Q4 2019 Earnings Call
[music].
Welcome to range resources fourth quarter and year end 2019 earnings conference call.
All lines have been placed on mute to prevent any background noise statements made during this conference calls that are not historical facts are forward looking statements such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in the forward looking statements. After this.
Peakers remarks, there will be a question and answer period.
At this time I would like to turn the call over to Mr. late Sunday, Vice President Investor Relations at range Resources. Please go ahead Sir.
[noise] Mr weight sandals.
Vice President Investor Relations at range resources. Please go ahead Sir.
Thank you operator.
Morning, everyone and thank you for joining Arrangers yearend earnings call.
The speakers on todays call or Jeff Im sure Chief Executive Officer.
Dennis Degner, Chief operating officer, and work Skokie, Chief Financial Officer.
Hopefully you've had a chance to review the press release and updated Investor presentation that we posted on our website.
We also filed our 10-K does he see yesterday.
Well on our website under the investors do where you can access it using the Fccs Edgar system.
Please note that will be referencing certain non-GAAP measures on todays call.
Our press release provides reconciliations of these are the most comparable GAAP figures.
For additional information, we posted supplemental tables on our website.
I was just in the calculation of EBITDAX cash margins and other non-GAAP measures.
With that let me turn the call over to John.
Thanks, Lee and thanks, everyone for joining us on this morning's call.
Looking back at 2019 range made steady progress one key strategic objectives, improving our cost structure executing multiple accretive asset sales.
Using debt.
Bolstering liquidity and completing or 2019 drilling program safely in under our original budget.
Looking at unit costs first range was able to reduce cash unit costs by 12% over the course of 2019.
Mark will touch on the improvements in more detail, but it's important to point out that these unit cost reductions drive lasting enhancements to margins and cash flow.
Don't require a changing commodity price.
While we made significant improvements across the board in 2019 on G.P.M.T. Elouise DNA and interest expense, we remain focused on becoming even more efficient in the years ahead.
Operationally the team continues to innovate and reduced normalized wall costs.
As a result of thoughtful planning efficient operations in a laser focus on capital discipline. The team was able to deliver the 2019 operational plan for 28 million less than originally budgeted.
This is the second consecutive year range has achieved these types of savings spending less than budgeted, which is a reflection of work commitment to discipline capital spending.
Range has been a leader in well cost per foot amongst Appalachian producers since discovering the Marcellus.
As Dennis will discuss the operational plan that we've laid out for 2020.
We're continuing to find ways [laughter] to become even more efficient with our well costs approaching $600 per lateral foot, which is the best amongst our peers.
Ranges class, leading DNC costs, coupled with our shallow base decline in our substantial core inventory all come together to support a very low and sustainable maintenance capital.
Ranges base decline entering 2020 was approximately 20%, allowing for maintenance capital of approximately 500 million.
Importantly, this maintenance capital figure is sustainable as the lateral footage ranges drilling completing and turning in line for the year is all very similar leaving us well positioned to continue into 2021 and beyond with equal or better capital efficiencies.
This is unlike what we've seen for many many others in the industry.
Relying on significant duck drawdowns from massive else spends in the last couple of years to provide a short lived tailwind into 2020.
Rather our 525 million all in capital to produce 2.3 Bcf per day is sustainable going forward in as a positive differentiator for range.
We announced this years 520 million capital program last month, which is aimed at aligning spending with cash flow.
Prices have come down since then but we are fortunate in that we have flexibility to adjust our program as we or efficiently utilizing our existing infrastructure and have cushion over and above our various commitments.
And every year is budgeting cycle, we're looking at multiple scenarios as we seek to optimize our operational plans and financial outcomes. This year is no different in if we don't see an improving macro we will adjust our capital accordingly, as aligning spending with cash flow remains a priority.
As I just previously highlighted branches come in below budget for the last two years [laughter].
With touted our shallow base decline.
Lower well costs and maintenance capital requirements for years Importantly, these positive differentiators bear out in the reported results taking a simple look at the relative capital efficiency using actual DMC capital spend per unit of production range, let all Appalachian producers in 2019, and we expect.
Similar results going forward.
As others exhaust their core inventories in the years ahead range remains well positioned with multiple decades of inventory, providing us with solid base for delivering free cash flow overtime.
Looking back at the last 18 months range also made significant progress bolstering our financial position not only have we improved our cost structure streamlined our operations and continued to add hedges our capital spending has been at or near cash flow from operations, allowing us to reduce absolute debt by approximately.
$1 billion through asset sales.
In the fourth quarter of 2019, we also increased the commitments on our credit facility from 2 billion to 2.4 billion further enhancing liquidity.
When paired with the refinancing of 550 million of dead in January range has materially de risk gets go forward plans.
We remain active in our efforts to monetize additional assets and remain focused on positioning the company for success through the cycles.
