EQT Corp (EQT) 2019 Q1 法說會逐字稿

Greetings.

Welcome to EQT Corporation's Q1 earnings conference call.

(Operator Instructions) Please note this conference is being recorded.

I will now turn the conference over to your host, Blake McLean, Senior Vice President of Investor Relations and Strategy.

Please go ahead.

Thank you.

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

With me today are Rob McNally, President and Chief Executive Officer; Jimmi Sue Smith, Senior Vice President and Chief Financial Officer; and Blue Jenkins, Executive Vice President, Commercial, Business Development, IT and Safety.

In addition, it's a pleasure to have Gary Gould, our newly appointed Executive Vice President and Chief Operating Officer, join us today.

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 13685068.

The call will also be replayed for 7 days on our website.

In a moment, Rob, Gary and Jimmi Sue will present their prepared remarks.

Following these remarks, we will take your questions.

I'd also like to remind you that today's call may contain forward-looking statements.

Actual results and future events may differ, possibly materially, from these forward-looking statements due to a variety of factors, including those described in today's press release and under Risk Factors in our Form 10-K for the year ended December 31, 2018, as updated by our subsequent Form 10-Qs, which are also 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, when able, reconciliations to the most comparable GAAP financial measures.

I'd now like to turn the call over to Rob.

Thank you, Blake, and good morning, everyone.

Before we jump into the quarter, I'd like to take a minute and thank our employees for their continued hard work, dedication and ongoing enthusiasm for EQT's transformation.

I know change can sometimes be challenging, but when you have a group of talented professionals committed to doing what's right, we're already a step ahead and that much closer to achieving our goals.

On our earnings call in February, we discussed the company's ongoing transformation into a leading pure-play natural gas producer.

As part of that transformation, we reconstituted our leadership team, simplified our corporate structure from 4 public entities down to 1 and, consistent with feedback received from shareholders, worked to address EQT's sum-of-the-parts discount through the midstream simplification transactions and the spinoff of Equitrans.

We also shifted our focus with a new emphasis on low-cost operations, efficiency and free cash flow generation.

Adding fresh perspectives and additional talent to both the Board and executive team has been and continues to be instrumental in helping drive this shift in EQT's corporate culture.

The strong financial and operational results we delivered in the first quarter are tangible signs that these positive changes are directly benefiting shareholders.

Put simply, cultural change is driving positive operational momentum, which is leading to strong financial results.

I'm excited to update you on the significant progress that we've made in executing on the rigorous bottoms-up operational plan that we announced in January.

That plan is in action now with real operational momentum building, and it provides the best path forward to capitalize on EQT's world-class asset base and generate substantial and importantly, sustainable free cash flow.

We operated with a high level of focus and efficiency during the first quarter, resulting in improved performance over what we outlined in our fourth quarter earnings call.

Production sales volume were 383 Bcfe, which is above guidance and up 13% from the first quarter of 2018 when adjusted for divestitures.

The beat on production was largely driven by improved winter operations and was specifically attributable to a more collaborative and proactive approach to water handling.

The remote locations of many of our wells, coupled with dangerous winter weather and road conditions, often leads to safety stand-downs on our water hauling fleet.

This year, due to improved planning and advanced logic embedded in our water optimization model, we were able to proactively target critical production tanks and minimize the impact to production and frac crew operations.

We continue to reduce drilling days through the simplification of our wellbore geometries, the fine-tuning of procedures, mud properties and bottom-hole assembly design.

We've also incorporated 24-hour engineering support from our real-time operations center that has assisted in identifying issues and allowed us to prevent future problems while drilling.

In the fourth quarter of 2018, we averaged 1.11 days per 1,000 foot drilled.

We brought that down to 0.87 days per 1,000 foot in January, 0.83 days in February and 0.79 days in March.

Said another way, first quarter performance was 25% better than that of the fourth quarter of 2018.

On the frac side, our stages per crew per day also continued to improve.

For the quarter, we averaged 30% more stages per crew than we did in the first quarter of 2018.

This is largely due to improvements in pad and logistics planning that were implemented late last year.

Additionally, we partnered with our vendors to identify inefficiencies that have historically slowed down operations.

As a result, we have achieved significant improvements in operating uptime.

A 30% improvement year-over-year is fantastic progress.

We are particularly proud of our operational improvements in drill-outs.

