CNXM CNX Midstream Partners LP

Filed by CNX Resources Corporation

Commission File No.: 001-14901

Pursuant to Rule 425 under the Securities Act of 1933

Subject Company: CNX Midstream Partners LP

Commission File No.: 001-36635

Date: July 30, 2020

30-Jul-2020

CNX Resources Corp. (CNX)

Q2 2020 Earnings Call

		Total Pages: 19
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MANAGEMENT DISCUSSION SECTION

Operator: Good day, and welcome to CNX Resources Second Quarter 2020 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. [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.

Tyler Lewis

Vice President-Investor Relations, CNX Resources Corp.

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’ve 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 pre-recorded video where Nick and Don review 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 home page of the cnx.com website as well as on the Investor Relations portion of the company website.

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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 cancelled its previously announced earnings call which was originally scheduled for 11:00 AM 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.

Nicholas J. DeIuliis

President, Chief Executive Officer & Director, CNX Resources Corp.

Okay. 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 two assumptions to do this and the assumptions and the reality that needs to be affixed to them are in two broad buckets. One, our 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 may desire that 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 and 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 and particularly 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 seven-year free cash flow plan that we laid out last quarter and updated on Monday.

We feel CNX is non-replicable. 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 repeatedly execute in the field at maintenance production levels, at the low capital intensity levels that CNX brings to bear. The peers can’t decide [ph] the date to (00:04:18) hedge, where our hedge book sits for the coming years, and 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 those capital efficiencies and those cash margins largely driven by our costs and the hedge book that I mentioned, and 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.

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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 six investment reasons that are shown on the slide. That is on our website as he 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 email to go over any areas of interest that you want to explore more in depth. We’re happy to do that.

These are the six that matter and although these six are important and drive the future of the company, I want to point out that they’re not just aspirational. These six 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, you have rarely backed up terms of transparency and following the map, being IRR-driven and being a low-cost producer. If we say it, we feel the duty to prove it, that’s something that excites us and we run toward.

Now, all six of the reasons of course they work in concert. One builds off the other and vice versa. Today, I just want to focus on two of the six, 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 number two 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 three 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 was about $0.35 today and drop into $0.30 for 2021 and beyond. In the CPA Utica, it should be as low, if not lower due to [indiscernible] (00:07:27) EURs.

But GAAP rules dictate financial statements apply historical look back DD&A that is about $0.68 per mcf for D&C, and 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 looking back.

The second driver to understand our capital efficiency is the non-D&C. This is the land and the water and the midstream. It’s a fraction today and in the future compared to what it was in the past few years. Now 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 six 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 in the 2022 to 2026 time period, we need about 25 tills 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’s going to talk about in a couple of minutes.

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Now, if you’d like to further discuss these three drivers of our capital efficiencies, again please give us a ring or an email 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 number 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. Now the first driver is we’re substantially hedged for the coming years, which is perhaps the one driver of the low risk that most of the market gets today.

The second driver is if 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 [ph] price tag (00:10:01) 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 index applied 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 seven-year plan to deliver over $3 billion in free cash flow. It’s effectively one frac crew setting up shop in our core fields. We will 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 and production plan. The inventory we enjoy in these core fields extends far beyond seven-year inventory, 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 de-risker 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 dollars in free cash flow, it not only removes our reliance on capital market’s 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 [ph] March (00:11:35) delevering and will 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 CNX [ph] I’m taking (00:11:54) 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 has 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.

I’m going to wrap up with slide 5 before we turn the mic over to Chad Griffith. And what this slide tries to 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 [ph] take-in (00:12:31) of the remaining interest of CNX Midstream, that CNX does not currently own. The transaction, it’s a catalyst for the six 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.

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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, at the sub-4 times multiple on true free cash flow for a business on top of it that we know inside now and that works hand-in-glove with our upstream business. And besides picking up free cash flow for less than four times, we also pick up lower risk free cash flow than upstream free cash flow. So pro forma, as I said earlier, our cost of capital and risk profile is climbing.

And besides picking up free cash flow for under four times is 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 side 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.

Chad A Griffith

President & Chief Operating Officer, CNX Resources Corp.

Thanks, Nick. There are two broad things that differentiate CNX from our peers, which lead to many tangible competitive advantages. First, well our peers have been jumping from 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 are only one small part of the picture, and our broad analysis has led to 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 cannot 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 two 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 the 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, the cost of risk adjusted rate of return. And we’re not trying to drill the longest laterals just for 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 while the team continually challenging conventional thinking to innovate and improve our capital efficiency. Longer laterals [indiscernible] (00:15:29). 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 longer 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.