The asset sales range accomplished in 2019, not only improved our financial position, but also reflect the significant value that range has in its asset base value that we believed is not reflected in the equity market today.
This substantial store a value is also reflected in ranges proved reserves at year end 2019.
At year end 2019, the PV 10 of ranges proved reserves with $7.6 billion.
For context after backing out our current debt balances this equates to over $17 per share.
In addition to proved reserves, which only accounts for the next five years of development range also has thousands of additional core Marcellus wells that provide range, a class leading inventory and future runway.
As inventory life and core exhaustion become growing narratives for the shale industry ranges depth of core inventory is an important differentiator and competitive advantage in comparison to both Appalachian peers as well as operators and other basins.
Before turning it over to Mark and Dennis I'll reiterate that I think range has made great progress over the last 18 months in the face of a difficult commodity environment.
We lowered our unit cost significantly we delivered our operational plans at less than originally budgeted for the second year in a row.
We continue to lead and well cost and capital efficiencies and we significantly de risk. Our go forward plans paying down over 1 billion in debt in refinancing our nearest term maturities over to you Dennis.
Thanks, Jeff.
Capital spending for the fourth quarter came in at approximately $152 million, while their capital spend for the year totaling 728 million.
This includes 667 million for drilling and completions.
87 million on acreage and 4 million for gathering and other support activity.
Our actual spend was $28 million below our capital plan set at the beginning of 2019.
And is a direct result of the operational and too.
Let upon ranges operational efficiencies.
Implement innovative technologies, such as an electric fracturing fleet.
And produce service cost in the current environment.
Similar to our message one year ago.
The initiatives that underpinned our capital understand in 2019 are primarily attributed to the continued success of our water recycling program.
Improved drilling and completion efficiencies and service cost reductions.
I'll go into more detail on these items in just a few minutes.
Last year, our message was clear.
We expect capital spending at or below budget to be the rule not the exception and the team delivered yet again.
Production for the fourth quarter came in above 2.34 Bcf equivalent per day, putting us firmly at the upper end of our Q4 production guide.
This generated annual production of approximately 2.28 Bcf equivalent per day.
4% higher than 2018.
Our annual production was comprised of 30% liquids and includes the production impact of asset sales executed during the year.
Continued excellent field runtime of our operations and strong well performance from both new and existing wells across southwest PA helped us deliver on our production plan to round out the year.
As we look forward into 2020.
Our capital budget has been set at $520 million with our activity focused on the Appalachian Marcellus program.
We have earmark, 94% of the capital will be directed towards drilling and completions related activity, which is in line with last year's budget.
The program will consist of 72 wells being turned to sales during the year.
While capital allocation will result in approximately 50% of our turn in lines to be located in our dry gas acreage with the remaining 50% being split across our liquids rich position.
Similar to prior years.
Approximately half of the wells planned it turned to sales this year will be from pads with existing production.
Moving back to pads with existing production has become a routine part of our program year end and you're out.
Allowing us to reduce cost.
Maximize infrastructure utilization.
And now will be a great fit with an electric fracturing fleets, which I'll go into more detail later.
Our planned average horizontal linked per well is projected to increase this year with our turn in line, averaging approximately 11200 feet. While the average drill horizontally will increase to over 11400 feet a.
Our year over year increase for both.
The capital plan for 2020 is projected to maintain production at approximately 2.3 Bcf equivalent per day and provide ample flexibility as we evaluate evaluate options for 2021.
Consistent with prior years capital spending is expected to be weighted towards the first half the year.
With approximately 60% of the capital spend taking place across the first and second quarters.
Looking back on some of the fourth quarters operational highlights in Appalachian the team turned to sales 23 wells on seven pads during the quarter from an average horizontal length of over 11900 feet.
This brought the 2019 total number of wells turned to sales to 84.
With approximately 60% of the wells located in the wet and Super rich portions of the field, allowing for utilization of existing infrastructure.
The wells turned to sales in the fourth quarter were spread across all three areas of the field covering our dry wet and super rich acreage.
And generated some of our top producing wells for the year.
This included six of our top producing wells per 2019th.
And the wet gas area, we turned to sales 10 wells in the fourth quarter with an average horizontal length of more than 14500 feet.
The wells were strong performers and help fully utilize our wet gas gathering system in Q4, resulting in lower unit cost.
And the Super Rich portion of the field, we turned to sales five wells on two pads in the quarter.
These pads are approximately 30 miles apart flaking, the north and south ends of our Super rich position.
Both passive generated strong 30 day rates of more than 15 million cubic feet equivalent per day per well.
Further showing the consistency of our acreage and ability for repeatable performance in the years ahead.
And lastly, and the dry gas area, we turned to sales our highest total producing pad up 2019.
