Greetings, and welcome to EQT Corporation 2019 Guidance and Update Analyst Presentation Discussion. At this time, all participants are in a listen only mode. A question and answer session will follow the formal presentation. As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Blake McLane, Senior Vice President, Investor Relations and Strategy.
Thank you. You may begin.
Thank you. Good morning and thank you for joining today's conference call. With me today are Rob McNally, President and Chief Executive Officer Jimmy Sue Smith, Chief Financial Officer Aaron Cenafani, Executive Vice President of Production and Blue Jenkins, Executive Vice President of Commercial. Before we begin, a few logistical comments. Following the formal presentation, we will host a question and answer session that will conclude at 9:15 Eastern.
As a reminder, a replay of this call will be available for a 7 day period beginning early this evening. The telephone number for the replay is 201-612 7415 with a confirmation code of 1,368,06,022. The call will also be replayed for 7 days on our website. Earlier this morning, we issued a press release and posted a slide presentation, which we will be walking through during this call. Both can be found on the Investor portion of our website ateqt.com.
I'd like to remind you that the press release, presentation slides and today's call may contain forward looking statements. Actual results or future events could differ, possibly materially, due to a variety of factors, including those described in our most recent Form 10 ks, Form 10 Qs and other SEC reports. Conference call and related materials may also include a discussion of certain non GAAP financial measures. Please refer to the appendix in the back of the presentation and to this morning's press release for important definitions and disclosures regarding such matters. With that, I'd like to turn the call over to Rob.
Thank you, Blake. Good morning, everyone. Let's start with Slide 2. I'm very excited to share our vision for EQT with you today. Since becoming CEO in November, my team and I have been laser focused on turning EQT into a free cash flow generation machine.
Today, we will present our plan to generate approximately $350,000,000 of adjusted free cash flow in 2019 and at least $2,700,000,000 of adjusted free cash flow over the next 5 years. This is a rigorous bottoms up plan that factors in EQT scale and operating complexities. And most importantly, we have a high confidence in our ability to achieve these results. We are also committed to reducing capital costs by an additional 10%, which will provide incremental upside to this plan. We have a world class asset base, are focused on capital efficiency and are well positioned to deliver sustainable free cash flow to our shareholders for many years.
I also want you to know that we have Q3. While we're not releasing earnings until February, I will share a few preliminary numbers with you this morning. First, we completed 2018 with full year production of approximately 14.88 Bcfe. Production for the 4th quarter was approximately 3.94 Bcfe, an increase of 5% over the 3rd quarter. 4th quarter development CapEx was in line with guidance.
Most importantly, we forecast approximately $100,000,000 of free cash flow in the 4th quarter. We're starting to see some of the benefits of our shift in strategy and this 4th quarter performance demonstrates our ability to achieve our plan and generate significant value for shareholders. Today, we will also discuss the recent claims made by former Rice executives. As you will see, those claims are fundamentally flawed and do not represent a viable path to generate incremental free cash flow versus the EQT plan. Now turning to Slide 3, which highlights the actions we have taken to strengthen and position the new EQT.
As you can see from this slide, we achieved a number of important milestones in 2018, transitioning our company into a leading pure play Appalachian upstream company and the largest natural gas producer in North America. In November, I assumed the role of CEO of EQT upon the successful completion of the separation. Our leadership transition and complex transformation is now behind us. This is a new company with a new leadership team and a new focus. Now turning to Slide 4.
Our company is built on 3 key pillars. 1st, the world class asset base positioned squarely in the core of the Marcellus and Utica basins with 680,000 net acres in the Marcellus and 15 to 20 years of drilling inventory. 2nd, our ability to generate substantial and sustainable free cash flow. We're aggressively focusing on operating efficiently and lowering costs. We have successfully shifted from a volume focus to a free cash flow focus, and we expect to generate approximately $350,000,000 of adjusted free cash flow in 2019 and at least $2,700,000,000 over the next 5 years.
As you can see from our Q4 cash flow generation, we are already realizing the benefits of this strategy. The 3rd pillar is our financial strength. EQT's investment grade balance sheet gives us the financial flexibility to thrive even in volatile commodity price environments. In addition, our investment in Equitrans Midstream gives us optionality to further strengthen the balance sheet. The map on Slide 5 is a great visual representation of the quality of our acreage position.
