Greetings, and welcome to EQT's Corporation's Q2 Earnings Conference Call. 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, Kyle Durham.
Please go ahead, sir.
Good morning. Thank you for joining today's conference call. With me today are John McCartney, Chairman of EQT Debbie Rice, President and Chief Executive Officer Derek Rice, Member of our Evolution Committee Jimmy 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 136, 85,070.
The replay will be available for 7 days on our website. In a moment, John, Toby, Jimmy 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 results 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 ks 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 at 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 vote 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. Covey'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, your newly appointed President and CEO.
Thanks, John, and thanks to everyone for joining us today. I'm humbled to have this opportunity to lead and transform EQT into a modern digitally enabled E and P company that will create significant value for shareholders. Leading 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 believed 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 consistent operational execution that will drive lower well costs and more free cash flow. Before I talk through 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 2 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 impact of planning on efficiency and costs. Since the same drilling team develops both projects in the same service cost environment, the development run on the left is clearly not an efficient setup. 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. Add in the fact that these wells had an average lateral length of less than 8,000 feet and the result was a drilling cost of $3.25 per foot, which is 80% higher than our targeted costs. Further, because these new wells were offsetting producing wells, approximately 30,000,000 cubic feet of gas per day had to be shut in 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 and wells that underperform type curves, all explained by a poorly designed development project. So what happens when this team is given a properly designed development project? 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 six wells, EQT has drilled at a rate of 1500 feet per day, a 50% improvement versus the previous pad. Drilling costs are trending to around $200 per foot, a 40% reduction in cost 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 plan 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 set up 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 and path to well costs of $7.35 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 for 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 fresh water pipe to the site for completion operations, and sufficient mid stream and downstream capacity for new production. This is how we get well cost to $7.35 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 Durham. 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. 1st, 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. 2nd, 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 emails 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 and P business. This platform, which we used at Rice Energy with great success, will break down silos and bring transparency to data and workflows to enable more value driven decisions. 3rd, 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 build out 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 hardworking, 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 $7.35 a foot?
As we've laid out in Slide 10, we expect a gradual improvement in 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 runs by mid-twenty 20, which will lead to a step change in well costs to $7.35 per foot around that time. With that, I'd like to turn the call over to Jimmy Sue to share our 2nd quarter results.
Thanks, Toby, and good morning, everyone. This morning EQT reported Q2 2019 net income of $126,000,000 or $0.49 per share and adjusted net income from continuing operations of $22,000,000 or $0.09 per share compared to $34,000,000 or $0.13 per share in the Q2 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 Bcfe to 375 Bcfe. Excluding sales volumes related to the 2018 divestitures, sales volumes of natural gas, oil and NGLs increased 8% over prior year. 2nd quarter 2019 adjusted operating revenues were approximately $958,000,000 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 dollars 0.22 below the average price in the Q2 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 derivatives. Total operating revenues for the quarter were approximately $1,300,000,000 up roughly $360,000,000 as the Q2 2019 included $408,000,000 of gains on derivatives not designated as hedges compared to a $54,000,000 loss last year. This reflects the increase in the fair market value of our NYMEX swaps and options due to declines in forward prices during the quarter. Now moving on to operating expenses.
2nd quarter operating expenses were down approximately 5% as $118,000,000 impairment charge recorded in the Q2 of 2018 and lower production expenses in 2019 as a result of the 2018 divestitures more than offset increases in SG and A, proxy costs and lease impairments in the period. The increase in SG and A was a result of royalty and litigation reserves of $38,000,000 recorded during the quarter. The lease impairments primarily relate to acreage expirations, mostly outside of our current development plan. At the unit cost level, Q2 2019 total cash unit costs were $0.02 higher than the Q2 of 2018. Of note, EQT's transmission cost per unit was $0.54 per Mcfe, which was $0.02 higher than the Q2 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 leased revenue in net marketing services. When we move gas on the pipeline, our gas or 3rd 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 and A was impacted by royalty and litigation reserves this quarter. Adjusting for these items, SG and A was $0.13 per Mcfe, which is within our annual guidance range. Now moving to cash flow items. 2nd quarter adjusted operating cash flow was $386,000,000 compared to $529,000,000 in 20 18.
