EQT Corp (EQT) 2019 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the EQT Corporation Q3 2019 Quarterly Results Conference Call.

(Operator Instructions)

I would now like to hand the conference over to your speaker today, Andrew Breese, Director of Investor Relations.

Thank you.

Please go ahead, sir.

Good morning, and thank you for joining today's conference call.

With me today are Toby Rice, President and Chief Executive Officer; Kyle Derham, Interim Chief Financial Officer; and Blue Jenkins, Executive Vice President and Chief Commercial Officer.

The replay for today's call will be available on our website for a 7-day period beginning this evening.

The telephone number for the replay is 1 (800) 585-8367 with a confirmation code of 6678269.

In a moment, Toby and Kyle will present our prepared remarks.

Following these remarks, we'll take your questions.

EQT published a new investor presentation this morning, which is available on the Investor Relation portion of the website, 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 could materially differ from these forward-looking statements because of factors described in today's earnings release and the Risk Factors section of our Form 10-K for the year ended December 31, 2018, our subsequent Forms 10-Q and other filings we make from time to time with the SEC.

We do not undertake any duty to update any forward-looking statement.

Today's call may also contain certain non-GAAP financial measures.

Please refer to this morning's earnings release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures.

With that, I'll turn the call over to Toby.

Good morning, and thank you for joining us.

I'm excited to share the progress we've made in a short period of time and what we believe we can accomplish moving forward.

I'll provide an update on the 100-Day Plan and our preliminary 2020 outlook.

I will also provide a brief update on our negotiation with Equitrans to amend our gathering agreements before turning the call over to Kyle to discuss third quarter results, our initiatives to improve leverage and liquidity and some quick thoughts on the gas macro.

As a reminder, the goal for 100-Day Plan was to kick-start our evolution and deliver the foundational elements needed for us to achieve the cost-saving targets that we discussed in our campaign.

October 18 marked day 100, and I'm pleased to share with you that we have successfully executed on our plan.

Slide 6 of our presentation lays out some of the key milestones we achieved, starting with the organization.

Following the annual meeting in July, we quickly added key leaders needed to complement the existing EQT team.

These leaders have a proven track record of operating EQT's assets to generate basin-leading operational performance, and they're off to a great start.

Over a dozen new leaders are offering fresh perspectives and best practices towards achieving our goals.

In September, we simplified our organizational structure, migrating from 58 to 15 departments and concurrently streamlined the workforce by reducing headcount by approximately 25%.

These changes enabled greater communication, accountability and have led to a much more nimble, proactive organization.

We expect to save approximately $65 million of gross general and administrative costs in 2020 consisting of $35 million reduction in SG&A expense and a $30 million reduction in capitalized overhead.

As it relates to our technological initiatives, we have made significant progress.

The workforce has fully embraced our digital work environment with participation in our platform increasing 700% since the annual meeting.

Silos are being knocked down and interdepartmental collaboration and transparency are accelerating.

We prioritized the 90 most critical workflows needed for our modern, technology-driven business and have successfully revived them within our digital work environment.

These workflows empower our employees, allow management to monitor the business, spotlight inefficiencies and optimize our planning efforts to maximize shareholder value.

We are currently working through the remaining 300 workflows and expect to have those turned online in the coming months.

Lastly, as it relates to our operational initiatives.

We've successfully laid the tracks for large-scale combo development by establishing a stable master operations schedule.

As a reminder, combo development consists of properly spaced, large-scale projects to develop 10 to 25 wells for multiple pads simultaneously.

This is the key to delivering consistently low well costs while maximizing the potential of our undeveloped acreage position.

In 2020, we expect roughly 50% of our wells turned in line and 80% of wells spud to be set for combo development.

We've also had some quick wins in the field.

On Slide 7, we are highlighting the step-change in drilling efficiency in the third quarter.

Marcellus drilling speeds are up 50% relative to the second quarter, and Utica drilling speeds have increased 20%.

This is the result of an experienced team offering fresh perspectives and leveraging technology in the field.

Additionally, all of our wells are being completed using the proven well design and choke management program that led to basin-leading well productivity at Rice Energy.

As a result, we expect EQT's base decline rate to decrease from 32% to 24% as measured by the decline of our expected PDP base from December 2019 to December 2020.

This decrease in base decline will result in less future capital required to achieve certain volume targets.

To summarize, the 100-Day Plan has been a massive success in kick-starting our evolution.

We are on track to deliver on the well cost savings we promised during the campaign, and we are doing it faster than we thought, which sets EQT up for success in 2020 and beyond.

