Good morning, and welcome to the Chesapeake Energy Corporation 2019 second quarter 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 telephone keypad. To withdraw your question, please press star then two. Please note that the event is being recorded. I would now like to turn the conference over to Gordon Pennoyer. Sir, please go ahead.
Good morning, and thank you for joining our call today to discuss Chesapeake's financial and operational results for the 2019 second quarter. Hopefully, you've had a chance to review our press release and the updated investor presentation that we posted on our website this morning. During this morning's call, we will be making forward-looking statements, which consist of statements that cannot be confirmed by reference to existing information, including statements regarding our beliefs, goals, expectations, forecasts, projections, and future performance, and the assumptions underlying such statements. Please note that there are a number of factors that will cause actual results to differ materially from our forward-looking statements, including the factors identified and discussed in our earnings release today and in other SEC filings.
Please recognize that except as required by applicable law, we undertake no duty to update any forward-looking statements, and you should not place any undue reliance on such statements. We may also reference to some non-GAAP financial measures, which help facilitate comparisons across periods and with peers. For any non-GAAP measures we use, a reconciliation to the nearest corresponding GAAP measure can be found on our website and in our earnings release. With me today on the call are Doug Lawler, Nick Dell'Osso, and Frank Patterson. Doug will begin the call and then turn the call over to Frank and Nick for a review of our operational and financial results before we turn the teleconference over for Q&A. With that, thank you, and I will now turn the teleconference over to Doug.
Thank you, Gordon. Good morning. I'm pleased today to report Chesapeake's continued strategic progress. The second quarter featured increased oil production and enhanced capital efficiency, which continue to drive margin growth as we advance towards sustainable free cash flow. We are maximizing the value of our diverse portfolio through a returns-focused capital allocation strategy. We are prudently managing our debt maturities to maintain future liquidity. On the call today, you will hear reference to our rate of change, which simply stated, highlights the ongoing transformational improvements that are reflected in our past performance, current business delivery, and future value growth proposition. You will also hear reference to our scale, which emphasizes the size, strength, and diversity of our portfolio. Our scale provides the foundation for competitive and differential economic resource development.
You will also hear reference to our technical and operating capability, which, combined with our scale and rate of change, drive differential capital efficiency, cash cost leadership, and future growth. During the quarter, Chesapeake produced a record 122,000 barrels of oil per day, and we increased our oil mix percentage to a record 25% of total production. The oil volume increase is driven by the successful integration of our Brazos Valley asset, steady growth from the Powder River Basin, and improved base production performance from South Texas and the Mid-Continent. Accordingly, we have raised the midpoint of our full year 2019 oil production guidance by approximately 250,000 barrels. Higher oil volumes and our focus on cash cost leadership yielded the highest second quarter margin per BOE in 5 years.
We have lowered our full year guidance for production expense as well as gathering, processing, and transportation expense. I'm very excited with the rapid progress we have made in our new Brazos Valley asset. After only five months from closing, we have a clearly defined plan to fully achieve the forecasted annual synergy savings of $250 million-$280 million per year. We will continue to build upon the cash cost improvements and capital efficiencies identified. Notably, we see further opportunity to the projected $600,000 capital reduction realized on a per-well basis, as we've recognized up to $2 million in savings on certain wells. As a result of our capital efficiency, we have lowered the break-even oil price for a Brazos Valley well to $39 per barrel, an approximate 26% improvement.
Oil production is poised to increase during the second half of 2019. We expect to turn in line approximately 170 oil wells in the Powder River Basin, South Texas, and Brazos Valley assets, an increase of roughly 50% over the first half of 2019. In a few moments, Frank will share more with you on our asset level progress. Capital spending for the quarter was in line with our guidance, and we remain confident in our full-year forecast. As a reminder, we have downside protection for approximately 75% of our 2019 oil and gas volumes. We will continue to pursue asset sales to further reduce debt. Nick will share additional detail on our liquidity, liability management, and financial improvements for the quarter.
As noted in our earnings release, in 2020, we expect to allocate more capital to oil growth areas with less capital going towards our gas assets. As a result, with an approximately flat capital program to 2019, we project our 2020 oil volumes will show double-digit % growth over 2019, while our gas volumes will show a double-digit % decline. Importantly, our projected adjusted EBITDAX remains approximately the same at 2019 levels using today's lower NYMEX strip pricing and our current hedge position. We look forward to driving further value from our diverse portfolio and capital discipline in 2020 and beyond. We will remain flexible and prudent with our capital allocation, using our scale and operating efficiencies to drive value in this volatile pricing environment. I'm excited about the future of Chesapeake Energy and the value that we have to offer.
Our employees, leadership, and board are driven and committed to achieving our strategic priorities of reducing our leverage metrics, improving margins through continued oil growth, and achieving sustainable free cash flow from our portfolio of high-quality assets. I'll now turn the call to Frank for some further commentary on our oil growth and other operational achievements from the second quarter.
Thank you, Doug. Good morning, everyone. Let me start by commenting further on the significant capital efficiencies we've already realized in Brazos Valley. The operating team continues to demonstrate the ability to rapidly change the outlook and performance profile of this asset. We've advanced the integration of Brazos Valley into our portfolio and are rapidly moving to full development mode. We've demonstrated significant improvements across all aspects of the business unit's operations. As Doug noted in his introduction, we've eliminated an average of over $600,000 per well, and a few wells we've seen, we've recognized over $2 million savings. These savings are the result of improved drilling and completion techniques, faster cycle time, and lower oil field service costs. We're not done. Just last week, the completion team set a field frac crew record by pumping 15 stages and placing 8.4 million pounds of sand in a single day.