We’re methodically increasing our lateral length over time as we solve the various challenges that 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 to run automotive, healthcare, 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 chains.

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We’ve also referred a number of design criteria with our well on completion designs, in order to deliver a more predictable drilling 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 number 6. The economic benefit of these improvements are demonstrated by recent all-in capital results such as our Shaw [indiscernible] (00:16:57) pad which we brought on line for an all-in dollar per foot of $680 and our more recent RHL 99 pad right in the core – right in the heart of our core SWPA field that we brought on line for $720 per foot.

And it’s important to note that in our capital per foot numbers we include everything except for land and permitting costs. That means we include pad construction, road construction, services facilities wellheads drilling, casings, cementing completions et cetera. When comparing our E&P dollar per foot metrics, we encourage the investment community to challenge our peers of 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 and dollar per foot 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 one example of this in action. Our most recent CPA Utica well is by far our best performing deep Utica well, turning towards 4.5 to 5 Bcf per 1,000 foot EUR. The net result of this effort is a continual year-over-year improvement and dollar per foot capital costs and improved well productivity. We’re getting nearly twice as much out of the ground for just about half of the capital. As shown on slide 8, this has driven our finding and development costs from a $1.20 per Mcfe back in 2013 to an estimated $0.35 today, and we expect those F&D costs to continue improve further and average $0.30 per Mcfe over the 2021 through 2026 forecast period.

Slide 9 illustrates the following, the recently announced Midstream transaction. We had the lowest production cash cost in the Appalachian basin. Again this is a feat, we have 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 you grow without firm transportation. Well, the team challenged the conventional thinking and realized we 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 appear to provide the upstream economics. We stayed [ph] major (00:19:24) in our approach, concerned about the significant downstream logistical challenges and lack of effective hedging.

And as many of our peers were divesting or farming out their gathering systems, we retain 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 [indiscernible] (00:19:49) in gathering rates, which by the way we’re establishing 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 for infill wells or neighboring pads.

Our lease operating expense also benefits from our approach. We asked ourselves while on one hand, do we pay to supply fresh water to our fracs, while on the other hand we’re paying [ph] disperse (00:20:18) of large quantities of produced water. And once we determine the reuse of produced water is all upside, we ask ourselves what the most efficient means of moving that water around in order to recycle it. And once we made that assessment, we again went against the grain where many of our peers for slashing capital expenses during 2018 and 2019, trying to hit calendar year and near-term metrics. We have focused on the long game and made a significant capital investment to bought a water management system that now allows us to reduce our disposal water volumes by over 90%.

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We’ve also improved our lease operating cost 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 from transportation commitments or long-term commitments of third-party gathers 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 these excess FT on the third-parties. With the companies who plan its base are extremely savvy, and I’m not sure why those firms will pay a premium rather than a face value for firm transportation that’s largely under water.

[ph] Building up (00:21:33) higher production cash costs, 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 our free cash flow towards paying down debt and with conservative assumptions on all other line items, our all-in full burdened cash costs fall below $0.90 over the next couple of years.

Moving on to revenue, our different approach has also positioned CNX add a distinct advantage to its peers. Instead of expecting or hoping for gas prices to improve, we think continuously about what the various factors [ph] are that (00:22:05) influence price. More often than not, we conclude that regardless of how smart or perfect our microeconomic analysis is, prices end up just coming down to the weather and how warm or cold each winter ends up being. So, we began programmatically hedging [indiscernible] (00:22:22) two years ago and now as illustrated on slide 11, we possess an industry-leading hedge book that predominately hedges more volumes and for longer time periods than any of our peers. As Don like to say, no matter what industry you’re in, if you can pre-sell 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 of rate 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 are widened enough to justify shifting some production from summer to winter, particularly if it would sync up with the flush production period from new wells.

Though we shut-in a handful of our new pads and then shut-in several more brand new pads over the past few months, after we got those wells flow back and cleaned up. We also took steps to modify our hedge book to lock in this summer winter arbitrage. We cashed in a number of summer 2020 hedges, resulting in a gain of $29 million and began layering on incremental winter hedges to mask the changed production profile. Those incremental winter hedges lock in the value of the shut-in new for CNX even if the actual winter prices soften over the next several months.