Our seven well pad was turned to sales early in the fourth quarter and produced at approximately 150 million cubic feet per day under constrained conditions for the remainder of the year.
In addition to drilling some of our longest laterals and 29 team. The team was able to achieve new operational efficiency levels with our average daily lateral footage drilled increasing approximately 30% in the fourth quarter compared to Q3, and 36% higher than the full year average.
In fact during the quarter range experienced our most efficient month for drilling operations, capturing an average daily lateral footage drilled of more than 5200 feet per day.
All while staying within our plan targeting.
This substantial increase in daily footage drilled is directly attributed to utilizing the latest directional drilling and drilling fluid technologies for both curve and lateral applications.
This type of performance is a key driver in our peer leading drill and complete capital efficiency for 2020.
In completions during the year. The team completed just under 4400 frac stages at an efficiency of 6.8 stages per day.
Which represents an 8% increase compared to the prior year.
All while reducing the average number of cruise needed.
In addition to improving efficiencies the completions team continued their testing efforts of an electric powered fracturing fleet.
Which resulted in contracting that fleet starting in the fourth quarter.
By replacing the diesel fuel with this fleet on the three test pads at 2019, the team was able to capture over $1.5 million in savings, while reducing operational noise levels and emissions.
When we look at using EPA emissions factors.
Utilizing this technology versus a conventional fleet becomes impactful, creating a significant reduction in emissions.
Combined the emissions reduction with the ability to fuel our operations with clean burning natural gas and we see this as a significant win on several fronts and a great next step to achieving our environmental goals.
The fleet will be futile fully utilized in our 2020 program as we operate on pads with existing production.
Which again represents approximately half of our activity this year.
In the fourth quarter. The team also initiated our first efforts to source frac sand directly for our completions.
Projecting from our early savings observed and completed and coupled with the cut cost reduction associated with the electric fracturing fleet is estimated to reduce completions costs by approximately $30 million in 2020.
Producing yet another layer of durable cost reductions.
Lastly, similar to our discussions on prior calls ranges water recycling program continues to reduce cost and improve efficiencies and Appalachian.
In addition to recycling, 100% of rages southwest PA water utilizing other producers water totaled just under 5 million barrels in 2019 and represented a year over year increase the more than 12% versus 2018.
And as a result reduced our completion costs by over $10 million.
In addition to the efficiency gains cost reductions and technology deployment. The teams ever May just is focused on our safety performance.
Through training efforts and job task evaluation. The teams were able to reduce contractor workforce Osha recordables by 29% and preventable vehicle incidents just under 15% compared to the prior year.
The message from our team has loud and clear having a safe work environment is of Paramount importance and we look forward to building. Upon these results in the year ahead with expanded goals and initiatives.
When you consider the repeatable operational efficiencies captured by the teams deployment of new technology.
Water recycling and utilizing pads with existing production.
We see this translating into a durable market, leading capital efficiency, producing a drilling complete cost of $610 per foot.
On the marketing front.
The current natural gas strip is obviously challenged but we see reasons for optimism as it relates to natural gas fundamentals.
Looking out through the balance of the year with reducing rig counts in frac crews along with the shift by most producers to spend at or below cash flow and lower year on year Capex guidance.
We anticipate use natural gas supply will decline year over year as we exit 2020.
The first declines since the spring of 2016.
On the demand side additional coal to gas switching is leading to record winter guess powervar and additional coal plant retirement announcements.
Yes, LNG feed gas recently reached new highs in excess of nine Bcf per day in late January.
Looking internationally, we're cautiously optimistic that higher coal to gas switching in Asia, and Europe at lower pipeline gas imports into Europe can contribute to rebalancing European gas storage. This summer.
Looking into next year, a significant slowdown and global LNG supply growth and potential improved industrial demand in Asia points to improving fundamentals.
With 2021 international gas prices continuing to trade above $5 per MBT.
We believe this improving demand picture, coupled with declining domestic supply should serve to improve domestic natural gas balances and pricing.
On the liquid side.
Ranges fourth quarter NGL realizations increased on continued escalations of premiums at the export dock.
As well as crop drying demand for propane and heavy gasoline blending demand for butanes.
Looking forward starting in April 2020 range will increase its capacity on Mariner East two as we continue to see a significant benefit to international LPG exposure.
International demand growth for 2020, coupled with the lack of us Gulf coast capacity expansions until later this year is expected to support strong premiums at Marcus Hook.
This is reflected in our 2020 NGL pricing guidance of a premium to Mont Belvieu for ranges barrels.
As we wrap up the operations section I'd like to congratulate our teams for all their achievements in 2019, along with the creative initiatives be executed today, allowing us to deliver on our operational safety and environmental goals all while we produce our most operational and capital efficient program, yet I'll now turn it over to me.
Yeah.
Thank you Dennis.