This accomplishment was aided by our operated sand mine, which is now supplying 100% of our sand needs for two frac crews. On top of operational performance and cost savings, the team has also accelerated production performance by more than 30%, with the average 2019 wells reaching similar cumulative production in 180 days that historically took 260 days. This year, we have turned in seven wells that have reached a maximum 24-hour production rate of more than 1,000 barrels per day, compared to just three that reached similar levels in 2018. Additionally, we've increased workover activity and made a concerted effort to raise the field to Chesapeake's operating standards, which has already improved base production by more than 500,000 barrels compared to our original projection for 2019.
Our subsurface understanding of the field was high when we completed the acquisition, but it's grown even stronger in recent months as the team has had a chance to gather additional data. We've been able to leverage our reservoir technology lab and new PVT data to greatly increase our understanding of fluid properties in the field. As a result, we've shifted more than 230 locations into the black oil window of the play. Our understanding will continue to evolve as we have recently taken two full cores, which are now under evaluation in our core lab. While there are many ways to measure how we've improved performance in this asset, I'm most proud of what the team has done to redefine the economics of the play. At current strip prices, we have increased our two-year per well cash flow projections by $1.3 million.
As Doug noted, since the acquisition, we've lowered the projected break even from $53 in 2018 to $39 today. As we look forward to the rest of the year, 100% of our activity will be focused in the high-margin oil window of the Eagle Ford. Our improved cycle times will allow us to accelerate our activity further, and we anticipate placing approximately 45 oil wells online in the second half of the year, compared to just 28 wells in the first half. We anticipate continuing this trend in 2020 and currently forecast delivering 44 million-46 million barrels of oil production from a four-rig drilling program. Needless to say, we're excited to have Brazos Valley in Chesapeake's oil portfolio and look forward to driving more value from the asset. Rate of change is not restricted to Brazos Valley.
This week, South Texas drilling team delivered a 15,361-foot measured depth well in a tad over 5.5 days, averaging over 2,700 feet per day, safe and fast. Awesome results. On the production front, the team continues to deliver strong base volume performance. This is driven by adjusted well spacing, enhanced completions, and production optimization. The team also did a great job managing a planned third-party plant outage that affected sales volumes in June. As a result, we exceeded our internal production forecast for the quarter in the field. South Texas continues to be a strong free cash flow generator for the company and a foundational asset. In the Powder River Basin, the team continues to drive costs down and grow our margins while remaining on target to deliver 100% year-over-year oil growth.
Our development plan in the Turner continues to evolve. The field EUR is moving lower as more wells are focused on the oil window. Our central production facility came online in July. Currently over 50% of our oil volumes are on pipe versus being trucked. We will continue to move more production to pipeline. As a result, we expect to reduce GP&T per barrel of oil equivalent by more than 25% this year. Operationally, our cycle times continue to improve, with the average Spud-TIL time expected to decrease approximately 25% year-over-year. While we've focused our attention on developing the Turner formation, we remain excited about the stacked- pay potential under our acreage footprint. We recently drilled our first Niobrara well.
Since 2014, expect to report initial results in the next quarter. Additionally, the team continues their technical work on the Mowry formation, and currently intend to drill an initial Mowry test in the eval oil window later this year. With the majority of our capital focused on high-margin oil assets, we will lean on our core gas assets for efficient free cash flow delivery. The Marcellus continues to generate significant free cash flow while we maintain a disciplined capital spend. The quality of Chesapeake's position in the region is exceptional, and our continued operating improvements, driven by refined spacing, longer laterals, and optimized completion, have significantly lowered our F&D costs and continue to yield improved recoveries per lateral foot. With these improvements, we've rapidly decreased our break-even price.
As we look ahead, at approximately 1,350-foot spacing and current rig pace, we have over 10 years of drilling inventory at a PV-10 break-even price of between $1.50 and $1.75 per Mcf. Overall, Chesapeake continues to deliver progress on the fronts that we can control operationally. Using our geotechnical and engineering expertise, we are seeing more opportunity across all basins. I'm confident that in the second half of the year, the rate of change will continue. With that, I will turn the conference call over to Nick to review our financial performance.
Thank you, Frank. Good morning, everyone. Driven by stronger adjusted oil production, an increase in our production mix towards oil, and lower total cash operating expenses, we reported a 26% increase in adjusted EBITDAX margin for BOE compared to last year. As we stated last quarter, the margin improvements we're delivering are not simply due to price, as realized prices before hedges were lower compared to last year, but primarily due to portfolio rotation and our intentional shift of capital toward higher-margin oil production and away from drilling natural gas. We improved our cash operating cost structure by approximately $57 million over the second quarter of 2018, primarily through lower GP&T expenses. Continuing the trend of optimizing our GP&T spend, we will be launching an RFP process for a new oil pipeline gathering agreement in the Brazos Valley area shortly.
