arb widened enough to justify shifting some production from summer to winter, particularly if it was synced up with the flush production period from new wells.

So we shut in a handful of our newer pads and then shut in several more brand-new pads over the past few months after we got those wells flowed back and cleaned up. We also took steps to modify our hedge book to lock in this summer winter arbitrage. We cashed a number of summer 2020 hedges, resulting in a gain of $29 million and began layering on incremental winter hedges to match the change production profile. Those incremental winter hedges locked in the value of the shut-in move for CNX, even if the actual winter prices soften over the next several months. Currently, we have just over 0.5 bcfe a day of gas shut in, and we are planning to bring that gas back online sometime around the first of November. [That led to our] original decision to shut these wells in when summer NYMEX prices were averaging $2.08 and winter was averaging $2.90, while August NYMEX just settled at $1.85, and while winter is still around $2.85.

The arbs has actually widened further since the original decision to shut in. So we're sticking to the plan to turn these wells back online in November. We have that flexibility thanks to our balance sheet health and low levels of [MDC]. Again, we're solving for all-in long-term value creation for our shareholders, not one-dimensional metrics. Interestingly, the decline in gas production that everyone was counting on as the basis for strong prices this winter doesn't seem to be happening. Lower 48 gas production has remained robust, storage inventories will likely be above 4 TCF heading into winter, and production that's currently shut in will start coming back online. If we don't end up with a cold winter, the bull case for '21 is pushed into 2022 and '21 gas prices will likely come down. Producers hoping and praying for those stronger '21 gas prices are basically betting the balance sheet on winter, and that is a risky proposition.

Finally, Slide 13 highlights our activity in the quarter. We're currently running 1 rig and 1 frac crew.

And with that, I'll hand it over to Don.

Thanks, Chad, and good morning, everyone. During the second quarter, we completed a $345 million opportunistic convertible notes offering at a favorable 2.25% interest rate. The proceeds were used to pay down the 2022 notes and will result in annual cash interest rate savings of approximately $13 million per year. And we simultaneously entered into a call spread to minimize potential equity dilution. The remainder of the 2022 notes are expected to be repaid using organic free cash flow generated from the business. Slide 14 shows the projected cumulative free cash flows versus our maturity schedule. And as you can see, retiring our debt as it comes due will be easy to achieve. Especially considering that our near-term projected free cash flows are over 90% protected due to our hedge book.

Slide 15 highlights that our 2020 guidance remains unchanged from last quarter. One thing to note is that we started deferring volumes in May, as Chad mentioned, and the current expectation is to turn those wells back online November 1. Assuming that scenario, we would expect production to be towards the lower end of the 2020 guidance range. But even with those production shut-ins factored in, we expect our annual EBITDAX to be on the high end of our capital -- our annual EBITDAX to be on the high end of our guidance range. And for 2020 CapEx, approximately 65% of the remaining projected spend should occur in Q3, resulting in a much lighter Q4. As we have mentioned, our production deferrals this year helped set us up nicely for 2021, where we continue to expect to produce around 550 Bcfe of volumes and $425 million of free cash flow.

To reiterate what we've stated previously and consistently proven through our actions, we will modify our production level up or down when we see opportunities to optimize value as gas prices fluctuate both up or down. Slide 16 is an illustration of the long-term free cash flow profile of the company, along with the math supporting the free cash flow yields. We expect to generate approximately $3.3 billion in cumulative free cash flow across our 7-year plan and have an average free cash flow yield of around 26%, which is remarkable by any standards. In order for our free cash flow yield to get to an energy sector average of approximately 6.5%, our share price would have to increase to over $30 per share, assuming the $2.30 per share of annual free cash flow generation baked into our 7-year free cash flow plan.

I would like to wrap things up on Slide 17, which we view as our investment thesis. CNX is the lowest-cost producer in Appalachia, using conservative assumptions and at the current NYMEX strip. We expect to generate over $500 million of free cash flow per year. Our business plan is low risk, with potential for material value creation above it. Not surprisingly, we believe our $9 stock price is significantly undervalued, based on debt-to-equity value math and the fact that we should be valued as a free cash flow yield investment.

