EQT Corp (EQT) 2018 Q4 法說會逐字稿

Ladies and gentlemen, greetings, and welcome to the EQT Corporation fourth quarter earnings conference call.

(Operator Instructions) As a reminder, this program is being recorded.

It is now my pleasure to introduce your host, Blake McLean, Senior Vice President of Investor Relations.

Thank you.

You may begin.

Thank you.

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

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

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 13674487.

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

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

Following these remarks, Rob, Jimmi Sue, Erin and Blue will be available to answer 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, 2017 and our Form 10-K for the year ended December 31, 2018 to be filed with the SEC later today as updated by any subsequent form 10-Qs and other reports we file with the SEC.

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.

Good morning, everyone.

The last several months have been a very exciting times at EQT.

Post-separation, the new management team, with support from everyone across the organization, has successfully shifted our direction to focus on development, optimization and efficiencies.

This strategic shift has resulted in significant progress in a short period of time and is exceeding my expectations.

This company is full of some of the best and brightest minds in the industry, and empowering these people to make real decisions and drive change has had an immediate and noticeable impact.

We are excited about the future of the company and our ability to execute on the plan that we've set forth.

I'm highly confident that we have the right overall execution framework set in motion to achieve our strategic vision.

Now I'd like to reiterate some of the progress that we made in late 2018.

On the operational side, we completed 2018 with full year sales volumes of 1,488 Bcfe and fourth quarter sales volumes of 394 Bcfe, above prior guidance and approximately 5% over the third quarter.

Additionally, fourth quarter capital expenditures were in line with guidance.

Most importantly, we generated approximately $134 million of adjusted free cash flow, a significant increase above the $100 million that we guided to on our call last month.

These results demonstrate that we are successfully executing on our plan to enhance efficiencies and deliver sustainable free cash flow.

As a premier pure-play upstream company with a world-class asset base, EQT has begun a new chapter.

We have a clear and compelling action plan and are taking meaningful and decisive steps to strengthen EQT's financial and operational results.

We are committed to driving down costs and operating more efficiently, and our entire organization is moving forward with a sense of urgency.

Over the course of 2019, we will continue to look for even more opportunities to unlock the tremendous potential of EQT's assets.

I am more confident than ever that EQT will deliver sustainable free cash flow to shareholders in 2019 and for many years to come.

Last month, we outlined our path to generate mid-single digit year-over-year production growth combined with meaningful adjusted free cash flow in 2019 and, over the next 5 years, a total of $2.7 billion with upside expected from our ongoing Target 10% Initiative.

We are turning EQT into a free cash flow generation machine.

Our confidence is driven by our unique and differentiated position built on 3 key pillars.

First, EQT has built a world-class asset base positioned squarely in the core of the Appalachian basin with 680,000 core net acres in the Marcellus and 15 to 20 years of drilling inventory.

Second, we are taking the right steps to operate more efficiently at lower cost.

On our January call, we announced immediate cost-saving actions that are expected to reduce annual cash costs by approximately $100 million.

We also discussed further cost savings to be realized in 2020 and beyond, our Target 10% Initiative.

We have line of sight on many of these opportunities and will report on our progress throughout the year.

That said, I am pleased to announce that we have already identified and have recently begun to implement approximately $50 million of additional cost savings.

These cost savings have been incorporated into our 2019 and 5-year forecast, which increases our total projected 5-year adjusted free cash flow from $2.7 billion to $2.9 billion.

We will discuss these savings in more detail later, but our progress is further evidence of this management team's commitment to both execute and improve this plan.

The third pillar is our financial strength.

EQT has an investment-grade balance sheet, and the company's stake in Equitrans Midstream, worth approximately $1 billion at current valuation, provides optionality to further strengthen the balance sheet.

That stake, combined with our free cash flow generation, gives us the ability to reduce leverage to our target of 1.5 to 2x net debt-to-adjusted EBITDA, while, at the same time, returning capital to shareholders.

As a reminder, our projected 5-year adjusted free cash flow of $2.9 billion, before realizing the full impact of the Target 10% Initiative, represents greater than half of our market cap at today's valuation.

As we announced last month, our search for a Chief Operating Officer is ongoing and a short list of highly qualified external candidates has been identified.

