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EQT Corp
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Greetings and welcome to EQT Corporation's Q2 Earnings Conference Call. [Operator Instructions]. As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Kyle Derham. Please go ahead, sir.
Good morning and thank you for joining today's conference call. With me today are John McCartney, Chairman of EQT; Toby Rice, President and Chief Executive Officer; Derek Rice, member of our Evolution Committee; Jimmi Sue Smith, Chief Financial Officer; Blue Jenkins, Executive Vice President, Commercial, Business Development and Safety; and Gary Gould, Chief Operating Officer.
The replay for today's call will be available for a 7-day period beginning this evening. The telephone number for the replay is 201-612-7415, with a confirmation code of 13685070. The replay will be available for seven days on our website. In a moment, John, Toby, Jimmi Sue and I will present our prepared remarks. Following these remarks, we will take your questions. EQT published a new investor presentation this morning, and we will refer to certain slides during our prepared remarks.
I'd like to remind you that today's call may contain forward-looking statements. Actual result and future events may differ possibly materially from those forward-looking statements due to a variety of factors, including those described in today's press release and under Risk Factors in our Form 10-K for the year ended December 31, 2018, as updated by our subsequent Form 10-Qs, which will also be on file with the SEC and available on our website. Today's call may also contain certain non-GAAP financial measures. Please refer to this morning's press release for important disclosures regarding such measures, including, reconciliations to the most comparable GAAP financial measures.
With that, I'd like to turn the call over to John.
Thank you, Kyle, and good morning, everyone. On behalf of the Board, I'd like to thank shareholders for entrusting us with the task of overseeing EQT's transformation into a world-class energy company. The shareholder vote was an overwhelming vote of confidence for the new direction of EQT. And I'm honored to serve as Chairman of what I believe is one of the most capable, diverse and dedicated set of directors in the energy space.
With more than 80% of the votes supporting the Rice team nominees, shareholders have clearly expressed their desire for EQT to become a leading edge, data-driven, transparent and socially responsible energy company. Toby's transformation plan offers significant value to shareholders, and the Board is united in supporting and providing accountability for its execution.
Beginning immediately following the shareholders' meeting, we've had several meetings and updates at the Board and committee levels to facilitate a smooth transition into a new era for EQT. In the near term, we will continue these efforts by collaborating with the Evolution Committee and designing a compensation plan that best aligns our stated goals of lowering well costs, improving capital efficiency, driving sustainable free cash flow per share and enhancing total shareholder return with an emphasis towards absolute return.
Finally, once we've made meaningful progress on the 100-Day Plan, we intend to engage with shareholders on a more proactive basis to enhance open communications, accountability and transparency at the Board level.
With that, I'll turn the call over to Toby Rice, the newly appointed President and CEO.
Thanks, John, and thanks to everyone for joining us today. I am humbled to have this opportunity to lead and transform EQT into a modern, digitally enabled E&P company that will create significant value for shareholders. Being the largest gas producer in the U.S. comes with an inherent responsibility to do what's best for our employees and contractors, our landowners, our shareholders and the environment, without compromise. I expect the turnaround that we are executing will lift the company to new heights as it relates to our overall corporate citizenship.
Before I continue, I would like to take a moment to recognize and thank our employees. EQT has undergone a lot of change in recent years, but I am impressed with our employees' enthusiasm and dedication to the company. Their openness to our new plan is encouraging and their participation will be one of the most important factors in our near and long-term success.
Getting back to my remarks. My team and I got to work immediately following the annual meeting and have made great progress in assessing the business. We've had some quick wins along the way, but I want to focus my remarks on sharing my vision for EQT. Let's first start with a snapshot of where EQT is today. EQT is the largest gas producer in the U.S., with 660,000 core acres in Southwestern PA and Northern West Virginia and 64,000 core acres in Southeastern Ohio. We believe EQT has the deepest inventory of economic locations in the basin and with the right leadership and approach, we can deliver superior shareholder returns in any commodity price environment. Unfortunately, EQT has not yet realized the potential of its asset base. Throughout the proxy contest, we communicated to our fellow shareholders that we believe EQT's legacy performance was the result of poor project planning due to underutilized technology and a disconnected organization. In our first 72 hours on the job, we were able to confirm our diagnosis was accurate. The employees are working tirelessly to improve current operations, but the organization has limited visibility on future development projects.
Planning in Appalachia is extremely difficult and perhaps more difficult than anywhere else in the lower 48. Our plan is specifically designed to leverage technology to connect the entire organization to improve development planning. A well-designed development schedule planned 36 months in the future is the key to consistent operational execution that will drive lower well costs and more free cash flow.
Before I talk to the details of our plan, let's look at an example that shows the importance of planning. Please turn to Slide 5 of the presentation we posted this morning.
What we are looking at here are two sets of pads developed by EQT in 2019. The pads on the left represent a poorly planned development run and on the right, a well-thought-out development run. The example gives us the opportunity to isolate the impacts of planning on efficiency and costs, since the same drilling team developed both projects in the same service cost environment. The development run on the left is clearly not an efficient set up. The new wells were squeezed onto pads with multiple existing producing wells. Our drilling team was forced to use complex well geometries to avoid wellbore collisions. The fractured rock down hole caused mud losses while drilling. And the poorly planned wellhead layouts required time-consuming rig maneuvers between wells. These factors led to inefficient and costly operations.
Adding the fact that these wells had an average lateral length of less than 8,000 feet, and the result was a drilling cost of $325 per foot, which is 80% higher than our targeted cost. Further, because these new wells were offsetting producing wells, approximately 30 million cubic feet of gas per day had to be shut-in for an extended period of time, which contributed to EQT's legacy curtailment issue. And finally, because of parent-child relationships, these newly drilled wells are expected to underperform our type curve by 10% to 15% once they are brought online. We just hit on many of EQT's legacy issues: elevated costs, curtailments of wells that underperform type curves, all explained by a poorly designed development project. So what happens when this team is given a properly designed developed development projects?