The formal 2020 budget will be approved by the Board in December but we are excited to share our preliminary outlook.

Our capital allocation philosophy has not changed.

We plan to delever EQT to below 2x net debt to adjusted EBITDA.

And in this gas price environment, we plan to get there by reducing absolute debt through free cash flow generation and asset monetizations rather than outspending cash flow to grow EBITDA.

Further, as we discussed on the 2Q call, we evaluated EQT's existing development plan and removed inefficient development and replaced it with large-scale combo development projects to ensure all capital allocated to the drill bit generates attractive cash-on-cash returns.

This philosophy of maximizing capital efficiency while generating free cash flow was the primary driver of our 2020 budget.

We plan to spend between $1.3 billion to $1.4 billion of CapEx to execute a disciplined development program that will result in sales volumes roughly flat to expected 2019 levels.

At strip pricing as of 9/30 or at an average 2020 NYMEX price of $2.42, we expect to generate $1.65 billion to $1.75 billion of adjusted EBITDA and $200 million to $300 million of adjusted free cash flow in 2020.

Turning to Slide 10, our CapEx budget is broken down into 4 main areas.

At the midpoint of guidance, we plan to spend just over $1 billion of reserve development capital, $150 million of land, $85 million of other CapEx and $55 million of capitalized overhead.

We further break down our reserve development budget by our 3 operating areas: Pennsylvania Marcellus, West Virginia Marcellus and Ohio Utica.

We plan to operate 2 to 3 top-hole rigs, 3 to 4 horizontal rigs and 3 to 4 frac crews.

Approximately 65% of our capital will be deployed to Pennsylvania, 19% to Ohio and the remaining 16% to West Virginia.

It's worth noting these horizontal rig counts are half the number of rigs EQT used in 2019 largely due to efficiency gains realized during the implementation of our 100-Day Plan.

In our Marcellus operations, we expect full year 2020 well cost to be approximately $745 per foot in PA and $900 per foot in West Virginia, and we expect over 90% of our 2020 wells spud will be at 1,000-foot spacing.

On Slide 11, you'll see a breakdown of our development plan by operating area.

I'd like to call out the increasing lateral lengths in all 3 operating areas, which will contribute to lower well cost per foot.

I'd like to highlight West Virginia in particular.

EQT's average lateral length for wells turned in line in 2019 is 4,600 feet but is expected to increase to 8,900 feet in 2020 and jump to 12,500 feet in 2021.

This is driving West Virginia well costs down faster and lower than we originally expected.

As we look at our long-term master operations schedule, West Virginia will become a much larger focus area in the coming years.

Our $150 million land budget consists of approximately $100 million allocated to leasehold maintenance and $50 million allocated to infill leasing in units on EQT's near-term development schedule.

This is approximately $50 million or 25% lower than the 2019 land budget.

Our other CapEx budget of $85 million consists of $55 million of asset maintenance and $30 million of capitalized interest.

The asset maintenance bucket represents spend related to site compliance, well tubing installations, road repairs and other general maintenance projects.

This CapEx is generally unrelated to current development and is, therefore, not shown in our reserve development category and is excluded from our well cost calculations on a dollar per foot basis.

Lastly, we have budgeted approximately $55 million of capitalized overhead, which is $30 million or 35% lower than 2019.

These costs consist primarily of employees and overhead that can be allocated directly to our development projects.

Slide 12 puts our budget into context.

We believe we are on track for a 25% decrease across a large portion of EQT's controllable costs as compared to legacy 2019 costs.

On the left, we are showing Pennsylvania well costs per foot.

Well costs are expected to decline to $745 per foot on average for 2020 and will trend down lower over the course of the year with second half 2020 well costs expected to be $730 per foot.

This represents a 25% decrease from the legacy management team's well cost estimates.

3Q well costs stand at approximately $850 per foot, which shows good progress.

4Q well costs aren't expected to show much improvement as we work through some of the inefficiencies of the prior schedule.

However, this is all baked into our 2019 CapEx guidance.

In the middle, we are showing gross G&A, which is SG&A expense plus capitalized overhead.

This is expected to be down $65 million from 2019 or 25%.

On the right, we are showing land and other CapEx, which we expect to be down $70 million from 2019 or another 25% reduction.

All told, execution of this maintenance development program under our new cost regime is generating an incremental $400 million of savings per year.

To the extent EQT resumes production growth in the future, these savings would grow accordingly.

Turning to Slide 14.

This is purely illustrative but highlights what we expect 2021 and 2022 CapEx would be if we wanted to maintain 2020 production volumes.