We have a substantial position in the core of the core of the most prolific natural gas play in North America, which supports long term sustainable free cash flow. We know there's great value in our acreage and our focus is on generating returns from these assets. On this slide, we've included our highlights. Most notably, we expect our assets to deliver 1470 to 1510 Bcfe of production in 2019, dollars 2,400,000,000 to $2,500,000,000 of adjusted EBITDA and approximately $350,000,000 of adjusted free cash flow. Slide 6 provides additional detail on the quality of our underlying asset base.
This slide includes the same heat map, but also includes boxes to highlight production data on a few specific EQT pads. We have delineated the boundaries of our core position and are confident that this asset can generate repeatable performance. As you can see EQT's core acreage consistently delivers average EURs of 2.4 Bcfe per 1,000 feet with the best areas over 3.0 Bcfe per 1,000 feet. Our 2019 Pennsylvania Marcellus drilling program contains average spacing of 8 80 feet with an expected average EUR of approximately 2.6 Bcfe per 1,000 feet. Now moving to Slide 7.
Let's talk about our 2019 plan and how we will achieve our financial objectives. We're excited about the opportunities ahead and have developed a 3 point plan to drive shareholder value. This includes providing clear measurable action items in keeping with the new management's focus on transparency and accountability. The first part of our plan is an unrelenting focus on execution and operational improvement. This is critical as everything starts with execution in 2019.
Have a search underway to identify an external Chief Operating Officer and the Board has created an operating and capital efficiency committee. The second item of our plan is the reduction of overhead, operating expenses and development capital to further drive down costs. In early January, we implemented a reduction in workforce to remove management layers, streamline functions and reduce contractor costs. This action generates approximately $50,000,000 annual cash savings. Today, we also announced an incremental $50,000,000 in capital cost reductions.
These actions added approximately $400,000,000 of additional adjusted free cash flow to our 5 year plan. The 3rd involves utilizing free cash flow to return capital to shareholders, while achieving our leverage targets through the monetization of our retained equity stake in Equitrans Midstream. As you can see, we have made a lot of progress on our strategic objectives. We will keep pushing hard to drive value because there is more work to do. Shifting gears over the next few slides, we will discuss each action item in sequential order and I will cover the key takeaways from our 2019 plan.
We've made a conscious effort to provide more transparency, which is reflected in these slides. Starting with execution and operational improvement on Slide 8. At a high level, our 2019 plan is expected to generate 14.70 to 15.10 Bcfe of sales volumes, $2,400,000,000 to $2,500,000,000 of adjusted EBITDA and approximately $350,000,000 of adjusted free cash flow. We plan to turn in line 147 net wells and run on average 7 horizontal rigs and 6 frac crews. On this slide, we also lay out the components of our 2019 CapEx program, building through a total of $1,900,000,000 to $2,000,000,000 Moving to Slide 9.
We compare our 2019 plan to our 2018 results. Estimated CapEx is down approximately $700,000,000 from 20 18, which reflects the reduced activity levels, elimination of the 2018 missteps, which as you can see from the 4th quarter results are behind us and quick win savings implemented recently. I would also note that our average lateral length continues to increase for both our spud and turned in line wells. This is critical for reducing development costs and EQT is uniquely positioned to execute on this type of program, thanks to our large contiguous asset base, especially in Southwestern Pennsylvania. In the spirit of full transparency, please see the appendix where we have added a detailed summary of our planned 2019 operating activity.
The summary of our 2019 program broken out by operating area can be found on Slide 10. In 2019, we will be drilling the vast majority of our wells in the Pennsylvania Marcellus with 13,200 foot average laterals. This is the region where our D and C cost per lateral foot is lowest and where we are delivering our lowest cost, highest return wells. Note that over the last 2 years, we've increased our average lateral length by roughly 50%. Going forward, we expect to consistently deliver spud laterals averaging 13000 to 15000 feet, which we are confident will create real value for our shareholders.
On Slide 11, we detail the relationship between lateral spacing, well costs and returns. As discussed on prior calls, we believe 1,000 feet to be the optimal well spacing. We've been trending towards wider spacing over the last several years. Average spacing in our Pennsylvania Marcellus area averaged 840 feet in 20 18 and is planned for 8 80 feet in 2019. We believe we will get to an average of around 1,000 foot spacing over the next couple of years.
Although we realize that dollar per foot is a common industry measure, the table on the right illustrates how this can be an imperfect metric as depicted by the relationship between cost per foot, cost per Mcfe and returns. Additionally, the accounting treatment of certain well costs varies widely among operators, leading to even more disparity on this metric. The table shows the dollar per foot increases as spacing increases as a result of larger frac jobs. We also showed that these costs are more than offset by the enhanced returns and optimization of long term reservoir development. Notwithstanding outside pressure to show the lowest possible cost per foot, our program remains focused on maximizing value for the benefit of our shareholders.
