Q3 2019 Earnings Call
Ladies and gentlemen.
Thank you for standing by and welcome to eat to Teekay Corporation Q3 2019.
Quarterly results conference call.
This time all participants are in a listen only mode. After the speakers presentation. There will be a question answer session.
Ask a question. During this session you will need to press Star then one on your telephone if you will acquire any further assistance. Please press star Zero I would now like hand, the conference over to your Speaker today, Andrew brief director of Investor Relations. Thank you. Please go ahead Sir.
Good morning, and thank you for joining todays conference call with me today, our Toby Rice, President and Chief Executive Officer Chi on their own interim Chief Financial Officer, and Blue Jenkins Executive Vice President and Chief Commercial Officer.
A replay for today's call will be available on our website for a seven day period beginning this evening.
Telephone number for the replay is one 800 585 athree six seven with a confirmation code of 6678 to six nine.
The moment koby in Cairo presenter prepared remarks. Following these remarks, we'll take your question.
If you T. published a new Investor presentation. This morning, which is available on the investor relation portion of the web site 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 a factor described in today's earnings release.
And the risk factor section of our Form 10-K for the year ended December 30, Onest 2018, our subsequent forms 10-Q and other filings we may from time to time with the FCC, we do not undertake any duty to update any forward looking statements. Today's call may also contain certain non-GAAP financial measures. Please refer to this morning's earned.
At least 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, Thank you for joining us Im excited to share the progress we've made in a short period of time in what we believe we can accomplish moving forward.
About an update on 100, they 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 with the Kickstart, our evolution and deliver the foundational elements needed for us to achieve the cost saving targets that we discussed in our campaign October 18th Mark Day, 100, and I'm pleased to share with you that we have successfully executed on our plan.
Slide six 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 leader key leaders needed to complement the existing EGD team. These leaders have a proven track record of operating these assets to generate basin, leading operational performance and they're off to a great start over a dozen new leaders are offering fresh perspective, 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 SDMA expense and a $30 million reduction in capitalized overhead.
As it relates to our technological initiatives, we've made significant progress the workforce has fully embraced our digital work environment with participation in our platform increasing 700% since annual meeting.
Silos are being knocked down and interdepartmental collaboration and transparency are accelerating.
We prioritize the 90, most critical workflows needed for our modern technology, driven business and if successfully revive them within our digital work environment. These workflows and power our employees allow management to monitor the business spotlight inefficiencies and optimize our planning efforts to maximize shareholder value. We're 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 have successfully laid the tracks for large scale combo development by establishing a stable master operation schedule.
As a reminder, combo development consists of properly space large scale projects to develop 10 to 25 wells for multiple pads simultaneously. This is the key to delivering consistently low well cost 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, but to be set for combo development.
We've also had some quick wins in the field on slide seven we're 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 in 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 Egcs 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.
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 and kick starting our evolution.
We are on track to deliver on the well cost savings we promise during the campaign and we're doing it faster than we thought which sets up for success in 2020 and beyond.
The formal 2020 budget will be approved by the board in December , but we're excited to share our preliminary outlook.
Our capital allocation philosophy has not changed we plan to de lever IEC UTI to below two times net debt to adjusted EBITDA and in this gas price environment, we plan to get thereby reducing absolute debt through free cash flow generation in asset monetizations, rather than outspending cash flow to grow EBITDA.
Further as we discussed on the Twoq call, we evaluated each of these 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.
Strip pricing as of 930 or 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 at the four 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 capitalize overhead.
We further breakdown of reserve development budget by our three operating areas, Pennsylvania, Marcellus West, Virginia, Marcellus in Ohio, Utica, We plan to operate two to three topple rigs three to four horizontal rigs and three to four 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 used in 2019, largely due to efficiency gains realized during the implementation of our 100 day plan.
And our Marcellus operations, we expect full year 2020, well costs to be approximately $745 per foot in PA and $900 per foot in West Virginia and.
And we expect over 90% of our 2020 wells spud will be at 1000 foot spacing.
On Slide 11, you will see a breakdown of our development plan by operating area I'd like to call out the increasing lateral lengths in all three operating areas, which will contribute to lower well cost per foot.
I'd like to highlight West Virginia in particular, you tease average lateral length for wells turned in line. In 2019 is 4600 feet, but is expected to increase the 8900 fee in 2020 and jump to 12500 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 operation 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 Egcs 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 capitalize interest the asset maintenance bucket represents spend related to site compliance well to be installations road repairs and other general maintenance projects. This capex is generally unrelated to current development and is therefore not.