We remain on track to announce an appointment of the COO during the first quarter of 2019.

Before we discuss the fourth quarter and full year results, I would like to briefly address the most recent public claims made by the Rice brothers.

I will start by saying that the focus of this management team is on running this business in the most efficient manner possible, executing on the rigorous bottoms-up and detailed plan that we laid out and working to continuously improve that plan.

We fully expect to deliver on our objectives and we will provide the details necessary to effectively evaluate our performance.

As previously noted, we believe the Rice claims are based on flawed assumptions, selective data and tell an incomplete and misleading story.

I don't intend to address every point here, but I will make some high-level observations and point out a few areas where their claims are not supported by the facts.

First, the claim that Rice wells consistently outperform EQT wells is simply not accurate and the analysis omits important information.

There are reservoir quality differences across Washington and Greene counties.

By examining the wells in the Rice analysis, an overlay of the EQT, Rice or any other heat map generated by public data would show that a greater percentage of the Rice wells sit in the Tier 1 Southwest core.

And those wells would be expected to have higher EURs.

In addition, approximately 30% of EQT's wells in the data set were impacted by offset Upper Devonian wells.

This codevelopment typically drives 10% to 15% underperformance relative to Marcellus wells without those offsets.

When comparing wells that fall within the same heat map region and ignoring wells impacted by codevelopment, there is no difference between EQT wells and Rice wells.

In fact, the directly comparable EQT wells performed marginally better than those drilled by Rice.

As a reminder, we have stopped Upper Devonian codevelopment, so those wells are not representative of go-forward well results.

With the support of our talented technical team, we have taken a measured and thoughtful approach to analyzing the data we acquired from Rice.

One observation about the 2017 Rice wells was the testing of a new frac design that utilized tighter cluster spacing.

We closely monitored the results of those wells and did some additional testing in 2018 and have since implemented this tighter cluster spacing as our standard frac design.

This demonstrates 2 things.

First, we've been open-minded about adopting best practices.

And second, when we talk about frac design, we also understand that sand, water, stage spacing and cluster spacing matter.

I will make one final point on frac design.

We have performed rigorous analysis on our extensive repository of well data, production results and reservoir quality intelligence.

That data, combined with our sophisticated reservoir modeling technology, has led us to target 1,000-foot lateral spacing in conjunction with larger frac jobs.

We firmly believe that this is the optimal way to both maximize returns and minimize dollars per Mcfe.

Second, the claim that Rice Energy operated this same set of assets is false.

To clarify, development footprint is not synonymous with operating area.

That assumption ignores the complexity of managing an extensive inventory of producing wells, substantial water handling and logistics and the maintenance of leases across the portfolio.

To put this in perspective, consider the fact that EQT's assets today compared to the legacy Rice assets include: 3x the leasehold position, 8x the number of counties with producing wells; 5x the total producing Marcellus, Upper Devonian and Utica wells; and 5x the daily produced water volumes.

Remember, all of this produced water must be moved to either disposal or an active frac and distance matters from both a cost and logistical complexity perspective.

To reiterate, this is not the same asset base, and the cost and complexities associated with operating these assets cannot be ignored.

Third, members of this leadership teams were and are major advocates of retaining and employing the key technology and senior technical resources acquired in the Rice transaction.

Digital and data tools continue to increase in importance in this industry and the role of these tools will continue to expand at EQT in 2019.

We retained Rice systems that were differentiated and could improve our own processes.

But effectively using such tools is not as simple as flipping a switch.

Digital and data tools sit on top of existing systems that run the day-to-day operations, and they must be integrated with those systems to add real value.

As a smaller team building from the ground up, Rice had the advantage of choosing the day-to-day systems and defining the business process alongside the technology.

As a larger company, with a well-established technology ecosystem, the only prudent course of action was to pursue a measured, phased implementation.

That process focused on integrating Rice's digital and data tools with our existing systems without introducing major disruptions or operational risks.

This takes time and resources, but let me assure you, the most relevant and compelling technologies are far from dormant at EQT.

I would also like to point out that EQT has been on a data-driven digital transformation over the past several years, both before and during the integration of Rice.

EQT is evolving, along with most other sizable E&P franchises to be a more robust user of technology and data.