Moving our oil production to a gathering system should greatly reduce our current reliance on trucking oil volumes, thereby improving our cost structure in the region. In addition, we're also making progress towards solutions to help deliver our Brazos Valley oil into the Gulf Coast market, allowing us to take advantage of improved pricing versus WTI. We expect to have more to announce on this by the end of the 2019 third quarter. In the PRB, we are connecting pads to our new oil gathering system every week and expect this to lower our oil gathering expenses in the field even further. As Doug noted, we are allowing our gas volumes, most specifically the Haynesville production, to fall in 2020 based on prudent capital allocation in this weak gas price environment.
Our gathering contract in the Haynesville is an acreage dedication with no minimum volumes or other commitments, so we will see no gathering penalty from this volume drop. We do have firm transportation out of North Louisiana that we will not fully utilize at this reduced volume profile. As a result, we forecast a net impact to our GP&T for the Haynesville region alone in 2020 versus 2019 of an absolute reduction of $79 million, or an increase of just over $0.03 per Mcf. Production expenses rose during the second quarter due to a number of factors. We began to improve our base production in Brazos Valley, which resulted in higher year-over-year workover activity and water disposal costs. Additionally, our ad val taxes increased due to higher property valuation assessments in Texas and in Wyoming.
We believe these anticipated one-time events and catch-up expenses are mostly behind us, so we expect our LOE per BOE to come down both in the third and fourth quarters, and accordingly, we have reduced our outlook range for full-year 2019 production expense. On the balance sheet side, our liquidity is strong as we ended the quarter with availability of approximately $1.6 billion under our $3 billion Chesapeake credit facility and approximately $600 million under the $1.3 billion Brazos Valley credit facility. We will retire our near-term maturities through cash flow and future asset sales. When market conditions are more conducive to refinance pending maturities, we will be prudent in doing so.
We currently have a couple of small portfolio cleanup asset divestitures underway, while we are optimistic they will yield positive outcomes, our liquidity position affords us the opportunity to be patient and hold off selling if the markets ultimately prove unattractive. Finally, we have significant price protection through the end of this year and for a meaningful portion of 2020 expected production. For the second half of 2019, over 75% of our forecasted 2019 oil production and natural gas production is hedged with downside protection at average prices of $59.38 per barrel and $2.83 per Mcf respectively. We also have approximately 265 Bcf of gas and 15 million barrels of oil hedged at $276 and $59.93 respectively for 2020. Additionally, we have locked in pricing for approximately 4 million barrels of our remaining Eagle Ford volumes in 2019 at a premium of approximately $5.85 to WTI.
Operator, we'll now turn the call over for questions.
Thank you. We will now begin the question and answer session. To ask a question, you may press star then one on your telephone keypad. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then two. Our first question comes from Devin McDermott with Morgan Stanley. Please go ahead.
Good morning. Congrats on the very solid execution in the quarter.
Thanks, Devin.
My first question, I wanted to hit in a bit more detail on the capital allocation strategy as you move into 2020. I think, as you laid it out, the shift away from gas over to oil makes a lot of sense, and it definitely highlights some of the value of your portfolio diversity as well. I wanted to dive into a bit more detail. As you think about where you cut on the gas side and allocate more capital on the oil side, what some of the levers are that you have there? Where would you cut first? Sounds like Haynesville's pretty high on the list, but a bit more detail there would be useful.
Sure, Devin. Appreciate the question. The focus of the company is obviously to drive where we can capture the greatest returns. We are very fortunate to have extremely strong gas assets, which we have a lot of confidence in. The breakeven in Marcellus is extremely low and very competitive. We obviously still have some takeaway constraints up there that just with the infrastructure that exists in the Northeast. That remains one of the very top rate of return investments in our portfolio. We expect that production to remain relatively flat as it has for the past few years.
The oil assets, the margin enhancement, and things that we're driving for with the sustainable free cash flow growth that we're targeting, that's all going to be driven by the oil investments, notably the base and execution in South Texas, and then the growth in Brazos Valley and the Powder River. Obviously, that leaves us with the Haynesville, which given current pricing and the flexibility we have, we will react accordingly as we have reduced that activity substantially there currently and forecast very low activity level with current pricing. If you see, if we were to recognize better prices in 2020, we will constantly evaluate that capital allocation and direct the investments where we can capture the best return.
That said, though, the economics and the margins that we're capturing from the oil investment make it difficult to see a lot of capital going back towards the Haynesville anytime in the near future. Where we sit, it is basically a lot of strength with Marcellus. We'll continue to monitor that production level there, but very pleased with the performance and execution and what we can deliver from that asset. The bulk of the capital as this year will be directed towards all the oil growth.
Got it. It's very helpful. You also had some comments on potential further asset sales for de-leveraging. You also noted that given the capital efficiency improvements that you've seen so far, there is a nice organic path to de-leveraging over time. As you think about the leverage targets and how further strategic action or asset sales might fit into achieving that over time, could you provide a bit more detail in what would fit in those asset sale targets and what the opportunity set you see there is?
Sure, Devin. We have a very large portfolio of producing assets and acreage, probably don't want to go into a ton of detail on this call, but we're looking at a little bit of acreage in northeast P.A. that probably makes sense for us to consider divesting. A little bit of acreage associated with the acquisition we just made that is not of our primary drilling target. Both areas have great returns, it's the kind of acreage positions that inside of our portfolio we are choosing not to drill right now, the return profile available to them is attractive and we believe therefore could be attractive to other producers in the market.
