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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good day and welcome to the 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.
Thank you, and good morning to everybody. Welcome to CNX’s second quarter conference call. We have in the room today; Nick Deiuliis, our President and CEO; Don Rush, our Chief Financial Officer; and Chad Griffith, our Chief Operating Officer.
Today, we’ll be discussing our second quarter results and we have posted an updated slide presentation to our website. Also, in conjunction with Monday’s announced transaction of CNX acquiring all the outstanding common units of CNXM, we released a prerecorded 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 a 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 AM, Eastern today.
As a reminder, any forward-looking statements we make or comments about future expectations are subject of business risk, which we have laid out for you in our press release today, as well as on 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 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 fixed to them are in two broad buckets, one, our external assumptions. The most obvious example that is gas prices, so we apply the NYMEX forward strip, not a different or an inflated gas price.
Even though we may decide that price, where 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 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 share 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 a hedge book sits for the coming years. And the peers can’t apply the water infrastructure that we employ to optimize activity pace and reduce costs. Last, but not least, the peers can’t protect the cash flows in the balance sheet to the extent that we can, if lower gas prices brought on by a weak start of the winter start to materialize going into 2021.
All this means that it’s going to be tough for others to pose CNX’s cash costs, certainly our cash margins or 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.
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, get really backed up terms of transparency and following the math, being IRR driven and being a low-cost producer. If we say it, we feel 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 misunderstood 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 and 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 is we show in the core Marcellus is about $0.35 today and drop into $0.30 for 2021 and beyond.
In the CPA Utica, should be as low if not lower due to that placed on in EURs. The gap rules dictate financial statements apply historical look back DD&A, it is about $0.68 per MCF or D&C. That historical D&C DD&A metric, it’s not accurate for current and future D&C capital efficiency, because it’s a collection of sunk PDP capital under very different and less prolific well profiles and capital costs.
So the world’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 look 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 cents an 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 TILs on average per year in our core Marcellus, and or the CPA Utica fields, that’s about $230 million of drill and complete CapEx annually. And that assumes no further improvement in operating efficiencies or well profiles that Chad is going to talk about in a couple of minutes.
Now, we’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.
Now, the second investment reason I want to cover today is reason number five on Slide 4, which is the low-risk business model. This is one that I think isn’t even on the radar for most of the capital markets today. So I just want to spend a minute on it. There’s a number of drivers that why we’re at 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 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 staying up sharp 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 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 have accessed to capital markets. It’s becoming more and more volatile and suspect.
In fact, our generation of the $3 billion plus in free cash flow, it’s 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 de-levering, and we’ll likely have less shares outstanding in the coming years if we don’t close our intrinsic value per share gap.
The fifth - last driver of low risk, it’s the nature of our cash flows. It’s not just upstream E&P, but it’s also lower risk midstream. The pro forma CNX after the CNXM taken is a blend of an Appalachian upstream and midstream entity, with midstream cash flows being lower risk and lower cost of capital and upstream, that means on a weighted average basis, CNX is at lower risk, and we’ll have a lower cost of capital and we’ll 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 taken of the remaining interest is CNX Midstream that’s 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 example, a 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 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 taken up free cash flow for less than 4 times, we also picked up lower risk-free cash flows than upstream free cash flow. So pro forma as I said earlier, our cost of capital and risk profile is declining. And besides picking up free cash flow for under 4 times is 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, $100 million of free cash flow will increase along with those metrics. So I’m very pleased that we’re able to add that last bullet to the 2020 box that you see on Slide 5.
So with that, now, I’m going to turn things over to Chad Griffith who’s going to dive a little more in depth on some of these performance metrics.
Thanks, Nick. There are 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 dimensional metric to the next, we continually stay committed to creating long-term value per share. And while the one-dimensional metrics do often relate to the creation of long-term value, they’re only one small part of the picture. And our broader analysis that lets 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 an 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 sell 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 by the team continually challenging conventional thinking to innovate and improve our capital efficiency.
Longer laterals are a great example. We agree that they can lead to a more efficient capital, but only if they do not simultaneously increase your risk profile. So we’ve approached drilling long laterals sort of like trying to get to the moon. You don’t want to get off the ground and have a problem when you’re 20,000 feet or 25,000 feet underground, things can get expensive fast.
We’re methodically increasing our lateral length over time as we solved the various challenges for 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. It’s extensively used throughout automotive healthcare and aerospace manufacturing to ensure the delivery highly reliable products and services. We’ve adopted that philosophy and process to the E&P space and began working with our service partners to extend that process upstream through our supply chain.