Evidence of this lies in our build-out of a centralized real-time operations center, our expanded use of cloud-based data services to support real-time analytics and our successful integration of certain legacy Rice tools.

The last point that I will with addresses is regarding our well costs.

As we stated in our January presentation, we do not agree that the Rice well cost projections are achievable or appropriately reflect EQT's 2019 operating environment.

We are believers in leveraging the power of technology to streamline operations, improve scheduling and planning and promote internal communication.

EQT has made great strides in this area over the past several years and it will be a critical component of our efforts to increase efficiency going forward.

But these efforts simply don't offset a 20% to 25% price increase in services from the cyclical lows of early 2017 to today.

The Rice cost curve, as presented in their public materials, is based on pre-inflation well cost results and a much smaller and more geographically concentrated produced water portfolio and is simply not a relevant comparison to the EQT 2019 operating plan.

Service cost inflation was real and felt by everyone in the basin.

If you adjust the Rice $735 per foot cost claim up by 20% for inflation, you see a significant erosion of their claimed savings.

In addition, consider the fact that EQT's producing water footprint covers 6x the linear mileage, running from Tioga County, Pennsylvania to Ritchie County, West Virginia.

The comparable Rice producing water footprint covered 2 adjacent Pennsylvania counties.

Put simply, this asset base produces more water across a larger geographic footprint.

That produced water must travel a greater distance to active fracs, resulting in higher trucking and water costs.

I will also point out that we view dollar per foot as an imperfect metric.

Accounting treatment of certain well costs varies widely among operators as does lateral spacing and frac design.

In our January presentation, we showed the dollar per foot increases as spacing increases, but these cost increases are more than offset by the enhanced returns and lower cost per Mcfe.

Remember, we make money by selling gas, not by selling feet.

In our January presentation, we also showed the significant impact that these accounting differences can have on cost per foot.

EQT capitalizes items that other operators expense like flowback, certain land and construction costs and the cost of moving impaired water to a drilling site for use in fracking.

These differences significantly impact the comparability of our cost per foot and is one reason why we have meaningfully lower LOE per unit compared to our peers.

These are real cash costs that are not showing up in the peers' dollar per foot metric.

And just to be clear, EQT's pure leading LOE per unit is not just a matter of scale.

Our 2017 LOE, adjusted for the cost of operating our Huron assets, was $0.07, far less than the $0.13 per unit for Rice during the comparable period.

I'll conclude by reiterating that we welcome and look forward to continuing discussions directly with our shareholders regarding this matter, and we will be diligent and thoughtful in our analysis.

This organization and this leadership team will continue to be laser-focused on executing the rigorous, bottoms-up and detailed plan that we laid out.

And we will be working hard to make that plan even better throughout this year.

The good news is that the presentation and accounting differences will all be washed out at the bottom line, which is free cash flow.

We remain focused on achieving lower cost and higher returns with a cash-driven mindset.

We have a compelling plan in place and a commitment to continuously improve.

This free cash flow machine is ramping up, and we're excited about 2019 and beyond.

I will now turn the call over to Jimmi Sue Smith to discuss our financial performance.

Thanks, Rob.

Today, I will briefly discuss the financial highlights for the fourth quarter and full year 2018 and then end with some forward-looking remarks.

But first, our notable accomplishments in 2018 included: the completion of 4 separate and complex midstream streamlining transactions that were negotiated simultaneously; the divestiture of our noncore Permian Basin and Huron assets, which significantly improved our cost structure and eliminated substantial plugging and other liabilities; and the execution of our spinoff with Equitrans Midstream, creating a premier, pure-play Appalachian midstream company and the third largest natural gas gatherer in the United States.

You will notice the difference in our reporting as a result of the November spinoff.

The financial tables that you see in the press release and our SEC filing later today are recast to reflect the operations of the stand-alone EQT for periods prior to the separation with the results of the midstream business reflected as discontinued operations.

The separation, combined with the divestitures of the Huron and Permian operations, position EQT as a pure-play Appalachian upstream company.

Now turning to 2018 results.

As detailed in the press release, EQT announced 2018 adjusted net income from continuing operations of $1.70 per share compared to $0.54 in 2017.