It is just a part of our strategy always to look very carefully at our portfolio every year and think about what assets we should continue to own and what assets are rather inefficient for us to hold on to given the development profile that we have. This is just part of that. It will be a nice tailwind to the handling of near-term maturities if that all plays out, and if we decide that the market conditions are not attractive to move forward with those divestitures, we can continue to hold them. It's really just a matter of whether or not the opportunity cost versus what's available in the market today makes sense to us.
I might just add, Devin, I might just add on top of Nick's comments there that our goal of de-leveraging, when you look at the future of the company, we have a clear line of sight with the oil assets and the strengths and quality of the portfolio to de-lever organically, as you said, over time. However, our focus is to accelerate that as quickly as possible. Whether it's non-core, small, or even larger assets, as market conditions dictate, we will remain open and focused on that de-leveraging priority, which still remains our number 1 strategic priority. We've got a few things that are in the works, as Nick highlighted, we'll continue to look for opportunities to further de-lever and accelerate that de-leveraging that we've described.
That makes a lot of sense. Thank you very much.
Our next question comes from Arun Jayaram with JPMorgan. Please go ahead.
Yeah. Good morning. Perhaps this one is for Nick. You showed some progress on the GP&T line item with the cost coming down in the Powder River Basin. I was just wondering if you could talk broadly about the portfolio and other opportunities to lower your GP&T costs over time.
Absolutely. Arun, you saw we talked a lot about last quarter, how we put in place the oil gathering contract in the Powder, and that's going to be a great contract for us. We're going to get our oil to market faster. We're going to get it to market more consistently without regard to having to wait for truck traffic and snow and things like that. In inclement weather, having oil on pipe is just a much more reliable form of delivery. In addition to that, the cost to deliver oil to a liquid, either other transportation point or liquid sales market via pipe is dramatically lower on a per-barrel basis. We're doing this, of course, through a third-party contract where we don't spend any of our own capital. We're going to look to do the same thing in Brazos Valley.
We've had a number of midstream companies approach us seeking a partnership there to go out and build that kind of a system similar to what we've contracted for in the Powder. We'll undertake that RFP here in the near term. There's more we can do across the portfolio, of course. We think very actively about how to manage our portfolio of volumes as they grow around the way that we contract for our gathering process and transport. It is, of course, always about delivering the highest value hydrocarbon for the lowest cost. I'll give you an example of what I mean by that. In the Powder, we did also sign up for a little bit of incremental transportation that takes us from Guernsey to Cushing, and in doing that, we give ourselves more stability of pricing. The pricing in the Guernsey market has held up pretty well.
You did see last winter, there can be times where the Guernsey market gets congested, and so with this incremental transport out of basin, we feel like we have that pretty well covered. We'll pay a little bit for that transportation and believe that it's well in the money to have that option. Especially as we grow volumes there, we will overrun what we can feasibly sell in Guernsey on a regular basis. Similarly, in the Brazos Valley, we're going to look to gain access to the Houston market and potentially the Corpus market as well, looking at making sure we have direct access into the premium MEH or LLS pricing structures that we utilize for our Eagle Ford barrels. We believe that there are a couple of options that we have to do that, and so we're moving down that path.
We will move away from trucking extensively in the field to gathering on pipe, and then we will pay a little bit of transportation incremental to what we do today to get from the field to the premium price point, and then all in, including the improvement in basis that we will realize we expect to have an overall more economic position. I did note that in the Haynesville, we will see our gas volumes fall. That'll put a little bit of pressure on the Haynesville specific GP&T next year. That's something we'll continue to look at and see if there are any other opportunities there to optimize that spend and that FT that we committed to back in 2010, in obviously a very different world.
The pressure that we'll see in 2020 is pretty manageable, and so we feel really good about the pretty obvious economic decision to pull back capital to the Haynesville at a time where gas prices are obviously extremely weak. In the Marcellus, we still maintain a very attractive gathering and transportation cost structure. We get access to very premium markets in the Northeast, especially in the winter. Our gathering cost in the Northeast is extremely attractive relative to peers. That is one place where we have a competitive standout position, and we look to continue to leverage that. It's part of what helps us recognize an extremely low break-even, as Frank pointed out, in the Northeast, and it's what holds up our investment in an asset like that, even in this time of very weak prices.
When we talk about gas falling year-over-year, we are very much pointed to the Haynesville there. We're going to do a pretty good job of maintaining our volumes in the Marcellus because the rate of return there is still pretty attractive, even at these levels with our break-evens as low as we've gotten them.
Just about the Eagle Ford, thanks for that commentary. Thoughts on the Eagle Ford there?
Yeah. We continue to look at a number of things in the Eagle Ford, both trying to consider alternatives for the gas gathering costs there that are on the high side of what we believe reflects the best situation we could have in the market today. Of course, that's also a contract that's been in place for many years and was built out for a different time and a different set of economics. Also on the oil takeaway, our growth activity in the Eagle Ford has really come to a place where we are generating free cash flow out of that asset and not really expecting that asset to grow volumes dramatically from here. We're going to work with our transportation partners there to think about if there's any other ways to optimize that. Those are all things that are works in progress.
You can assume that in every basin, our marketing team is hard at work every day trying to optimize how and where we're going to deliver our volumes and under what cost.