On the right side of the page, we're looking at 12 wells developed simultaneously from 2 adjacent pads. This development was initially designed by Rice Energy back in 2017 as part of what we call combo development. This project is currently being drilled by EQT today by the same team that executed the development run on the left.
Through the first 6 wells, EQT has drilled at a rate of 1,500 feet per day, a 50% improvement versus the previous pad. Drilling costs are trending to around $200 per foot, a 40% reduction in costs versus our prior example. I'll pause here to make this clear. When EQT's operational teams are given properly designed development projects, they are nearly at our targeted well cost goals, which for drilling are $190 per foot. With some additional leadership, improved engineering practices and the right pad layout, these cost goals are well within reach. Rounding out this development run, because we planned these wells so far in advance, curtailment issues are minimized and we expect all 12 wells to perform at or above type curve once turned online.
This example is focused on drilling, but we are seeing the same thing on completions. When our completion teams are given poor projects at the last minute, their efficiencies are half of what they are on properly planned projects. You may ask, "Why would EQT develop the pad on the left?" The answer is simple. EQT did not have a better location to send the rig and the teams were given orders and incentivized to hit production targets. Unfortunately, less than 50% of EQT's future schedule is currently setup for efficient development, as illustrated on the right. This is why we are here.
Our jobs as leaders of this organization is to align the workforce to march towards these large-scale development projects so our operational teams can execute. Our vision in path to well costs of $735 per foot ends when 80% of our development looks like what you see on the right. This is what we're simply calling the end state.
The end state is where all planning tasks are completed at least 12 months before spud, giving our execution teams the opportunity to succeed every time they step onto a pad to drill and complete a standardized well design with the lowest possible cost, on budget, on schedule and for maximum value. To give you a sense of how achievable this is, by the end of our time at Rice Energy, we had definitive and detailed development planning 3 to 5 years into the future.
Combo development represented more than 80% of our planned activity. That type of visibility becomes very powerful for decision-making, particularly around capital allocation. Planning further out in time also provides for better oilfield service contracts, lower well costs, greater leverage for commercial arrangements, ample freshwater pipe to the site for completion operations and sufficient midstream and downstream capacity for new production. This is how we get well costs to $735 per foot and hit type curve for each and every pad.
I realize this sounds simple, it is not. That said, it is our job as leaders of this company to take complicated tasks, such as master planning, and simplify them for our employees to execute. Our first step towards the end state was the creation of our Evolution Committee. This committee is comprised of EQT's Executive Team as well as Danny Rice, Derek Rice and Kyle Derham. The committee will serve as the primary liaison to the Board with respect to the execution of the 100-Day Plan. Under the oversight of the Evolution Committee, we are going to transform EQT to our planned end state in 3 key areas. First, we're going to restructure the organization to be function-based. Employees will have clear roles and priorities that facilitate efficient project planning and execution. Over the last 130 years, EQT's org structure has morphed into more than 50 departments that has led to a lack of accountability. We'll reorganize the business into 16 departments with roles that better match the life cycle of a well.
Second, we're going to bring new technology to this organization to foster the level of inter-departmental collaboration and real-time decision-making that the end state requires. The company currently operates in a very siloed manner. Data and workflows are trapped in e-mails and each department is acting on predetermined department goals, even when the goals of the organization may demand adjustments. The solution here is to implement a digital work environment that has been customized to run an Appalachian E&P business. This platform, which we used at Rice Energy with great success, will break down silos and bring transparencies to data and workflows to enable more value-driven decisions.
Third, we have high-graded leadership where needed to execute our vision. I'm happy to report that we have hired all 8 Evolution leaders mentioned during the campaign. On the operational side, we've added a VP of Operational Planning to oversee proper planning and coordination of future development; a VP of Asset Performance to oversee management of the optimal well design for each of our operating areas; a VP of Drilling and a VP of Completions to ensure well designs are consistently executed. On the technology side, we've added a Chief Information Officer and a VP of Digital Technology to oversee the buildout of our key digital solutions and change the way we work. On the organizational side, we've added a Chief Human Resources Officer to create a world-class culture and a Director of Evolution to ensure the transformation remains in compliance with established audit, governance and risk controls. These 8 leaders previously worked together in the same end state at Rice Energy and are currently marching on the 100-Day Plan we outlined.
And finally, we'll achieve the end state by properly aligning, valuing and supporting our people. EQT's employees are motivated and hard-working, but they have not been allowed to reach their full potential. In addition to the benefits of the operational, technological and organizational changes I discussed earlier, we are to challenge our employees with proper goals, recognize them in real-time and align them through incentives. This will allow them to see how they contribute to the company's mission: achieving the end state and making EQT a better business for all of its stakeholders. I'm committed to making EQT the best place to work in Pittsburgh, and these steps will get us there.
Stepping back, how long will it take before EQT is executing at well costs of $735 a foot? As we laid out in Slide 10, we expect a gradual improvement of well costs as best practices are implemented and efficient development -- inefficient development is removed from the schedule. Master planning takes time, but we expect our schedule to be predominantly combo development-run by mid-2020, which will lead to a step change in well costs to $735 per foot around that time.
With that, I'd like to turn the call over to Jimmi Sue to share our second quarter results.
Thanks, Toby, and good morning, everyone. This morning, EQT reported second quarter 2019 net income of $126 million or $0.49 per share and adjusted net income from continuing operations of $22 million or $0.09 per share, compared to $34 million or $0.13 per share in the second quarter of 2018. For the quarter, we achieved 370 Bcfe of sales volume, in line with expectations and at the high end of our guidance range of 355 to 375 Bcfe. Excluding sales volumes related to the 2018 divestitures, sales volumes of natural gas, oil and NGLs increased 8% over prior year.