Adjusted operating cash flow attributable to EQT, which excludes cash generated by but includes cash distributions from the midstream operation was approximately $2.5 billion in 2018 compared to $1.2 billion in 2017.

Adjusted operating revenue increased 66% over 2017 primarily on increased sales volume.

For the year, EQT reported sales volume of approximately 1,488 Bcfe compared to 888 Bcfe in 2017.

Average realized price was $3.01 per Mcfe in 2018 versus $3.04 in 2017.

Additionally, as we highlighted in January, capital expenditures were in line with our prior guidance.

Moving to our operating expenses for the year.

With the Equitrans spinoff, we no longer distinguish between affiliate and third-party gathering and transmission expenses.

All of our expenses are with third parties.

Total gathering and transmission expenses increased on higher volumes in 2018, while processing expenses were down slightly year-over-year, primarily as a result of the 2018 divestitures.

On a per-unit basis, total gathering, transmission and processing were in line with the midpoint of our guidance at $1.14.

SG&A was up approximately $75 million for the year and the fourth quarter as a result of a litigation reserve and indirect midstream costs we were unable to allocate to discontinued operations under the accounting rules.

Excluding both of these items, per-unit SG&A expense for the year came in slightly above our guidance at $0.12.

Our guidance for 2019 is $0.11 to $0.13 per unit, reflecting the impact of fixed costs that were previously allocated to our midstream business, net of the cost savings we announced in January.

Lastly, I would like to discuss the impact of the asset sales as they pertain to our per-unit cost.

Lease operating expenses were down year-over-year primarily as a result of the divestiture of our Huron assets.

The Huron assets were very expensive to operate and, in addition, since 2016, we have gathered our own production in the Huron and reported those costs as LOE rather than gathering expense.

With the 2018 divestitures, our overall gathering costs per units are expected to increase slightly in 2019 as we no longer operate in the Huron, and we will record the costs to gather all sales volumes in gathering expense.

Excluding the Huron and Permian assets, per-unit gathering expense was $0.55 and $0.60 and per-unit transmission expense was $0.50 and $0.61 in 2018 and 2017, respectively, while divestiture adjusted per unit 2018 LOE was $0.05 compared to $0.07 in 2017.

As reflected in our full year 2019 unit cost guidance, we expect the 2019 cost per unit to improve or remain flat compared to the divestiture-adjusted full year 2018 cost.

Now moving to fourth quarter results.

The quarter was pivotal as EQT transitioned from an integrated energy company to a stand-alone upstream business.

Further, the new management team developed a structured plan to address legacy issues and focus on capital efficiency.

We announced, several weeks ago, a 4Q production beat of approximately 20 Bcfe on the midpoint of our guidance and a preliminary fourth quarter adjusted free cash flow projection of approximately $100 million.

Today, we announced actual fourth quarter adjusted free cash flow of $134 million and production of 394 Bcfe.

It's worth noting that the $134 million of adjusted free cash flow reflects the litigation reserve recorded in the fourth quarter.

Without this, we would have generated approximately $185 million of adjusted free cash flow in the fourth quarter of 2018.

Adjusted earnings per share from continuing operations was $0.79 in the fourth quarter versus $0.54 in the fourth quarter of 2017, while adjusted operating cash flow was approximately $693 million compared to $465 million.

Adjusted operating revenue increased 38% over fourth quarter 2017 on increased sales volumes, which were up approximately 100 Bcfe.

Average realized price for the quarter was $3.13 per Mcfe compared to $3.04 in 2017.

The increase in average realized price was the result of an increase in the NYMEX price, net of cash-settled derivatives and the average differential, offset by a lower contribution from higher-priced liquid volume.

I will now briefly discuss EQT's cash flow and liquidity position.

As of January 31, 2019, EQT had borrowings of $500 million under our $2.5 billion credit facility compared to the $800 million outstanding at year-end.

Based on the NYMEX natural gas curve as of January 31, we are currently forecasting adjusted EBITDA of $2.3 billion to $2.4 billion, and $2.2 billion to $2.3 billion of adjusted operating cash flow in 2019, which will fully fund our all-in 2019 capital expenditure forecast of $1.85 billion to $1.95 billion and result in $300 million to $400 million of free cash flow for the year.