Great. Just my follow-up, Nick, is the CapEx is slightly tilted to the first half of the year. If you just take the midpoint of the range, roughly 53% of all your CapEx in the first half, 47% in the back half. Your tills are, on the oil side, more concentrated in the back half. Can you just help reconcile thoughts on second half CapEx given that mix?
Sure. That's just timing. If you think about what has to happen in order for our till schedule to reflect what you see there's a chart in our slides today that show that the largest number of tills occur in the third quarter. In reality, the largest number of tills occur in late August through late September.
In order to do that, we've started spending money sooner than that. You have more money that comes out in the first half than you do in the second half. The cycle times on these assets are something that we think about often and always trying to compress, but they are still very real. You spend money in May and June to start bringing wells online in August and September, and the cycles that follow.
All right. Thanks a lot.
Our next question comes from Brian Singer with Goldman Sachs. Please go ahead.
Thank you. Good morning.
Good morning, Brian.
In Brazos Valley, can you add a little bit of color on the expansion of the black oil window? Can you take us through the results that you saw from well data that you saw from first quarter wells to 230 additional locations, and then what you see as the upside versus downside risk to the economics of locations as you get more data on decline rates from these first quarter wells?
Brian, this is Frank Patterson. When we went through the acquisition, we walked everybody through. At that point, there were only four PVT samples for the entire field area. We were working with a limited amount of data. The drilling program had not drilled several parts of the field, we were being very cautious and conservative the way we viewed the fluid windows. As we've now dug into it and been able to go out and capture some PVT samples, do some analysis, we've drilled a few wells. What's happened is those wells, the 230 wells that have shifted, they've shifted from basically the volatile oil condensate window to a black oil or a relatively low GOR window.
We have pretty high confidence in that, because not only do we have PVT data, but we also have well performance data, and I think there's a map in the presentation that'll demonstrate that. We're seeing pretty high confidence of delivery across the footprint. We're trying to describe that in one of the other maps that we put in the presentation in that we've drilled across a big portion of the footprint now and seen really good results. We're going to continue to extend that as we go out and drill additional wells. We're still trying to optimize the completion design here. We're pumping less fluid, quite a bit of sand, which we think is key, but we're trying to eliminate some of the fluid that we're pumping and getting a more complex fracture network around the well bores. We're still at 1,000-foot spacing.
That's the next step, is what is the spacing really going to look like at the end of the day? We think it's between 750 and 1,000. We'll know more about that after we get our core results. We have two cores that we have just taken, and we took those cores across the Austin Chalk through the entire Eagle Ford section. We're going to get a lot of good data here in the next few months. I think what you're going to see is our footprint is going to expand, and I think we're going to see potentially some areas where we can maybe tighten up on some spacing as well.
Great. Thank you. My follow-up is with regards to natural gas, both in the Haynesville and the Marcellus. Can you talk to any constraints on how long you could keep your rig count in the Haynesville at zero and in the Marcellus to keep production flat? Is there any point at which either any of the GP&T or midstream becomes a constraint where you would otherwise either need to raise the rig count or want or need to renegotiate contracts?
There's really no constraint, Brian. We do have FT, as I noted earlier, and the 2020 impact of that FT is pretty muted. It would grow a little bit over time as you saw volumes continue to fall if you stayed at zero rigs. I don't expect that we will stay at zero rigs forever. I would think that at some point, the gas market will begin to look at some sort of a rebound here and come back to some reasonable level where the Haynesville is more economic than it is today. As you think about what our breakevens are in the Haynesville, they're not terrible, and we're just choosing at the moment to think just as much about near-term free cash flow as we are about long-term rates of return.
In a market where things might be a little bit more stable, there is long-term rate of return here that we can access at prices that do not need to be north of $3. In fact, they can be well below $3, and we might choose to drill some more wells in the Haynesville. This is not a departure from the Haynesville forever by any stretch. It is, in the near term, a recognition that with gas in the low $2 on the prompt and falling in 2020, that it probably makes sense for us to focus on free cash flow more so for the immediate term. I'll also note that our FT begins to fall a little bit starting in 2021. As you do think about that long-term profile, it's pretty manageable.
The costs are real, but again, we've incorporated those in what I gave you earlier to note that the gathering or the transportation cost all in for the Haynesville alone next year would see $0.03 pressure per Mcf. We can digest that, and then we can think about how we want to position it for 2021 as we get into 2020 and consider where we are. Great thing about the Haynesville, of course, is that when we get a price signal to do so, we can bring capital back and bring a lot of production online relatively quickly.
There's no real penalty there other than just the FT that exists for quite a while, but does get a little smaller starting in 2021, and then again, another slight step down in 2022. As we think about the Marcellus, on the other hand, we are maintaining relatively flat volumes there and are always eager for a price signal that we can grow our volumes in the Marcellus with the confidence that we would see current pricing. As we all know, the Marcellus is capable of a tremendous amount more volume from us, and we just worry that if we overrun the in-basin markets, we would see prices collapse in a hurry. We just try to balance what that demand looks like with the supply that we deliver.
Brian, this is Frank. I'll just give you a little more color on Marcellus. Just think of it as a two to three rig program to maintain that 2.3, 2.4 Bcf a day output. It's probably the lowest activation cost in the gas world in the U.S. and really capital efficient. We're seeing a lot of dramatic changes because we have the footprint to allow us to drill longer laterals, so we can basically drive the capital efficiency of that even higher. The completion and the spacing, upgrading the spacing to a wider spacing has also paid huge dividends. We're pretty pleased with our Marcellus. As Nick said, that's a lever we could pull if the gas market allowed us to. Just think of that right now as a steady state of two to three rigs going forward for a while.