We improved our average drill-out plugs per day by 71% in the first quarter of 2019 versus the first quarter of 2018, and we cut nearly 3 days off drill-out times per 100 plugs.

This was accomplished by working collaboratively with our contractors to optimize and simplify our bottom-hole assembly design as well as by refining the rigs, bits and fluid dynamics being utilized in the process.

These improvements have continued and just last week, we set an all-time EQT record by drilling out 43 frac plugs and cleaning out over 7,500 feet in a 24-hour period.

Really great progress.

I'd now like to discuss some operational scheduling changes that we strategically implemented during the quarter as a result of our increased efficiencies.

Going into 2019, we had more rigs under contract than we needed to achieve our near-term operational and volume growth targets.

As part of our ongoing effort to increase operational efficiencies and reduce costs, we were able to successfully negotiate a penalty-free early reduction to our horizontal rig count, which will result in approximately 30 fewer horizontal wells being drilled in 2019.

As a result, we will also spud approximately 15 fewer wells in 2019.

Additionally, due to the operational efficiency gains that have been achieved within our completion operations, we now plan to frac approximately 10 more wells in 2019 with the same frac crew count.

And finally, 7 fewer wells are expected to be turned in line during 2019 as a result of non-operated activity by joint venture partners and a bit of timing.

This is all good news from a capital efficiency point of view.

These operational changes will not impact our full year 2019 volumes or capital expenditures, but they will move us closer to an optimal resource count and development cadence and will enhance our capital efficiency as we move into 2020.

Over the last 3 months, we've talked a lot about our Target 10% Initiative, which is aimed at driving incremental cash costs out of the system.

Since this new team was appointed in the fourth quarter of 2018, we have already identified and are now capturing $150 million in annual cost savings, $50 million of which fall under our Target 10% Initiative.

In addition, as an organization, we have identified and are pursuing over 100 projects that will further drive down costs.

These projects vary in scale but are largely centered around process optimization, elimination of redundancies, enhanced engineering designs and the procurement of goods and services.

As you all know, in March, we announced the appointment of Gary Gould as our Chief Operating Officer.

Gary is a great addition to our leadership team as he's a seasoned operator with a proven track record and is ideally suited to help us achieve further cost reductions and accelerate free cash flow generation.

With Gary officially joining this week and the continued work of our existing team, we are confident that we will identify additional opportunities to operate more efficiently and further reduce costs to achieve our target of removing $800 million in costs from the business over the next 5 years.

As we identify and quantify these cost-cutting measures, we are committed to keeping you updated on progress as we go.

Before Jimmi Sue provides additional detail on our strong first quarter financial results, I would first like to turn the call over to Gary to share his thoughts on the company and what drew him to EQT.

Gary?

Thanks, Rob, and good morning, everyone.

I'm very glad to be here and to join you today as EQT's new Executive Vice President and Chief Operating Officer.

Before I joined the EQT team, I most recently served as Senior Vice President of Production and Resource Development at Continental Resources.

And earlier in my career, I held various positions at Chesapeake, ConocoPhillips, Burlington Resources and Exxon.

These experiences taught me a lot about collaborative leadership, operational excellence and the efficient development of shale assets, and I'm very much looking forward to applying this knowledge here at EQT.

I'm glad to be back in the Marcellus and I'm excited about our future.

This company has a world-class acreage position in the heart of the play, and our contiguous footprint is well situated to become the lowest cost, most efficiently developed asset in the entire basin.

I'm pleased to partner with Rob and the rest of our management team here to drive further development efficiencies and cost reductions, and I believe we will generate significant free cash flow for many years to come.

Also I look forward to getting on the road to meet with shareholders in the next weeks and months ahead to discuss the future of our company, and I want to thank everyone here at EQT for the warm welcome I've received this week.

Now I'll turn the call over to Jimmi Sue.

Thanks, Gary, and good morning.

To echo some of Rob's earlier comments, I will begin by highlighting that our continued efforts to improve operations are materializing in our financial results.

In the past 2 quarters, EQT has generated approximately $306 million in free cash flow.

Our shift to steady-state operations, combined with our concerted effort to improve efficiencies, resulted in first quarter capital expenditures that were in line with our expectation, which is down 22% with more feet of pay turned in line compared to first quarter 2018.

We expect to hit our full year capital expenditure guidance of $1.85 billion to $1.95 billion.

We're excited by this progress and reiterate our adjusted free cash flow guidance of $300 million to $400 million for the full year based on strip pricing as of March 31 as well as our expected $2.9 billion of cumulative adjusted free cash flow through 2023.