As noted in our press release, 2nd quarter adjusted operating cash flow and adjusted free cash flow include the impact of approximately $38,000,000 of royalty and litigation reserves and $22,000,000 of proxy, transaction and reorganization related expenses. Excluding these two items, operating cash flow would have been $445,000,000 and adjusted free cash flow would have been a negative 21,000,000 dollars which is slightly better than the favorable end of the range that we provided in June. Our 2nd quarter capital expenditures of 4 $66,000,000 were better than internal expectations for the quarter, primarily due to continued efficiency gains. Looking forward, we are guiding to 3rd quarter volumes of 3.65 Bcfe to 3.85 Bcfe at an average differential of negative $0.55 to negative $0.35 and we reiterate our full year capital expenditure guidance of $1,825,000,000 to 1,925,000,000 From a timing perspective, we expect 3Q CapEx to be slightly higher than 4th 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 $25,000,000 to $125,000,000 for the year, with negative cash flow in the 3rd quarter being offset by positive cash flow in the 4th quarter. Lastly, I will briefly discuss our cash flow and liquidity position. On May 31, EQT entered into a $1,000,000,000 term loan agreement and used the proceeds to repay $700,000,000 in senior notes that matured on June 1 and to repay outstanding credit facility borrowings. We ended the quarter with no funds drawn on our $2,500,000,000 revolver and approximately $30,000,000 in cash. This leaves our net debt at approximately $4,970,000,000 At this level, our net debt to trailing 12 month adjusted EBITDA leverage is at 2.1 times.
When reduced for the value of our investment in Equitrans Midstream using quarter end pricing is 1.7 times. With that, I will pass the call to Kyle.
Thanks, Jimmy 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 allocation strategy. To help set expectations, I would like to lay out our guidance plan for the next few months. Jimmy Sue walked through some of the changes to 2019 guidance, but we are suspending our outlook in 2020 beyond as we develop a 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 than 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 buyback stock at 10 year lows. We believe EQT trades at a significant discount to its intrinsic value. And while we recognize many E and Ps share this trade 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 inefficiency 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 themes 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.
2nd, we generate more near term free cash flow that can be used to repay debt and buy back stock. 3rd, 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 a soft service cost environment. Stepping back, over the last 3 months, the forward gas strip has weakened, bringing significant pressure to the balance sheets of both public and private gas levered E and Ps. There are approximately 75 rigs running in Appalachia today and 50 in the Haynesville.
We believe the vast majority of these rigs are sub economic at strip pricing. The equity and gas markets are sending a clear message to operators to cut growth to maintenance levels and some will 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 $900,000,000 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 forecast 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.
2nd, we are working together to simplify our services contracts. While we all recognize the gathering fees are on the high end of 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 DQT's assets and remain open to divesting acreage or production if 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 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 and A. Operator?
Thank you. At this time, we'll be conducting a question and answer session. Our first question today is from Holly Stewart of Scotia Howard and Weil. Please go ahead.
Good morning, gentlemen. Jimmy Sue, maybe just first touch on a few of the midstream things and 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 MVP. So 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. 1, 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-twenty 20. 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 penalty.
And so that's just not how we look at it.
That's just not a reasonable outcome.
Okay. That was what we thought, but just wanted to clear that up. 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 divest to that before a year.
So just maybe provide a little bit of color on that process?
Yes. No, it's 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 plans. 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. So Tobey, 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 target is 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 and $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 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. Please go ahead.
Thank you. Good morning. In your opening remarks, you mentioned you see the benefits of your plan maximized when you're planning 36 months in the future. And 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 twenty twenty.
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?
Sure. Brian, this is Toby. When looking at our $7.35 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 efficiencies that we're able to achieve in the field, how fast can we drill, how many stages per day can we complete. Feel very confident after looking at the teams that we're going to 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 we have some 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 cost 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 4th 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 you're going to get when you get to combo development are going to be largely driven on the logistics front and also on bulk materials procurement.
Yes. And just to jump in, Ryan, 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 $7.35 a foot.