We expect CapEx would decrease to approximately $1.15 billion in '21 and drop to $925 million in '22, a 30% decrease from 2020 spending levels.

Ultimately, our long-term activity levels and free cash flow profile will be dictated based on gas prices but will also be influenced by the outcome of our negotiations with Equitrans, our primary midstream service provider, to lower our gathering and transportation costs.

Achieving meaningful fee relief is the next step in lowering EQT's cost structure.

EQT's goal in this negotiation is straightforward: simplify the structure and reduce gathering fees to enable EQT the ability to grow volumes through Equitrans' systems and generate free cash flow in a lower gas price environment.

Over the last couple of weeks, we have made good progress with the Equitrans team towards a solution that we believe would be a win-win for both parties.

In exchange for gathering fee relief, the timing of fee relief will likely be tied to the in-service date of Mountain Valley Pipeline, a project that, including other related projects, is expected to add over $300 million of EBITDA for Equitrans upon going in service.

Second, EQT can offer an extension of the contract term and a substantial increase in the minimum volume commitments to provide long-term cash flow certainty for Equitrans shareholders.

Lastly, EQT can dedicate the remainder of its undedicated West Virginia acreage position to Equitrans.

As we have highlighted before, West Virginia will become a larger part of EQT's story going forward.

Our recent success in extending laterals, executing acreage swaps and lowering well costs show this area is competing for capital.

I'm encouraged by the progress we have made, and both sides are working diligently to have an agreement in place in the next few months.

With that, I'll turn it over to Kyle.

Thanks, Toby.

I'll briefly touch on a couple of notable items in the third quarter, provide updates on our 2019 guidance, discuss our initiatives to improve leverage and liquidity and then touch on the gas macro.

In the third quarter, we achieved net sales volumes of 381 Bcfe at the high end of our guidance range.

Our third quarter CapEx was $475 million, which is $380 million or 44% lower compared to the third quarter of 2018.

This is also $25 million favorable compared to our expectations coming into the quarter, which is primarily the result of better field execution.

Adjusted operating cash flow and adjusted free cash flow for the quarter were negatively impacted by 2 items worth noting that could not be adjusted out of the metrics.

First, we recorded proxy-, transaction- and reorganization-related expenses of $77 million during the quarter.

This was primarily driven by the organizational streamlining in September that reduced our workforce by 25% as well as changes to the executive leadership team.

Second, we recorded an increase in royalty and litigation reserves of $37 million.

We feel that our improvements in operational planning and partnering with landowners will translate to lower litigation spend in the future.

Excluding these 2 items, adjusted operating cash flow and adjusted free cash flow would have been approximately $115 million higher for the quarter and well above consensus estimates.

Turning to fourth quarter 2019 guidance.

We expect net sales volumes of 355 to 375 Bcfe, a 4% decline from the third quarter at the midpoint.

This is driven by changes to the operations schedule and implementation of our choke management program.

Average differentials are expected to be negative $0.45 to negative $0.25 per Mcfe.

We expect CapEx to be $320 million to $370 million, which will drive adjusted free cash flow of $100 million to $150 million.

For full year 2019 guidance, we are lowering CapEx by $115 million at the midpoint while reiterating our full year production guidance.

We expect adjusted free cash flow to be $10 million to $60 million, which, again, includes the impact of proxy, transaction and reorganization-related expenses and an increase to our royalty and litigation reserves, which is further described in our earnings release.

Turning to leverage and liquidity.

As of 9/30, EQT's net debt to LTM adjusted EBITDA was 2.2x, and assuming a sale of EQT's retained stake in Equitrans is used to repay debt, that ratio would decrease to 1.9x.

While EQT is expected to generate between $200 million and $300 million of adjusted free cash flow in 2020.

Leverage is expected to increase from current levels at strip pricing.

This is largely due to lower commodity prices but also due to our commitment to not grow production until gas prices show improvement or until we see gathering fee relief.

As Toby mentioned, in the current commodity price environment, we are focused on absolute debt reduction to manage leverage rather than outspending cash flow to increase EBITDA.

We have 87% of our 2020 gas production hedged at a weighted average floor price of $2.71 which will provide downside protection if gas prices slip further.

We remain committed to maintaining our investment-grade ratings and believe it's a strategic differentiator amongst our peers.

This is not merely lip service.

We think the best way to increase the stock price is by delevering the business to thrive in a $2.50 gas price environment.

To achieve this, we are committed to reducing absolute debt by at least $1.5 billion or 30% by mid-2020.