Based on the shape of the natural gas curve and the forecasted cadence of drilling and production during the year, we expect our adjusted free cash flow will be higher in the bookend quarters of 2019, with $200 million to $300 million of adjusted free cash flow expected in the first and fourth quarters, although we expect the first quarter to be closer to $200 million.

This will be slightly offset by negative free cash flow of $50 million to $100 million in each of the second and third quarters of the year.

As Rob said in his opening remarks, we are working to identify the areas that will make up the cost savings in our Target 10% Initiative.

As part of that process, we identified $50 million of savings that we will implement in 2019, including: renegotiation of certain contracts for water hauling, temporary water lines, sound wall rentals, aggregate and winter maintenance, implementation of our proprietary water optimization model and other process changes and contractor savings incremental to those announced in January.

Again, we had not included this $50 million of savings in our 2019 plan announced last month, but we are now confident that we can implement these initiatives in 2019.

We will continue to update you as we identify additional initiatives that will deliver the target 10% in 2020 and beyond.

Finally, this management team strives to be efficient capital allocators.

Our 2019 and 5-year plan represent the optimal result from our iterative planning process that was run at multiple price ranges.

Put simply, at our long-term natural gas view of $2.85 NYMEX with negative $0.45 local basis, a 5% growth rate maximizes cash flow per share and delivers significant free cash flow through 2023, all before considering the upside from our Target 10% Initiative, which we are in the process of delivering.

This presents significant opportunity for increased shareholder value creation.

As always, our peer-leading balance sheet remains top of mind, and we continue to target 1.5 to 2x net debt to adjusted EBITDA.

And with that, I will turn the call over to Erin

Thanks, Jimmi Sue, and good morning, everyone.

As we have stated for the past 3 months, we have moved toward a stable operating model by maintaining a consistent fracture count that supports our strategic plan to generate significant cash flows and increased capital and operating efficiency.

We are being very cognizant about the proportion of ultra-long laterals, those with lengths greater than 15,000 feet, that we are developing simultaneously in our development program.

We have made changes on the drilling side that have improved our performance.

We have simplified the geometry of our long wells by eliminating back builds and made adjustments to our drilling mud properties and fine-tuned our connection and tripping processes.

As a result, our horizontal drilling performance in January of 2019 was approximately 25% better than the second half of 2018, improving from 1.17 days per thousand feet to 0.87 days per thousand feet.

Our frac crews have executed incredibly well in the early winter months, increasing performance by 65% from January of 2018 to January of 2019.

We fully expect that these efficiency gains will continue throughout 2019.

Our well costs in January are in line with the guidance we published in our January 22 presentation.

This all underscores that the operational missteps of 2018 are behind us.

As you may expect, the shift from a high of 12 frac crews in the middle of 2018 down to a steady-state operation with 5 to 7 frac crews in late 2018 and throughout 2019 will lead to some fluctuations in our quarterly volume cadence.

As a reminder, we turned in line 81 net wells in Q3 of 2018 and 45 net wells in Q4 of 2018.

The high number of Q3 tills resulted in high Q4 production.

We exited Q4 of 2018 at approximately 4.3 Bcfe per day and net sales for the quarter totaled 394 Bcfe, exceeding the high end of guidance.

Due to the move to stable operations and lower activity, our Q1 2019 production will be lower than the previous quarter and we are guiding between 360 and 380 Bcfe.

We expect to turn in line 31 net wells in Q1.

As a result, Q2 production will also decrease with subsequent increases projected in Q3 and Q4, ending 2019 with a full year guidance range of 1,470 to 1,510 Bcfe.

Even though our quarterly numbers will be lower in the first half of 2019 versus Q4 of 2018, we expect to average 4.1 Bcfe per day in 2019 versus a divestiture-normalized 4.0 Bcfe per day in 2018.

Moving on to reserves.

EQT's year-end 2018 proved reserves increased 11% to 21.8 Tcfe versus year-end 2017 when adjusting for our Permian and Huron asset divestitures.

The increase is largely due to the high activity levels in 2018, which resulted in the conversion of 2.7 Tcfe of undeveloped reserves into the proved developed category.

Our booked PUD length increased by 14%.

This increase in booked lateral length amounts to an overall increase in proved undeveloped reserves with 113 fewer top hole locations, resulting in significant fixed cost savings.