Second quarter 2019 adjusted operating revenues were approximately $958 million, down 6% compared to the prior year as a result of weaker pricing, partly offset by the higher sales volumes. Average realized sales price for the quarter was $2.59 per Mcfe, $0.22 below the average price in the second quarter of 2018. The decrease in average realized price was primarily due to a decrease in higher-priced liquid sales and Btu uplift as a result of the 2018 divestitures and lower NYMEX net of cash settled derivative.
Total operating revenues for the quarter were approximately $1.3 billion, up roughly $360 million, as the second quarter of 2019 included $408 million of gains on derivatives not designated as hedges, compared to a $54 million loss last year. This reflects the increase in the fair market value of our NYMEX swap and options due to declines in forward prices during the quarter.
Now moving on to operating expenses. Second quarter operating expenses were down approximately 5% as $118 million impairment charge recorded in the second quarter of 2018 and lower production expenses in 2019 as a result of the 2018 divestitures more than offset increases in SG&A, proxy cost and lease impairments in the period. The increase in SG&A was a result of royalty and litigation reserves of $38 million recorded during the quarter. The lease impairments primarily relate to acreage exploration, mostly outside of our current development plan.
At the unit cost level, second quarter 2019 total cash unit costs were $0.02 higher than the second quarter of 2018. Of note, EQT's transmission costs per unit was $0.54 per Mcfe, which was $0.02 higher than the second quarter of 2018 and $0.03 above the high end of our guidance range. This increase was primarily due to higher unreleased Tennessee Gas Pipeline capacity. As a reminder, we have unused capacity on this pipeline in Northern Pennsylvania. We typically either release this capacity to others or, depending on market conditions, purchase gas to sell off the pipeline.
When released, the cost of this capacity is netted against the released revenue in net marketing services. When we move gas from the pipeline, our gas or third-party gas, the cost is reported in transmission expense. We have increased our guidance range for transmission costs for the year to reflect our current expectation for the use of this capacity in 2019.
As noted above, SG&A was impacted by royalty and litigation reserves this quarter. Adjusting for these items, SG&A was $0.13 per Mcfe, which is within our annual guidance range.
Now moving to cash flow items. Second quarter adjusted operating cash flow was $386 million, compared to $529 million in 2018. As noted in our press release, second quarter adjusted operating cash flow and adjusted free cash flow included the impact of approximately $38 million of royalty and litigation reserve and $22 million of proxy, transaction and reorganization-related expenses. Excluding these 2 items, operating cash flow would have been $445 million and adjusted free cash flow would have been a negative $21 million, which is slightly better than the favorable end of the range that we provided in June.
Our second quarter capital expenditures of $466 million were better than internal expectations for the quarter, primarily due to continued efficiency gain.
Looking forward, we are guiding to third quarter volume of 365 to 385 Bcfe at an average differential of negative $0.55 to negative $0.35, and we reiterate our full year capital expenditure guidance of $1.825 billion to $1.925 billion. From a timing perspective, we expect 3Q CapEx to be slightly higher than the fourth quarter.
With respect to free cash flow, we have updated our annual guidance for the strip price as of June 30. At these prices, we anticipate adjusted free cash flow of $25 million to $125 million for the year, with negative cash flow in the third quarter being offset by a positive cash flow in the fourth quarter.
Lastly, I will briefly discuss our cash flow and liquidity position. On May 31, EQT entered into a $1 billion term loan agreement and used the proceeds to repay $700 million in senior notes that matured on June 1 and to repay outstanding credit facility borrowing. We ended the quarter with no funds drawn on our $2.5 billion revolver and approximately $30 million in cash. This leaves our net debt at approximately $4.97 billion. At this level, our net debt to trailing 12-month adjusted EBITDA leverage is at 2.1x. When reduced for the value of our investment in Equitrans Midstream using quarter end pricing, it's 1.7x.
With that, I will pass the call to Kyle.
Thanks, Jimmi Sue. I've had a chance to get to know many of our investors over the last few months. I'm currently a member of the Evolution Committee. And I'm working alongside the team to execute certain finance, Corporate Development and Investor Relations initiatives as well as helping form our general capital and allocation strategy. To help set expectations, I would like to lay out our guidance plan for the next few months.
Jimmi Sue walked through some of the changes to 2019 guidance, but we are suspending our outlook in 2020 and beyond as we develop our revised plan. We expect to come back to The Street with longer-term guidance in the next 60 to 90 days, but I will spend a few minutes providing some directional color on where we expect things to shake out.
We will be taking a different approach to capital allocation to many of our peers. In today's commodity price environment, there's a high bar to allocate capital to the drill bit, especially given the opportunity to improve our leverage profile and buy back stock at 10-year lows. We believe EQT trades at a significant discount to its intrinsic value, and while we recognize many E&Ps share this strip today, net asset value will always be an anchor for us to make the right capital allocation decisions. Fortunately for shareholders, EQT also has the potential to generate substantial near-term free cash flow per share even at current strip pricing, and that will be our focus going forward.
As Toby mentioned in his comments, EQT's legacy capital and efficiency was a function of poor development planning. Our near-term strategy will be to remove high-cost development from the schedule and focus our land, permitting and planning teams to transform that development into a combo development run that we can drill in 12 to 24 months.
This disciplined approach to development has several benefits. First, the capital efficiency of our program improves because we are only deploying development dollars when we know we can execute highly economic projects. Second, we generate more near-term free cash flow that can be used to repay debt and buy back stock. Third, we put less near-term supply on a soft gas market. And lastly, we give our midstream service provider a chance to catch its breath and provide water and gathering services at the lowest cost possible, greatly improving their capital efficiency and free cash flow.
