Good day, and welcome to the CNX Resources Q2 2020 earnings conference call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your touchtone phone. To withdraw your question, please press star then two. 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. Good morning, everybody. Welcome to CNX's Q2 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 will be discussing our Q2 results, and we have posted an updated slide presentation to our website. Also, in conjunction with Monday's announced transaction of CNX acquiring all 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 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 Gathering LLC, and CNX Midstream Partners LP. Earlier this morning, CNX Midstream Partners, ticker CNXM, issued a separate press release. 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.
Hey, thanks, Tyler, and good morning, everybody. I'm going to start with my comments on slide three of our slide deck. Slide three 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. 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. The assumptions and the realities that needs to be affixed to them are in two broad buckets. One are external assumptions. The most obvious example of that is gas prices.
We apply the nine-month 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. 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 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, and particularly you need to do that at the bottom parts of the cycle to really have this approach work well. We think that we've obviously done that as well.
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. 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 today to hedge where our hedge book sits for the coming years.
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's 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.
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 four. Slide four, 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'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 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. 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, yet rarely backed up terms of transparency and following the math, being IRR 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. 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. 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. This is a crucial point to the investment opportunity that CNX represents. 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.
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. The CPA Utica should be as low, if not lower, due to that play's stunning EURs. The GAAP rules dictate financial statements apply historical lookback 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.
The world's 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 lookback. 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. That build-out is completed and behind us. 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 an Mcf.
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 fills on average per year in our core Marcellus and/or the SWPA 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 gonna talk about in a couple of minutes. 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 with them in more detail. As I said, they are crucial to understanding not just the capital efficiency, but our investment thesis with CNX.
The second investment reason I want to cover today is reason number five on slide four, 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. 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 one 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 and decks applied on projections. 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. 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 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 seven-year inventory that's gonna 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+ 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 of 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 in 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. I'm going to wrap up with slide five before we turn the mic over to Chad Griffith.
What this slide tries to communicate, 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 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. 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. Besides picking up free cash flow for less than 4x, we also picked up lower risk-free cash flow than upstream free cash flow. Pro forma, as I said earlier, our cost of capital and risk profile is declining. Besides picking up free cash flow for under 4x this lower risk than our upstream free cash flow, we also are now going to enjoy any upside that would 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.
I'm very pleased that we're able to add that last bullet to the 2020 box that you see on slide five. 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 two broad things that differentiate CNX from our peers, which lead to many tangible competitive advantages. First, while our peers have been jumping from one one-dimensional metric to the next, we continually stay committed to creating long-term value per share. 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 broader 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 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. 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 at 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 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. 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. 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, and it's extensively used throughout 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 and have begun working with our service partners to extend that process upstream through our supply chains. 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 number six.
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 RHL 99 pad, right in the heart of our core SWPA field, that we brought online for $720 per foot. 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, surface facilities, wellheads, drilling, casing, cementing, completions, et cetera. When comparing our E&P dollar per foot metrics, we encourage the investment community to challenge our peers on what all is included in our cost bucket to ensure that you're comparing apples to apples across the industry space.
We've not made these improvements in dollar per foot capital efficiency at the cost of well productivity. Again, we're solving for long-term value creation for our shareholders. 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 seven shows one example of this in action. Our most recent CPA Utica well is by far our best performing deep Utica well, trending towards 4.5-5 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 eight, this has driven our finding and development costs from $1.20 per Mcfe back in 2013 to an estimated $0.35 today. 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 nine 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?" 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.
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 effective hedging. 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 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 for infill wells or neighboring pads.
Our lease operating expense also benefits from our approach. We asked ourselves why on one hand do we pay to supply fresh water to our fracs, while on the other hand, we're paying to dispose of large quantities of produced water. 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 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 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 firm transportation commitments or long-term commitments with third-party gatherers will have that burden on their books for many years to come. Yes, there is some ability for our peers to unload some of this excess FT onto third parties. The companies who play in that space are extremely savvy, and I'm not sure why those firms would pay a premium, let alone face value, for firm transportation that's largely underwater. Building off our 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 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, microeconomic analysis is, prices end up just coming down to the weather and how warm or cold each winter ends up being.
We began programmatically 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 pre-sell your product and know your price before spending capital or operating to produce it, how could you not take advantage of that? 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, 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. 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 the 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 match the changed production profile.