On top of that, the company and gas prices have a tremendous amount of upside in the future. Our company is even more attractive when considering the flexibility we have to invest our free cash flows, to create even more value beyond what's projected in our base business value proposition. You add all this up, and it supports our belief that CNX is one of the best investments in the entire public market. As we move forward quarter-by-quarter, year-by-year, we look forward to delivering on our free cash flow projections, paying down our debt, creating more value and eventually, not only getting our stock to a point where our free cash flow yield is more reasonable, but creating more incremental value on top of that.

With that, I'll hand it back over to Tyler for any questions.

Thanks, operator. If you can open the line up for Q&A at this time, please?

(Operator Instructions)

Our first question today will come from Welles Fitzpatrick with SunTrust.

It sounds like the curtailments are going to last through November. If that's the case, do you guys have any incremental hedges that you would plan to sell if that actually comes to fruition and those volumes are held back?

Yes. Thanks for the question, Welles. This is Chad. So right now, we're actually planning to bring those volumes on November 1. So we would expect those volumes to be online for all of November and December. But you're right, that is a function of price. We have hedged those volumes. So we've hedged the change in production profile in November, December, all the way through March. And really all the way into '21, we added some incremental hedges to match the deferred production profile. So if something would happen that November prices would erode, we have tremendous flexibility to be able to wait till December. We can just keep sort of rolling that play forward, cashing in the hedge value and saving those molecules for a stronger price day. So sitting here today, we're looking at the Forward Strips, seeing where the prices are. The plan continues to bring those bring those wells online November 1.

Okay. Okay. That makes sense. And then any chance we could get an update on the economics or maybe the relative value of new wells and -- in Southwest PA Marcellus versus Shirley Pennsboro. I mean it seems like the costs are coming down a little bit quicker on the Shirley Pennsboro side, but maybe I'm misreading that.

Sure. The Shirley Pennsboro wells, they're really the biggest part of our undeveloped wet production. So the economics of those wells remain subject to the volatility of NGLS. We're certainly hopeful the NGL markets return, that would enhance the economics of the Shirley Pennsboro wells. But for the time being, with the volatility and risk associated with NGLs and sort of everything that's going on with the oil markets, it's sort of caused Shirley Pennsboro to fall behind some of our core SWPA area.

Okay. Perfect. And just 1 last one, if I could sneak it in. I mean, in both the CNX and CNXM presentation from a couple of days ago and today, you guys highlight the attractiveness that you would bring to an acquirer, especially with kind of a deleveraging aspect. Should we be viewing that -- the transaction with CNXM, at least to some extent, as a function of wanting to simplify for the sake of maybe being a little bit more tempting for others to kind of come after you in the A&D market? Or am I just reading too much into that?

Welles, this is Nick. I think that M&A, and particular items or views on M&A, we'll take a no comment approach. But I will say that with the midstream take-in transaction, there were a number of what I would perceive advantages or drivers of that. I mentioned the free cash flow acquisition cost, which was very attractive. That's a big positive when you're solving for intrinsic value per share. The simplification that you mentioned is another one, right? That will lead on to other sort of cost reduction improvements and efficiency drivers, which will be great. And there is, as I said, some significant upside.

So if you're looking at free cash flow generation or leverage ratio or optionality if and when things strengthen with the gas markets or in-basin, and you're looking how that sort of rolls into the perceived value proposition of the company and M&A activity, but those are all positives, of course. So just to sort of answer it generally, I think yes, I think it does improve our standing in that metric. But beyond that, wouldn't want to comment on M&A.

And our next question comes from Jeffrey Campbell with Tuohy Brothers.

I think the list of innovations on Slide 5 is instructive, and I'd even add construction of the dual system gathering as another one. With that in mind, is investment in the CPA infrastructure to flow the Utica resource completely off the table for the next 7 years? Or are there signals that could bring that effort forward to some extent?

Yes. No, this is Don. Definitely, I think it's not off the table. I think what we tried to lay out and construct here is that we're able to bring in some volumes up in CPA Utica without sort of a, call it a step change in infrastructure that's required up there. And the recent transaction we did and the flexibility that opens up for us in the future in gas prices increasing and you'd want to step change and actually grow some production. It's a great area to do that in. And the flexibility of bringing midstream in-house now gives us the ability to self do that function. It gives us the ability to partner with folks.