On Slide 16, we outline the levers we can pull.

First, EQT's retained stake in Equitrans represents $750 million of value at current market prices.

We have multiple options for divesting this stake to go beyond a simple block trade on the open market.

We are not long-term holders and will likely divest this stake in the next 9 months.

Second, we have a number of assets that are outside of our core Marcellus fairway that represent up to $300 million of EBITDA and up to 600 million cubic feet of gas per day of net production that could bring in over $1 billion of proceeds.

We are actively marketing certain of these assets today and are in discussions with multiple parties.

Lastly, we are evaluating various structures to potentially monetize EQT's core mineral interest.

Today, EQT owns 50,000 fee acres in our core footprint that contribute to an average 8/8 net interest revenue in our Pennsylvania acreage of 83% and in our West Virginia acreage of approximately 85%.

As our peers have shown, these monetizations of these types of assets can be highly deleveraging.

Given EQT's relatively higher net revenue interest, larger production base and the undeveloped acreage position, we are confident this strategy could generate significant proceeds that can be used to delever without a significant impact on development returns.

We are actively exploring this opportunity and believe a transaction could be effectuated in a matter of months.

Delevering is a strategic priority for EQT.

We believe execution of this debt reduction plan is achievable in the near term and will allow EQT to maintain investment-grade metrics.

While we believe the rating agencies will give us time to execute this plan, to the extent we are downgraded, we have laid out the impacts to liquidity on Slide 17.

To cut to the chase, we have a plan in place and do not believe the impact of a downgrade would materially change our current liquidity position.

Focusing on the chart on the right, EQT has a $2.5 billion unsecured revolver in place, which will stay unsecured through at least the maturity of the credit agreement in July of 2022.

Unlike most of our peers, the facility size is not subject to semiannual borrowing base redeterminations and would not be in a downgrade scenario.

Assuming the rating agencies downgraded EQT one notch, certain counterparties would have the option to call up to approximately $850 million of letters of credit that primarily relate to EQT's midstream commitments.

We believe we can add $1 billion of liquidity back to the system.

First, the revolver has a $500 million accordion feature built into the credit agreement.

Exercising the accordion does require bank approval but our discussions with lenders give us confidence in our ability to execute on this.

Next, we believe we can add $400 million of liquidity by entering into asset management agreements with certain gas marketers.

We are currently in advanced discussions with various counterparties to utilize these agreements to transfer some of the posting requirements in exchange for a small fee.

Many of our peers utilize these arrangements to manage liquidity today.

EQT is also exploring entering into new bilateral letter of credit arrangements with banks that specifically want the letter of credit exposure, which we believe could free up $100 million of liquidity on the revolver.

These 3 initiatives would more than offset the $850 million of potential posting requirements, assuming they are called.

EQT has an additional $750 million of potential posting requirements to Equitrans and MVP.

Ultimately, we do not believe these will be called for a variety of reasons, but we have shown the impact of liquidity as a further downside scenario.

To be clear, we recognize EQT has upcoming bond maturities, but we have multiple options to both retire and term out the debt even in a downside rating scenario.

We have market access today, we have set up a development plan to generate free cash flow and we are highly focused on executing our debt reduction plan by midyear 2020, which will only serve to enhance our leverage and liquidity per well to improve terms on potential future bond issuances.

A quick note on the gas macro.

We have been encouraged by the decrease in rig count over the last few months.

Appalachia rigs have declined from 80 rigs at the beginning of the year to 52 today.

We believe the basin needs around 50 rigs to hold production flat, but at current strip prices, we see the basin outspending cash flow to do that.

Given recent commentary from most Appalachia producers regarding capital discipline, we would anticipate rigs falling below maintenance levels in the coming months.

Permian rig count has dropped by approximately 75 rigs year-to-date, 55 of which were in the Delaware Basin, which is the largest contributor to associated gas growth.

Ultimately, Permian gas is constrained by takeaway capacity.

Kinder Morgan's recently announced delay to the in-service date of its Permian Highway Pipeline demonstrates the execution risk of these projects.

Further, we believe the Permian slowdown to potentially jeopardize producer commitments to future natural gas expansion projects, which may keep associated gas growth in check.

We expect these rig count reductions to begin showing up in supply in the back half of 2020 and could lead to exit-to-exit production declines.

This supply setup, combined with the expected LNG demand growth, could provide a substantial uplift to 2021 gas prices.

As management, we view that as an upside case and will continue to focus on lowering costs further to allow EQT to thrive in a lower gas price environment.