As 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 consists primarily of employees and overhead that can be allocated directly to our development projects.
Slide 12 puts our budget into context, we believe we're on track for a 25% decrease across a large portion of egcs controllable costs as compared to legacy 2019 cost.
On the left we are showing Pennsylvania, well cost per foot well costs are expected to declined 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 teams, while cost estimates through.
Requeue, well cost stand at approximately $850 per foot, which shows good progress.
For Q well costs are 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're showing gross DNA, which is SGN a expense plus capitalize over at 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 EGD resumed production growth in the future. These savings would grow accordingly.
Turning to slide 14.
This is purely illustrated but highlights what we expect 2021 and 2022 Capex would be if we wanted to maintain 2020 production volumes.
We expect Capex would decreased to approximately $1.15 billion and 21 and dropped to $925 million in 22.
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 as the next step and lowering cost structure.
He is going this negotiation is straightforward simplify the structure and reduce gathering fees to enable EGD the ability to grow volumes through equitrans systems, and generate free cash flow and 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.
Timing of fee relief will likely be tied to the in service date of Mountain Valley pipeline project that including other related projects is expected to add over $300 million of EBITDA for Equitrans upon going in service.
Second UTI 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, UTI can dedicate the remainder of its undedicated West Virginia acreage position to Equitrans as we've highlighted before west Virginia will become a larger part of BTT story going forward.
Our recent success and extending laterals executing acreage swaps and lowering well costs. So this area is competing for capital I'm encouraged by the progress. We've made in 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, Debbie 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 MACRA.
In the third quarter, we achieved net sales volumes of 381 Bcf fee at the high end of our guidance range.
Third quarter, Capex was $475 million, which is $380 million or 44% lower compared to the third quarter of 2018.
It 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 or negatively impacted by two 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 reported 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 two items adjusted operating cash flow and adjusted free cash flow would've 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 Bcf fee, a 4% decline from the third quarter at the midpoint. This is driven by changes to the operation schedule and implementation of our choke management program.
Average differentials are expected to be negative 45 to negative 25 cents per mcf fee.
Capex to be 320, $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 by 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 Frac, the 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 as 930 equities net debt to LTM adjusted EBITDA was 2.2 times and assuming a sale of you could use retained stake in Equitrans is used to repay debt that ratio decreased to 1.9 times.
You can see is expected to generate between 200 300 million of adjusted free cash flow in 2020, Leverages 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 Tony mentioned in the current commodity price environment, we're 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 look further.
We remain committed to maintaining our investment grade ratings and believe its strategic differentiator amongst our peers. This is not merely lip service, we think the best way to increase the stock prices by delivering the business to thrive and a 250 gas price environment.
To achieve this we're committed to reducing absolute debt by at least one and a half billion dollars or 30% by mid 2020.
On slide 16, we outlined the levers we can pull.
First egcs retained stake in equitrans represent $750 million of value at current market prices.
We have multiple options for divesting the stake that go beyond the simple block trade on the open market.
We are not long term holders and will likely divest the stake in the next nine months.
We have a number of assets that are outside of our core Marcellus fairway 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 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 these core mineral interest.
Today.
50000 fee acres in our core footprint that contributed to an average updates net revenue interest in our Pennsylvania acreage of 83% and in our West Virginia acreage of approximately 85%.
As our peers as shown in these monetizations of these types of assets can be highly deleveraging given egcs relatively higher net revenue interest larger production base and undeveloped acreage position. We are confident this strategy could generate significant proceeds that can be used to de lever without a significant impact on development returns. We are actively exploring this up.
It's entity and believe a transaction could be effectuated in a matter of month.
Delevering as a strategic priority for agency, we believe execution of this debt reduction plan is achievable in the near term and will allow you 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 of liquidity on slide 17.
The cuts of the Chase we have a plan in place and do not believe the impact of a downgrade when materially change our current liquidity position.
Focusing on the chart underwrite.
As 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 DCT, one notch certain counterparties would have the option to call up to approximately $850 million of letters of credit the primarily relate the duties 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.
So sizing the accordion does require banker 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're 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 manage liquidity today.
He 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 three initiatives when more than offset the $850 million of potential posting requirements, assuming they are called EGD as an additional $750 million of potential posting requirements Equitrans and MDP.