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Currently, we have just over 0.5 Bcfe a day of gas shut-in, and we are planning to bring that gas back on line sometime around the 1st of November. The main 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 arm has actually widened further since the original decision to shut-in. So, we’re sticking to the plan to turns these wells back on line in November. We have accessibility, thanks to our balance sheet help and low levels of [indiscernible] (00:24:26). Again [indiscernible] (00:24:28) for all-in long-term value creation for our shareholders, now one dimensional metrics.

Interestingly, the decline in gas production that everyone was counting on is the basis for strong prices this winter doesn’t seem to be happening. Lower 48 gas production has remained robust. Storage inventories were likely be above 40 CF heading into winter and production that’s currently shut-in will start coming back on line.

If we don’t end up with a cold winter, the [indiscernible] (00:24:55) for 2021 is pushed into 2022 and 2021 gas prices will likely come down. Producers hoping and praying for the stronger 2021 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 one rig and one frac crew.

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

Donald W. Rush

Chief Financial Officer, CNX Resources Corp.

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 we used to pay down the 2022 notes and will result in annual cash interest rate savings of approximately $30 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 on line 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 or – 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 deferral this year helps 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 seven 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 seven year free cash flow plan.

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I would like to wrap things up on slide 17, which reviews 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.

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?

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Yeah. 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 this volumes to be on line for all of November and December. But, you’re right, that is a function of price. We have hedged those lines. So we’ve had the change in production profile November, December, all the way through March and really all the way into 2021, we had some incremental hedges to match the deferred production profile. So, if something, what happened at November prices would erode. We have tremendous flexibility to be able to wait for December. We can just keep sort of rolling that play forward, cashing in the hedge value and saving those molecules for a [ph] stronger price day (00:30:54). So, sitting here today, looking at the forward strips and where are the prices are that the plan continues to bring those wells on line, November 1.

Okay. Okay. That makes sense. And then any chance, you could give an update on the economics or maybe the relative value of new wells 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 productions. So, they – 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 – but for the time being with the volatility and risk associated with NGLs and sort of everything is going over the oil markets, that’s sort of cost Shirley-Pennsboro fall behind some of our core SWPA area.

Okay. Perfect. And just one last one, if I could sneak it in. I mean in – in both the CNX, CNXM presentation from a couple days ago and today, you guys highlight the attractiveness that you would bring to, to and acquire especially with the – you know kind of a deleveraging aspect. Should we – 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 come, come after you in the A&D market or am I just reading too much into that?

Well, this is Nick. I think that M&A in particular items or views on M&A will 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 – 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 to foresee value proposition of their company and M&A activity, but those are all positives of course. So, just to sort of answer generally, I think, yeah, I think it does improve our standing in that metric. But beyond that, I wouldn’t want to comment on M&A.

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Okay. Fair enough. Thank you so much.

Operator: And our next question comes from Jeffrey Campbell with Tuohy Brothers. Please go ahead.

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

Yeah. 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 the CPA Utica without sort of a part of step change in infrastructure that’s required out there. The recent transaction we did and the flexibility that opens up for us in the future and 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 to bring in Midstream in-house now gives us the ability to self do that function. It gives us the duty 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 seven-year based business model that produces so much cash flow that you 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 to making those decisions just like we did on the sort of the infrastructure build out and [indiscernible] (00:35:29), we build it out, but we also put in a bunch of hedges to protect us in case market dynamics shifted door in the middle and post that build out. So I think we do anything incrementally in CPA above and beyond within our seven year base cash flow plan similarly.

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

Yes, it’s – it’s just – Chad, Chad can weigh in [indiscernible] (00:36:12) for us. I mean we like hedging like I said I think in any industry out there that you could lock in volumes and prices for a product that makes substantial

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margins and returns on your capital still by locking in those prices, take it right, don’t be greedy. We always have more, more wells to drill. We’ve got a lot of interesting opportunities, the 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.

Yeah, I think, when we think about shut-in math and hedging and taking the risk of that shut in value proposition. So, your 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 and in favor of stronger revenues tomorrow. If you can lock that risk away by layering on hedges, it’s almost a no brainer right. So, what’s your point about cost, we have a sufficiently deep sort of counter particle that we’re able to especially the near-term hedges, it’s really not a big transaction cost on them. So, it’s not a real expensive proposition to go hedge those. It’s a fairly liquid market and the prices are – 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 or warm winter or it’s an incremental 1 or 2 Bcfe a day of supply shows up. And with that kind of unpredictability it’s a tough thing to speck on and we’re going to stick to locking in prices that make sense for us and fortunately we’re the lowest cost producers who will always have better ability to kind of hedge where other folks higher on the cost curve, some more difficult decisions, 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.