As mentioned on previous calls our strategic priorities for guiding principles are to fund investments in the business from cash flow to further strengthen the financial position and to protect and grow margins through continuous cost management and innovative sales agreements.
Collectively executing on these principles, we believe can create significant sustainable stockholder value.
First let's discuss significant strides taken reinforcing ranges financial foundation.
We've been decisive and early to monetize assets as the first among public peers to sell royalty interests and non core acreage for $1.1 billion.
Scale and cost advantage asset base supported a 400 million dollar increase and commitments under the bank credit facility during the fourth quarter.
And in January we were prepared and moved quickly to issue unsecured bonds, raising $550 million and capital to refinance near term maturities.
In the aggregate this totals over $2 billion and capital brought into the business over the last 15 months.
Reducing debt by 22%.
Expanding liquidity by $1.2 billion and extending the debt maturity profile.
Questions are common in this market about the workings of a reserve based lending facility.
Pace and the certainty of current bank commitments.
We have consistently made conservative elections to set ranges borrowing base and commitment levels well below the calculated value. According to reserve based lending methodology.
At the last Redetermination date, the maximum calculated borrowing base under RBL methodology was approximately $4 billion.
This compares to the $2.4 billion and commitments.
We will soon have our annual Redetermination and using the latest price assumptions from lenders. We continue to see substantial cushion above both ranges $3 billion borrowing base and its $2.4 billion and commitments.
Consequently, we are confident in the durability of ranges liquidity position.
Yes.
We believe ranges debt reduction refinancing and expanded liquidity creates a long runway several years before there isn't need to access capital markets.
Despite creating a long runway it is not our strategy to passively wait for improved prices that we do believe visibly declining us production and growing demand will rebalance prices.
Nevertheless, asset sales remain high priority and we are actively marketing and negotiating multiple packages.
These are formal processes and we look forward to announcing results.
As is our practice rather than publicly set a target divestiture amount will strive to maximize value for stockholders as quickly as we can.
As investors evaluate our plans and objectives for 2020.
Including possible divestitures, it's informative to recall, what we have successfully delivered towards prior plants as well as what we intend to do going forward.
Results for the fourth quarter and full year 2019 reflect ranges focus and ability to deliver on financial and operating objectives.
Consistent with prior periods operating efficiency that are close attention to capital discipline to.
Delivered planned production with capital spending better than budget.
And continuing to drive down unit costs.
Capital spending for 2019 beat budget by $28 million.
Turning to cash unit costs, and continuing progress to drive unit cost too and below $2 per Mcf fee.
In the fourth quarter range achieved all in cash costs of $1.92.
Our unit of production.
Including lower Louie.
Gathering processing transport DNA and interest expense.
We delivered on guidance and our forecasted trend and unit costs.
The quarter over quarter improvement of 10 cents per unit.
And 26 cents per unit compared to the fourth quarter 2018.
The result of efficiency across the board led by improvements in gathering processing and transport.
Overtime, we expect a downward trend in cash unit cost to continue.
At times margin enhancing transportation or sales agreements may cause slight upticks in GP anti expense due to the accounting geography in the income statement.
When that occurs you will see higher relative expected sales price and higher margins.
As an example.
This year range has capacity on Mariner east II slated to come online.
These barrels are currently transported.
These barrels are currently transported by rail under a net price arrangement.
Consequently, when the pipeline capacity as available that transport costs will be classified as GP anti expense, but it is more than offset with improved margins.
It is also worth noting that no incremental production is needed to fill this capacity.
To put these unit cost savings and perspective, just assuming 2019 annual production of 833 Bcf fee.
Each pending in margin adds over 80.
To the bottom line.
For efficient use.
Yes.
But it's in itself.
Direct operating expenses continue to benefit from efficient water handling and the sale of legacy properties.
DNA has been reduced through both asset sales and staffing reductions with full time employee head count reduced 18% this year.
Annual cash interest expense was also reduced by $19 million due to lower debt balances.
In the fourth quarter, we recorded non cash impairment charges, reducing book value of proved and unproved properties in North Louisiana.
The noncash charges for North, Louisiana result from our strategic focus on the highest return projects in the Marcellus.
The lack of intend to drill the unproved, Louisiana acreage combined with lower commodity prices effecting the book value of Louisiana proved properties.
There were no impairments of the Marcellus.
The first step in a GAAP proved property impairment test is to compare undiscounted future net revenue to book value.
At year end strip pricing for the Marcellus future net revenue exceeds book value by greater than $20 billion or roughly 600% providing substantial cushion.
As we begin 2020, while near term commodity prices remain under pressure.
Ranges resilience and its ability to adapt has been demonstrated.
For 2020 range developed to plan driven by internal cash flow.
Reserving and enhancing liquidity.
Maintaining capital efficiency.
Managing leverage and efficiently utilizing existing infrastructure.