Ultimately, we do not believe these will be called for a variety of reasons, but we have sandy impacted liquidity as a further downside scenario.
To be clear, we recognize that TD has upcoming bond maturities, we have multiple options to both retire and term out the debt even in the downside rating scenario, we have market access today, we have set up a development plan to generate free cash flow and we're highly focused on executing our debt reduction plan by mid year, 2020, which will only serve to enhance our.
Leverage and liquidity profile to improved terms on potential future bond issuances.
A quick note on the gas macro we've been encouraged by the decrease in rig count over the last few months.
Appalachian rigs have declined from 80 rigs at the beginning of the year to 52 today, we believe the basic 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 Appalachian 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 are in the Delaware basin, which is the largest contributor to associated gas growth.
Ultimately Permian guess constrained by takeaway capacity Kinner, 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 the 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 in 2020 and could lead to exit to exit production declines.
The supplied set up 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 we'll continue to focus on lowering costs further to allow easy 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.
100 day plan has positioned DQ T for long term success.
We believe we will reduce ctcs controllable costs by 25% in 2020, which will drive $400 million of annual cost savings, assuming a maintenance development program.
This is allowing you to generate $200 million to $300 million of 20 to 20 adjusted free cash flow at strip prices.
With the operating model in place, we're now focused on negotiating our gathering fees lower and believe this will firmly position.
The lowest cost gas operator, with the deepest inventory of tier one locations and not just the Appalachian basin, but the entire us.
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 QNX.
As a reminder to ask a question.
The press Star one on your telephone to withdraw your question press the pound or Heskey. Please standby will be compiled the culinary roster.
Your first question comes from the line of era.
Aram from JP Morgan Your line is open.
Yeah, Good morning Jen.
Kyle I wanted to start with you.
Looking at your unit cost guidance for 2020.
It does highlight about an eight cents per mcf fee increase.
Despite the fact that MVP I think you're now anticipating that to be on in 2021 can you get through some of the moving pieces there and.
Secondly, just maybe characterize.
Your confidence.
In terms of the negotiations with the train to receive a successful win win kind of outcome.
This quarter.
Hi. Thanks. This is this has to have ill take that.
Just walk me through our unit costs gathering is going to be up five cents. This is largely coming from under utilized nvcs that we have so when we look at our our gross production. We while we do have our nbcs covered across all systems. There are certain certain areas that are under the NBC volume thresholds. So.
We're working on some creative solutions to to reduce the underutilized nbcs.
But this is this is something that can be solved with the renegotiation with equitrans.
On the on the transport side of things this is up a little bit, but thats due to new contract coming online when we look at our low cost is coming up a couple of cents.
This is due to a little bit of a slowdown in completion activity. So our salt water disposal costs are going up a little bit.
We think that the keys to getting this back in line to 2019 levels.
Ken can be helped with more efficient scheduling on the produced water side of things also our choke management program is going.
Lead less wear and tear in our production facility. So that would decrease some of the part repairs that make up our low cost.
And then on top of all this basis differentials are expected to be.
For Penn five cents lower than our 2019 and this offsets some of these increases.
Going forward.
Your second point on on our each train comp our confidence in renegotiating.
Our gathering range with the 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 increase the amount of quality revenues that that you trains received and thats through increasing our nbcs commitment. We can 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 and it could you could make a great set up for a great deal with the train.
Great and my second question.
Jeff have you been and contact yet with the rating agencies regarding the $1.5 billion asset monetization program the involved.
This morning, and just wanted to know if you could maybe highlight.
Priority is between.
Looking at a mineral sale versus.
Upstream assets.
Alighted on slide 16.
Yes sure.
We have not.
Working with the agencies about this specific debt reduction plan, obviously, we've been speaking to them leading up to earnings and.
Obviously, equitrans our retained stake and 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 were.
We are targeting executing this by midyear 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 theyre, all actionable and all Expo in the near term.
So I wouldn't give any preference to one or the other but they're all being evaluated today.
Great. Thanks, a lot.
Your next question comes from the line of Bryan singer from Goldman Sachs. Your line is open.
Thank you good morning.
Wanted to follow up on slide 16.
Slowed with the with the detail that you've provided on the potential divestiture candidates.
A couple of questions for.