We replaced 317% of our 2018 production through drilling activities.

And including the negative offset from divestitures and changes to our 5-year development plan, we replaced 242% of our 2018 production with new reserves.

The PV-10 of our reserves increased by 29%, largely due to an increase in 2018 pricing over 2017, with a NYMEX price of $3.10 per MMBtu for 2018 compared to $2.98 per MMBtu for 2017.

I will now turn the call back over to Rob.

Thank you, Erin.

Our strong fourth quarter performance demonstrates our focus on enhancing operations and positioning EQT for increased efficiency, free cash flow growth and shareholder value creation.

While we are proud of the progress we have made, we are only getting started.

With that, I'll hand the call over to the operator who can open it up for Q&A.

Operator?

(Operator Instructions) Our first question comes from the line of Holly Stewart from Scotia Howard Weil.

Maybe, Jimmi Sue, just on my first question, you kind of rattled through that fast on the free cash flow bookends for the quarter.

I think that would imply, obviously, 1Q and 4Q and then negative free cash flow during 2Q and 3Q.

Is there any detail behind that?

Is that kind of just driven by the basis assumptions or is there a certain CapEx shift in those quarters that we should be aware of?

No, Holly, it's really driven by the shape of the natural gas curve as well as the shape of our production curve for the year.

Okay, okay, that's good.

And then just another maybe small one on the guidance.

It looked like there was a slight shift in the EBITDA change but no shift in cash flow guidance.

Is there anything to highlight there?

I think the big highlight there is the $50 million of additional cost savings we identified.

That lowered our CapEx guidance and let us keep our free cash flow guidance the same, even though we lowered the strip pricing, and that was what's driving the decline in the forecasted EBITDA numbers from our last release.

Okay, that makes sense.

Maybe 1 final one on the guidance, if I could.

It looked like EQM, this morning, reiterated their timing of 4Q for the in-service of MVP.

Is there anything baked into either your cost or basis assumptions for MVP at this point for '19?

Holly, this is Rob.

No, we're assuming that their guidance is correct that that pipe will come online in the fourth quarter, and that is baked into our assumptions on both basis and realized pricing.

But it really doesn't affect 2019 very much.

That's really a 2020 issue.

Okay.

Because it's probably late in the year.

And then one, maybe just 1 final one maybe for Blue, if I could.

It looked like basis came in certainly better than our expectation.

Is there anything right now just to kind of highlight in kind of the overall marketing landscape, I mean, it looks like your guidance for 1Q is pretty solid as well?

Yes, hi, Holly.

No, you're absolutely right.

With the new pipes that came online in 4Q and coming online in 1Q, so the basis -- the basis in Appalachia tightened up and so we were able to take advantage of that opportunity, and that's the primary conversation around that move.

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

I just wanted to talk a little bit about water.

It seems like water is kind of at the heart of a lot of the differences in cost structure that you all have discussed, also sounds like it was part of the early $50 million savings that you highlighted this morning.

Just wondering what can be done to potentially structurally address water costs and improve that over a longer-days basis?

And kind of what sort of initiatives -- a little more color on the initiatives that are in place right now.

Michael, this is Erin.

First on the initiative.

I'll say on -- we have 2 main things on the initiative, the first one is we were able to bring our water hauling rates down by an additional 8% since we first put our business plan together back in November, December time frame.

We've also implemented a proprietary water optimization model.

So this model was developed in-house by our optimization engineering team and the goal of the model is to really optimize the logistics of how we move our water and the number of trucks that we have on the roads every day to minimize our costs.

Is there anything to be done to just take trucks off entirely, I mean, any sort of additional capital projects that might make sense or the payback is just not there on those.

Or how are all you thinking about that?

Yes, Michael, there certainly is.

There is opportunity to pipe produced water and, obviously, there are geographic constraints to that and it won't work in every instance.

But we do have projects underway to develop piped water solutions, and not just for fresh water but also produced water.

And any time that we can make those economics work, it really is beneficial for us as we can get trucks off the road.

And from a safety, environmental and cost perspective, it is a win.

But there is not -- given the geographic footprint that we have, there's not a 100% pipe solution.

There will always be trucking involved to some degree.

Understood.