And planning these objectives to maximize value from the 2020 capital program.
We developed a $520 million capital plan that is focused and efficient.
With virtually all capital going to the Marcellus.
This 2020 budget is 31% or $236 million lower than 2019th budget.
And targets production approximately flat to fourth quarter 2019.
Range as well hedged for 2020 with over 60% of natural gas protected at an average of $2.64 at approximately 80% of our condensate hedged at $58 per barrel.
Additionally, the capital plan is flexible such that we can and will adapt spending to changes in commodity prices.
In summary range delivered again on its operating and financial plans.
Has created significant running room.
For supply and demand to rebalance prices.
Recast the cost structure to enhance resilient resilience for a low price environment.
It continues to work meaningful asset sales the goal of continuing these trends.
Jeff Thank you.
Operator, we'll be happy to take questions.
Thank you Mr. Ventura. The question answer session will now begin if you'd like to ask a question. Please indicate by pressing the star.
Then one if you're on speakerphone, please pick up your handset before asking your question.
To withdraw your question you may do so by pressing the pound key once again, please press star one to ask a question.
Your first question comes from the line of.
Do you ramp with Jpmorgan Your line is open.
Yes, good morning up my first question.
Involves the capital allocation in 2020 versus 2019.
As you mentioned in your prepared comments, you're now allocating 51% of the capital to the dry gas assets and southwest PA versus 36% last year and it does reflect lower capital allocation to the Super Rich. So just wondering if you could talk about the year over year changes and that.
Higher capital allocation to dry gas just given the weakness we're seeing in gas prices.
Yes. Good morning room. This is Dennis as we look at the plan.
Really year in in your outage, it's important that we look at a host of variables on how we consider capital allocation in one of those being where we have room in the existing gathering system and our ability to to fully utilize that keep our unit costs low.
Part of Q3 in Q4 of last year really involved a.
65% and 73% of our turn in lines were really in wet and Super Rich. So we're now getting an opportunity today to harvest those those volumes as a part of the plan that were toward the second half of last year Thats create critical critical in key when you think about just the development process as a whole, but as we look toward the the 2020 program.
Ramp there will be 20, 50% of the program via the dry gas and that is to also utilize some gathering that was.
A project that was starting to put in place toward.
The middle of 2019 is in further developing so again will be fully utilize that it look to keep our unit costs low lastly, we always keep some flexibility in the plan.
With our ability to move back into existing pads. So that when we do see commodity prices change we always allow for some flexibility. So that we can move back into those pad sites and take advantage of of market condition changes, but we don't tend to also try and overcorrect on the steering with our program. Because we also know is key to stay focused on multiple.
Metrics.
Great and then just wondering if perhaps you could oh elaborate a little bit more.
On the Mariner East two capacity. It is you mentioned that is driving up your GP and Ti costs, but could you comment on.
What you expect as the offset in terms of.
The NGL price.
Yeah sure and this is mark I'll start and then handed over to Ellenberger Vice President of NGL marketing. So I think the first key point to understand is the accounting behind us, it's really geography and the income statement.
As I tried to describe in.
The scripted portion of a call.
The current sales arrangement is net price, meaning we are paid a price that is after the cost of transport by rail that has carried by the buyer.
When this capacity comes online it is something that range can control and optimize so in essence it to check that we're cutting it shows up in the gathering processing transport line item.
What we receive a higher price. So net net this is a cost saving a margin enhancement because moving ngls by pipe is cheaper than moving by rail so Alan.
Okay.
Yes, I would just add to that that the.
Overall attractiveness.
Have access to the international markets, it's really a differentiator for range. We're one of only two.
Independent in piece in the country that can directly access the export market.
The premiums that we've been seeing at the dock have improved considerably during 2019 and they continue to improve actually.
We saw premiums if I go back to fourth quarter of 18, there roughly five in half sense at the export docs.
By the third quarter 19, there at seven cents by the fourth quarter of 19, there were 12 cents.
Actually despite everything going on in the in the world today in the larger macro environment the year to date premiums as actually published.
By when the price reporters in us here year to date premiums are actually at 15 cents per gallon.
So overall, we've guided higher in our NGL realizations for 2020, because we expect to do much better.
Continued growth and expansion in our export program.
Great. Thanks, a lot.
Thank you.
Bryan singer with Goldman Sachs. Your line is open.
Thank you good morning.
Good morning.
Realize that yeah. When you think about your cost structure not all of it is variable, but given the low gas and NGL price environment, just wanted to get a better sense. How you debate internally about what price environment, you would need to see or sustained price environment for either a further slowing of activity or then is there some point at which at least.
Well that maybe a little bit more marginal within the portfolio should be temporarily shut in.
Well, let me, let me start and then flip it over to Mark Yes, we were again laser focused on making sure that our program is going to be aligned with cash flow. We have multiple scenarios that we look at.