We’ve also refined a number of design criteria with our well completion designs in order to deliver a more predictable drilling and completion process. Evolution is all electric frac fleet has also contributed to this improvement in many ways, including reduced fuel costs and significantly more flexible [indiscernible]. 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 Shirley 38 M1 pad, which we brought online for an all-in dollar per foot of $680. And our more recent Richhill 99 pad right in the core - right in the heart of our core SWPA field that we brought online for $720 per foot.
It’s important to note that in our capital per foot numbers, we include everything except Atlanta permanent costs. That means, we include pad construction, road construction, surface facilities, wellheads, drilling, casing, cementing, completions, et cetera. That 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 in 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 and pursued 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 trending towards - 4.5 to 5 Bcf per thousand foot EUR. The net result of this effort is a continual year-over-year improvement in dollar per foot capital costs and improved well productivity. We’re getting nearly twice as much out of the ground for just about half the capital.
As shown on Slide 8, this has driven our finding and development costs from $1.20 per Mcfe back in 2013, to an estimated $0.35 today and we expect those F&D costs to continue to improve further and average $0.30 per Mcfe over the 2021 through 2026 forecast period.
Slide 9 illustrates that following the recently announced midstream transaction, we have the lowest production cash costs in the Appalachian Basin. Again, this is a feed 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 you grow without firm transportation?
Well, the team challenge that 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 appeared to provide the upstream economics. We stayed majorly in our approach, concerned by the significant downstream logistical challenges and lack of effective hedging.
And as many of our peers were divesting or farming out their gathering systems, they retained control of our midstream and recently reached an agreement with the buyback the remaining public interest in our midstream. The value spread here were only one 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. And once we determined the reuse to produce 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 with 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 costs by finding more cost-effective ways to operate our stations, pads and pipelines.
We believe this difference in approach to gathering, processing and transportation and to our lease operating expense has created a sustainable competitive advantage for CNX. Our peers who have made large, long lived firm transportation commitments or long-term commitments to third-party gatherers will have that burden on their books for many years to come.
And yes, there is some ability for our peers to unload some of this excess FT onto third-parties. With the companies who plan a space are extremely savvy, and I’m not sure why those firms will pay a premium rather than face value for firm transportation that’s largely underwater.
Moving on to 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 as 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 the influenced 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 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 that for longer time periods than any of our peers. As I’d 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 the 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 and COVID-19 had a dramatic impact on the entire global economy.
Summer 2020 gas prices plummeted. But the huge reduction in rig activity created some real bullishness for supply reductions and for improved prices this coming winter and beyond. For the first time in several years, the winter-summer are widened enough to justify shifting some production from summer to winter, particularly if it was synced up with a flush production period from new wells.
So 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 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. The main 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 arm had actually widened further since the original decision to shut in. So we’re sticking to the plan to turn these wells back online in November. We have that flexibility and thanks for our balance sheet help and low levels of [NBC] [ph]. Again, we are 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 is the basis for strong prices this winter, doesn’t seem to be happening. Lower 48 gas production has remained robust, storage inventories will likely be above 4 Tcf heading into winter and production that’s currently shut in will start coming back online. If we don’t end up with a cold winter, the bull case for ‘21 is pushed into 2022 and ’21 gas prices will likely come down. Producers hoping and praying for those stronger ‘21 gas prices are basically betting the balance sheet on winter and that is a risky proposition.
Finally, Slide 13 highlights our activity in the quarter. We’re currently running one rig and one frac crew. And with that, I’ll hand it over to Don.
Thanks, Chad and good morning, everyone. During the second quarter, we completed a $345 million opportunistic convertible notes offering at a favorable 2.25% interest rate. The proceeds were used to pay down the 2022 notes and will result in annual cash interest rates savings of approximately $13 million per year. And we simultaneously entered into a call spread to minimize potential equity dilution. The remainder of the 2022 notes are expected to be repaid using organic free cash flow generated from the business.
Slide 14 shows the projected cumulative free cash flows versus our maturity schedule. And as you can see, retiring our debt as it comes due will be easy to achieve, especially considering that our near-term projected free cash flows are over 90% protected due to our hedge book.