Thanks, Holly. This is Chad. So, counter averages are a bit lumpy and they have the artifacts of like you know wells we turned on line at the very beginning of the year end up getting lumped into that sort of counter year

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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 2021. As we talked about in the prepared remarks, RHL 99 came on line at $720 per foot, really phenomenal performance by the team. We have two additional Marcellus pads that we plan on bringing on line 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 – bringing that dollar per foot average down over the course of the year and setting us up for a strong 2021 and really beyond.

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 – there’s no one-timers in that – in that. We’ve got a bulk of wells that are teed up and ready to turn on line. We’ve got – we’ve got two pads right now that we’re in the process of drilling out and like basically drilling out flowing back, so those will be TILs in Q3. It’s sort of – we talked earlier in the year, it’s – it’s a – 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 a trend down.

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Got it. That’s perfect. And then maybe just one clarification question on the production shut-ins, Chad, that you mentioned I think you called for roughly 0.5 Bcfe a day and I guess it was June 15th update said that you were moving down to $300 million as of July 1, so just wondered

There is. So, when we initially made the shut-in decision, we were out $350 million a day, follow – as we talked about that 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 through 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.

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And frankly, there’s another one or two pads planned as well that we’re looking at doing the same thing. So that puts us today at about 0.5 Bcfe a day of shut-in.

Operator: And our next question comes from Kashy Harrison with Simmons Energy. Please go ahead.

Good morning and thank you for taking my questions. 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 [ph] lateral (00:43:34) 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?

Yeah. This is Chad. I’ll take that. So, it was really a combination of two things. The biggest driver and there’s two major drivers in the reduction of sort of dollar per foot D&C costs, all-in capital cost really and that’s – first and foremost, the efficiency of our operations, so maximizing uptime while minimizing downtime and the team’s laser focus on making improvements on both of those fronts and that’s being achieved through our [ph] QMS (00:44:19) 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 a 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 [ph] a lot (00:44:46) 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 designs 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 you highlight 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. And obviously as you highlight here the implications at least should be that with the lower F&D costs you would expect you know that D&A rate to trend 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? Thank you.

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Yeah. 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 — on the next pad whether you drill it or we don’t drill. 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 ROCI number on a corporate basis?

I’d have to get back to you on that. I mean I’ve been looking more on the cash flows side than that off the top of my head.

So there’s going to be the meeting of what DD&A will do and ROCI 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 an mcf and then the maintenance of production activity pace, which is about the 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 ROC 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.

Operator: And our next question will come from Harry Halbach with Raymond James. Please go ahead.

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

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Yeah. 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 – November 1 eking it out of the current strip. So, to the extent that November would weaken relative to the rest of winter is when we will 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 – with 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 five-year range on storage inventories. Most analysts are thinking we’re going to enter winter at 4 tcf or more in storage and those large shut-in volumes there 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, that’s why we added additional hedges in 2021 at this – at the high prices that we’re seeing in the fourth strip and we’re cautiously optimistic that they hang in, but we’re protected if they don’t.

For 2022 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 the – that is setting up supply reduction. And when that manifests itself and improves [indiscernible] (00:50:54) balance it will happen, it’s just a question of when.

We turn them online in October. We could turn them online in a week. So it’s ready and willing. We’ve already kind of restructured our hedge book sales. So any kind of positive run up there, we’d get it, cash flow dollar-for-dollar by get – turning those online sooner at a higher price and we still just because of the flat profile at least for the next six months or so, we still got the coverage in the queue for the timeframe that we still made a decision.

So, gas prices go down, the shut-in decision, made our money and 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 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.

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Great. I appreciate all the color, guys.

Operator: 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 101 458 61. Once again, the dial in number to access the replay will be 877-344-7529 or 412-317-0088 using replay active code 101 458 61.

The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect your lines at this time.