It will be sensitive to that in reacting enough time to make sure that occurs obviously.
The changes that will make will focus on wells that have better return versus the poor return animal as Dennis said, we'll look at.
Unit cost and all the other things to talk demise of program team does a good job. If you looked the last couple of years. We've we've adjusted our program would come in below budget.
Let me flip over to Mark.
Sure, Brian I would say there's really two.
Essential elements for range.
That come to bear in the question, you've asked and Thats first of all the flexibility we have.
The fact that our gathering infrastructure and long haul transport.
It's fully utilized gives us a tremendous amount of flexibility in other words were not trying to cover those costs and doing analysis on a sunk cost basis. In fact, we have production above and beyond our take or pay contracts. So again that gives us flexibility in terms of determining the level of activity.
In a year and or.
If you were in an extreme scenario and evaluating shutting in production what that would mean in terms of your cost structure.
And cost structure is really the second main point I wanted to bring it back too and that's with cash unit cost fourth quarter of $1.92.
That puts us.
Very good stead in the environment.
For 2020 and beyond.
We have shown a consistent track record of driving that down and I would also note that the preservation and expansion of our margins is critical there if you look at.
The gross margin you will as a percentage of revenue thats been sustained when the prices have come down given the fact that we've driven down.
Absolutely costs, the third point I would make there as we evaluate prices and people are looking at natural gas prices. It's important to note that even on an unhedged basis. When you look back at ranges realized price per Mcf fee.
Even unhedged.
It was 30 cents above Nymex for 2019, and if you look back over the last few years, it's anywhere from that 20 to.
20 to 30 cents. So again that gives us a lot of flexibility to adapt to whatever prevailing market prices are.
Great. Thanks, and then my follow up is also on the cost structure on the capital cost structure, you highlighted a number of the initiatives you were taking on in terms of fleets and water and I think you mentioned that the fleets are reducing your completion costs by about $30 million. This year is that 30 million built into your capital budget or would that be an area.
You, where you could potentially spend spend under your budget and.
Can you talk within the other initiatives debt that you mentioned, if that's built in or if theres the potential for either further savings relative to that capital budget that you have.
Yes, Brian I would say a significant portion of the cost savings that we're projecting for the year are built into that $610 per foot assessment that we're communicating today. However.
The team always continues to move the goal posts and I can speak to hold other calls worth of time talking about the good work that the team has done and year over year. They continue to drive additional water recycling, taking other operators through a collaborative effort there water.
Capturing those additional savings and really on the drilling side same thing, we see that deficiencies that we're planning for.
Lot of times the team is exceeding those expectations through the balance of the year. So from what we're planning for today would I expect.
Additional savings I, certainly wouldn't surprise me because the team just continues to really do a great job and exceeded expectations and it's been really the the the cornerstone of why we've come in under budget. The past two years consistently so.
We would we would hope and expect to see some additional savings come to come to fruition, yes. It would just.
Referencing with Dennis is saying, we the team continues to get better and move the goal coat goalpost. So last year I think a lot of more peers were targeting range cost of drill and complete per foot whatever it was 750 or whatever in there for theres still striving to hit that yet what we did as move that further down to approximately 600 per foot. So.
And I have great faith in the team that they'll continue to find ways to lead the pack, we put a new slide in our deck. So slide 11, and its looks that we talked about peer leading capital efficiency or whether you look at it on well costs per lateral foot and I think importantly, the the new part at the bottom where you look at total drill and complete capital.
For Mcf fee added and we put it in there over the last three years or through your average in last year range with best in the in the entire basin.
And Greg results across three year, so great faced the team will do that and also like Mark said that we have flexibility and being able to alter the budget as needed.
Thank you.
Thank you.
Jamie Thank you with Stifel. Your line is open.
Good morning, and thanks for taking my question.
Yes on asset sales and oil today, if you can comment on how the market for these assets looks like today.
Then, let say compared to a year ago itself.
Sure as I described earlier, we have multiple active processes underway.
We've spoken of North East, Pennsylvania, before the Lycoming County asset there.
Discussions ongoing there we have obviously had success in monetizing a small portion of our inventory and resource potential in southwest, Pennsylvania half million acres of stacked pay potential there 1.1 billion proceeds out of the royalty, but given the scale of that asset it clearly.
Represents future potential and then obviously an asset that has not and garnered its fair share of capital within our portfolio.
Yes.
Inactive candidates. So we do have a process and data room open on north Louisiana. So there are multiple dialogues across multiple assets and.
Projects and.
I think I would look back on ranges track record of being able to deliver on divestitures over the last number of years as an indicator of what we intend to do.
What do you generally characterize that as like more ingest oil just rather than assets.
I would not characterize it that way.
It depends on the asset base and the location there are different buyers for different assets some.