Great. Thank you.
Our next question comes from Douglas Leggate with Bank of America. Please go ahead.
Thanks. Good morning, everybody. Thanks for taking my questions. Doug, I wonder if I could just follow up on Brian's question and ask you the same in the Haynesville. With 0 rigs, what does the underlying decline look like there? What would it take to stabilize the Haynesville?
It's a great question. As you know, the Haynesville is a tremendously productive asset and very dependent upon commodity prices. What we love is that the team there has done such a good job around capital efficiency and productivity, and the investment profile there is essentially at our discretion. As Nick highlighted there, I think it was very well said that when we look at 2020, the decline and the current GP&T commitments are not significant enough that it says we're going to direct capital there to satisfy a GP&T obligation. As we look out into 2021 and beyond, then we will continue to look at how we can best maximize those volumes to satisfy those legacy GP&T commitments. We also are excited about other opportunities in the Haynesville area, particularly in respect to the Cotton Valley.
Cotton Valley is an area or a horizon that we have not actively invested in, to my knowledge, here at Chesapeake. We have a great acreage position that we can continue to look for economic development there in the future. I think it's a good question. It's something that we're not really that concerned about, and we will direct capital there and make the best investment decisions with the continued priority of driving the greatest margins and achieving that sustainable free cash flow.
I appreciate the answer, Doug. My follow-up is for Frank, if I may. Frank, there's a couple of call-out wells here in the presentation, Balfour in Brazos and RRC BP up in Powder River. Can you just talk what's going on there? Because those look like dramatically better results than what you've guided towards. I'm just wondering if there was something unusual about those, or if we're starting to see a trend up and to the right in terms of how you see the productivity of those areas.
Okay. Doug, thanks for the question. The Balfour, remember, that's a four-well pad, you have to scale that down. That's in the black oil window. What that did was that well validated the work that we did on PVT analysis, and it validated that the black oil window extends further down dip than we had originally thought. We're still trying to get the optimum completion style on those wells. That's a four-well pad, that looks really impressive, but you got to scale that back.
Right.
On the RRC, we highlighted that in our last call. It's a well up in the oil window of the Turner. It's in an area where we've got the spacing, we think, correct. The well performance is really stout in the north part of that field. If you look at the entire oil window, we've tried to demonstrate that in the graphic in that our average oil window wells are exceeding the peer performance within the basin and two of the wells to the north that we're highlighting that we talked about last time that had really high IPs, those wells are hanging in there and really outperforming. What we're seeing is there is variability in the Turner, and that was something that we expected. This is not a shale, this is a sandstone and a silty sandstone.
As we drill across the footprint, we're going to see a little bit of variability, but even with that variability, we're seeing really high rates of return on the mean well.
Understood. I appreciate the clarification, guys, and great effort in the quarter. Thanks.
Thank you.
Our next question comes from David Heikkinen with Heikkinen Energy. Please go ahead.
Morning, guys. Curious if you have any thoughts or expectations on the impact of oil realizations in the Eagle Ford Brazos Valley premiums as Permian volumes get to the Gulf Coast? Do the premiums contract in your expectation?
The way we forecast that, Dave, is that we simply look at the same forward curves that you all do. There's a curve for MEH, which is our primary pricing point. It certainly shows a contraction. That's how we build our economics. As the U.S. continues to export oil, we think that there's potentially the opportunity for some of that premium to be sticky. We don't forecast anything beyond what the market tells us to expect today.
Okay. That's helpful, Nick. As you talk through each asset, GP&T, ex the $79 million or $0.03 for Haynesville, what do you think the run rate should be for GP&T into 2020?
Well, it's always a function. Yeah. It's not just a function of what the current rates are everywhere today, but also a function of the mix that we will see going forward. As we refine capital allocation going into 2020, and we refine our budget going into 2020, we would give everybody more specific guidance. It should be around where we see it today. Could be a little higher, could be a little lower in theory, although, I think we've done a pretty good job getting things down today. We'll continue to work on other step changes that may present themselves to us. For now, I'd say, until we have other renegotiations or new contracts that we would put in place, we feel pretty good about our run rate.
Okay. Thanks, guys.
Our next question comes from Charles Meade with Johnson Rice. Please go ahead.
Morning, Doug and Nick and Frank and the rest of the team there.
Morning, Charles.
Thank you. Frank, I'd like to pick up on one of your answers to an earlier question. You were talking about that bell pad that validated your view of that black oil window. You talked about how you're still trying to figure out the right way to complete those wells, and I'm curious, did you vary your completion and/or your landing zone across those four wells on that pad? If you're not iterating that way, how should we look for you to iterate as you try to triangulate in on the right recipe?
Yeah, I think it's going to just come with more and more exposure, Charles. When we took over the asset, we had to complete some wells that had already been drilled that were already drilled by the previous operator. We started, and the first thing we wanted to do was get our logistics down and get our stage count up. We've successfully done that. The team has done a fantastic job, as I stated in the commentary. What we're doing now is we're starting to look at, as you say, landing zones. We're looking at the actual design and how much sand to put away. We've reduced the amount of water we're putting in the wells, which helps us both on the pump times as well as the flow back and handling fluid on the surface, and so we're seeing a lot faster oil cuts on flow back.