So it's a freedom of how to properly structure it. We've spent a lot of time looking at different ways to go about it. And it's great to have a 7-year based business model that produces so much cash flow that you've could have the optionality to think about when is the right time for that. And as Nick said in his opening remarks, we'll follow the NYMEX strip in making those decisions, just like we did on the sort of the infrastructure build-out in Southwest PA. We built it out, but we also put in a bunch of hedges to protect us in case market dynamics shifted during the middle and post that build out. So I think we'd view anything incrementally in CPA above and beyond what's in our 7-year base cash flow plan similarly.

Okay. And kind of going back to this hedging and curtailing business. Going forward, do you ever get to a point where you'd think about curtailing production without hedging as a way to save hedging costs while enhancing pricing? Or would that just be too risky an approach to ever take?

Yes. It's -- Chad can weigh in some on this too, but for us, I mean we like hedging, like I said, I think any industry out there that you could lock in volumes and prices for a product, and make substantial margins and returns on your capital still by locking in these prices, take it, right? Don't get greedy. We always have more wells to drill. We got a lot of interesting opportunities if gas prices rise. So I think we're going to stick to the, let's have safe, predictable cash flows and returns method for the company.

Yes. And I think when we think about shut in math and hedging and taking the risk of that shut in value proposition. So you shut in volumes today betting on improved prices tomorrow. Well, you're carrying risk by waiting, right? You're deferring volumes, you're deferring revenue today in favor of stronger revenues tomorrow. You can lock that risk away by layering on hedges. It's almost a no-brainer, right? So -- but to your point about cost, we have a sufficiently deep sort of counterparty pool that we're able to, especially with the near-term hedges there's really not a big transaction cost on those. So it's not a real expensive proposition to go hedge those. It's a fairly liquid market, and the prices are fairly transparent. So we don't see a huge transactional cost in putting that risk to bed.

And even the best crystal ball gets messed up based on cold winter, warm winter or if an incremental 1 or 2 Bcf a day of supply shows up. And with that kind of unpredictability, it's a tough thing to spec on, and we're going to stick to locking in prices that make sense for us. And fortunately, we're the lowest cost producer. So we'll always have that ability to kind of hedge where other folks are higher on the cost curve. It's a more difficult decision if the cost and the margins are a lot thinner, hedging in the current forward price. But for us, they work, and we're going to continue to chip away at hedging them.

Yes, well, I like that answer. And it's also logically consistent with what you said earlier in the call, which is that your longer horizon hedging is based on a recognition that the weather remains a big deal no matter how much you try to plan around it. So I like that answer a lot.

And our next question will come from Holly Stewart with Scotia Howard Weil.

Maybe first, looking at Slide 6. It looks like the most recent Southwest PA Marcellus well costs are in the $720 per foot [range], which is quite a bit lower than the $830 that's included in the guidance. So can you maybe give us a sense where maybe first half ended up or maybe even 2Q as a comparison? And then what you need to see to reassess that $830

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So counter averages are a bit

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and then we have the artifacts of like wells we turned online at the very beginning of the year end up getting lumped into that sort of calendar year average for capital per foot. But to your point, the dollar per foot number is strongly trending down over the course of the year and really setting us up for a strong '21. As we talked about in the prepared remarks Richhill 99 came online at $720 a foot, really phenomenal performance by the team. We have 2 additional Marcellus pads that we plan on bringing online in the balance of the year. Both of those are expected to come in, in that $700 a foot range, between -- somewhere between $700 and $800 a foot. So tremendous efforts by the team for bringing that dollar for foot average down over the course of the year and setting us up for a strong '21 and really beyond.

Okay. So Chad, any sense maybe where the first half trended or even 2Q?

I mean, Holly, we can follow up on it. I don't have that number right in front of me. I've got about a year, but I don't have the individual quarter or first half of the year metrics in front of me.

Okay. Okay. I'll follow-up with Tyler. And then maybe second question. Just on the 2Q CapEx, it looks like there were fewer wells drilled and completed than the first quarter, but the actual E&P spend essentially looked flat. So is there anything like one-timers driving the 2Q number?