Operators in a given area may want bolt on just add production to there given area. It's efficient if you're in the Gulf coast that one's adjacent to petrochemical demand and LNG offtake. So that has appealing interest both domestic and international players. So it depends on the asset allocation, you're talking about as to who the interested parties may be.
Okay got it and then the second question. So they will buy discussion that you had in the prepared remarks was very helpful and thank you for that.
I have a question.
Regarding the neo till maturity dates and to what extent it would be possible to put to put them maybe a portion of that on the revolver and if it's even an option.
Yes, it is an option.
As we disclosed I think beginning in Q3, we had begun repurchasing nearer term maturities on the open market.
And we will continue to do that carefully so that is definitely an option and we have substantial liquidity to deal with near term maturities combine that refinancing. We did early this year pushing maturities out and expanding the credit facility last fall and then lastly, and most importantly, the fact that we see substantial.
Cushion to the current borrowing base at current prices and assumptions by the lenders we feel like we're in great shape as it comes to the debt maturity profile.
Okay got it thank you so much.
Thank you.
Jeffrey Campbell with Tuohy Brothers your line is open.
Good morning.
My first question is theres been a lot of really interesting discussion about cost reduction and a lot of specifics I just wanted to kind of backup announced what portion of this leading cost per barrel lateral foot cost surrounds returning to your portfolio of 200 pads as opposed to the other items that.
You discussed.
Yeah Jeffrey this is Dennis.
Year ending year out.
Kind of tried to touch on it during the call. This morning, but this year's activity will represent about 50% of it will be going back to pads with existing production, but if you were to look back over the past several years it can be as much as 50% on a year end year outpaces. So.
We look at our cost savings are there other cost savings were capturing due to this absolutely, but what we see though is that theres a fair bit a durability in the cost savings that we're capturing this year that a repeatable year in a year out and that's just just one of them. The other is clearly the team being creative that looking at sourcing sand directly for our complete.
Since operations.
Thats, an initiative that may not necessarily be new to the MP space. However, we feel like patients as kind of paid off for us in that regard because of where the market is from from a profit standpoint, we see there'll of there being a fair bit of durability that and that going into 2021 and beyond so as we start.
To stack up electric frets fracturing fleets the technology the drilling teams deploying moving back into existing pads, we see there's a fair bit of durability and capturing these cost savings steadily this year, but also with years to come.
Okay. Thank you for that.
And then regarding north Louisiana bearing in mind that it sounds like that its apparently are potentially for sale.
Do you have any midstream volume requirements in 2020 that.
And can you meet them until a sale can close just wondering about midstream down there.
So I think we've alluded to before and was disclosed early on at the time of the acquisition there our commitments on processing volumes. So those processing volumes are not fully utilized right now but that cost is already reflected in ranges GPMI line item. So even though we are paying for some processing capacity.
Fully utilized we still driven the cost from $1.51 in the fourth quarter last year down to $1.39. So.
We did have early this year, a $40 million to $50 million portion of that commitment roll off so that will be an improved run rate for 2020, and we'll continue to certainly worked to optimize that in the context of potential sale.
Okay, great appreciate that color. Thank you.
Thank you. Thank you.
David Deckelbaum with Cowen Your line is open.
Morning, guys. Thanks for the time good morning.
Just to expand a little bit more so I understand that the multiple years of capital efficiency.
Being on 50% your budget on existing pads. This year is obviously, helping you get as well cost down on the blended basis.
If you were just to remain.
On existing pads, how long could that program sustain for.
Yes, they sound parks and let me, let me kind of.
Take that question a little bit first of all we've been as Dennis mentioned, a little over to go and you look at our track record over the past several years, we've probably been about 50% of the wells on the pad probably on average we have over 200 pads out there and on average we're probably in the five to six wells on an existing pad. So we've built these pads to handle up to 20, well so I thought.
The the.
The runway is very long on on our ability to be able to keep that happening. So I think our LOE costs arent necessarily reflective of of going back on pads for 50%. This year, it's been built into the entire cycle. So you can always see we're always building. Some pads every single year, if you're only going back on on half the wells to be able to get there. So you already.
You always have some some of that opportunity.
Down the road. So eventually you'll be in a situation, where you won't be able to you won't be building any new pads, so costs actually could come down as you think think through the longer cycle.
Well I guess I'm wondering the market is obviously, not particularly robust right now why isn't that percentage, increasing more as a way of sort of augmenting your margins.
I think part of that starts with I'll go ahead and start with that I think part of that starts with just the way. The development plan is set up the permitting process and in Pennsylvania somewhat cumbersome and takes a fair amount of time. So a lot of the pads have already been built they may have been built in 2019 and as a real.
Soldiers now just getting to drill the wells in 2020, So I think you'll see a change over time and it's just a matter of the of the the way. The development plan is is put together in just the timing of everything and of course, you want to be able to efficiently use gathering system as well.