How if at all is the timeline and need to renegotiate the equitrans contracts related to the timeline to consider the divestiture of your stake and in your free cash flow of 200 300 million for the company. Overall does that include the distribution from from Equitrans, maybe I'll start there and I've got one other on slide 16.
Sure I'll start with the the last question for Rcs, our adjusted free cash flow guidance. In 2020 includes a $90 million dividend from Equitrans. So thats included there.
In the first part of your question remind me what that was.
Yes, the timeline the timeline the same in terms of renegotiate Equitrans contracts and then also considering the divestiture of your stake in is there any one that you would want to come before the other or or maybe other way around do you see your ownership of Equitrans add helpful mentions of your ability to get to get the renegotiation completed.
Sure I think we're looking at we're approaching this train renegotiation as some that's going to be positive for both companies.
So.
We will continue to hold the train stake as we 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.
Relative to the second quarter.
You mentioned on your color on your prepared comments that kind of make a decision MLP paraphrasing here, whether or not you want to grow and what the rate of growth is can you just talked about what would go into that as you think about the red activity levels and is essentially set up for flat production at the end of 20 at the end of 2020.
Yes so.
What we've laid out for 2020 gives us optionality for potential growth in 21, we've we've got enough capex budgeted and 22, either stay flat in 21 or grow depending on a number of items that we laid out earlier.
How things go with Equitrans men renegotiation gas prices and then just as our longer term development plan comes together.
Is there a further reduction in cost that you may want to see to say at the current commodity strip.
Growth makes sense for 2021, or if commodity prices don't change would in aggregate when do you need to see to say.
It's worth stepping up on the.
On the activity.
Yes. This this is totally out I would say that the cost reductions that were looking for in the future going to be coming more on the unit cost side of things so seeing reduction in gathering fee relief is.
The goal of this of this deal for Us is.
Achieve meaningful fee relief that allows us to to grow to 50 gas price environment and generate free cash flow.
So thats where were looking to to try and achieve with this.
With this renegotiation in that that would change our growth going forward.
Thank you.
Your next question comes from the line of Josh Silverstein from Wolfe Research. Your line is open.
Thanks. Good morning, guys, you outlined the 200 $300 million in free cash flow. This year I think was highlighted before that some of that is from the.
The trend distribution.
How sustainable is that you given the reduction in maintenance level spending going into 2021. Once you. Once you divest you train you don't have the cash tax benefits in some of the hedge benefits roll off is that a good number for for 2021 zone.
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 will be made up by.
Lower capex expenditures, given will have a full year of well cost reductions baked in.
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 any non cash flow producing assets that might be divesture candidates as well.
Obviously some of your peers are going down the same path as well on divesting cash flow.
And it hasnt necessarily been rewarded in stock price yet so I just wanted to see if there any other assets out there.
Not not really that someone would would pay something meaningful for I think the mineral interest side of things there's an implicit.
You get credit for some undeveloped value and how some of those deals are structured.
And so yes.
The one example, where we'd be able to.
Generates and proceeds from non cash flowing assets.
And I know you haven't fully disclosed this program yet with the with the rating agencies, but in your view is is the one and a half billion debt reduction more important than a leverage ratio going down I'm, just trying to get a sense as to what might be more important is like absolute debt because.
As you are going to be losing EBITDA.
If you go and divesting these assets.
Yes, Thats right.
Both are important but when we look at the numbers executing this debt reduction program. In addition to the free cash flow generation that and that is going to lower our leverage profile and we'll be able to maintain investment grade metrics also has the added benefit of bringing and proceeds which help us manage our maturities that are upcoming.
Great. Thanks, guys.
Your next question comes from the line of Michael Hall from Heikkinen Energy. Your line is open.
Thanks, Good morning.
Just curious if you could discuss a little bit more on the progress you've made in the west Virginia well costs.
Things.
Let the key drivers of those improvements with that and then.
Yes, how how material is that in helping west Virginia competes 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 Leonard.
Sure Michael I'd ask you to turn to slide 11.
On the top right there, we've we've shown our west within your Marcellus activity.
And and we sort of order these bar charts.
From turned in line to spud.
You can see one of the big drivers in our 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 are going to be turning in liner.
Almost 9000 feet and Thats, the new wells that were Spudding in West Virginia in 2020 are going to be.
Almost 12000 foot lateral so that's going to be one of the largest drivers of our of our.
Cost savings and and Western your 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 support long laterals on the schedule.