With that, I'll turn it back to Toby for some closing remarks.

I'd like to summarize the key points from today's call.

The 100-Day Plan has positioned EQT for long-term success.

We believe we will reduce EQT's controllable costs by 25% in 2020, which will drive $400 million of annual cost savings, assuming a maintenance development program.

This is allowing EQT to generate $200 million to $300 million of 2020 adjusted free cash flow at strip prices.

With the operating model in place, we are now focused on negotiating our gathering fees lower and believe this will firmly position EQT as the lowest-cost gas operator with the deepest inventory of Tier 1 locations in not just the Appalachia Basin but the entire U.S.

We remain committed to investment-grade ratings and are focused on executing on our debt reduction plan by mid-2020 to maintain investment-grade metrics.

With that, I'll turn it over to the operator for Q&A.

(Operator Instructions) Your first question comes from the line of Arun Jayaram from JPMorgan.

Kyle, I wanted to start with you.

Looking at your unit cost guidance for 2020, it does highlight about an $0.08 per Mcfe increase despite the fact that MVP, I think you're now anticipating that to be on in 2021.

Can you go through some of the moving pieces there?

And secondly, just maybe characterize your confidence in terms of the negotiations with E-Train to receive a successful win-win kind of outcome this quarter.

This is Toby.

I'll take that.

So just walking through our unit costs, gathering is going to be up $0.05.

This is largely coming from underutilized MVCs that we have.

So when we look at our gross production, while we do have our MVCs covered across all systems, there are certain areas that are under the MVC volume threshold.

So we're working on some creative solutions to reduce the underutilized MVCs.

But this is something that can be solved with the renegotiation with Equitrans.

On the transport side of things, this is up a little bit, but that's due to new contracts coming online.

When we look at -- our LOE cost is coming up a couple of cents.

This is due to a little bit of a slowdown in completion activity.

So our saltwater disposal costs are going up a little bit.

We think that the key is to getting this back in line to 2019 levels, can be helped with more efficient scheduling on the produced water side of things.

Also, our choke management program is going to lead to less wear and tear on our production facilities, so that would decrease some of the part repairs that make up our LOE costs.

And then on top of all this, basis differentials are expected to be $0.05 lower than our 2019, and this offsets some of these increases going forward.

To your second point on our E-Train, our confidence in renegotiating our gathering rates with E-Train for a win-win solution.

I think the things that give me confidence is we have a lot to offer.

I think we can increase the amount of quality revenues that E-Train receives, and that's through increasing our MVCs commitment, we can increase that substantially.

And then also, we've got a lot of undedicated leasehold in West Virginia that is going to be competing for our capital going forward.

So I think with those couple of things, it could make a great setup for a great deal with E-Train.

Great.

And my second question, gents, have you been in contact yet with the rating agencies regarding the $1.5 billion asset monetization program that you unveiled this morning?

And just wanted to know if you could maybe highlight priorities between looking at a mineral sale versus upstream assets that you highlighted on Slide 16.

Yes.

Sure.

We have not spoken with the agencies about the specific debt reduction plan.

Obviously, we've been speaking to them leading up to earnings.

And obviously, Equitrans -- our retained stake in Equitrans has always been a divestiture candidate, and the intended use of proceeds there has always been for debt reduction.

But we're going to be speaking with them next week to walk them through this plan, our commitment to it and to do it in the near term, right?

We're targeting executing this by mid-year of 2020.

Your second question with respect to priority on looking at Slide 16 of all the options that we have, we're evaluating all of these.

I think they're all actionable and all actionable in the near term.

So I wouldn't give any preference to one or the other, but they're all being evaluated today.

Your next question comes from the line of Brian Singer from Goldman Sachs.

Wanted to follow up on Slide 16 with the detail that you provided on the potential divestiture candidates.

A couple of questions.

First, how, if at all, is the time line and need to renegotiate the Equitrans contracts related to the time line to consider the divestiture of your stake?

And in your free cash flow of $200 million to $300 million for the company overall, does that include the distributions from Equitrans?

Maybe I'll start there, and then I've got one other on Slide 16.

Sure.

I'll start with the last question first.

Yes, our adjusted free cash flow guidance in 2020 includes a $90 million dividend from Equitrans, so that's included there.

And then the first part of your question, remind me what that was.

Yes.

The timeline -- is the time line the same in terms of renegotiating Equitrans' contracts and then also considering the divestiture of your stake?

And is there any one that you would want to come before the other or maybe the other way around?

Do you see your ownership of Equitrans as helpful in terms of your ability to get that renegotiation completed?