Got it. And did 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 benefits 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 the economies of scale necessary to reach the 7 35 a foot.
Great. Thanks. And then just one follow-up on the midstream discussion. Earlier you highlighted within the 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. Don't want to give any specific guidance with respect to rates reductions or anything like that. But the new business for Equitrans that could be 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 Maroon Jerome of JPMorgan. Please go ahead.
Yes, good morning. Toby, Kyle, the Rice team had identified, call it, dollars 500,000,000 dollars of free cash flow uplift relative to EQT's prior plan when implemented. I was wondering if you can maybe help us walk through the $500,000,000 that you previously cited between the D and C cost savings and other initiatives. Just trying to better understand how you get to that number.
Yes, sure. So the $500,000,000 we talked about in the campaign, there was a couple of things that were driving us getting to $500,000,000 First being an 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 $1100 a foot or compared to our 7.30 $5 per foot target. So some things have changed. Obviously, we are resetting 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 $7.35 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 at trying to understand is if the project is delayed, call it past 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 Blu, 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 should that be the case and are prepared for that. But no, 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 Decabaugh of Cowen and Company. Please go ahead.
Thanks guys. It's David from Cowen. Just and congrats coming back in the public fold guys. I did 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 know 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 sign ups, it was also shorter laterals or perhaps the 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 Darrin. 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 $1100 per foot type wells 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 up the schedule. In 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 1st 2 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 and focus our resources to make these projects more economic, lengthen the 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 affect those changes by the first half of next year in that drilling program? Or is this more a second half of twenty twenty 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 and that can kind of take 12 months to set that up. I guess what else needs to be done on the midstream side and 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, I would say this is Toby. There's a couple of things outside of land and permitting. The other long lead time items as you identified is gathering takeaway and having access to fresh water 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 an optimum schedule. And this is the work that we're doing, and 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.
All right, fair enough. Thank you, guys. Best of luck.
Thanks.
The next question is from Michael Hall of Heineken Energy Advisors. Please go ahead.
Good morning and 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 walk through that, obviously there's some risk maybe that the legacy activity will cannibalize the opportunity to move forward in a more in that kind of properly planned development case. How confident are you in the kind of ability to move forward with that properly planned case and fully achieve that end stake goal? How much more work 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 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 Green, 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 to get that leasehold ready to develop and that's where 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 looking 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 2015 when we had the same vision. It's we know what end state we'd 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.
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 we've done it before and we think we can get there again.
All right. Makes sense. And then, I mean, sorry, go ahead. Is there 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 game plan on that timelines 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 game plan is we've got a couple of years, while we're focusing our development in Green 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 contiguous leasehold position is something that's important. And with the fractured lease position in West Virginia makes 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 a contiguous leasehold position that will support combo development.
Okay. Makes sense. And last one on my end is just if you had any sort of estimate yet for what you would think about as a kind of breakeven gas price in the context of driving corporate level free cash flow going forward?
Yes. No, let me let us get back to you in 60 to 90 days, and we'll be able to better run some sensitivity so you can kind of see free cash flow at different price decks.
All right. Thanks very much guys. Welcome back.
Thanks.
The next question is from Josh Silverstein of Wolfe Research. Please go ahead.
Yes, thanks. Good morning, guys. Just following up on some of the questions before. There definitely seems to be a much bigger emphasis on free cash flow generation and overgrowth. 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. I mean, when you think about it, 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 said are going to be the outcome of fundamentally sound investment decisions on the drill bit.
Got you. I mean, can I guess once implemented, assuming we're in a $250,000,000 environment, can EQT be sub 2x levered, grow 5% and generate a significant amount of free cash flow?
At $250,000,000 Yes, I mean, Josh, I think it's realistic. But again, at $250,000,000 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 $250,000,000 would help there. And then just to understand, you talked about this massive penalty potentially for getting out of the MVP pipeline. You put some context around that?
Is it $100,000,000 Is it $500,000,000 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 from the project. I think that's probably the short answer.
Fair
enough.
The next question is from Jeffrey Campbell of Tuohy Brothers. Please go ahead.
Good morning.