Slide 15 highlights that our 2020 guidance remains unchanged from last quarter. One thing to note is that, we started deferring volumes in May, as Chad mentioned, and the current expectation is to turn those wells back online November 1st. Assuming that scenario, we would expect production to be towards the lower end of the 2020 guidance range. But even with those production shut ins factored in, we expect our annual EBITDAX to be on the high end of our capital - our annual EBITDAX to be on the high end of our guidance range.
And for 2020 CapEx, approximately 65% of the remaining projected spend should occur in Q3, resulting in a much lighter Q4.
As we have mentioned, our production deferrals this year help 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 that what we’ve stated previously and consistently proven through our actions, we’ll 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 will 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 CMX is one of the best investments in the entire public market. As we move forward, quarter-by-quarter, year-by-year, we look forward to delivering on our free cash flow projections, paying down our debt, creating more value and eventually not only getting our stock to a point where our free cash flow yield is more reasonable, but creating more incremental value on top of that.
With that, I’ll hand it back over to Tyler for any questions.
Thanks. Operator, if you can open the line up for Q&A at this time, please.
Certainly. We will now begin the question-and-answer session. [Operator Instructions] And our first question today will come from Welles Fitzpatrick with SunTrust. Please go ahead.
Hey, good morning.
Hey, Welles.
Good morning.
It sounds like the curtailments are going to last through November. If that’s the case, do you 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. So right now we’re actually planning to bring those volumes on November 1. So we would expect those volumes to be online for all of November and December. But you’re right, that is a function of price.
We have hedged those volumes. So we’ve hedged the change in production profile in November, December all the way through March, and really all the way into ’21, we added some incremental hedges to match the deferred production profile.
So if something would happen that November prices would erode, we have tremendous flexibility to be able to wait till December, we can just keep sort of rolling that play forward, cashing in the hedge value and saving those molecules for a strong price day. So sitting here today looking at the forward strips and where the prices are that the plan continues to bring those wells online on November 1.
Okay, okay then that makes sense. And then 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. 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 that - you know, they’re really the biggest part of our undeveloped wet production. 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 this Shirley-Pennsboro wells, but for the time being with the volatility and risk associated with NGLs and sort of everything that’s going over the oil markets it’s sort of cost Shirley-Pennsboro fall behind from our core SWPA area.
Okay, perfect. And just one last one, if I could sneak it in. I mean 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 acquirer, especially with a you know kind of a de-leveraging aspect, should we be viewing that the transaction with CNXM at least to some extent as a function of wanting to simplify for the sake of maybe being a little bit more tempting for others to come after you in the A&D market or am I just reading too much into that?
Well, this is Nick. I think that you know, M&A, in particular, items or views on M&A will take a no common approach. But I will say that with the midstream taking transactions, there were a number of what I would perceive advantages or drivers of that. I mentioned the free cash flow acquisition costs, 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 are 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. So just to sort of answer generally, I think yeah, I think it does improve for outstanding in that metric. But beyond that, I wouldn’t want to comment on M&A.
Okay, fair enough. Thank you so much.
And our next question comes from Jeffrey Campbell with Tuohy Brothers. Please go ahead.
Good morning. I think the list of innovations on Slide 5 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 or are there signals that could bring that effort forward to some extent?
Yeah, no, this is Don. Definitely I think it’s not and 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 harder step change in infrastructure that’s required up there and you know, the recent transaction we did and the flexibility that opens up for us in the future, you know, 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 of bringing midstream in-house now gives us the ability to self do that function, it gives us the ability to partner with folks.
So it’s a freedom of how to properly structure it. We’ve spent a lot of time looking at different ways to go about it. And, you know, 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 you know, as Nick said in his opening remarks, we’ll follow the NYMEX strip in making those decisions just like we did on the sort of the infrastructure build out in Southwest GA, we build it out, but we also put in a bunch of hedges to protect us in case you know, market dynamics shifted during the middle and post that build out. So I think we do anything incrementally in CPA above and beyond what’s in 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 costs, while enhancing pricing or would just be too risky and approach to ever take?
Yeah, it’s, you know, it’s - Chad can weigh in on this too. But 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 and make substantial margins and returns on your capital still by locking in this prices, take it, right don’t get greedy. We always have more wells to drill, we got a lot of interesting opportunities if gas prices rise, so I think we’re going to stick to the, let’s have safe predictable cash flows and returns method for the company.
And 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 to say in favor of stronger revenues tomorrow. You can lock that risk away by layering on hedges. It’s almost a no brainer, right.