The actions we're taking today are part of our broader 5 year strategy outlined on Page 12. Through more efficient operations, we will continue to do more with less, including increasing lateral lengths across our program and increasing production with less capital. This translates to accelerated free cash flow. We expect our plan to generate at least $2,700,000,000 of adjusted free cash flow over the next 5 years, a significant increase from our estimates provided in October of 2018. Notably, this does not include the impact of the incremental cost reductions we are targeting, which I will highlight on the next slide.
Now moving to Slide 13. This management team is intent on reducing costs and increasing efficiency. As you saw earlier, we've already taken action to reduce annual cash costs by approximately $100,000,000 We're now in the process of doing a thorough evaluation of our operations and processes and are targeting a 10% cost savings program that will be executed in 2019 and realized in 2020. We call this our target 10% initiative, which is a primary focus of our employees across the entire organization. Areas where we expect to realize the most significant cost savings include materials and service sourcing and contracting, water related process changes, portfolio and scheduling optimization and overall increased operational efficiencies across the organization.
Through the successful execution of the Target 10% Initiative, we expect to add approximately $700,000,000 of adjusted free cash flow, which will increase the cumulative adjusted free cash flow to approximately $3,400,000,000 through 2023. On Slide 14, we address our efforts to mitigate production curtailments. I won't go into great detail here, but I would like to make a few points. First, on the top right, you see a graphical depiction of our wellhead constrained type curve. This is the first time we have made this information publicly available and it's been posted to the EQT website in the Investor Relations section.
2nd, below the curtail type curve, we show a visual representation of the back off phenomenon related to system curtailments. This demonstrates that even though new wells are backing off older wells, they're still adding a significant amount of new production. We're actively working with our midstream providers to reduce these constraints as quickly as possible. Our plan reflects mitigation of system curtailments and operational reductions by year end 2020. Moving on to Slide 15.
We have a new team here at EQT and we're open to bringing on additional expertise that would advance our goal of delivering shareholder value. We recognize that EQT would benefit from additional operational expertise. So in early December, we began a comprehensive search to identify a Chief Operating Officer. That search process is now well underway and we have already identified a short list of highly qualified and experienced external candidates. Once appointed, our new COO will work closely with me and the team to implement significant improvements and realize efficiencies across the business.
Finally, in early December, the Board formed a new operating and capital efficiency committee. Directors on the committee have strong reputations as efficient operators, as well as substantial financial expertise to help drive improved financial performance. Moving to Slide 16. 1 of the first jobs of this new management team was to identify opportunities to reduce capital costs and overhead. Earlier this month, we announced approximately $50,000,000 of annual cash savings associated with workforce reductions, elimination of management layers and reduced contractor expenses.
Additionally, this review led to a few quick wins that will result in approximately $50,000,000 of additional annual cost reductions. These reductions will be driven across optimized water handling procedures, streamlining various drilling and completion activities, changes to planned surface facility activities among other items. These are the kinds of operational improvements and cost savings we expect to achieve through our target 10% initiative. Collectively, these early wins add approximately $400,000,000 to our 5 year adjusted free cash flow. Slide 17 outlines the 3rd aspect of our plan to enhance shareholder value.
In addition to strengthening our standalone business, we will also enhance our already top tier financial position. Our 19.9% stake in Equitrans worth approximately $1,000,000,000 at current valuation represents significant balance sheet flexibility and we expect to monetize that over the next 1 to 2 years. That stake combined with our free cash flow generation gives us the ability to both reduce leverage to our target of 1.5x to 2x net debt to adjusted EBITDA and return cash to shareholders. To give you a sense of scale, our projected $2,700,000,000 in adjusted free cash flow could afford us the ability to buy back roughly half of our current shares outstanding at today's valuation. Now moving to Slide 18.
Before we wrap up and open the line for Q and A, I want to provide an update regarding our recent interactions with the former Rice Executives and our perspectives on their assumptions and claims regarding EQT. Last week, Toby and Derek Rice presented to the full Board of Directors at EQT. The Board thought it was important to consider their feedback and ideas to improve operations as we evaluated and finalized our 2019 plan. We share a common objective driving shareholder value at this company, and we value input from all investors. And as we relate to them last week, we would like to continue working together constructively for the benefit of all EQT shareholders.