Okay.

And is any of that kind of contemplated in the outlook at present or...

It is not contemplated in the numbers that we've put forward or in the $50 million of cost savings for 2019.

And frankly, it's going to take a little more time.

So I think those are things that you would see in 2020 and beyond.

Okay.

And then I was also curious, just on the longer dated plan, I just noticed the average lateral length obviously increasing over time.

What are you all assuming in West Virginia at this point as it relates to lateral lengths and where you can get those?

And I'm just curious what sort of acreage spend is required to do that over the course of the 5-year outlook.

Sure, Michael.

This is Erin.

So on the West Virginia side, the real challenge in West Virginia for us is from a legislative standpoint.

And so it isn't necessarily spending more money on the leases.

It's more about trading acreage with our competitors, and we have great relationships with all of our competitors in West Virginia.

We're currently working some very large acreage trades, and you'll see that start to affect our 2020 and beyond lateral lengths in West Virginia.

So we expect to be relatively short this year, but the short wells in West Virginia still compete pretty well because of the liquids content of the gas.

And we also have firm gathering and transportation commitments that we're trying to fill in West Virginia as well.

So we expect 2020, you'll see a pretty large step change in our lateral lengths in West Virginia.

Okay.

So it sounds like maybe these trades are something we could hear and get formalized by the end of the year.

Is that fair to think?

That's is fair to say.

I will say I don't know that we would comment on it publicly, that's not typically our practice, but they are in the works.

Okay.

And the last one, just curious if there's any indications around timing of the general meeting, obviously that's been a focus point of late.

Appreciate any color if you're be able to provide any.

Yes, Michael, the date of the annual meeting hasn't been set yet, and it's obviously a board decision.

And the board has committed to an orderly annual meeting process that ensures that all of the shareholders' views will be heard and represented.

And so we'll come back to the market when we have more information on that.

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

Two questions.

One, and I apologize if you mentioned this earlier, but can you just break down the $50 million portion of the Target 10% Initiative driving down the CapEx relative to the call on the initial plan a few weeks ago, where that's coming from and the risk around that, one way or the other?

Yes, sure, Brian.

This is Erin.

So as Jimmi Sue mentioned in her talking points, the $50 million is focused in a couple of areas.

So the first one we talked about was water hauling, so bringing the rates down on our water hauling fleet and then also implementing our proprietary water optimization model.

The second area is around construction, both on the facility and civil construction side.

So we're working diligently to retrofit and redeploy our existing equipment for new wells and streamline our construction timing by prefabbing a lot of that equipment off location.

On the civil construction side, we've renegotiated rates for our sand wall rentals, our winter maintenance and our aggregate trucking.

And we've also aligned our survey and inspection needs to eliminate any redundancies in our processes.

And the third area that we have streamlined our processes around is production operations.

So we are assigning our work and deploying our resources by exception, which is largely due to the implementation of technology over the course of 2018 that we are now starting to realize the benefits of in 2019.

This, again, allows us to streamline our processes and eliminate any redundant work practices.

Okay, great.

And my follow-up is just on the constrained production.

What are your expectations for how that evolves over the course of 2019?

And what's the -- remind us again what's built into guidance there?

Yes, what's in the guidance is that we will relieve the constraints by the end of 2020.

As I've mentioned in the past, I do think that there's real opportunity for us to get that done quicker than the end of 2020, but I think it really will be late 2019, early 2020 before we see any meaningful movement on relieving the constraints.

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

Just a question on the COO process here.

Just wanted to get an understanding of what you guys are trying to look for in a new operating officer to come in.

You outlined a plan that you think already optimizes the best outlook for production and cash flow optimization.

Does this COO have to come in and work with that or 3 months into the plan -- 3 months into them being hired, they can go and rework the plan and come up with either a higher or lower growth rate or other cash flow outlooks?

Josh, here's what I'd say is, I think that our team, our organization has the right basic plan in place that we're executing on.

My expectation is that a new COO is going to come and bring added leadership and focus on real optimization around operational efficiency, and it will be incrementally improving the plan.

I don't think it's going to be throw this plan out and implement a whole new plan is much as help us optimize and get better.

The low-hanging fruit, we're doing a pretty good job of finding right now on our own.