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Forward-Looking Statements

All statements in this transcript (and oral statements made regarding the subjects of this communication), including those that express a belief, expectation or intention, may be considered forward-looking statements (as defined in Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act) that involve risks and uncertainties that could cause actual results to differ materially from projected results. Without limiting the generality of the foregoing, forward-looking statements contained in this communication include statements relying on a number of assumptions concerning future events and are subject to a number of uncertainties and factors, many of which are outside the control of CNX Resources and CNX Midstream, which could cause actual results to differ materially from such statements. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The forward-looking statements may include, but are not limited to, statements regarding the expected benefits of the proposed transaction to CNX Resources and CNX Midstream and their stockholders and unitholders, respectively; the anticipated completion of the proposed transaction and the timing thereof; and the expected future growth, dividends and distributions of the combined company; and plans and objectives of management for future operations. When we use the words “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. While CNX Resources and CNX Midstream believe that the assumptions concerning future events are reasonable, they caution that there are inherent difficulties in predicting certain important factors that could impact the future performance or results of their businesses. Among the factors that could cause results to differ materially from those indicated by such forward-looking statements are: the failure to realize the anticipated costs savings, synergies and other benefits of the transaction; the possible diversion of management time on transaction-related issues; the risk that the requisite approvals to complete the transaction are not obtained; local, regional and national economic conditions and the impact they may have on CNX Resources, CNX Midstream and their customers; the impact of outbreaks of communicable diseases such as the novel highly transmissible and pathogenic coronavirus (COVID-19) on business activity, the Company’s operations and national and global economic conditions, generally; conditions in the oil and gas industry, including a sustained decrease in the level of supply or demand for oil or natural gas or a sustained decrease in the price of oil or natural gas; the financial condition of CNX Resources’ or CNX Midstream’s customers; any non-performance by customers of their contractual obligations; changes in customer, employee or supplier relationships resulting from the transaction; changes in safety, health, environmental and other regulations; the results of any reviews, investigations or other proceedings by government authorities; and the performance of CNX Midstream.

The forward-looking statements in this transcript speak only as of the date of this transcript; we disclaim any obligation to update these statements. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the risks and uncertainties set forth in the “Risk Factors” section of CNX Resources’ Annual Report on Form 10-K for the year ended December 31, 2019, and Quarterly Report on Form 10-Q for the three months ended March 31, 2020, each filed with the Securities and Exchange Commission, and any subsequent reports filed with the Securities and Exchange Commission.

No Offer or Solicitation

This transcript is for informational purposes only and shall not constitute an offer to sell or the solicitation of an offer to buy any securities pursuant to the proposed transaction or otherwise, nor shall there be any sale of securities in any jurisdiction in which the offer, solicitation or sale would be unlawful prior to the registration or qualification under the securities laws of any such jurisdiction. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act.

Additional Information and Where You Can Find It

In connection with the proposed transaction, CNX Resources will file a registration statement on Form S-4, including a consent statement/prospectus of CNX Resources and CNX Midstream, with the SEC. INVESTORS AND SECURITY HOLDERS OF CNX RESOURCES AND CNX MIDSTREAM ARE ADVISED TO CAREFULLY READ THE REGISTRATION STATEMENT AND CONSENT STATEMENT/PROSPECTUS (INCLUDING ALL AMENDMENTS AND SUPPLEMENTS THERETO) WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE TRANSACTION, THE PARTIES TO THE TRANSACTION AND THE RISKS ASSOCIATED WITH THE TRANSACTION. Investors and security holders may obtain a free copy of the consent statement/prospectus (when available) and other relevant documents filed by CNX Resources and CNX Midstream with the Securities and Exchange Commission (the “SEC”) from the SEC’s website at www.sec.gov. Security holders and other interested parties will also be able to obtain, without charge, a copy of the consent statement/prospectus and other relevant documents (when available) from www.cnx.com under the tab “Investors” and then under the heading “SEC Filings.”

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CNX Resources, CNX Midstream and their respective directors, executive officers and certain other members of management may be deemed to be participants in the solicitation of consents in respect of the transaction. Information about these persons is set forth in CNX Resources’ proxy statement relating to its 2020 Annual Meeting of Stockholders, which was filed with the SEC on March 24, 2020, and CNX Midstream’s Annual Report on Form 10-K and Form 10-K/A for the year ended December 31, 2019, which were filed with the SEC on February 10, 2020 and April 27, 2020, respectively, and subsequent statements of changes in beneficial ownership on file with the SEC. Security holders and investors may obtain additional information regarding the interests of such persons, which may be different than those of the respective companies’ security holders generally, by reading the consent statement/prospectus and other relevant documents regarding the transaction, which will be filed with the SEC.