We've acknowledged that both operational and financial improvements are necessary to EQT. However, after performing a thorough analysis, which included a detailed review of Rice Energy's historical records acquired in the merger, we disagree with the Rice claims. They are based on flawed assumptions, lack detail and result in no incremental free cash flow versus our plan. We've provided a number of slides in the appendix with additional detail around our analysis and findings, but I will touch on a few key points here. First, the Rice's $7.50 per foot well cost is not realistic.
It ignores the current service cost environment and the realities of EQT's water usage and delivery portfolio. In fact, it does not align with Rice Energy's own guidance or historical performance in the second half of twenty seventeen when its Pennsylvania Marcellus wells averaged $8.80 per foot. Obviously EQT's 2019 operating plan should not be predicated on Rice Energy's well cost for wells turned in line during the first half of twenty seventeen, the This is not repeatable given EQT's geographic footprint, infrastructure and produced water dynamics. I would also note that EQT's cost per foot on an apples to apples basis during the first half of twenty seventeen was $6.95 per foot. 2nd, they claim that a 10% production uplift can be achieved compared to our plan by increasing well spacing.
As we have discussed, we agreed that wider well spacing is optimal, but we also believe that maximizing asset value is only achieved through a corresponding increase in frac size. Our internal analysis shows that 1,000 foot spacing with smaller fracs would actually result in a negative production impact versus our 2019 wells with 8 80 foot spacing and larger fracs. Put simply, our current plan results in greater production volumes from fewer wells. Notably, the Rice well cost claims also admit material accounting treatment differences between EQT and Rice Energy for certain well costs, such as flowback operations and certain land and construction activities. These are not included in a simple D and C cost analysis, but they are real cash costs that must be included in any cash flow analysis.
The impact of these differences are shown by the starkly different cash operating costs between EQT and Rice. The appendix includes an analysis showing the magnitude of these differences to be as large as $150,000,000 per year. In summary, when we make a few of these basic adjustments, we find that the Rice claims would generate no incremental free cash flow versus EQT's plan when adjusted on a directly comparable basis. We've laid out the true and realistic nature of their incremental free cash flow claims in our appendix. That said, the focus of this call is on our 2019 plan and the positive change that is underway at EQT.
We are laser focused on reducing costs, increasing operating efficiency, mitigating volume curtailments and providing greater transparency and accountability. The Board and management team are confident in our ability to deliver superior shareholder value. We have a bright future ahead as a more focused efficient EQT. This is a very exciting time at EQT. We expect to generate approximately $350,000,000 of adjusted free cash flow in 2019 and at least $2,700,000,000 of adjusted free cash flow over the next 5 years.
Our plan is achievable, is based on EQT's actual size operating complexities and is being executed upon as I speak. We also commit to further reduce capital cost by 10%, which will provide additional upside to our plan. I'm confident that we will achieve these results and deliver substantial value to our shareholders. I do want to take a moment to thank all of the EQT team members for their dedication and hard work through this transitional period in the company's history. With that, I will hand the call over to the operator who can open it up for questions.
Thank you. Our first question is from Scott Hengold with RBC Capital Markets. Please proceed with your question.
Thanks. Good morning. Appreciate all the thorough information on the presentation, a lot to go through. But you discussed obviously previously the streamlining from the corporate side, saving some money as you look forward in 2019 beyond. And today there's some incremental savings in the capital side.
Can you generally discuss where those are coming from specifically? And in addition to that, is that something you're seeing like right now today or is it something you're going to gradually see as 2019 unfolds?
Hi, Scott. Thanks. So these are these items I would really characterize as just low hanging operational fruit, where there are some things that we were doing that were just not efficient, where we've been able to change, whether it's water scheduling optimizations, some things in frac operations and drilling operations that are really pretty straightforward and low hanging fruit that we're executing on now. So these are being realized as we speak. And I would also say, it also gives us confidence in our ability to further reduce costs, because this team has been in our seats now for about 2 months.
And we've had a pretty intense focus on getting our cost structure right. And but after what we've seen in the first 2 months, I think there's more room to do it better. And it's really more around efficiency of operations versus headcount. But we've I think we've taken steps in the right direction to get our cost structure in line that's going to allow us to generate the free cash flow that this business should generate.