The ultimate level of our development capital spend will be determined by the number of economic projects we have to drill measured against the opportunity to buy back shares and achieve our leverage targets. Production growth, if any, will be an output of that decision, not a target. We will be driven by growing free cash flow per share, which we believe is the key to driving shareholder value.
In making these near-term decisions, we have maximum flexibility as all of EQT's rig contracts roll off by the end of the year and we have minimal long-term commitments to other services. We will use that flexibility to design the most efficient program possible with services procured in the soft service cost environment.
Stepping back. Over the last 3 months, the forward gas strip has weakened, bringing significant pressure to the balance sheet to both public and private gas-levered E&Ps. There are approximately 75 rigs running in Appalachia today and 50 in the Haynesville. We believe the vast majority of these rigs are subeconomic at strip pricing. The equity in gas markets are sending a clear message to operators to cut growth to maintenance levels and someone need to go further than that.
While we have started to see a pullback in activity, more is needed to balance the market. We believe the marginal cost of supply is well above strip and the market will work itself out over the long term. That said, all of our efforts are geared towards transforming EQT into the lowest-cost operator in the basin to weather what could be a challenging 2020 and position the business for long-term success when prices normalize.
Turning to the balance sheet. In general, our policy will be to target forward leverage of less than 2x net debt-to-EBITDA at the lower of strip gas prices or $2.50. Free cash flow and any potential divestiture proceeds will be used to achieve this leverage profile and any additional cash flow will largely be returned to shareholders via stock buybacks. We are committed to the investment-grade rating and believe access to low-cost financing will be a strategic advantage over the next several years. We believe this policy will allow us to maintain investment-grade metrics. And we look forward to engaging with the agencies over the coming months after we have finalized our long-term development plan.
One lever we can pull to manage debt is our retained interest in Equitrans, which is worth approximately $900 million as of today. While we are evaluating a divestiture, it is not part of our immediate plans. Any potential exit will be done responsibly, and we have several options at our disposal. For now, we are benefiting from the 10% dividend yield and see several positive catalysts for Equitrans as we transform EQT.
First, while there may be a reduction in our volume forecasts in the near to medium term, we expect that our ability to hand Equitrans a fully baked schedule that plans combo development 12 to 36 months in advance will greatly reduce their capital needs and boost free cash flow. We saw this happen in 2017 at Rice Midstream Partners following Rice Energy's upstream transformation, and we expect it to happen for Equitrans as early as 2020.
Second, we are working together to simplify our services contracts. While we all recognize the gathering fees are on the high end of the market, our strategy allows for other levers to be pulled that will be a win-win for both parties, including increasing utilization of freshwater systems and the construction of produced water disposal systems. These opportunities should lower our overall cost mix, while providing incremental revenue sources for Equitrans. We have already engaged with Equitrans management, and both sides are thrilled to start working together to develop this world-class resource and deliver gas to market at the lowest cost possible.
Regarding asset sales, we're in the process of reviewing all of EQT's assets and remain open to divesting acreage or production as it fits within our capital allocation framework of maximizing free cash flow per share and NAV. To summarize, we are taking a differentiated approach to capital allocation. We are in the process of rationalizing EQT's development schedule and we will come back to The Street with a revised long-term outlook that reflects the potential of this world-class asset while also respecting the current commodity price environment.
With that, I'd like to open up the call for Q&A. Operator?
[Operator Instructions]. Our first question today is from Holly Stewart of Scotia, Howard and Weil.
Maybe just first to John, a few of the midstream things. And Kyle, I think you hit on certainly a couple of them. Seems to be some sentiment out there in the marketplace today around your commitment to MVPs. I was just hoping maybe you could sort of clear the waters a little bit there.
Holly, this is Blue. I'll take that one. So a couple of things on MVP. One, we're confident that it will get built and we are utilizing the most recent -- most likely scenario used by E-Train, which is mid-2020. In terms of the conversation of can we walk away, would we get out, there isn't a reasonable scenario in which we would walk away from that project without a massive [indiscernible] and so that's just not how we look at it. That's just not a reasonable outcome.
Okay. That's it. That was what we thought, but just wanted to clear that out. Kyle, you mentioned thoughts around the E-Train shares. Maybe you could just provide a little bit of color. I know there's some timing issues with that equity being public and the files that have to be -- forms that have to be filed if you decided to divest that for a year. So can you just maybe provide a little bit of color on that process?
Yes. No. We're really focused on the business for now. I think, clearly, that's a divestiture candidate for us over the longer term, but it's not part of the immediate plan. We're not going to guide to any timing expectations around when that might happen.
Okay. That's great. And then maybe just one last one for me. It looked like Moody's recently moved you down to -- your outlook down from stable to negative. Can we just talk? There seems to be several maturities coming up in the next few years. Toby, just wanted to kind of get your thoughts on how those maturities are addressed and sort of general outlook on the leverage profile.
Sure. Yes. This is Kyle. I'll take that one. Yes. The leverage targets, again, going to be below 2x. And when we say that, we include our gas price assumption for that which to us is the lower of strip in $2.50, and I think that positions us very well from an investment-grade rating metrics perspective. In terms of the maturities, certainly, they're on our radar. It's not something we're ignoring right now, but want to sort of improve the cost structure of the business before assessing that, but it's certainly on our radar.
The next question is from Brian Singer of Goldman Sachs.
In your opening remarks, you mentioned that you see the benefits of your plan maximized when you're planning 36 months in the future, I think you said when you complete the planning 12 months ahead of spud. In Slide 10, your expectation seems that you will see the greatest step change in value creation over the course of the second half of 2020. Can you just add more color for what drives that step change in 2020 and then how lower commodity prices and lower activity could, if at all, impact the scale you're trying to achieve?