Those incremental winter hedges lock 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 half a BCFE a day of gas shut in, and we are planning to bring that gas back online sometime around the first of November. We made our original decision to shut these wells in when summer NYMEX prices were averaging $2.08 and winter was averaging $2.90. Well, August NYMEX just settled at $1.85, and while winter is still around $2.85. The arb has actually widened further since the original decision to shut in. 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 MVCs. 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 productions remain robust. Storage inventories will likely be above four 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 2021 is pushed into 2022, and 2021 gas prices will likely come down. Producers hoping and praying for those stronger 2021 gas prices are basically betting the balance sheet on winter. That is a risky proposition. Finally, slide 13 highlights our activity in the quarter. We're currently running one rig and one frac crew. With that, I'll hand it over to Don.
Thanks, Chad, and good morning, everyone. During the `Q2 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. 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. 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 1st. Assuming that scenario, we would expect production to be towards the lower end of the 2020 guidance range. Even with those production shut-ins factored in, we expect our annual EBITDAX to be on the high end of our guidance range. 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 Bcf 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.
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.
Thanks. Operator, if you could open the lineup for Q&A at this time, please.
Certainly. We will now begin the question and answer session. To ask a question, you may press star then one on your touchtone phone. If you're using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then two. Our first question today will come from Welles Fitzpatrick with Truist. Please go ahead.
Hey, good morning.
Good morning.
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?
Yeah, thanks for the question, Welles. This is Chad. Right now, we're actually planning to bring those volumes on November 1. We would expect those volumes to be online for all of November and December. You're right. That is a function of price. We have hedged those volumes. We've hedged the change in production profile November, December, all the way through March.
Really all the way into 2021, we added some incremental hedges to match the deferred production profile. If something were to 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. Sitting here today, looking at the forward strips and where the prices are, the plan continues to bring those wells online November one.
Okay. That makes sense. Any chance we could get an update on the economics or maybe the relative value of new wells in Southwest PA Marcellus versus Shirley-Pennsboro? 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. 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. 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. Just one last one, if I could sneak it in. In both the CNX, CNXM presentation from a couple of days ago and today, you guys highlight the attractiveness that you would bring to an acquire, especially with a kind of a de-leveraging aspect. Should we be viewing 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 after you in the A&D market? 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, we'll take a no-comment approach. 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. There is, as I said, some significant upside.
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, those are all positives, of course. Just to sort of answer generally, I think, yeah. I think it does improve our standing in that metric. Beyond that, wouldn't want to comment on M&A.
Okay. Fair enough. Thank you so much.
Our next question comes from Jeffrey Campbell with Tuohy Brothers. Please go ahead.
Good morning.
Good morning.
I think the list of innovations on slide five is instructive, and I'd even add constructing 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 seven years? Are there signals that could bring that effort forward to some extent?
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 step change in infrastructure that's required up 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. 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. 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. It's great to have a seven-year base business model that produces so much cash flow that you could have the optionality to think about when is the right time for that. As Nick said in his opening remarks, we'll follow the dynamics trap in making those decisions, just like we did on the sort of the infrastructure build-out in Southwest PA. We build it out, we also put in a bunch of hedges to protect us in case market dynamics shifted during the middle and post that build-out. I think we view anything incrementally in SWPA above and beyond what's in our seven-year base cash flow plan similarly.
Okay, thanks for that. 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 costs while enhancing pricing? Would that just be too risky an approach to ever take?
Yeah. Chad can weigh in some on this too, but for us, 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 those prices, take it. Right? Don't get greedy. We always have more wells to drill. We got a lot of interesting opportunities that gas prices rise. I think we're going to stick to the let's have safe, predictable cash flows and returns method for the company.
I think when we think about shut-in math and hedging and taking the risk of that shut-in value proposition. 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. If you can lock that risk away by layering on hedges, it's almost a no-brainer, right? 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. It's not a real expensive proposition to go hedge those. It's a fairly liquid market, and the prices are fairly transparent. We don't see a huge transactional cost in putting that risk to bed.
Even the best crystal ball gets messed up based on cold winter or warm winter, or if an incremental one or two Bcf a day of supply shows up. 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. Fortunately, we're the lowest cost producer, so we'll always have that ability to hedge where other folks 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. For us, they work, and we're going to continue to chip away at hedging them.
Yeah. Well, I like that answer. It's also logically consistent with what you said earlier in the call, which was 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. I like that answer a lot. Thank you.
Thanks.
Our next question will come from Holly Stewart with Scotia Howard Weil. Please go ahead.
Good morning, gentlemen. Maybe first looking at slide six. It looks like the most recent SWPA 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. 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 $839 [inaudible] ?
The calendar averages are a good look, and they have the artifacts of wells we turned online at the very beginning of the year end up getting lumped into that sort of calendar year average for CapEx per foot. 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 online at $720 a foot. A really phenomenal performance by the team. We have two additional Marcellus pads that we plan on bringing online in the balance of the year. Both of those are expected to come in that $700 a foot range, somewhere between $700 and $800 a foot.