With the successful implementation of our Target 10% Initiative, our 5-year cumulative adjusted free cash flow is still expected to be $3.4 billion.

Now I'd like to provide a little more insight into our 2019 expectations.

To reflect our first quarter volume of 383 Bcfe, which was above our guidance range, we have increased our full year volume range by 10 Bcfe to 1,480 to 1,520 Bcfe.

We expect our second quarter volumes to be between 355 and 375 Bcfe with modest sequential increases in the third and fourth quarter.

On our last earnings call, I highlighted the cadence of our adjusted free cash flow for the year, in which I guided an adjusted free cash flow range of negative $50 million to negative $100 million for both the second and the third quarters.

While we continue the guide this range, we expect that adjusted free cash flow will be slightly better than the midpoint for both quarters.

With respect to the cadence of our capital expenditures for the remainder of the year, we expect the second and third quarters will be slightly higher than the first quarter on increased activity during the summer months, especially for our construction crews.

The fourth quarter capital expenditures will be lower, closer to $400 million, reflecting full realization of our cost savings and lower activity as we reduce to our steady state with 1 fewer drilling rig.

Regarding our detailed guidance, per-unit cash expenses may fluctuate each quarter alongside volume, but the full year guidance is in line with previous expectations.

Focusing on the quarter results, EQT reported first quarter 2019 adjusted net income of $212 million or $0.83 per share compared to $179 million or $0.67 per share in the first quarter of 2018.

First quarter adjusted free cash flow was $171 million, up 92% year-over-year.

As noted in our press release and in accordance with SEC rules, this number is not adjusted for an $8 million litigation reserve and $4 million of proxy-related expenses in the quarter, which would have made free cash flow $183 million for the quarter.

Sales of natural gas, oil and NGLs were up approximately $45 million from the first quarter of 2018, primarily on increased sales volume.

However, this improvement was offset by a loss on derivatives not designated as hedges in 2019.

Our net marketing service revenues were also down as a result of fewer releases of contractual capacity not used to transport our gas and as a result of the divestitures in 2018.

This line item is generally not expected to be significant in 2019.

Per-unit cash operating expenses decreased by 5%, primarily due to increased sales volumes.

In addition, on a per-unit basis, LOE was lower and gathering expense was higher compared to the first quarter of 2018 as a result of the divestitures last year.

As I mentioned at year-end, not only were the divested assets expensive to operate, but the divested volumes did not incur gathering charges because our production group operated the gathering assets and included those costs in LOE.

We did realize personnel cost savings in SG&A as a result of our cost saving initiatives and reduction in force during the first quarter.

However, this reduction was offset by a benefit recorded in the first quarter of 2018 related to forfeited incentive compensation awards.

Excluding the $8 million litigation reserve recorded in the first quarter of 2019, SG&A would have been flat on a per-unit basis compared to the first quarter of 2018.

Before moving to our standard liquidity update, I would like to make a few comments about first quarter pricing dynamics.

Our average realized price was lower for the first quarter at $3.16 per Mcfe compared to $3.33 in the first quarter of 2018.

This was primarily due to a lower differential and a decrease in higher-priced liquid sales as a result of the divestitures in 2018.

Our average differential was down $0.12 compared to the first quarter of 2018 on lower gas daily pricing during the quarter.

In 2018, as during most winters, cold weather resulted in higher gas daily pricing versus the 1st of the month, especially in the Northeastern United States.

We leave a portion of our portfolio open to capture these peaks, which did not materialize in 2019.

The lower gas daily pricing also resulted in a lower average differential compared to our guidance for the quarter.

As we noted in our release this morning, we still anticipate full year average differential will be a negative $0.45 to a negative $0.25 per Mcfe.

Moving to EQT's cash flow and liquidity position.

We ended the quarter with $350 million drawn on our $2.5 billion revolver and $41 million in cash, which is a reduction in net debt of just under $500 million from year-end.

At this level, our net debt to trailing 12-month adjusted EBITDA leverage is just under 2.1x, and when reduced for the value of our investment in Equitrans Midstream, is 1.6x.

We continue to target leverage of 1.5 to 2x and still expect to use proceeds from the future divestiture of our Equitrans stake to reduce leverage.

And with that, I will pass the call back to Rob.

Thank you, Jimmi Sue.