Okay. So it sounds like it's more logistical sort of an operational approach versus where you were before. And just out of curiosity, is that consistent with what, say, EQT had been doing 2 years ago? Was it just an 'eighteen issue that's being corrected back to what you were doing before? Is this sort of these logistical improvements an improvement from where EQT has ever been?
Yes. So, Scott, I would say that historically EQT for a decade or more has been very volume driven. It was a different time in the marketplace, growth was what was at a premium. And so really the fundamental change that we're making here is a move from being driven by volume targets to being driven by capital efficiency. So to correct the missteps from 2018, that really was a function of running more like a manufacturing operation, running at steady state, 6 frac crews, 7 rigs and not trying to jump through hoops to get to volume targets.
And importantly, also being realistic about lateral mix, right? So now in 2018, we drilled some laterals past 15,000 feet to as much as 20,000 feet. Now we're cutting the majority of our laterals off at 15,000 feet. And we've drilled more than 100 wells in the 10,000 to 15,000 foot range and have done it very successfully. So we think that the operational issues and delays that were caused by that in 2018 are now behind us.
The additional $100,000,000 of cost savings that we've identified in the past 2 months are in addition to making those efficiency changes.
Got it. Got it. And then you had mentioned that, I guess, your average type curves about 2.4 Bcf per 1,000 foot. And then 2019 is 2.6 at 880. Did I hear that right?
Is there a bit of high grading going on in 2019? Or is there a reason why that's above the average?
Right. So the 2.4 has been our historical average, which was on narrower well spacing. So now in 2019, we're moving to 8 80 foot well spacing on average, and we will pump slightly larger frac jobs, and that drives the higher recoveries.
Got it. Got it. Can you quantify those frac or the frac that has changed the proppant usage?
I don't have it in front of me, Erin. Do you know the
I do, Scott. So at 850 foot spacing, we're pumping 2,625 pounds per foot and when we move to 1,000 foot that goes up to 3,000 feet or 3,000 pounds per foot, so proportional in between there.
Got it. Okay. Thank you.
Thanks, Scott.
Our next question is from Brian Singer with Goldman Sachs. Please proceed with your question.
Thank you. A couple of questions. First, on the capital costs per lateral foot, it looks like the way you guys see it, your plans are for $8.65 to $8.70 per foot. Can you just remind us of where either current costs are or 2018 costs were? And then what do you see as the milestones in 2019, both in your base case plan and under your target 10% initiative?
So Brian, this is Erin. On the wells that we turned in line in December, they are right in line with what we're expecting for our 2019 business plan costs that we have in the presentation.
The other thing that I would say, Brian, as we move to 1,000 foot spacing, I would point you to the slide in the deck where we're showing dollars per foot versus dollars per Mcfe. Ultimately, we think that the best measure is dollars per Mcfe. So as we go to wider spacing and larger frac jobs, our dollar per foot metric will go up, but the dollar per Mcfe goes down. And I think that's a better measure to measure capital efficiency.
Great. And my second question is on the production beat in Q4 relative to your expectations. Can you talk to what drove that and any impact from curtailments?
Yes. So that's there's really no effect from curtailments yet. That work is still in progress. And I would just say that it was timing and efficiency in getting wells turned in line.
Got it. So more wells got online earlier than you'd anticipated?
Right. Wells returned in line sooner than we expected.
Great. Thank you.
Thanks, Brian.
Our next question is from Welles Fitzpatrick with SunTrust SunTrust
Robinson Humphrey.
Given the uplift on Page 27 or Page 11 for those 1,000 foot space wells and given the depth of inventory, why not move there as soon as you can? Is it just pads and permits aren't quite set up for that in 'nineteen? Is that the rationale?
That's correct. Yes, the permitting work and the land work isn't complete. So we continue to move that direction. It's just we can't do it overnight given the land constraints in Appalachia.
Okay. It makes sense. And then how much of the over 5% growth in 2020 is because of curtailment remediation that you guys outlined on Page 14?
Go ahead, Erin.
None, actually. So we're not assuming the curtailment issues get solved until the end of 2020.
It's actually one area where I think we've got upside to the 2020 numbers, both production and financial numbers, is that we solve the curtailments quicker than what we have planned. But as of now, we don't have the curtailments being solved until the system curtailments that is being sold until the end of 2020.
Okay. That's great. And then just one last one, and I'm sorry if it's a little touchy, but the search for the new COO, can you talk about how that may or may not have been affected by the activist campaign?