Okay, and what is I guess I think is a $900 a foot.
This last quarter for for West, Virginia, If I got that right I mean, what he's trying to get that down to everybody. Thank you can cut that down to.
Yes, Michael So 2020, we have that around $900 a foot and.
We expect that to continue to come down as we as we get a more consistent schedule that as 12000 foot laterals.
Second that could come down closer to lessen $800 a foot.
Okay. That's helpful.
And then I mean.
I guess, it's worth asking any sense on.
Quantifying what what sort of impact you think this this rate relief might.
Provides.
Please sort of.
And then turn to guardrails around that.
Yes.
Now Michael out while we're in negotiations, we're not going to provide guidance on that.
Yes juniors.
Sounds good I appreciate it guys congrats on the progress.
Your next question comes from line of Holly Stewart from Scotia, Howard Weil. Your line is open.
Good morning, gentlemen, maybe just one other quick follow up on on Slide 16, what is assumed in NIM in the EBITDA guidance, you're highlighting secondly, Tony since you're highlighting.
Potential to divestitures and what impact that.
Yes. Good question, how its 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 billion a half of monetizations and we'll provide updates to guidance as we announced them.
In general free cash flow will decrease.
After selling assets, but that will 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 and on free cash flow.
But it allows us to maintain investment grade metrics brings and liquidity ahead of the upcoming maturities and obviously at the big focus for us.
And then maybe cows to follow on to that do you have or do you all have a sense of what the rating agencies unwind.
You have accomplished as a review the business in the rating.
Yes that they want to see.
US maintain investment grade metrics and for us to do that Thats divesting assets generating free cash flow and so I really think it's this plan specifically is what they want to see.
Executing.
Yeah.
Okay, and then maybe just one final one from me.
Toby you Didnt mention any.
Any part incident I going to water conversation initially that Larry.
Highlighted.
With a gathering fee adjustments.
The conversation with the training that still apart of the conversation.
Yes, the focus has been on.
The biggest needle mover for us, which is which is on the gathering but certainly water would be a natural follow on discussion for us to for us to have.
Yes.
All right. Thanks.
Your next question comes from the lightest Sameer Panjwani from Tudor Pickering, Holt and company. Your line is open.
Hey, guys good morning.
You highlighted minerals as a potential monetization candidate, but look to see if you've given any thought as to how you are willing to take that and arrive from.
84% on average and then maybe as you've had conversations with Counterparties on this.
The early implications on valuation holding up to what we've seen recently from tier transactions or has it has kind of that benchmark changed drastically in past few weeks.
Yes, we don't have a specific and our target in mind.
Today, and and haven't gotten into valuation discussions as of today.
That said, we think that what we're offering is a pretty compelling investment too.
Wide University of investors.
Absolutely.
Has the largest production base.
In the country cross a massive undeveloped acreage position in the core of the Marcellus So.
We're.
Pretty excited about what would be able to do with the deal structure around these minerals.
Okay. Okay. That's helpful and then on the renegotiation wanting to make sure I understood. A few things correctly. Thank you mentioned the timing of the lower gathering rates and me concurrent with the startup of NBP. So if the project continues to get delayed would that also delay lower gathering rates rates UTI and then on a more nuanced.
I think he also highlighted.
Potential increase to Nvcs.
Right now they're shortfall fees, so what am I missing there.
Yes, Thats correct on the on the timing.
Inc. at one of the 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 that in the associated nbcs within each area. So.
That would be in increase step up in nbcs would be paired with.
The elimination of all these individual areas I think that would give us greater flexibility to.
Focus our development on.
Where the condo development makes makes is available for us.
Able to deliver.
Volumes and meet our MVC commitments that equitrans.
Okay, great. Thanks, guys.
Your next question comes from the line of Ross Payne from Wells Fargo. Your line is open.
How you doing guys.
For just a little bit a clarification does a 2020 budget include savings in the second half.
Because of your restructuring so some of your rates there and second of all MVP is delayed again are you still committed to selling equitrans mid year.
We don't assume any fee relief in any of our guidance numbers.
And we're committed to divesting equitrans in the next nine months, regardless of NBP timing.
Okay. Thanks, so much.
Your next question comes from the line of.
Fitzpatrick from Suntrust. Your line is open.
Hey, good morning.
A quick clarification, one for me to distort Kyle I think you said.
That we could see exit to exit declines.
At the endeared statement was 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.