Before we open the call up for Q&A, I'd like to reiterate that our strong first quarter results reflect our focus on enhanced operational efficiency, and I'm extremely proud of the hard work and dedication displayed throughout the entire organization.

Not only do we have a world-class asset base, but we also have a world-class group of employees.

With the oversight of an active and engaged Board, we have developed a comprehensive and thoughtful roadmap to maximizing free cash flow, not only in 2019 but for many years to come.

We have successfully reshaped our culture to focus on capital efficiency per share returns through accountability, collaboration and transparency, driving stronger results for our shareholders.

Our strong financial and operational performance is just the beginning, and we're excited that our renewed operational focus will deliver significant value for our shareholders.

We look forward to updating you as we continue to deliver results throughout the rest of 2019.

So at this point, we'll open the call up for questions.

(Operator Instructions) Our first question today comes from Arun Jayaram with JPMorgan.

Rob and team, I wanted to first start off with your thoughts on how some of the operational improvements that you've outlined are impacting how you're thinking about, call it, D&C costs on a per lateral foot basis.

I believe, if I'm not mistaken, that your guidance was based on, call it, 900 to 915 per lateral foot this year, and how are you seeing things today?

Arun, yes, so I would say that the results that we've seen both in the fourth quarter and the first quarter of 2019 are all really positive, right.

I mean, so they would shade us a bit lower on our cost per unit, whether MCF or per foot.

Really pleased with the efficiencies that we've seen with drilling, with completions and drill-outs.

We're making real progress on all fronts.

So it's early in the process and our guidance has remained pretty consistent for the rest of the year.

But if I had to bias it, I would say that costs would shade further down and not up.

Okay.

Second question is you talked a lot about, at least in the press release, some of the success on the lateral -- on pushing lateral lengths.

Could you comment, Rob, on what you're seeing on the well productivity front as you're pushing lateral lengths longer?

Yes.

So all of the data that we've collected thus far suggests that there's no degradation in productivity with longer laterals, that we're still getting effective fracs away.

We do have to make some adjustments on stage lengths so that we can keep the rate high enough.

But everything that we've seen so far suggests that there's no degradation of productivity based on lateral length.

So pleased with the well productivity results.

And final question, Gary, for you.

Obviously, you had a lot of success, thinking about being a continental, a low-cost operator.

What are some of your thoughts just early on and some of the benefits that you think you can bring to the table as you think about the operating plan on a go-forward basis?

Sure.

I've been fortunate to be on a lot of really strong teams and had a lot of good results.

And I think what first attracted me to EQT was the strong oil and gas asset position that we have here.

We have several years of inventory in the core of the Marcellus.

And with that in hand, I think the future looks great.

The second thing that impressed me here was earlier in the year, when I met the executive management team, and I found them to be just very smart, very energetic and very collaborative in their approach to leadership.

And that matches up with my style also.

I also found the team to be very focused on maximizing long-term shareholder value, and that's exactly how I approach operations.

And then lastly, I would add that this week, as I've continued to meet with my management team and some of the staff, I have found them to also be very smart, very collaborative in their teamwork and with a strong initiative to get operational results.

I think that if you look at my background, whether it be at Continental Resources or Chesapeake or some of the companies before that, we have always run our operations with the bottom line in mind of maximizing shareholder value and we've been successful in doing that in a multitude of plays, whether it be oil plays or gas plays.

And I look forward to leading operations here to continue to generate operational efficiencies and maximize shareholder value.

The next question comes from Scott Hanold of RBC Capital Markets.

Yes.

I just want to hit the point on some of the efficiencies and lateral cost per foot that you kind of highlighted earlier.

I know in your most updated detailed 2019 capital plan that you had in your deck, you do cite a little higher cost for D&C CapEx for the PA Marcellus.

And your TILs and spuds are going down but the budgets stay the same.

So could you help me kind of the square the circle around that?

Yes, sure.

There's a few moving pieces here.

The first thing I'd say is that the changes in schedule really are a good thing from a capital efficiency point of view.

So the TILs and the lateral drills -- or sorry, the spuds and lateral drills are going down because we were able to drop a couple of rigs earlier than we expected.

We had more rigs under contract than what we really needed for this plan that were just going to build DUC inventory.

But we were able to lay down rigs quicker than we thought.

So that was a positive.

The next piece is we're -- have been more efficient in our frac operations, so we're getting more stages per day done than what we budgeted.