No. There's no one-timers in that. We've got a bulk of wells that are teed up and ready to turn online. We've got 2 pads right now that are in the process of drilling out. And like basically drilling out and flowing back, so those will be TILs in Q3. It's sort of -- we talked earlier in the year, it's a fairly linear program. It's a little bit shifted towards the first half of the year. And I think Don talked a little bit about the shape of the capital spend, but there's nothing really lumpy going on. It's just sort of like, fairly linear with the trend down...

And the transition from 2 rigs to 1 rig. So now we're running 1 rig and 1 frac crew. It's moving us that direction. Q3, we'll still have a little bit of a bigger -- proportionately. We said around 65% of the remaining capital will be spent in Q3 or Q4 getting to more of a steady-state run rate, 1 rig, 1 frac crew plan that Nick talked about.

Okay. Sorry, Don, you said what percent in Q3?

Q3, about 65% of the remaining capital will be spent in Q3. Q3 will be heavier than Q4.

Got it. That's perfect. And then maybe just 1 clarification question on the production shut ins, Chad, that you mentioned, I think you called for roughly 0.5 Bcf a day. And the -- I guess it was June 15 update said that you were moving down to $300 million as of July 1. So I just wondered, is there a change there, I'm assuming?

There is. So when we initially made the shut-in decision, we were at around 350 million a day. Follow -- as we talked about in the operational update, NGL prices had improved marginally. So we had brought back online some of our wet production in the Shirley-Pennsboro field -- not all of it, but some of it -- so that got us to the 300 million a day number. And since that time, we've had a number of wells that have been drilled out, flowed back and ready to flow, and now we've shut back in waiting for the stronger winter prices. And frankly, there's another 1 or 2 pads planned as well that we're looking at doing the same thing. So that puts us today, it's at about 0.5 Bcfe a day of shut in.

Our next question comes from Kashy Harrison with Simmons Energy.

So looking at Page 8 of the slide deck, so you highlight improved lateral adjusted well performance in 2019 relative to 2018 and an expectation for further improvement in 2020. And you're showing an improvement in lateral adjusted well performance while showing longer laterals. And so I was just curious if you could walk us through some of the drivers of what's causing the lateral adjusted productivity to increase.

This is Chad. I'll take that. So it's really a combination of 2 things. The biggest driver, and there's 2 major drivers in the reduction of sort of dollar per foot D&C costs, all-in capital costs, really. And that's, first and foremost, the efficiency of our operations, so maximizing uptime while minimizing downtime, and the team's laser-focused on making improvements on both of those fronts, and that's being achieved through our QMS program. And the second factor is really longer laterals. As I said in my prepared remarks, longer laterals do make a difference if you can get them done without having a bunch of issues: without impairing your productivity, without getting stuck down hole, these longer laterals can create a lot of challenges.

And I think that's why some of our peers who made a big -- tried to make a big leap. It was sort of a step too far. Instead of trying to make a big leap, we've been methodically walking it up as we've solved these challenges. As we've been able to adjust our completion designs, as we've been able to adjust our well design in order to maintain that well productivity, while reaching the longer lateral lengths. And so for us, it's been a methodical increase in lateral length without really increasing our risk profile or impairing well results. And that's how we've been able to achieve the improvements on a dollar per foot while maintaining and improving our actual well results.

Got you. Got you. That's helpful. And then just for my follow-up, sticking with Slide 9, on the top left of the page a DD&A rate of $0.87 and then looks like for the first half of this year, you guys are kind of in the $0.95 to $1 an M, and obviously, as you highlight here, the implication at least should be, that with the lower F&D costs, you would expect that DD&A rate to trend [lower] over time. And so I was just wondering if you could give us a sense of how to think about the DD&A rate over the long-term and how you guys are looking at ROC, ROIC, just so we can get a sense of the return metrics to capital employed.

Yes. It'll -- you'll see it sort of trending down across these pieces here. We didn't really break out how that rolls, outside of just the D&C and the fact that our non-D&C spend dropping every year too, clearly will allow it to trend towards the go-forward average as Nick likes to say, as opposed to the trailing average on these metrics. And when we do look at any of the return on the capital that we are employing, right now we are making these incremental decisions on the next pad, whether you drill it or we don't drill it. So we're looking at the information on a go-forward basis to make the decision.