This is just going to evolve over time. We haven't completed that many wells yet, and as we complete more wells, I think you're going to see that we're going to start having an increase in productivity as we learn more and more about where to physically land the wells and exactly how to treat all the wells. There's a lot of knobs to turn, and you just can't turn them all at the same time. You have to slowly work your way through. We're in the very, very nascent stage of this development, and I think you're going to see this thing evolve a lot like South Texas, where we get the spacing, the completion design all optimized in pretty short order.
No. That's helpful detail. Thank you for that, Frank. If I could go back to the 2020 CapEx question and ask maybe a bigger picture or ask it from a different perspective. I get that you guys are shifting towards oil and away from natural gas, but I wonder if you could talk about how you're arriving at the total level of CapEx that you're choosing, because it looks to me like another meaningful outspend versus 2020 cash flows, at least at the current strip.
Maybe could you guys talk about your thought process, if it makes sense, in terms of what is obligated CapEx, perhaps to hold your lease position together in your key plays, and then maybe perhaps the next piece of the stack would be the work that you have to do to optimize your development plan along the lines of what Frank was just talking about? How do you guys stack up the pieces to arrive at that total 22 level?
Yeah, Charles. We really don't have an obligated CapEx or a lease expiration or commitment that obligates us to a particular capital level. As we think about our capital allocation and the flexibility that we've achieved over the past several years, we have tremendous flexibility in how we choose our CapEx program and where we direct those investments. As we think about how we generate the greatest value, given any particular asset decline, given the margins that we're trying to capture, given the free cash flow development, and how we optimize the NAV of the company over time, we will rigorously evaluate each of the investments. What is great, and I love, is that we have a tremendous amount of flexibility. The capital efficiencies that have been driven into our program have resulted in lower breakevens.
We've seen, as Frank highlighted in some detail there, that each of the asset areas, the rate of change that we've accomplished results in greater productivity and greater capital efficiency. We are not projecting a meaningful outspend in 2020. We'll continue to evaluate pricing and the economics and how we best optimize the capital investment and the production over that near term or one-to-two-year window. We also continue to look at hedging. We haven't provided the guidance out there, we've established some meaningful hedges for 2020. We're confident in our ability to continue to perform and achieve our strategic metrics.
Thank you for that color, Doug.
The only thing I would add to that, Charles, is that as we think about where we want to be long term, which is obviously to be free cash flow positive, we want to be there in a way that is sustainable. The investments we're making today are generating very strong returns. As long as that is true, we will continue to make those investments so that we can get to a level of cash flow that will be sustainable. If prices fall much further, then we'll re-look at that. As Doug noted, we have that flexibility, and that is something that with a diverse portfolio of assets that some of them have extremely low break-even costs all the way through gas in the Haynesville today, which is certainly at a level that pressures its economics.
It's a competitive strength for us to be able to pick and choose where we spend our capital and make sure that we are earning a great rate of return on every well that we drill. If we are doing that, then we will continue to invest in our program and build shareholder value. If we are not, then that capital will come down. It's pretty much as simple as that.
Got it. Thanks.
Our next question comes from Josh Silverstein with Wolfe Research. Please go ahead.
Yeah, thanks. Good morning, guys. Wanted to build on that last question there. Do you think sustainable free cash flow would come in 2021? I guess, Doug, from your comments, you guys do expect to be free cash flow negative next year? Doing, I guess, some of the math that you put out there. If you take the 255 EBITDAX from this year, hold it flat, roughly $700 million of interest expense, that's roughly $1.85 billion versus the CapEx spending of around $2.2 billion. Should we be thinking that the outspend is less than that? Wanted to clarify those comments.
Yeah, sure, Josh. No, we have not provided guidance for next year. Obviously, pricing makes a big impact on that, as we look, we are obviously going to be driving towards being free cash flow positive just absolutely as quickly as possible. I think that the best thing to do is to look at the rate of change of what we've accomplished and the productivity of our wells, the continued improvement in our capital efficiency. We are definitely not saying that we're going to have an outspend next year because, as Nick highlighted, we have a tremendous amount of flexibility in our capital allocation. The key is what he said, and I'll reiterate, is that we have great flexibility in our program. We have tremendous assets. We'll continue to adjust and look for opportunities to further improve our productivity and capital efficiency.
We'll continue to look at asset sales and how we can best manage the portfolio for long-term value. The progress that we've made up to this point in time gives us tremendous flexibility and options going forward. I think that the best thing to look at is that the rate of change and the stability that's in our company and program today, we'll continue to build upon that in 2020 and 2021. We'll be pursuing that positive free cash flow just as quickly as we possibly can with the tremendous portfolio that we have.
Got it. Thanks for that. Just understanding the two times leverage target that you want to get to. Based on where you guys are right now, it's almost double that. Is the goal to delever through EBITDA growth faster, or is it asset sales that will get you guys down faster?
It's both, and it will be as rapid as we possibly can and what makes the most sense for our long-term value creation story. There's no question that the strength and quality of the portfolio, that we can do that organically with the growth that we expect from our oil assets, and we will continue to monitor and look for opportunities with small and potentially bigger asset sales to accelerate that.
Thanks, guys.