Sure.

I think we're looking at -- we're approaching this E-Train renegotiation as something that's going to be positive for both companies.

So we'll continue to hold the E-Train stake as we get through these negotiations.

Great.

And then separately, you talked about -- in your -- in Slide 11, the production trajectory by quarter.

Flattish in the second half of next year and up relative to the second quarter.

You mentioned on your call -- or on -- in your prepared comments that you kind of make a decision, and I might be paraphrasing here, whether or not you want to grow and what the right rate of growth is.

Can you just talk about what would go into that as you think about the right activity levels?

And is -- are you essentially set up for flat production at the end of 2020?

Yes.

So what we've laid out for 2020 gives us optionality for potential growth in '21.

We've got enough CapEx budgeted in '20 to either stay flat in '21 or grow, depending on a number of items that Toby laid out earlier, how things go with Equitrans in the renegotiation, gas prices and then just as our longer-term development plan comes together.

Is there a further reduction in costs that you would want to see to say, at the current commodity strip, growth makes sense for 2021?

Or if commodity prices don't change, what in aggregate would you need to see to say is -- it's worth stepping up on the activity levels?

Yes.

So this is Toby.

I would say that the cost reductions that we're looking for in the future are going to be coming more on the unit cost side of things.

So seeing a reduction in gathering fee relief is -- I mean, the goal of this deal for us is to achieve meaningful fee relief that allows us to grow in a $2.50 gas price environment and generate free cash flow.

So that's what we're looking to try and achieve with this renegotiation and that would change our approach going forward.

Your next question comes from the line of Josh Silverstein from Wolfe Research.

You outlined the $200 million to $300 million of free cash flow this year.

I think it was just highlighted before that some of that is from the E-Train distributions.

How sustainable is that view given the reduction in maintenance level spending going into 2021?

Once you divest E-Train, you don't have the cash tax benefits and some of the hedge benefits roll off.

Is that a good number for 2021 as well?

Yes.

We certainly haven't guided to '21 free cash flow, but expect that the -- if we lose Equitrans' dividends and the tax benefits, that'll be made up by lower CapEx expenditures given we'll have a full year of well cost reductions baked in.

And then, obviously, we're hopeful on the Equitrans gathering fee renegotiation will add some cash flow as well, if we're successful there.

Got it.

And then I was also curious if there were any noncash flow producing assets that might be divestiture candidates as well.

Obviously, some of your peers are going down the same path as well of divesting cash flow and it hasn't necessarily been rewarded in the stock price yet.

So I just wanted to see if there were any other assets out there?

Not really that someone would pay something meaningful for.

I think the mineral interest side of things, there's an implicit -- you get credit for some undeveloped value in how some of those deals are structured.

And so yes, that would be one example where we'd be able to generate some proceeds from noncash flowing assets.

Okay.

And I know you haven't fully disclosed this program yet with the rating agencies, but in your view, is the $1.5 billion debt reduction more important than leverage ratio going down?

I'm just trying to get a sense as to what might be more important.

Is like -- is it absolute debt because if -- because you're going to be losing EBITDA if you go and divest some of these assets.

Yes.

That's right.

Both are important.

But when we look at the numbers, executing this debt reduction program in addition to the free cash flow generation, net-net, is going to lower our leverage profile and we'll be able to maintain investment-grade metrics.

It also has the added benefit of bringing in proceeds, which help us manage our maturities.

Your next question comes from the line of Michael Hall from Heikkinen Energy.

I was curious if you could discuss a little bit more on the progress you've made in the West Virginia well cost side of things.

Kind of what the key drivers of those improvements have been?

And then kind of, like, how material is that in helping West Virginia compete for capital?

And what do you think kind of long-dated cost per foot goals might be for that asset at this point given what you learned over the last 100 days?

Sure.

Michael, I'd ask you to turn to Slide 11.

On the top right there, we've shown our West Virginia Marcellus activity, and we sort of ordered these bar charts from turn in line to spud.

And you can see, one of the big drivers in our cost performance is going to be from us increasing lateral lengths.

We're going from -- the wells that are -- sort of have been in progress that we're going to be turning in line or almost 9,000 feet, and that's -- the new wells that we're spudding in West Virginia in 2020 are going to be almost 12,000-foot laterals.

So that's going to be one of the largest drivers of our cost savings in West Virginia Marcellus.

The other thing that we're focused on is we're doing some acreage trades to be able to allow us to continue to put long laterals on the schedule.

Okay.

And what is like a -- I mean, I think you said $900 a foot this last quarter for West Virginia, if I got that right.