Got you. Do you have any sense of if/when you might get to a double-digit type ROCE number on a corporate basis?

I'd have to get back to you on that. I mean, I wasn't looking more on the cash flow side than off the top of my head.

There's going to be the meeting of what DD&A will do and ROCE under the accounting GAAP rules and when it starts to meet or hit a confluence with sort of the here and now capital allocation, which is that $0.35 going to $0.30 F&D on drill and complete the $70 million of other CapEx for land, water and midstream, which is about $0.13 in MCF. And then the maintenance of production activity pace, which is about a 25 TIL average a year that we spoke about. So that, to me, I look at that as that's sort of the current add year-by-year or quarter-by-quarter to what our ROCE is on our capital deployment decisions today moving forward. And at some point, that DD&A rate under the GAAP accounting rules will start to bleed into that pretty compelling, all-in sort of per Mcf capital charge.

Our next question will come from [Harry Hallock] with Raymond James.

I just have a quick question on the shut ins. You all had mentioned that you would potentially move them out to December. I just wonder what gas price you're looking for before bringing those volumes back in, and also slightly more optimistic on gas than some others. So I was just wondering if the same would apply and you all could possibly bring them back sooner, in like October, if gas prices rebounded?

Yes. So right now, what we see is that the value proposition or the NPV of bringing those wells online November 1 versus December 1 is very close, with November 1 eking it out, in the current strip. So to the extent that November would weaken relative to the rest of winter is when we would start considering pushing some of that gas back. I don't have an exact number for you because it's going to vary by -- well by well, by pad by pad, but that's the type of analysis we do. We're looking at it on sort of a day by day, well-by-well basis.

Really molecule by molecule and determining the optimal time to turn each of those molecules online in order to generate the best present value for our shareholders. On the broader macro picture, sort of talked a little bit about it in the prepared remarks. We've got summer prices that are continuing to deteriorate. There has been a bit of a rally over, call it the last week. I think a lot of folks are scratching their head at the recent rally. Storage inventories continue to fill at phenomenal rates. We're at the upper end of sort of the 5-year range on storage inventories. Most analysts are thinking we're going to enter winter at 4 TCF or more in storage. And there's a lot of shut-in volumes that are probably going to -- we hear there are a lot of shut-in volumes that are sitting there ready to be turned back online.

When you look at the data, production data, things like that, production data is rallying, production volumes are increasing over the course of summer. I don't know if I'd actually say I was more optimistic about gas prices than others. I'm a little bit worried about gas prices, particularly moving into winter and next summer. But that's why CNX, that's why we've hedged the shut-in arb. That's why we've added additional hedges in '21 at the high prices what we're seeing in the Forward Strip. And we're cautiously optimistic that they hang in, but we're protected if they don't. For '22 and beyond, I think that's maybe -- obviously, there are a lot of rig reductions. There's a lot fewer rigs running today than there have historically been. So that's setting up -- that is setting up supply reduction. And when that manifests itself and it improves supply-demand balance, it will happen. It's just a question of when.

Yes. And if things do get better sooner, which that would be great if they did. Yes, we could turn the wells back online, September, we can turn them online in October, we can turn them online in a week. So it's ready and willing. We've already kind of restructured our hedge book. So any kind of positive run-up there, we'd get it cash flow dollar-for-dollar by get turning wells online sooner at a higher price. And we still -- just because of the flat profile of these for the next 6 months or so, we've still got the coverage in the Q4 time frame that we still made a decision. So gas prices go down, the shut-in decision made our money, we're better off because of it. Gas prices go up, we'll put them -- bring them in earlier and made even more money because of it. So we've set ourselves up to win either way, if gas prices go up or down, which you have to be set up that way in a commodity industry because it's just too hard to get it right every time.

And this will conclude our question-and-answer session, thus concluding today's conference. A replay of the event will be available by accessing the number (877) 344-7529 or 412-317-0088 using the replay access code 10145861. Once again, the dial-in number to access the replay will be (877) 344-7529 or 412 317 0088, using replay access code 10145861. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect your lines at this time.