And therefore, we're going to frac about 10 or 11 additional wells in 2019 above what was planned using the same number of frac crews.

So we'll spend a bit more money there, which largely offsets the reduction in drilling.

So -- and that sets us up very well for 2020 because as we come in to 2020, we're going to end up -- we're going to TIL, I believe it's going to be 7 less wells than planned in 2019, but those wells will be ready to TIL early 2020 and require very little capital to get them online.

So overall, the scheduling changes are a reflection of getting to steady state a bit quicker than we thought we would and more efficiencies, particularly on the frac side.

Okay, okay.

And you're seeing cost per lateral foot then -- and I know there's -- some of the calculations are difficult to get your arms around because of the changes here.

But you are seeing that trending down or fairly consistent with your prior outlook, I guess, when you shake everything out?

Yes, I mean, all of the efficiencies, both drilling and on the frac side, those translate into lower cost per Mcfe.

So the cost per unit is trending down.

Okay.

And then with that shift in activity, did that have an impact on your liquids expectation for the year?

I think the liquids expectation came down a little bit for the full year.

That's not related to scheduling.

That's more around Mariner East as well as a [D high] unit that isn't going to be in service as soon -- I think it got delayed 2 quarters, I believe.

So that's the reason that we've seen ethane volumes come down.

Okay, okay.

All right.

And then finally, so what is your rig count right now?

So how many rigs were you able to drop?

Where did you go to -- from and to with these efficiencies?

We started the year running 10 rigs and we were planning to get down to 7 and then 6 throughout the year.

We just got there faster.

We're down at 7 rigs right now, 7 horizontal rigs.

And originally, we weren't intending to be there until sometime in the third quarter.

So we were able to sublet 3 of the rigs.

The next question comes from Jane Trotsenko of Stifel.

I'll try to ask a question on Mountain Valley Pipeline.

Maybe you can give us an update in terms of construction and regulatory process and if we still should be thinking about the project as 1Q '20 event?

Yes, Jane, that's really a better question for the Equitrans management team.

I believe that they're reporting next week.

So we really see what is public information and so far, Equitrans has maintained a year-end 2019 in-service date, and that's still what we have baked into our plans.

From our point of view, we think that this pipe is one that is highly likely to get built.

The risk really is more around timing.

But from an EQT perspective, if there is a delay, which we certainly don't know that there will be, but if there is, it actually is not detrimental to us.

It actually is a little bit helpful for 2020 cash flows because the spreads on that transportation right now are a bit underwater.

But we do -- I want to be clear that we really do want to see MVP get built.

And as a significant shareholder in Equitrans, we still hold our 19.9% stake, it's very important that, that that pipe get done.

And it's important for the industry's takeaway capacity and our own takeaway capacity as we move forward in time that MVP get built.

Okay, got it.

I have a clarification question about changes in the operational plan for 2019.

2020 -- so 2020 numbers did not change.

CapEx remains unchanged and production outlook remains unchanged.

So I was just thinking how those changes in 2019 operational plan are going to translate in some sort -- maybe lower CapEx or higher exit rates for '19.

Right, that's a good question.

And I would point out that we have not updated the 5-year plan.

We've updated the 2019 guidance, but we've not updated the 5-year plan.

When we do, what you will see is there will be capital efficiency improvements in 2020 and beyond that are not yet reflected in that 5-year plan.

And as we have gained efficiency, both on the drilling and the completion side, that will flow through and we'll really start to see the benefits of that in 2020.

And a good example is the additional 10 wells that we're going to frac in 2019 that only marginally affect 2019 volumes, will take effect in 2020 and there will be limited capital that has to be spent on those 10 wells in 2020.

Okay, got it.

And if I may, the last question.

I would just like to understand the role of Ohio Utica in your asset portfolio and maybe West Virginia Marcellus as well.

I just see that the number of wells drilled there is considerably less than, let's say, in the core acreage.

What's the future outlook for the production in Ohio Utica and West Virginia Marcellus?

Yes, so as you rightly point out, we're drilling fewer wells in West Virginia and Ohio than we do in Pennsylvania, which really is the core for us.

In Ohio, that Ohio Utica, economically, it matches up reasonably well versus the Marcellus.

It's not quite as good.

It's core Greene County and Washington County Marcellus, but it is reasonably good.

And it's a nice, blocky position where we're able to drill long laterals, and it is a little bit different in terms of pipes that we can touch with it.