Well, it's something that we recognized early on. We made quite a few changes to the organization when I first took the CEO role. And then subsequent to that, another layer of the operations management came out. And this was done kind of early on in our tenure, late November. And we decided that we could probably benefit from having some additional operations expertise from the outside.
And I think that our team has great technical capability, and I think they've actually done really well here in the Q4 as we've changed the focus to capital efficiency versus volume growth. But I think given where we are, having another person added to the senior management team that has more of a history of running a capital efficient business is probably helpful. And there's some upside for the organization.
Wonderful. Thank you.
Our next question is from Jean Tranchenko with Stifel. Please proceed with your question.
Good morning. I have a first question about the DUC inventory. If you guys can disclose how many DUCs are left in Utica as of today or as of year end 2018 and in Marcellus as of year end 2018?
We haven't made Jim, we haven't made that information public yet. We will have it all updated when we release earnings here in 2 weeks. But rather than give you a off the cuff number, I'd rather wait until we publish our earnings.
Okay. Sounds good. And then the second question is on production cadence in 2019. How should we think about it? Should it decline from 1Q 'nineteen?
And maybe should it decline from 4Q 'eighteen going forward in 2019?
Yes. I think the shape of the curve will be a slight decline in Q1 and then will continue to grow through the rest of the year. And ultimately, we'll see about a 3% production growth versus 2018 when adjusted for the divestitures that we did in the middle of 2018.
In terms of exit to exit rate, can you comment on that in 2019?
We exited 2018 at 4.3 Bcf a day.
Yes. So, Blake, we'll follow-up with you
with that information.
Okay. Sounds good. Thank you so much. And the last question is on Utica program. If you could expand a little bit how you think about Utica going forward?
Well, I mean, the Utica is a very solid asset base. It's a nicely consolidated land position. And you can see by the average lateral lengths that we're drilling, it is it's a good strong position. The economics aren't quite as good as core Marcellus, but they're almost competitive. And so I think that the pace that we're drilling in 2019 is how you should think about that business going forward.
And even though it is close geographically to Pennsylvania and West Virginia, it does give us a bit of geographic change in terms of access to different pipes and where that gas ultimately goes. So we think it's a productive part of the portfolio, but it's not we're not going to be drilling 50 or 60 wells a year there.
Our next question is from Betty Jiang with Credit Suisse. Please proceed with your question.
Thanks. I'm just wondering, given the increasing lateral length expected for the next 5 years, how are you handling the progression of that to make sure we don't see the issues that we saw in 2018? Would you would there just be no wells with lateral length in excess of 15,000?
Yes. Sorry, Betty. So in 2019, we'll have 20 wells that are 15,000 foot or greater. So that's about 1 rig's worth. In 2018, we did more than that.
So we were in the 25 range. So again, we're trying to get to only one rig at a time. The biggest problem in 2018 was we have so many of them going simultaneously.
I think that the focus will be making these wells more cheapest foot of pay is the last one that you drill. So being more methodical about how we move out the learning curve on the longer laterals, I think, is important. And I think that Erin and her team have got a good plan for doing it in a much more methodical way, but keeping the focus on capital efficient manufacturing mode of operations.
Got it. That's helpful. And then just a follow-up on the well cost of $9.34 per foot. What's the projection that's baked into the 5 year outlook? Are you assuming some sort of deflation on a dollar per foot basis?
Or is that staying flat if you're widening out spacing?
Yes, it's very modest decline in well costs, although that's offset by the fact that we're going to wider spacing and pumping bigger frac jobs. So there's more moving parts in that number than just a simple dollar per foot number, which again is why I would point you back to the dollar per Mcfe developed is a much better measure because that captures the EUR uplift as well as the frac cost increases when you go to wider spacing and larger fracs.
Okay. That concludes the end of our question and answer session. I would like to turn the call back over to management for closing remarks.
Okay. Thank you all very much. We do appreciate the time today. I would just like to reiterate that this really is a new company with a new management team and a new focus being capital efficiency. So it is a real change here in the last 2 months.
But we think that we have one of the really premier asset bases in North America, and we have a plan that is getting better. And I think it's a great plan to achieve free cash flow. And my last point is that we are back on track financially. We have gone to a manufacturing mode, running 6 rigs or 6 frac crews and 7 rigs and believe that the inefficiencies we saw in 'eighteen are a thing of the past. So we're excited about the future and think that we are one of the premier gas producers and that we're going to produce real shareholder value.
So thank you all very much for your time this morning.
Thank you. This concludes today's conference. You may disconnect your lines at this time and thank you for your participation.