I mean what are you trying to get that down to?

Or what do you think you can get that down to?

Yes.

Michael, so in 2020, we have that around $900 a foot, and we expect that to continue to come down as we get a more consistent schedule that has 12,000-foot laterals.

That could come down closer to less than $800 a foot.

Okay.

That's helpful.

And then, I mean, I guess it's worth asking.

Any sense on quantifying what sort of impact do you think this rate release might provide, putting a sort of guard rails around that for us?

No.

Michael, while we're in negotiations, we're not going to provide guidance on that.

Your next question comes from the line of Holly Stewart from Scotia Howard Weil.

Maybe just one other quick follow-up on Slide 16.

What is assumed in the EBITDA guidance since you're highlighting -- for 2020, since you're highlighting potential divestitures that would impact that?

Yes.

Good question, Holly.

It's Kyle.

So our 2020 guidance across the board does not assume asset sales.

We wanted to show what the business was capable of today status quo.

On Slide 16, there are multiple ways we can get to that $1.5 billion of monetizations, and we'll provide updates to guidance as we announce them.

In general, free cash flow will decrease after selling assets, but that'll be offset by decreases with savings from interest expense, from repaying debt.

So net-net, I think full execution of our debt reduction program gets us towards the lower end of our guidance range, potentially below it on free cash flow, but it allows us to maintain investment-grade metrics, brings in liquidity ahead of the upcoming maturities, and obviously, that's a big focus for us.

Yes.

And maybe, Kyle, just to follow on to that, do you have -- or do you all have a sense of what the rating agencies want to see that you have accomplished as they review the business and the rating?

Yes.

They want to see us maintain investment-grade metrics.

And for us to do that, that's divesting assets, generating free cash flow.

And so I really think it's this plan specifically is what they want to see.

Executing on it?

Yes.

Okay.

And then maybe just one final one for me.

Toby, you didn't mention any part of the, I guess, the water conversations initially that were highlighted with gathering fee adjustments with the conversation with E-Train.

Is that still a part of the conversation?

Yes.

The focus has been on the biggest needle mover for us, which is on the gathering, but certainly, water would be a natural follow-on discussion for us for us to have.

Your next question comes from the line of Sameer Panjwani from Tudor, Pickering, Holt & Co.

So you highlighted minerals as a potential monetization candidate, but I wanted to see if you've given any thought as to how low you're willing to take that NRI from about 84% on average?

And then maybe as you've had conversations with counterparties on this, are the early implications on valuation holding up to what we have seen recently from peer transactions?

Or has kind of that benchmark changed drastically in the past few weeks?

Yes.

We don't have a specific NRI target in mind today and haven't gotten into valuation discussions as of today.

That said, we think that what we're offering is a pretty compelling investment to a wide universe of investors.

Obviously, we have the largest production base in the country across a massive undeveloped acreage position in the core of the Marcellus, so we're pretty excited about what we'd be able to do with a deal structured around these minerals.

Okay.

That's helpful.

And then on the renegotiation, wanted to make sure I understood a few things correctly.

I think you mentioned the timing of the lower gathering rates would be concurrent with the start-up of MVP.

So if the project continues to get delayed, would that also delay lower gathering rates for EQT?

And then on a more nuance note, I think you also highlighted potential increase to MVCs, but right now, there are shortfall fees.

So what am I missing there?

Yes.

So that's correct on the timing.

One of the things that we'll be looking to do is to establish sort of a global area so that we get away from having -- trying to balance 19 different capacity areas and the associated MVCs within each area.

So that would be an -- a step up in MVCs would be paired with the elimination of all these individual areas.

And I think that would give us greater flexibility to focus our development on where the combo development makes -- is available for us and be able to deliver volumes and meet our MVC commitments to Equitrans.

Your next question comes from the line of Ross Payne from Wells Fargo.

For just a little bit of clarification, does the 2020 budget include savings in the second half because of your -- restructuring some of your rates there?

And second of all, if MVP is delayed again, are you still committed to selling Equitrans midyear?

Yes.

We don't assume any fee relief in any of our guidance numbers.

And we're committed to divesting Equitrans in the next 9 months regardless of MVP timing.

Your next question comes from the line of Welles Fitzpatrick from SunTrust.

Just a quick clarification one for me to start.

Kyle, I think you said that we could see exit-to-exit declines at the end of your statement.

Was that for the Marcellus specifically?

Or was that for the lower 48 as a whole?

Both, frankly, I think, are possible based on where we see rig count going over the next 3 to 4 months.