So it does give us some diversification of operations that we like.

In West Virginia, it is more difficult to operate.

The land -- the rules and laws around land pooling, et cetera, are more difficult.

It's harder to put together long laterals.

But it is high-quality rock and it has more liquids content.

So economically, it does compete reasonably well with Pennsylvania Marcellus.

Again, not quite as good as core Greene County and Washington County, where we're drilling 12,000- to 14,000-foot laterals.

But there is a place in the portfolio for both West Virginia and for Ohio.

And as we make progress on the land position in West Virginia, you'll see us try to deploy more capital in West Virginia.

Our next question comes from Holly Stewart of Scotia Howard Weil.

Maybe just an extension on Scott's question.

Rob, you mentioned that you guys were ahead of budget on stages per day.

Can you give us kind of what you're doing on that front and then what you had budgeted for?

Sure.

It's really around -- it's largely around the logistics on the pads.

So this is being thoughtful about pad layouts, how we get sand and water trucks in and out in the most efficient manner.

It's through manifold design changes on offloading water.

It's measuring KPIs on time to unload, waiting times.

So it's paying attention to all the small details around logistics on the pad and making sure the frac crews have the water and the sand that they need, when they need it.

And it's just kind of optimization of what is a fairly complex logistics problem, and we've made real strides on that front by paying attention to the variables that really matter.

Okay.

And maybe just kind of continuing on this sort of cost savings.

The slide deck, I think, goes through a lot, and particularly as it relates to water.

I know you guys in E-Train have talked a lot about sort of optimization of the gathering system.

Could you just make any comments on maybe where that process stands?

What you all could do with your water needs there and then how that sort of plays into this longer-term well cost reduction?

I...

Yes.

So at this point, we haven't -- there's not much physically that's changed in terms of how we manage water, other than we're doing a much better job optimizing how we move water with trucks.

Ultimately, the real win is to move as much water as possible in pipes as opposed to trucking it, including impaired water.

So we are in discussions with Equitrans on a number of fronts, one of which is how to better manage water logistics in areas where we have a real concentration of activity.

So that really points you to Greene and Washington Counties in Pennsylvania.

There is opportunity to start to move some of our impaired water or maybe even a majority of our impaired water via pipe as opposed to trucks.

And that's a significant difference, right?

When you -- today, we move about 75,000 barrels of impaired water a day.

About half of that is in our core Greene and Washington County areas.

If we can pipe the water, we think that it's going to save us something like $5 a barrel in water costs.

And so when you do the math on that, it's valuable.

This isn't going to happen overnight.

It's going to require some infrastructure, but it's something that's in the works and I think that it is very doable.

I think the other advantage is, from a safety and environmental perspective, it is much more desirable to pipe the water as opposed to trucking.

Water hauling is one of the most dangerous parts of this business, and the fewer trucks that we have on the road, the better.

We'll never get to 0, but as much as we can minimize it, it is an economic, safety and environmental advantage.

Perfect.

And then maybe one last one, if I could.

Any update around your plans for the June maturity?

Sure.

Holly, this is Jimmi Sue.

We said all along that we had -- we intend to sell down the E-Train stake and reduce debt.

But we've also said that, that sell-down is going to take 1 year to 2 years, although I would be surprised if we're still holding it 2 years from now.

So with that and the June maturities coming up, we have plenty of room on the revolver -- remember, it's $2.5 billion -- to cover those maturities, and so I would expect to see those taken out with a revolver or something cheaper than the revolver.

Our next question is from Brian Singer of Goldman Sachs.

Following up on a couple of the earlier questions on the efficiencies that you're seeing translating into free cash flow.

You use the phrase capital efficiency improvement a lot and just kind of wanted to nail you down a little.

Is the conclusion that the combination of efficiencies that you're seeing as well as the scheduling and cadence changes will lead to otherwise greater free cash flow in 2020 and greater free cash flow over the 5-year program, if there's that upside bias, but not necessarily to 2019?

I think that what you said is correct.

It would bias us towards better -- all else remaining equal, better free cash flow in 2020 and beyond.

Great.

Okay.

And then my follow up is for Gary.

As you enter and come back to the Marcellus after having worked actively, looking at the oil fields more recently, do you see more an opportunity for EQT on the productivity improvement front or the cost efficiency front?

And to what degree do you see opportunity to pull expertise and apply them from the oil shale plays and apply them to the Marcellus?