So Brian, this is Toby. To -- when looking at our $735 per foot cost target, I think it's important to understand there's really 4 main drivers behind us achieving that level. The first being operational efficiency that we're able to achieve in the field, how fast can we drill, how many stages per day can we complete. I feel very confident after looking at the teams that we're going be able to achieve the operational efficiencies needed to hit that $735 a foot. The second thing we look at is the procurement and the oilfield. So we have flexibility with our oilfield service contracts in place right now. So we have -- we feel pretty good about our ability to acquire the right services at the right costs to achieve our cost targets. The third is -- comes to well design, and we are deploying our proven well design. We feel really confident in the cost to execute and the type curve that we will receive. And then the fourth thing we look at is our schedule. And this is really where we're going to be doing a lot of the heavy lifting and is to get a schedule that allows for combo development, starting with multiple wells per pad, meeting a minimum horizontal well length. And that's really where the focus is going to be. I'd say the benefits that you're going to get when you get the combo development are going to be largely driven on the logistics front and also on bulk materials procurement.
Yes. And just to jump in, Brian. I think, with respect to timing, the biggest impediment to setting up combo development right is on the land and permitting side, and so that's where we'll be focusing our resources. And those realistically take about 12 months to set up, and so that's why you see that step change in well cost on that graphic on Slide 10. And so once those are set up and they start hitting the schedule, you'll really see the benefits and start to see $735 a foot.
Got it. And do the benefits change if you're running at a lower activity level in response to the lower commodity prices or you think the same per foot assets can be achieved kind of regardless of activity?
Yes. We think we're going to be operating at a level of activity that allows us to achieve economies of scale necessary to reach the $735 a foot.
Great. And then just one follow-up on the midstream discussion. Earlier, you highlighted within existing contracts some opportunities that could potentially come up where you can restructure and add new business. Can you just give us just a little bit more of a sense of what that could mean, either from a cost perspective or free cash flow perspective?
Yes. Sure. This is Kyle. I don't want to give any specific guidance with respect to rate reductions or anything like that. But the new business for Equitrans that could be is expanding the utilization of the freshwater systems. They're actually largely built by Rice Midstream Partners a few years ago. And then, obviously, the water disposal options, getting trucks off the road, allowing Equitrans to build a system to move water, those are the incremental revenue sources that we think would offset any potential rate reduction on the midstream gathering side.
The next question is from Arun Jayaram of JPMorgan.
The Rice team had identified call it $500 million of free cash flow uplift relative to EQT's prior plan when implemented. I was wondering if you could maybe help us walk through the $500 million that you previously cited between the DMC cost savings and other initiatives. Just trying to better understand how you get to that number.
Yes. Sure. So the $500 million we talked about in the campaign was a couple of things that were driving us getting to $500 million. First, being assumed activity level, and that activity level would assume that we were growing at 5%. And the second being the cost difference between executing well costs at $1,100 a foot or compared to a $735 per foot target. So some things have changed, obviously. We are setting expectations and coming up with an amount of activity that is based on economic projects to develop. So what we're really focused on and want to be comparing ourselves against going forward in the future is going to be how close we are to our $735 per foot cost target because that's irrespective of activity levels.
Fair enough. And just a follow-up, you guys expressed a strong commitment to the MVP pipeline. But just better kind of understand is -- if the project is delayed, call it, passed mid next year, is there any recourse for EQT in terms of the tolling agreements or the fees on that to -- just given that the project is beyond its original time line?
Yes. So this is Blue, Arun. So the short answer is, no. What we have is a contract that caps our rate based on time and based on cost, and that's where we sit. So if it happens to slide, let's say, it's Q4 instead of Q2, so it wouldn't change anything. We have plans in place to manage if that should be the case and are prepared for that. But know that the contract is fairly set at this point and we still expect, as I mentioned, that it will be completed and we don't have any financial incentive to walk away from that.
The next question is from David Deckelbaum of Cowen and Company.
It's David from Cowen. Just -- and congrats coming back into the public fold, guys. I just want to ask just -- you commented earlier, I think -- I know that the 2020 vision and beyond is suspended for the time being. You said, I think, about half of the development programs moving forward right now are not set up optimally. I note like in Slide 5 where you highlighted a sort of ideal or end game pad versus something that was recently drilled. That wasn't necessarily just not [indiscernible] was also shorter laterals or perhaps a project that wouldn't be drilled. I guess what percentage of projects that exist right now would you just not drill that are on the current schedule?
Yes. David, this is Derek. So we're currently going through the schedule and assessing good projects versus bad projects. And obviously, the bad projects we would like to pull those from the schedule. I don't think it makes sense drilling $1,100 per foot type well at this gas price environment. So before pulling those off of the schedule, we're running those through the traps. Whenever you make any change to the schedule, there is a ripple effect, where do you send that rig if it's not going to the proposed site. And so I think, over the next, call it, 30 to 60 days, we'll have a better assessment of what exactly we can pull off the schedule. An ideal situation, we pull those poor development projects off the schedule, replace them with correct projects that are planned appropriately, whether or not we can do that again, that's just going to be part of the assessment. So from within the first few weeks, we've identified some inefficiencies in the program, and now we're just going to evaluate whether or not we can pull those through.
Yes. And I would just make one point. I mean we've identified these projects and these are projects that can be improved and our job is to align the workforce, focus our resources to make these projects more economic, lengthen laterals, add wells per pad, see if we can make -- turn them into combos. So we're not just taking stuff off the schedule. We are focusing resources to make them end state-like.
Sure. I mean, but given that, can you effect those changes by the first half of next year in that drilling program or is this more a second half of '20 program and you might just be willing to kind of eat lesser economics in the beginning of next year?
Yes. I think we're going to have a better understanding on timing if we get a little bit more time here. I mean it's been 10 days. I think we've done a good job in identifying some of the issues, and now it's -- what's our confidence in being able to align the schedule to meet our minimum development criteria, and that's something we'll report back to you guys when we have better clarity on that in the future.