Our next question comes from Kashy Harrison with Simmons Energy. Please go ahead.
Hi. Good morning, everyone, and thank you for taking my question. Just one quick one from me. Frank, in the press release, you highlighted 10 years of inventory remaining in the Marcellus at your current spacing assumptions. I was just wondering if you could give us some color on how we should think about economic inventory in years across your major regions, including the Eagle Ford, the PRB, the Haynesville, the MidCon, and the Brazos Valley.
Okay, Kashy. We were trying to describe the core of the Marcellus. There's a lot more inventory there that's economic than what is stated. That's the $1.50-$1.75 breakeven locations. That's only a partial available inventory to us. In Eagle Ford, and we can talk about Brazos Valley. Brazos Valley, we're just getting started. We have a lot of locations available to us today. We're still trying to understand exactly how big the low breakeven window is. It looks to be quite large. I would say you have multiple years at the four-rig program. The inventory, it really depends on how many rigs you want to throw at it. We could accelerate Brazos Valley if we so desired. I think four rigs is a really good run rate for us operationally. In South Texas, we have less runway there.
We probably have three or four years in the lower Eagle Ford, we have the Austin Chalk and the upper Eagle Ford, which will tag onto that. It's probably one of our more mature assets. In Gulf Coast, in the Haynesville, we have years of inventory. If we go to a low rig count, which we will be doing in the near term, zero to low rig count, it's just going to extend. MidCon, there's a lot of different plays available to us in the MidCon. The issue with the MidCon is that there's not one large play. It's a bunch of discrete plays. There's thousands of locations available to us if we wanted to push that lever. The nice thing about the MidCon is it's a very oily basin, there's a lot of oil opportunity there.
In the Powder, the Turner probably has another few years of run rate at the current rig deployment. The NGL is basically across our entire footprint and is well over 1,000 locations. Mowry will be very similar to that as we move forward. We have Parkman, Sussex, and other formations available to us. We have long runway in every single one of our assets that will be competitive in our portfolio.
All right. That's it for me. Thank you.
Our next question comes from Neal Dingmann with SunTrust. Please go ahead.
Morning, guys. Thanks for getting me in. Doug, just a quick one for you and Nick. You talked all about, I know you've done a great job of accelerating the oil growth. I'm looking how good, how the returns look for both your Brazos and the PRB. I'm just thinking, you want to deaccelerate or I'm sorry, you want to obviously lower the leverage, and you're getting these type of returns. Would that consist of potentially increasing activity potentially even more in those plays? I'm just wondering how you sort of balance the two, you know what I mean, given the de-leveraging strategy and the returns you're seeing, especially in the PRB and the Brazos.
Yeah, sure, Neal. We're very excited about it and encouraged by the capital efficiency and those productivity gains that we're capturing and indeed, that there are opportunities for us to potentially accelerate. The balance that we have to look at in this portfolio, given the debt that we have and incurring additional costs, we just are very mindful of how we manage through this commodity volatility that we're seeing. We will constantly evaluate the option there. We see opportunities. We can increase the rigs in both assets, but we are targeted on the most efficient development plan that we can possibly capture. We're not going to react to just a one-month or two-month type of price, particularly on oil. We're looking for the long term, making adjustments on the gas because of the greater macro issues that exist there.
It's always an option, but at present, that's not something that we're thinking about.
Okay. Thanks very good. No, go ahead. I'm sorry.
I'm sorry, Neal, this is Frank. One thing to think about, and I think we've spoken about this before, but we're not going to sacrifice efficiency in our assets. Think of if you accelerate, you have to accelerate both drilling and completion and align the two. What you don't want to do is go drill a bunch of wells and end up with DUCs and fallow capital. When you think about expanding in any play, it might be more than one rig to match up with the completion crew.
No, great add, Frank. Just lastly, one quick one, just Frank, in the PRB with that Windy Ridge test in the West, what are you trying to get out of that? Could that change plans on the go forward?
Yeah, Neal, in the western part of our play, we actually have the Turner and the Frontier kind of sitting on top of each other, and it appears that there might be a frack barrier between the two, and we're trying to find a way to access the entire storage of those two systems. It's kind of a combo test between Frontier and the Turner, which they're genetically the same. They're just deposited from different ends of the basin. We're testing that concept. If that holds true and it works, you'll probably see additional line racking on the west side of our field.
Very good. Thanks, guys.
Thank you.
That's it for the question and answer session. I'd like to turn the conference back over to Doug Lawler for any closing remarks.
Yeah. Thank you, operator. We appreciate everyone joining us today. Just to reiterate, in the months ahead, you'll continue to see Chesapeake execute on our priorities and driving change throughout all of our assets, as we look to deliver record oil production and a record oil production mix in 2019, followed by the stated double-digit oil growth that we expect on relatively flat capital in 2020. We'll continue to be targeting improved margins as we increase our production through lower GP&T and other cash costs. As we noted, we will be reducing our gas activity and forecasting double-digit decline in gas in 2020 at current pricing. We have a tremendous amount of confidence in our ability to continue with the momentum that we have and building on the rate of change that we've stated today.
With our scale and diverse portfolio and disciplined approach to allocating capital to the highest return opportunities, we're very well positioned to deliver value for our shareholders. We thank you, everyone, for your time today. If you have any further questions, please don't hesitate to reach out to us. Thank you.
The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.