Yes, this is Gary Gould.

And I've been here about 3 days now.

I think it's my fourth day.

So it's probably a little early to comment on that.

But what I would tell you is that we will certainly be looking at all of that.

We will absolutely be looking at cost, on CapEx, on LOEs as far as optimizing cost and generating these operational efficiencies that we talk about.

But we will certainly be looking at the production side also to look at the combination of production and cost for designs associated with completions, designs associated with our production capacity in order to make sure that we are maximizing shareholder value, not just reducing costs, but maximizing shareholder value and therefore, optimizing when it comes to production.

And as we look at that, we will be continuing to compare our own performance to ourselves quarter-over-quarter and continuing to look for improvement.

I think you already see great results from the first quarter here at EQT.

And then we will also compare ourselves to others within the basin to make sure that we become the lowest-cost producer.

Our next question comes from Sameer Panjwani of Tudor, Pickering, Holt & Co.

Circling back to the midstream side of things for a second.

I think previously, you've mentioned being optimistic that the constraints could be addressed by the end of this year or early 2020.

I'm trying to understand how much a lead time is needed to execute on that time frame in terms of trying to triangulate when an announcement regarding the ongoing negotiations will need to be made.

Right.

So there is work that's ongoing.

And what we have said and what is baked into our plan is that the midstream constraints are resolved by the end of 2020.

Now we do think that we can make progress prior to that.

And in fact, even in the first quarter, we saw throughput on one of our major systems above what we thought we could do.

And so we are making some progress with tweaking the midstream system.

The greater -- and having the greater high-pressure/low-pressure system will take a bit longer to do because there are permitting issues that have to be resolved.

There's engineering that has to be done and there's some pipe that has to be put in the ground.

But we're confident that, that can happen and that work is ongoing.

And it is -- while related to the other negotiations with Equitrans, we're not waiting on those to be completed before we keep that work moving.

So we're optimistic about how we fare versus our plan, that we will be at least on time or maybe early on that plan.

And we'll continue to update you as we make progress.

Okay, that's helpful.

And then on the A&D side of things, we've definitely seen the market start to thaw here a little bit.

So wanted to get your updated thoughts on your willingness or ability to maybe prune some of your noncore Marcellus acreage.

And also just to get an update on the leasing side of things, what the going rate for kind of leasing in your core areas is today.

Yes, so on the A&D side, on our willingness to divest noncore assets.

Certainly, we are open, we're always open to discussions around value of assets.

And if it's more valuable to somebody else and they're willing to pay us for it, and it's accretive for our shareholders, then that's certainly something that we would consider.

I think that realistically, there's not much of a market for Tier 2 Marcellus at that -- at this point.

I think the economics just don't support it.

But we're always open to having those discussions if there are people who are interested in -- either in Tier 2 Marcellus or even stuff that's further back, that's Tier 1 to further back in our drilling program.

On the leasing rates, I'd say that there's not a material change in what we're seeing in leasing rates.

It's been fairly consistent.

And it varies a bit area by area, but I don't think there's been any major change.

Okay, great.

And then finally, to the extent you're able to provide some commentary on the litigation announcement this morning, I'd be interested to hear your thoughts or the Board's rationale around the voting process.

Yes.

So look, the Board is reviewing the Rice nominees.

We're preparing our proxy materials.

It's all kind of in the normal course of how this process needs to run.

And the decisions will get made on the appropriate timeline, and we're not going to get pushed to do it faster than what the Board is ready to do.

And frankly, this is kind of much to do about nothing and it feels a bit like an attempt to just distract attention from what was really a great operational quarter and real progress for the company.

So that's really where we want to keep our focus.

Your next question is from Michael Hall of Heikkinen Energy Advisors.

Just curious if you could maybe -- coming back on the -- just kind of the operational efficiency front, it seems like you're building up a handful of DUCs here over the course of the year.

How do you think about the optimal level of kind of an operational DUC backlog versus the current activity profile?

And how would that DUC backlog compare to what you expect to exit the year at as opposed to like what the kind of normal operational backlog might look like?

And then I guess, do any of these changes in efficiency change your thoughts on what an optimal rig and frac crew count look like in that 5-year outlook?

And that'll do it for me.

Sure, yes.

Thanks, Michael.

In terms of the DUC count, it's actually going to come down a little bit as we work through the year.

It was going to rise some prior to us being able to farm out the 3 rigs that we talked about earlier.