I appreciate that. I think, Kyle, I think you remarked that the most difficult impediment to the future plan is sort of around land and permitting in that it can kind of take 12 months to set that up. I guess what else needs to be done on the midstream side just in terms of facilities to be able to turn in that many wells in these locations? I know you talked about the waters opportunity that's out there. I guess, logistically, what needs to happen on the midstream side so you can execute this plan?
Yes. This is Toby. There's a couple of things outside of land and permitting, yes, the long lead time items, as you identified, is gather and take away and having access to freshwater and have that be piped to locations. So I mean we're going through an analysis right now understanding the gathering systems and the capacity forecasts, combined with our schedule to make sure that everything is synced up so we don't have -- we can minimize any curtailment issues. And the same thing, with a good schedule, we understand when we're going to be fracking. We could pair that up with water needs and make sure that the midstream team can service our water needs when we need to complete. So this is the type of work. In addition to this, there's another 40 constraints that we are maneuvering into optimum schedule. And this is the work that we're doing and where we'll be looking forward to updating people when we have a more complete picture of what the development schedule will look like in the future.
The next question is from Michael Hall of Heikkinen Energy Advisors.
Welcome back to the public fold. Yes, I just -- I guess I wanted to talk through a couple of the slides. On Slide 5, I was just thinking as you walked through that, obviously, there's some risk maybe that the legacy activity will have kind of cannibalized the opportunity to move forward in a more -- in that kind of properly planned development case. Kind of how confident are you in the kind of ability to move forward with that properly planned case and fully achieve that end state goal? How much more work do you think remains to be done in terms of understanding the potential impacts of legacy development on the ability to optimize things going forward?
This is Toby, real quick, and then I'll pass it over to Derek. I would say the thing that we're excited about is the fact that we have such a large inventory of undeveloped leasehold. If you look at where we're going to be focusing our development in Southern Greene, there's not a lot of producing wells we have to dance around so our inventory is pretty virgin. And so -- but it does take work to get that leasehold ready to develop, and that's we're going to be focusing our teams. Any other color you want to add on that, Derek?
Yes. I mean just one thing. I mean just look at the asset base and this is what gets us comfortable saying we're going to get there is because the issues that we're seeing with EQT today, to be frank, this is what we dealt with at Rice Energy in 2014 and 2015 when we had the same vision. It's -- we know what end state we like to get to, what are the steps needed to get there. It's essentially the same asset base, primarily in Greene County and Washington County. A lot of the sites that we plan to develop going forward are Rice Energy sites, so we have a clear picture of what we need to do to get there and I think we've done it before and we think we can get there again.
All right. Excellent. And then, I mean -- sorry, go ahead. Share more.
No, that was it.
Okay. Yes. In that context, I guess, I can't help but look at West Virginia and think that there's quite a bit of potential for optimizing that land position and potentially helping build out that inventory into something more ready for optimal development. What's the kind of gameplan on that, time lines and thought process as to when that will kind of compete internally, if you will?
Yes. This is Toby. Yes, so we are working to develop West Virginia and make that drill-ready. And we have the resources, so we're prepared -- we're going to start preparing that right now. The gameplan is we've got a couple of years while we're focusing our development in Greene and Washington counties to get West Virginia ready. Obviously, it's a little bit more challenging in West Virginia just because terrain is a little bit more difficult, makes site selection a little bit harder and putting together a continuously sole position is something that's important and with the fracture lease position in West Virginia makes it a little bit more challenging. But I will say that the EQT team does have some trades currently going on, so we are focused on building contiguously sole position that will support combo development.
Okay. Excellent. And last on my mind is just if you had any sort of estimate yet for what you would think about as a kind of a breakeven gas price in the context of driving corporate level free cash flow going forward.
Yes. No. Let us get back to you and fix you in 90 days. And we'll be able to better run some sensitivity so you can kind of see free cash flow at different price stacks.
The next question is from Josh Silverstein of Wolfe Research.
Just following up on some of the questions before. There definitely seems to be a much bigger emphasis on free cash flow generation and -- over growth. Are you guys willing to go to maintenance mode or even decline as you're implementing the strategy into next year?
Yes, Josh. This is Toby. I mean I would say that the driver of activity levels is going to be the setup on economic projects that we have to develop. So I mean that's really where it all starts when you think about, I mean, just bringing this business back to fundamentals and making investments in good projects. And the production growth targets or the production targets that we set are going to be the outcome of fundamentally sound investment decisions on the drill bit.
Got you. I guess, once implemented, assuming we're in a 2.50 environment, can EQT be sub-2x levered, grow 5% and generate a significant amount of free cash flow?
At 2.50? Yes, I mean, Josh, I think it's realistic. But again, at 2.50 , it's not really where we're going to be growing production volumes into that type of environment, so that's not really the scenario we're talking about. But we'll get back to you after we spent some time with the development schedule to really forecast this out and give you the granularity you need.
Got you. Okay. I mean as the biggest gas producer out there, certainly setting tone around 2.50 would help there. And then just to understand, you talked about this massive penalty potentially for getting out of the MVP pipeline. Can you put some context around that? Is it $100 million? Is it $500 million? Like what is massive in terms of getting out of MVP?
Yes. This is Blue. The short answer is we're not going to walk on the project. I think that's probably the short answer.
Our next question is from Jeffrey Campbell of Tuohy Brothers.
My first question was back -- going back to Slide 5, but just looking at something else there. It says that greater than 80% of the remaining inventory can look like the good pad that you illustrated. I was just wondering, is it reasonable to assume that some of that other less than 20% could either be sold or impaired?
Yes. This is Derek. So the majority of that sort of poorly planned development that remains, it's largely within EQT's producing well footprint, so very similar to what you're seeing on the left there. Not exactly something that anybody wants to buy. The way that we look at it is that's stuff that we'd like to develop in the year 2030-plus. So as much as we can push that back, the better.