Three to four months and that that's not just our view that a couple of.
Industry analysts are starting to look at where supply could shake out for the lower 48.
Could see that scenario playing out.
Yes, good good to hear and then.
A follow up on the.
50000.
Or fee acres can can you give some sort of production metrics that might go along with that so we might be able to back into.
Prices in some of these recent comps.
Yes, I am not mistaken I believe some of the transactions range has been able to execute its really more on a cash flow multiple basis has been in the 12 to 13 times.
Cash flow.
And in can you give us any including as to the cash flow on that 50000 core fee acres.
Yes, I mean, it's it would be we can kind of carve out whatever we won on the royalty side and include these fee acres as part of that.
So we can kind of design whatever mineral structure, we won.
Okay, great. So it's almost it's almost a plug to get to the one five that that makes sense. That's all that thanks guys.
Your next question comes from the line of true then.
From Morgan Stanley Your line is open.
Good morning, guys. Thanks for all that Mckellar on.
On 2000, Tony.
Regarding the asset sales can you give us any more detail on the NPS Etsy identified he said I believe outside of the Marcellus fairway, but any more color would be helpful.
Yes, Andrew I would I would say our focus is going to be on in this in this very so everything is just going to be outside of that.
And there's there's these are some of the the pruning that needs to happen and by setting some of these out some of these noncore assets that are outside the fairway.
Or is one of things that could help.
Focus our development and reduce some of our operating expenses as well, so specifically southern lesser than.
Central PA, Ohio those are assets that are that are on the table.
Okay, and Ohio, including the entire Utica.
The Ohio Utica, Yes.
Okay.
One other one just on financing and addressing the maturities.
Just wanting a bond offering today be one solution to refinancing at $20 21 maturities.
Absolutely we have market access today.
We've seen our 2007 nodes rally pretty significantly in the last two weeks, especially after this morning's announcement.
So yes, we have access today, but we also know.
Executing some of these monetizations.
Only helped to drive terms on a potential bond offering so.
We will continue to opportunistically evaluate the market.
Thanks.
Your next question comes from the line of Jane tried and true dense call from Stifel. Your line is open.
Thanks, Good morning, and thanks for taking my questions looking at slide nine.
Can you maybe talk about the key drivers follow well cost apart from the longer laterals and maybe what has been driving that performance year to date.
Sure we're looking at slide nine is.
Was our original expectation on when we can achieve these cost savings I think part of the some of the things that are allowing us to.
Do this faster than we thought.
What has to be a little bit of a softer service price environment, certainly accelerates that.
And two we I think we've been able to put together a much higher quality schedule and a shorter period of time than we originally anticipated.
Okay. Okay.
I have a follow up question.
In Joseph.
Changes that you're making two well designs.
You mentioned longer laterals.
Did you any other changes maybe like proppant loadings spacing.
Yes, I mean, there's there's 40 different parameters that we've identified that that have the ability to impact the economics of our of our wells by plus or minus 5%.
So yes, we've made changes to some of the bigger bigger ones would be proppant loadings clusters number of clusters per stage.
Water loading.
So, yes, weve and we're adding some new technology and that we're testing out now so we have a.
Proven while design that we're putting in but we're also evolving that well designed to adapt to the environment that we're in.
Hi, So you can you guys talk maybe in terms of is it like higher proppant loadings.
Why the spacing that externally.
Yes. It it's the same very similar well design that we executed at rice energy.
That led to basin level.
Jason leading well productivity and so at that same well design, we're just spacing it out to 1000 feet and we actually published our type curve. This morning on the website, we expect that to generate in the U.R. of around 2.4 Bcf per thousand.
Got it this is very helpful and my last question is.
Related to DNA expands and that so that you included the impact of Royalton Litigation Asia.
Just curious if it's going to impact cash flow Monday.
Yes, so we've accrued for everything which we feel a loss is profitable 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 of these type of issues going forward.
I see anybody that we shouldn't be expecting it.
Okay.
Do you expect that to happen in Fourq, you as well I just saw that that happen.
Thank you and then we had.
Glenn often impact on DNA into Q.
Yes, I mean, we've we've accrued for everything that that that we know of today.
And it's tough for us to BRCA and the future, but but.
Building, a sustainable business of doing things the right way is going to be our safeguard against.
Unexpected litigation expenses in the future.
Okay got it thank you so much.
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 on 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.