In terms of an optimal DUC count, I'm not sure there really is one, right?

We want to make sure that the wells are drilled and ready to be fracked so that we don't have a bottleneck in the process, and there's also some land considerations on holding acreage.

So we sometimes need to drill wells and build DUC backlog from a land point of view.

But I'm not sure if there's a magic number in terms of number of DUCs.

We just to make sure that the operation is running smoothly and that there aren't bottlenecks in it.

Okay.

And as a view on the needed level of rig count and frac crew counts, does the 5-year outlook change at all with the improvements in efficiency?

Or is that not yet material enough, I guess, to fully change that for the long-dated view?

Well, we're only a quarter into this, and while we have seen some efficiency gains better than what we had planned on, I think we need to let this run forward a little more before we change rig and frac counts.

I think right now, we're running 7 rigs and 5 -- actually, 6 frac crews.

That neighborhood is going to be the right one in this commodity price environment.

And maybe if the efficiencies really hold or continue to improve, it means that we'll drop another rig and one more frac crew.

But I think this is probably the right neighborhood to think about.

Okay.

And maybe just one follow-up on that.

Are you guys seeing any just raw pricing improvement from the services side as you guys are working with your partners on that end?

Or yes, any movement on that front?

There's been a little bit of improvement in pricing, but it's single digits, it's not a big number.

What I would say though, is our efficiency in working with our frac crews and with our frac providers has gotten much better, right?

We have changed the culture a bit, where we are really trying to be a good partners with our service providers, making longer-term commitments and really working hand-in-hand to improve the efficiency of the operations.

That's where we've seen the big gains, right?

I mean, we've gone as far as saying, "You guys tell us what we're doing to slow down the operations and how we're causing problems." And we've changed a number of our procedures and processes in that partnership that has -- we've seen real improvement.

So I'm extremely excited about that.

I think that's been a big move in the right direction, and it really is much bigger and more important than any pricing changes, is the efficiency gain.

The next question is from Betty Jiang of Crédit Suisse.

Maybe a follow-on to, Rob, what you just said earlier.

Concerning your free cash flow target guidance for this year is based on, I think, around $2.90 gas price, which is higher than where strip is today, do you basically see the efficiency gains today capable of offsetting the impact of lower prices just based on strip pricing?

And then like whether in a lower price environment, is the goal to maintain free cash flow in lieu of activity in production?

Yes.

As I said, there's a few competing points here, Betty.

Certainly, pricing coming off has a negative impact to free cash flow.

But the efficiency gains that we have made do offset that partially.

And I would also say that we've been fairly aggressive in hedging the back part of the year, and so we've protected ourselves from the recent -- from at least a portion of the recent price moves.

So we still stand by our guidance of $300 million to $400 million of free cash flow in 2019.

Great.

And then you alluded to earlier about negotiations with Equitrans.

Considering the midstream costs really make up a substantial part of the cash cost structure, what type of measures is possible to potentially push those costs lower?

Yes, I think that there's a broad -- there's potential for a broad renegotiation with Equitrans over our midstream contracts, gathering, transmission, it includes water.

There's a number of areas where we can help Equitrans grow their revenue base with us by providing other services or other areas where they don't currently do the gathering.

Water is a great example of a new revenue stream that they can generate.

And then for us, Equitrans can help lower our per-unit gathering rates.

And you're right, that is a big portion of our cost.

And so when you think about where we are with G&A and LOE, we're at pretty low levels.

But there's big numbers in the gathering and transportation costs, where I think we can make real progress with Equitrans and have it truly be a win-win deal for Equitrans and EQT, where Equitrans has the ability to grow their revenue base and we have the ability to lower our per-unit costs.

Great.

I'm going to throw it out there, but in terms of, what type of magnitude could we -- are we talking about here?

Well, when you think about LOE or SG&A, you're talking about pennies or portions of pennies, right, per Mcfe.

When you're looking at $1.20 plus of gathering and transportation costs, maybe you're talking about nickels or dimes.

So there's potential for significant improvement that we can't find in other parts of the cost structure.

There are no further questions at this time.

I will now turn the call over to Rob McNally for closing remarks.

Okay, thank you, everybody.

Appreciate the time this morning.

Look forward to updating you in the second quarter.

And as always, if you have follow-on questions, please feel free to contact Blake.

Thank you.

This concludes today's conference.

You may now disconnect your lines at this time.

Thank you for your participation.