Yes. I mean the development is not set up for economic development today. But I mean gas prices change, that's where that stuff can make economic sense. But we're going to be disciplined to develop that when it does make sense.
Okay. And I guess that could also be a decision between -- I mean, because you can also sell producing reserves, but then if you sell them, then it might raise your corporate decline rate, so there might be a reason you want to keep them just to -- as part of a good base decline. I mean is that reasonable as well?
Yes. That's correct.
Okay. And I was wondering -- I thought this is really interesting in your earlier remarks. I was wondering how much time do you think is going to be required to digitize EQT along the lines of the former Rice Energy because it sounds like it's not just a software shift, but it's actually a different way of working that's enhanced by technology.
Yes. I think we think about a digital transformation is sort of what we're going through. I mean it's not just bringing technology to an organization. It's bringing a cultural change as well. You think about what we're going to be doing here with technology, it's going to bring massive transparency to the business. People need to be comfortable with that type of transparency. And what's exciting about that is once we have that transparency, then we're going to start having the opportunity to start collaborating more. And when people start collaborating, then we're going to start having some more ideas and innovation is going to start bubbling up. And if we can focus that innovation on the things that matter, the bottlenecks and the opportunities within our business, then we can start generating value for shareholders, and that's evolution. And so it all starts with technology, but it's really going to change the culture here at EQT and we're excited about that opportunity going forward.
Okay. And last question was just kind of structural, I guess, is you mentioned that the Evolution Committee is the main liaison to the Board of Directors. I was wondering how does the Evolution Committee interface with operational leaders to facilitate the changes that you've enumerated?
Sure. So it's a transparent plan that we're executing. Part of our -- when we talked about transforming EQT into a modern company, what modern means to us is coming up with a good strategy and leveraging technology to execute. So the strategy in this case is our 100-Day Plan. And the technology that we're implementing is in our digital work environment, and that will be available for all the employees to see the tasks that we're doing to take us one step, to take us closer to an evolved state. We have -- the EQT executives are on this Evolution Committee. We have a feedback channel set up for employees to speak up and tell us what do they want to change, what do they want to keep the same. And these employees are speaking up, we've got over 400 responses to this survey. So we are currently assessing the feedback and implementing that into our task list that we're doing. So it's -- everybody here is going to be engaged.
The next question is from Jane Trotsenko of Stifel.
I have a question regarding DUCs and how they fit into the current or, let's say, future development plan. I see that there are over 200 DUCs in Marcellus and I'm just curious how do they compete versus, let's say, drilling new wells using this combo development.
Jane, this is Toby. So I say -- I think the way that we wrote that is just the way that we've categorized the 209 is wells that have been drilled in some form or fashion. I think 92 of those are actually drilled to total depth, so that was -- would be what we would call a true DUC.
Okay. So the other way of saying is that you guys plan to compete the existing 96 DUCs, right? And I would say that we should expect 10% lower EUR just because they have been done using the old approach, right?
No. It wouldn't say that we would change the production that we said we're going to receive from these wells. We've reaffirmed our production guidance for this year.
Okay. Okay. And then the remaining over 100 DUCs, those are just kind of top hole, I guess?
Yes. That's correct.
Okay. Got it. And then I have a question for Jimmi Sue regarding these term loan agreement. If you guys can kind of explain the logic for entering into this agreement for $1 billion.
In the term loan agreement? So [indiscernible] clear that the proceeds from the ETRN state will be used to reduce our leverage, but that we were going to be disciplined about when we did that sale. We had a $700 million maturity coming up on our revolver. And the term loan was available at rates lower than our -- I'm sorry, the $700 million maturity was long-term borrowings we could have put it on the revolver, but the term loan was available and the interest rates on the term loan are lower than those on our current revolver.
Okay. Got it. The last question, if I could. Regarding the production mix going forward. Is it going to remain roughly the same in terms of Southwest Pennsylvania, Ohio and West Virginia completions?
Yes. This is Kyle. I think it will be similar for the rest of the year, as we've outlined. I think it's possible as we get through this review that we have a little more activity focused in Washington and Greene County in Pennsylvania and a little less in West Virginia as we're putting that land position together to set it up for combo development. So it's possible, in 2020 and maybe 2021, you'll see a little more in Pennsylvania than West Virginia than in 2019.
The next question is from Drew Venker of Morgan Stanley.
Just wanted to follow up on a question earlier about CapEx. I think you had said -- Jimmy Sue you had said that 3Q CapEx you expect to be a bit higher than 2Q, but did I also hear you right in saying that you'd likely be settling down D&C spending in the near term?
No. I think we've reaffirmed our CapEx guidance for the year. I think what I said was if you take what we spent year-to-date, you look at the midpoint of the guidance and if you want to try to get the case of that third quarter, fourth quarter, third quarter will be higher than the fourth quarter.
Okay. And I guess just one for Toby is on the land spending, as you guys are spending more time there and on permitting. Do you think the lower land spending rate per year is still a realistic goal from the $200 million a year or so that EQT had been running at?
Yes. So I mean I think the way we look at land, we've got a large asset base, and one of the things that we're going to bring to this organization is focus. And that operation schedule that we put out is going to allow our land teams to focus their resources on preparing for that operation schedule. So this is part of the -- understanding what our -- the land spend that we need is going to be something that we're focusing our assessment on right now and have better color for you in the future when we get through that assessment.
One on the midstream contracts as well. Do you expect to start negotiations to then extend this, I think, particularly gathering contracts? It sounds like you guys already had some conversations with the folks at Huron [ph].
Yes. No. We're just continuing the discussions that had started earlier this year. And so, yes, we're excited about working with them and excited about handing them a fully baked development schedule to make their lives easier. So we'll keep the group updated on how things go.