And that's not just our view, that's -- a couple of industry analysts are starting to look at where supply could shake out for the lower 48 and could see that scenario playing out.

Yes.

No, good to hear.

And then a follow-up on the 50,000 core fee acres.

Can you give some sort of production metric that might go along with that so we might be able to back into prices in some of these recent comps?

Yes.

If I'm not mistaken, I believe some of the transactions range has been able to execute, it's really more -- on a cash flow multiple basis has been in the 12 to 13x cash flow.

And can you give us any inclines to the cash flow on that 50,000 core fee acres?

Yes.

I mean it's -- it would be -- we can kind of carve out whatever we want on the royalty side and include these fee acres as part of it.

So we can kind of design whatever mineral structure we want.

Your next question comes from the line of Drew Venker from Morgan Stanley.

Regarding the asset sales, can you give us any more detail on the E&P assets you identified?

You said, I believe, outside of the Marcellus fairway, but any more color would be helpful.

Yes.

Drew, I would say, our focus is going to be on -- in this fairway.

So everything is just going to be outside of that.

And there's -- these are some of the pruning that needs to happen.

And by setting some of these noncore assets that are outside the fairway is one of the things that could help focus our development and reduce some of our operating expenses as well.

Yes.

So specifically, Southern West Virginia, Central PA, Ohio, those are assets that are on the table.

Okay.

And Ohio including the entire Utica?

The Ohio Utica, yes.

Right.

I guess one other one, just on financing and addressing the maturities.

Would just launching a bond offering today be one solution to refinancing the '20 and '21 maturities?

Yes.

Absolutely.

We have market access today.

We've seen our '27 notes rally pretty significantly in the last 2 weeks, especially after this morning's announcement.

So yes, we have access today, but we also know executing some of these monetizations will only help to drive terms on a potential bond offering.

So we'll continue to opportunistically evaluate the market.

Your next question comes from the line of Jane Trotsenko from Stifel.

Looking at Slide 9, can you maybe talk about the key drivers for lower well costs, apart from the longer laterals?

And maybe what has been driving the outperformance year-to-date?

Sure.

Well, looking at Slide 9 is -- was our original expectation on when we could achieve these cost savings.

I think part of the -- some of the things that are allowing us to do this faster than we thought, one has to be a little bit of a softer service price environment certainly accelerates that; and two, I think we've been able to put together a much higher-quality schedule in a shorter period of time than we originally anticipated.

Okay.

I have a follow-up question.

In terms of changes that you are making to well designs, you mentioned longer laterals, do you do any other changes, maybe like proppant loadings or spacing?

Yes.

I mean there's 40 different parameters that we've identified that have the ability to impact economics of our wells by plus or minus 5%.

So yes, we've made changes to some of -- the bigger ones would be proppant loadings, clusters, number of clusters per stage, water loading.

So yes, we've -- and we're adding some new technology that we're testing out now.

So we have a proven well design that we're putting in, but we're also evolving that well design to adapt to the environment that we're in.

I see.

Can you guys talk maybe in terms of is it like higher proppant loadings or wider spacing directionally?

Yes.

It's the same -- very similar well design that we executed at Rice Energy that led to basin level -- basin-leading well productivity.

And so it's that same well design, we're just spacing it out to 1,000 feet.

And we actually published our type curve this morning on the website.

We expect that to generate an EUR of around 2.4 Bcf per 1,000.

Got it.

This is very helpful.

And my last question is related to G&A expense and also that you included the impact of royalty and litigation reserve, I'm just curious if it's going to impact cash flow one day.

Yes.

So we've accrued for everything which we feel a loss is probably that we know of today.

Going forward, I think one of the benefits of us doing things the right way and having a connected organization is it will minimize the impact of these type of issues going forward.

I see.

But we shouldn't be expecting a kind of -- do you expect it to happen in 4Q as well?

I just saw that, that happened in 3Q, and then we had one-off impact on G&A in 2Q.

Yes.

I mean we've accrued for everything that we know of today.

And it's tough for us to predict out in the future, but building a sustainable business of doing things the right way is going to be our safeguard against unexpected litigation expense in the future.

There are no further questions at this time.

Mr. Toby Rice, I turn the call back over to you.

Thanks, everyone, for participating on our call today.

We're proud of the work we've done so far and look forward to executing on our plans going forward.

I'd like to close out our first full quarter by thanking our employees for their hard work and dedication.

Thank you.

Ladies and gentlemen, this concludes today's conference call.

Thank you for participating.

You may now disconnect.