So, but to your point about cost, you know, we have a sufficiently deep sort of counterparty pool that we’re able to, especially with the near-term hedges, there’s really not a big transaction cost on those. So it’s not a real expensive proposition to go hedge those. It’s a fairly liquid market and the prices are fairly transparent. So we don’t see a huge transactional cost in putting that risk to that.
And even the best crystal ball gets messed up based on you know, cold winter or warm winter or as an incremental 1 or 2 Bcf a day of supply shows up and you know with that kind of unpredictability, it’s a tough thing to spec on. And, you know, we’re going to stick to locking in prices that make sense for us.
And, you know, fortunately, we’re the lowest cost producer. So we’ll always have that ability to kind of hedge where other folks higher on the cost curve. It’s a more difficult decision if the cost in the margins are lot thinner, hedging in the current forward price. But for us, they work and we’re going to continue to chip away at hedging.
Yeah, well I like that answer. And it’s also logically consistent with what you said earlier in the call, which is that your longer horizon hedging is based on a recognition that the weather remains a big deal, no matter how much you try to plan around it. So I like that answer a lot. Thank you.
Thanks.
And our next question will come from Holly Stewart with Scotia Howard Weil. Please go ahead.
Good morning, gentlemen. Maybe first looking at Slide 6, it looks like the most recent Southwest PA Marcellus well costs are in the $720 per foot range and which is quite a bit lower than the $830 that’s included in the guidance. So can you maybe give us a sense where maybe first half ended up or maybe even 2Q as a comparison, and then what you need to see to reassess that $830 number that’s included in the 2020 guide?
Thanks, Holly, this is Chad. So, you know, counter averages are a bit lumpy and they have the artifacts of like you know wells we turned online at the very beginning of the year end and getting lumped into that sort of counter year average for capital per foot.
But to your point, the dollar per foot number is strongly trending down over the course of the year and really setting us up for a strong ’21 as we talked about in the prepared remarks, Richhill 99 came online at $720 a foot, really phenomenal performance by the team.
We have two additional Marcellus pads that we plan on bringing online about in the year, both of those are expected to come in, in that $700 foot range between somewhere between $700, $800 a foot. So 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 ‘21 and really beyond.
Okay. So Chad any sense maybe where the first half trended or even 2Q?
I mean –
Per average –
We can follow up on, 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 have first half of the year metrics in front of me.
Okay, okay. I’ll follow up with Tyler. And then maybe second question just on the 2Q CapEx. It looks like there were fewer wells drilled and completed than the first quarter, but the actual E&P spend essentially looked flat. So is there anything like one-timers driving the 2Q number?
No, there’s no one-timer in that. We’ve got a bulk of wells that are teed up and ready to turn on line. We’ve got two pads right now that we’re in the process of drilling out. And like basically drilling out flow and back so those will be TILs in Q3.
It’s sort of, you know, we talked earlier in the year, it’s a fairly linear program. It’s a little bit shifted towards the first half of the year. And I think Don talked a little bit about the shape of the capital spend, but there’s nothing really lumpy going on. It’s just sort of like fairly linear with a trend down.
Yeah in the transition from two rigs to one rig. So now we’re running one rig, one frac crew. It’s moving off that direction, Q3 will still have a little bit of a bigger proportionately, you know, we said around 65% of the remaining capital will be spent in Q3 with Q4 getting to more of a steady state run rate one rig, one frac crew plan that Nick talked about.
Okay, sorry, Don, you said what percent in Q3?
Q3 about 65% of the remaining capital will be spent in Q3.
Okay, remaining. Okay, that’s –
In fact Q3 will be heavier than Q4.
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 half a Bcf a day and the, I guess it was June 15th update said that you were moving down to 300 million as of July 1st. So I just wondered if it was - is there a change there, I’m assuming?
It - there is. So when we initially made the shut-in decision, we were about 350 million a day. Follow, you know, as we talked about that in the operational update, NGL prices had improved marginally. So we have brought off back online, some of our wet production, the Shirley-Pennsboro field, not all of it, but some of it. So that got us to the 300 million a day number.
And since that time, we’ve had a number of wells that have been drilled out flowed back and rate is low, but now we’ve shut back in, waiting for the stronger winter prices. And frankly, there’s another one or two pads planned as well that that we’re looking at doing the same thing. So that puts us today about half the Bcfe a day of shut in.
Okay, that’s perfect. Thank you.
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 a further improvement in 2020. And, you know, you’re showing an improvement in lateral adjusted well performance while showing longer laterals. And so I was just curious if you could, you know, walk us through some of the drivers of what’s causing the lateral adjusted productivity to increase?