Okay. One last one. Can you just tell us a bit about the Happiness campaign?
Yes. The whole point here is we're -- we want to do two things. We want to create great results for shareholders and we want to create a great working environment for our employees, and I believe that those two things go together. And part of us being -- creating a great work environment for our employees is having a happy workforce. And we believe the keys behind driving happy employees is creating employees that are increasing their -- that are productive, employees that are challenged, recognized and have fun at work. Fortunately, our plan, everything that we talked about, focusing and aligning our employees on the things that matter, that fits largely into making our employees more productive. Challenging, I think we're asking employees to hit some goals that I think would be optimistic from where they're at today. But as we've shown, they have the capability of doing it, so we're going to be challenging the employees. And then the digital work environment, the transparency that's going to bring is also going to bring -- allow us as leaders and managers of this business to recognize the performance of the employees. And then the last part, having fun at work, really what we're going to be focusing on there in winning, and winning is setting goals and hitting goals and that's going to be the fun that we have is by doing those things. So that's that in a nutshell.
The next question is from Welles Fitzpatrick of SunTrust.
Thanks for all the detail and getting cost down via efficiencies in midstream. But can you talk a little bit more to how much wood there is to chop on the drilling and completion contracts? And is it fair to assume that those legacy contracts generally roll off in 2020?
Yes. This is Toby. So the drilling contracts, the horizontal rigs are rolling off by the end of this year. The frackers we have are currently rolling month-to-month with our frac suppliers. So we're looking to continue relationships we have and also making sure that we're acquiring services at the cost that we need to hit our targets. We are -- after seeing that, we're -- one of the things I was pleased to see is that we have the flexibility and don't see procurement as an impediment to us reaching our $735 cost per foot goal.
Okay. Perfect. And then just one follow-up. On the G&A side, I guess it's fair to assume that it will be a little bit choppy through year-end as you bring in new people and whatnot. Do you expect that to stabilize pretty early in 2020 or even later this year?
Yes. We are continuing to go through our assessments of the departments right now, but we know what we're looking for and we would expect that to be through that through '19, for sure.
Perfect. That's all I have. Congrats on getting back at it.
Thanks.
The next question is from Sameer Panjwani of Tudor, Pickering, Holt.
First off, on CapEx. Wanted to see if it's possible to realize some of the savings in 2019 as you try to high grade the program or are we just too far along for that to be meaningful at this point?
Yes. So this is Derek. So I mean, I'll be honest. In the first 2 weeks, our primary focus has been to stabilize the business. We've largely been in listen-only mode. I will say there have been a couple things we've come across that we felt as though we need to change in the near term. One thing on the completion design front, when we walked in the door, there were 30 different completion designs. We looked at all the data with the teams and we came to a conclusion that reducing that to one design, one proven design, was efficient. What that allows us to do is not only predict the performance of our wells going forward, but it also gives our completions team the ability to procure the appropriate amount of materials on a go-forward basis. On the drilling front, we briefly looked at their drilling parameters. We noticed there were some self-imposed limitations, a little bit technical, I won't go into it. We lifted those limitations and saw immediate gains in drilling performance. To put some color on that, the previous single-day 24-hour rate in the second quarter was 6,600 feet in a 24-hour period. And just last week, this drilling team surpassed 7,800 feet in a 24-hour period. So again, largely in listen-only mode the first 2 weeks, but we think that as we get more hands-on going forward, we will start seeing more efficiency gains and continued operational improvement.
Okay. Okay. That's good to hear. And then next, there was a question earlier about the potential to kind of move to a maintenance program next year. I know you guys haven't decided on anything yet, but would it be too early to ask you what a maintenance budget would look like next year, kind of given that transition period where you're still going to be realizing some of the savings? And how you expect a maintenance budget to look longer term once you're fully at that $735 per foot?
Yes. No. Sorry to punt, but we're going have to get back to you on that after we go through our assessment.
Yes. Yes. No worries. And then, I guess, last question. You talked a little bit about potential non-core asset sales. Wanted to see if you had any interest in following one of your peers who just monetized some NRI. I think historically, EQT has had a fairly high NRI, so just what are your thoughts on potentially taking advantage of the valuation spread between those assets and the equity today?
Yes. This is Kyle. That's really not something we're evaluating currently.
The next question is from Betty Jiang of Crédit Suisse.
Can you talk about the levers you have to reduce leverage -- leveraging the near term to get to sub-2x. If E-Train stake is not in the immediate plan, are non-core asset sales being prioritized as tools to delever? Maybe just to get some color on what you guys consider to be non-core.
Yes. No, I mean like we said, everything is sort of on the table. Obviously, it's selling for just PDP PV-10 is a top way to delever. And there are a ton of buyers who want to buy non-core assets for more than that. So asset sales are difficult way to delever. I think what we're looking at is delevering organically, and we'd do that by lowering well costs and rationalizing the development plan, so that's kind of our path forward to 2x or less.
Got it. And just to clarify, what's your view on balancing between debt reduction and share buyback? Is the goal to get to 2x leverage first before you do buyback?
Yes. That's correct, Betty.
Got it. Okay. And last thing, with the potentially lower volumes on less activity, do you see reduced production constraint, that was last estimate at roughly 10% of the current production?
Yes. That could be a result, right? We know the prior team characterized about 10% of production base as curtailed. After assessing that, that's not really the way we're going to talk about it going forward. But, yes, any potential curtailments would be alleviated by a reduced capital spend and less production volumes.
That concludes the question-and-answer period. I'll turn the call back over to Toby Rice for closing remarks.
Thanks, everyone, for joining us. We appreciate your support in this campaign. And we are looking forward to continuing the work we've laid out and excited about sharing our progress with you in the future. Thank you.
This concludes today's conference. You may now disconnect your lines. Thank you for your participation.