I think that's -- and that's evident in the $150 million of cash costs that we've pulled out since November.

I think to truly get to a manufacturing type operation, it takes a little bit different mindset.

And I think that's where the new COO can help the organization get to.

So this is more an accountability to have a person in place to go and deliver this game plan, that's the sense I'm getting.

I think it's to -- frankly, I think it's to deliver what we've laid out, I think, can be done with the organization as we have it.

I think that the new COO is going to help us do better than that, get us to a truly manufacturing style of operation, and it's -- frankly, it's a change in mindset, right?

I mean, this has been an organization that's been driven by volume growth for a decade.

And so making the shift to capital efficiency, manufacturing style operation, it will take a little bit of time and I think some different skill sets.

Got it.

And then just wanted to follow up on the land spend.

I think you guys have outlined a budget of around $200 million annually.

This was also a big gap in the free cash flow differentials that the Rice fellows outlined, I think it was around $85 million.

Can you just -- I think they talked about some apps and technology that would allow them to reduce that amount.

Can you just talk about what the difference in the gap there would be as to why it's $100 million annually?

Well, I don't know what their assumptions are, they don't -- they didn't give much detail on those assumptions.

But the reality is there is money that will have to be spent to maintain our land position, and it can be spent either on leasing, it can be spent on operations to hold land by operations, and there is no magic app that's going to decrease the land spend by $100 million, that's just not reality.

And frankly, the apps that they've talked about on the land side, we have employed.

Actually, we're using those fully now in our land operations.

And the spend on land is just the reality of the business and there's no way to wave a magic wand over it to make it get cut in half or more.

Got it.

And then just a quick follow up on that.

The $200 million spend for this, is this to just maintain the inventory as is, that's roughly 12, 13 years, within that range?

Or does this actually extend it beyond that?

Or is it just to make sure it's not depleting?

Josh, it's really to maintain the inventory and for fill-ins.

There's always going to be gaps in the land position so it's to fill in those doughnut holes and lengthen laterals.

So it's a realistic look at what it will take to manage the land position and the drilling operations.

Our next question comes from the line of Sameer Panjwani from Tudor, Pickering, Holt & Company.

Given some of the issues that you highlighted earlier around West Virginia and the limited activity that's planned for the region in 2019, what's your appetite for carving off some of that acreage to offset the land spending for bolt-ons in Southwest PA?

It seems like it could be a pretty easy way to boost free cash flow while further high-grading your acreage.

We're always willing to consider selling acreage that's further back in the drilling queue if somebody is willing to pay us more than what we think it's worth in our portfolio, so we're always open-minded about that.

I would caution, however, that there's not a long list of buyers for acreage out there right now, given where gas prices are and the shape of some companies' balance sheets.

So while we're always open-minded about that, I would caution about too much optimism in terms of available buyers.

Okay, that makes sense.

And then I think you guys mentioned earlier, just as you ran the sensitivities on your 5-year plan, just trying to get a sense of how you think about increasing or decreasing activity according to commodity prices in order to meet your target of maximizing free cash flow.

I ask because current share pricing is closer to $2.70 versus your outlook of $2.85 that's baked into your 5-year outlook?

Yes, I'd say broadly, Sameer, that lower pricing that we think is going to hold will push us towards lower growth, and then, the opposite is also true.

But we're not talking about huge swings, right?

This plan already contemplates a mid-single digit growth rate.

I think that, if we believe that the forward curve is going to be at $2.70 or $2.60, that probably pushes us a bit lower, and you could see activity come down but not big changes.

Ladies and gentlemen, we have no further questions in queue at this time.

I'd like to turn the floor back over to management for closing.

All right, thank you all.

This is a very exciting time at EQT, and we really are encouraged by the progress we've already made towards delivering value for our shareholders.

Our plan is being successfully executed by the capable and hard-working employees at EQT.

We look forward to updating you on our progress and additional upside that we expect to realize throughout this year.

As always, none of this would be achievable without the dedication of the outstanding people of EQT.

Our thanks go out to all the EQT team members who are making this plan a reality.

Thank you.

Thank you, ladies and gentlemen.

This does conclude our teleconference for today.

You may now disconnect your line at this time.

Thank you for your participation, and have a wonderful day.