My first question was 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. It's not exactly something that anybody wants to buy. The way that we look at it is that stuff that we'd like to develop in the year 2,030 plus.
So as much as we can push that back, the better.
Yes, I mean, and
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 it could also be a decision between, I mean, because you can always sell producing reserves, but then if you sell them, then it might raise your corporate decline rate. So there might be a reason why keep them just 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 the 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 when you think about a digital transformation 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 this is kind of structural, I guess. You mentioned that the Evolution Committee is the main liaison to the Board of Directors. I was just 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 we talk about transforming EQT into a modern company. What modern means to us is coming up with a good strategy and leveraging technology to execute. 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 everybody here is going to be engaged.
The next question is from Jane Trotsensko of Stifel. Please go ahead.
Good morning. I have a question regarding DUCs and how they fit into the current, 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?
Yes. Jane, this is Toby. So 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 of 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 complete 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, I 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. And then the remaining over 100 DUCs, those are just kind of top haul, I guess?
Yes. That's correct.
Okay, got it. And then I have a question for Jimmy Sue regarding this term loan agreement. If you guys can kind of explain the logic for entering into this agreement for 1,000,000,000
dollars And the term loan agreement? Yes. So we've been pretty clear that the proceeds from the ETRN stake would be used to reduce our leverage, but that we were going to be disciplined about when we did that sale. We had a $700,000,000 maturity coming up on our revolver and the term loan was available at rates lower than our I'm sorry, the $700 maturity was long term bonds. 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'll be similar for the rest of the year. As we've outlined, I think it's possible as we go 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 see a little more in Pennsylvania than West Virginia than in 2019.
The next question is from Drew Venker of Morgan Stanley. Please go ahead.
Hi, guys. I just wanted to follow-up on a question earlier about CapEx. I think you had said I'm sure 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 slowing down D and C spending in the near term?
No, I think we well, 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 cadence of that Q3, Q4, Q3 will be higher than the Q4.
Okay.
And I guess 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 at least per year is still a realistic goal from the $200,000,000 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.
Thanks for that, Tobey. One on the midstream contracts as well. Do you expect to start negotiations to amend extend this, I think in particular gathering contracts? It sounds like you guys already had some conversations with the folks at EQM.
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, thanks. One last one, could you just tell us a bit about the happiness campaign?
Yes.
The whole point here is we want to do 2 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 that are productive, employees that are challenged, recognized and have fun at work.
Fortunately, our plan, everything that we talk 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 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 is 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.
I like the idea. Thanks, Jeremy.
The next question is from Welles Fitzpatrick of SunTrust. Please go ahead.
Hey, good morning. Thanks for all the detail on getting costs 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 frac crews 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 $7.35 cost per foot goal.
Okay, perfect. And then just one follow-up. On the G and A side, I guess it's fair to assume it'll be a little bit choppy through year end as you're bringing in new people and whatnot. Do you expect that to stabilize pretty early in 2020 or even later this year?
Yes. We would we're planning to continue 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 2019 for sure.
Perfect. That's all I have. Congrats on getting back at it. Thanks.
The next question is from Sameer Tadhwani of Tudor, Pickering and Holt. Please go ahead.
Hey guys, good morning. First off on CapEx, wanted to see if it's possible to realize some of 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 1st 2 weeks, our primary focus has been to stabilize the business. We've largely been in listen only mode. I will say there has been a couple of things we've come across that we felt as though we needed 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 look at all the data with the teams and we came to 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 Q2 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 for the 1st 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 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 $7.35 per foot?
Yes. No, let us sorry to punt, but we're going to 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.
Okay, thanks.
The next question is from Betty Jiang of Credit Suisse. Please go ahead.
Good morning. Can you talk about the levers you have to reduce leverage in the near term to get to sub two times? If e trend stake is not in the immediate plan, are non core asset sales being prioritized as tools to delever? Maybe just 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, selling for just PDP, PV-ten is a tough way to deliver. And there aren't 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 do that by lowering well cost and rationalizing the development plan. So that's kind of our path towards 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 constraints that was last estimated at roughly 10% of the current production?
That could be a result, right? We know the prior team characterized about 10% of the production base is 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.