Tremendous efforts by the team for 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. Chad, any sense maybe where the first half trended or even Q2?
I mean-
For average.
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. I'll follow up with Tyler. Maybe second question, just on the Q2 CapEx, it looks like there were fewer wells drilled and completed than the first quarter, but the actual E&P spend essentially looked flat. Is there anything like one-timers driving the Q2 numbers?
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 two pads right now that we're in the process of drilling out, and basically drilling out, flowing back. Those will be TILs in Q3. 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. 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 fairly linear with a trend down.
The transition from two rigs to one rig.
Right.
Now that we're running one rig, one frac crew, it's moving us that direction. Q3 will still have a little bit of a bigger proportionately. We've said around 65% of the remaining capital will be spent in Q3, with Q4 getting to more of the steady state run rate, one rig, one frac crew plan that Nick talked about.
Okay. Sorry, Don, you said what % in Q3?
Q3, about 65% of the remaining capital will be spent in Q3.
Okay. Remaining. Okay.
Q3 will be heavier than Q4.
Got it. That's perfect. Maybe just one clarification question on the production shut-ins, Chad, that you mentioned. I think you called for roughly half a Bcf a day, and I guess it was June 15th update said that you were moving down to 300 million as of July 1st. I just wondered.
Right
Is there a change there, I'm assuming?
There is. When we initially made the shut-in decision, we were at 350 million a day. As we had talked about that in the operational update, NGL prices had improved marginally. We had brought back online some of our wet production in the Shirley-Pennsboro field. Not all of it, but some of it. That got us to the 300 million a day number. Since that time, we've had a number of wells that have been drilled out, flowed back, and ready to flow that now we've shut back in waiting for the stronger winter prices. Frankly, there's another one or two pads planned as well that we're looking at doing the same thing. That puts us today at about 0.5 Bcf a day of shut-in.
Okay. That's perfect. Thank you.
Our next question comes from Kashy Harrison with Simmons Energy. Please go ahead.
Good morning, and thank you for taking my questions.
Sure. Yeah.
Looking at page eight 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. You're showing an improvement in lateral adjusted well performance while showing longer laterals. 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. Thanks. This is Chad. I'll take that. It was really a combination of two things. There's two major drivers in the reduction of dollar per foot D&C costs, all in capital costs, really. That's, first and foremost, the efficiency of our operations. Maximizing uptime while minimizing downtime, the team's laser-focused on making improvements on both of those fronts. That's being achieved through our QMS program. 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, I think that's why some of our peers who 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 designs in order to maintain that well productivity while reaching the longer lateral lengths. For us, it's been a methodical increase in lateral length without really increasing our risk profile or impairing well results. 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. That's helpful. Just for my follow-up, sticking with slide nine, on the top left of the page, a DD&A rate of $0.87 an Mcf. It looks like for the first half of this year, you guys are in the $0.95 to $1 an Mcf. Obviously, as you highlight here, the implications at least should be that with the lower F&D costs, you would expect that DD&A rate to trend over time. 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 or ROIC, just so we can get a sense of the return metrics to capital employed. Thank you.
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. 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 we drill it or we don't drill it. 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've been looking more on the cash flow side.
Yeah.
I know, 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 an Mcf, and then the maintenance of production activity pace, which is about that 25 TILs average a year that we spoke about. 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.
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.
Got it. That's it for me. Thank you.
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 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. 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.
Yeah. Right now, what we see is that the value proposition or the NPV of bringing those wells online November 1st versus December 1st is very close, with November 1st eking it out of the current strip. 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 well by well, by pad by pad. 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 five-year range on storage inventories. Most analysts are thinking we're going to enter winter at four TCF or more in storage. There's a lot of shut-in volumes that are probably well, 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. That's why CNX, that's why we've hedged the shut-in arb. That's why we've added additional hedges in 2021 at the high prices we're seeing in the forward strip. 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. That is setting up supply reduction. When that manifests itself in an improved supply-demand balance, it will happen. It's just a question of when.
Yeah. If things do get better sooner, which that'd be great if they did, we could turn the wells back online September. We could turn them online in October. We could turn them online in a week. It's ready and willing. We've already kind of restructured our hedge book, so any kind of positive run up there, we get it cash flow dollar for dollar by turning those online sooner at a higher price than we still just because of the flat profile of these for the next 6 months or so. We still got the coverage in the Q4 timeframe that we still made a decision. 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 bring them in earlier and made even more money because of it.
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.
Great. Appreciate all the color, guys.
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