Thanks, this is Chad, I’ll take that. So is really a combination of two things. The biggest driver and - but 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 focused on making improvements on both of those fronts. And that’s being achieved through our QMS program.
And the second factor is really longer laterals as I said in my prepared remarks, longer laterals do make a difference if you can get them done without having a bunch of issues, without impairing your productivity, without getting stuck down hole.
These longer laterals can create a lot of challenges and I think that’s why some of my peers who made a big - try to make a big leap, they - it was sort of a step too far, instead of trying to make a big leap, we’ve been methodically walking it off as we’ve solved these challenges. And we’ve been able to adjust our completion designs, as we've been able to adjust our well design in order to maintain that well productivity, while reaching the longer lateral length.
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, you know, on the top left of the page, you highlight DD&A rate of $0.87 and then it looks like for the first half of this year you guys are kind of in the $0.95 to a $1 in them.
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 DD&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, you know, ROC, ROIC just so we can get a sense of the return metrics for capital employed. Thank you.
It - yeah it - you’ll see it’s sort of trending down, you know, across these pieces here. We didn’t really break out how that rolls it 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 you know, any of the return on the capital that we are employing, you know, right now we are making these incremental decisions on the next pad, whether you drill it or we don’t drill it so we’re looking at the information on a go-forward basis to make the decision.
Got you. Do you have any sense of, if/when you might get to a double-digit type ROCE number on a corporate basis?
I’d have to get back to you on that. I mean, I haven’t looked at more on the cash flow side than –
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, you know, the $70 million of other CapEx for land, water and midstream which is about $0.13 an Mcf and then the maintenance 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 ad year-by-year or quarter-by-quarter to what our ROCE is on our capital deployment decisions today moving forward. And at some point that DD&A rate under the GAAP accounting rules will start to bleed into that pretty compelling all-in sort of per Mcf capital charge.
All right, that’s it for me. Thank you.
And our next question will come from [indiscernible] with Raymond James. Please go ahead.
Good morning. I just have a quick question on the shut ins. Y’all had mentioned that you would potentially move them out to December. I just wonder what gas prices you’re looking forward for bringing those volumes back in? And also slightly more optimistic on gas than some other so I’m just wondering if same would apply and y’all could possibly bring them back sooner in like October if gas prices rebound in?
Yeah, so 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, it can get out of the current strip. So to the extent that November would weaken relative to the rest of winter is when we would start considering pushing some of that gas back.
I don’t have an exact number for you because it’s going to vary by well-by-well by pad-by-pad. But that’s the type of analysis we do. We’re looking at it on sort of a day-by-day well-by-well basis, really molecule-by-molecule and determining the optimal time to turn each of those molecules online in order to generate the best present value for our shareholders.
On the broader macro picture sort of talked a little bit about in the prepared remarks. We’ve got summer prices that are continuing to deteriorate. There has been a bit of a rally I recalled 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 towards the five-year range on storage inventories. Most analysts were thinking we’re going to enter winter at 4 Tcf or more in storage. And there’s a lot of shut in volumes that are probably going to - we hear there are a lot of shut in volumes that are you know, 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 and other side. I’m a little bit worried about gas prices, particularly moving in the winter and next summer. But that’s why CNX, that’s why we’ve hedged the shut-in arm.
That’s why we’ve added additional hedges in ’21 at the high prices where we’ve seen in the forward strip and we’re cautiously optimistic that they hang in, but we’re protected, if they don’t, you know, for ‘22 and beyond, I think that’s maybe you know, obviously there are a lot of rig reductions, there’s a lot - last year rig growing today than there have historically been. So that’s setting up - that is setting up supply reduction. And when that manifests itself and improves supply demand balance, it will happen. It’s just a question of when.
Yeah, and if things do get better sooner which you know that’d be greatest they did, we could turn the wells that go online in September like we can turn them on online in October, we can turn them online, you know, in a week. So it’s, you know, ready and willing we’ve already kind of restructured our hedge book so any kind of positive run up there we’d get it, cash flow dollar for dollar buy - get turned in those online sooner at a higher price. And we still just because of the flat profile these for the next six months or so we still got the coverage in the queue for 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 make even more money because of it. So we’ve set ourselves up to win either way if gas prices go up or down which you have to be set up that way in a commodity industry, because it’s just too hard to get it right every time.
Great, appreciate all the color guys.
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 access code 101-458-61. The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect your line at this time.