Just back to cash flow, where where theres room, and the gathering system, where you can get that production online to market and where the netback and quicker payback period for those dollars invested our it boils down to the cash flow.
And then I'll I'll pile on here lastly, but I think piece of this it's ever evolving. So when you look at the lateral links and how they've increased over the past, let's just say two to three years not only for us, but for a lot of folks, but especially range and the efficiencies associated with that we're seeing the opportunity to reduce the number of pad sites that were needing to build.
Touching on that a little bit with just the average lateral links increasing the gathering system. So all of this really becomes a very integral piece of the of the planning process as we think about.
As mark touched on efficiently using their the gathering and infrastructure in our processing.
I appreciate the color.
Hi, just my second question.
As you look at the landscape right now and I believe so you've talked a lot about initiatives to de lever through asset sales.
You've had a lot of success with noncore asset sales and overriding royalty interest sales.
On the other side of it I guess when you think about some cost control. Some of your peers look at insolvency. Obviously the market is undergoing a lot of distress are you seeing opportunities to renegotiate things with your gathering.
Partners with your processing partners and do you foresee opportunities to renegotiate with long haul as well.
I think just getting a good bead on our situation today is important and then we can consider how renegotiations may may plan to that going forward with over a decade.
Of development of the Marcellus and signing of the earliest gathering processing and transport agreements here, you're at the stage, where some of those early agreements are already out there.
Option to extend or drop at ranges election. So.
Beginning this year next year and kind of steady cadence thereafter, we have portions of capacity that we can allow to just drop off that do not require renegotiation. That's just our our option.
You also have elements of the cost structure, particularly on the gathering side, we spoken to before where some of the capital recovery pieces begin to drop out and the cost do decline overtime. So the glide slope there is in our favor for a long running so steady decline in the cost.
Sure on the gathering processing transport, but I'll, let dennis speak to more detail on renegotiation.
Yes, I think ultimately all kind of step up higher level here for second but.
We.
We are working always on ways to optimize our portfolio and that doesn't that includes all aspects of the gathering the processing and the transportation side of our business as Mark indicated being an early mover. There are packages that were seeing the opportunity to set the C. Let those expire.
And then also be strategic about how we we consider renewing or adding transport to our portfolio down the road sometime so we like where we're at we're exceeding our ft commitments today, we're maximizing our portfolio. However.
Look our part these are our partners as well and so we're always actively looking for ways that we can renegotiate. We can also look for ways for strategically reducing cost making sure that we're we have the right cost structure for the cycle.
As we put in our slide deck, we already had a 12% reduction in our GTT cost over the past 12 months. When you look from Q4 18 to Q4 19, and we're projecting a similar trajectory in the years ahead. So it'll come our cost reductions will come through multiple avenues, one of which could be renegotiations.
Thank you guys.
Thank you.
We are nearing the end of today's conference. We will go to Sameer Panjwani with Tudor Pickering Holt for our final question.
Lines open.
Hey, guys. Good morning wanted to ask on the 2020 outlook I know theres been some some back and forth on this call here, but I guess just to clarify do you see the current program as free cash flow neutral or positive at current strip and then can you also quantify the buffer you have in terms of production above your midstream commitments.
So as it relates to the 2020 plan when we rolled that out in January obviously prices were somewhat higher and that program was designed to be cash flow neutral to positive at strip prices at the time.
Again, given the prices have come down somewhat.
It would require some adjustment to that plan and as Jeff and Dennis and I have each described our primary motivating factor kind of the guiding principle is to self fund the program to be cash flow neutral cash flow positive throughout the cycle. So there is flexibility and it would be our intend to make adjustments to that plan as need be.
Over the course of this year to make sure that we are self funding that to the maximum extent possible.
Okay and are you able to quantify that buffer you have in terms of production above your midstream commitments.
So.
In the ft side commitments are roughly 1.6.
And production about 1.8, so you've got a good 10% offer.
Okay got it and then on the asset sale side of things you mentioned there they were opened for Louisiana and.
Northeast, Pennsylvania assets, but on the market for a while do you happen to have PV 10 value is as of the into 2019 for each of those and just from a higher level standpoint, when you're kind of marketing. These are you hoping to get some level of undeveloped acreage to have described in the transaction values.
Yes, we have PV 10 values, but we're not going to set any markers out there for individual assets or the aggregate asset sale proceeds. So we will just continue to seek to maximize the value of so that it's both deleveraging enhancing to the cash flow going forward.
And just monetize those as quickly as we can.
Okay. Thank you.
Thanks.
Thank you. This concludes today's question and answer session I'd now like to turn the call back over to Mr. Ventura for his concluding remarks.
Yes, I just want to thank everybody for participating on the call and feel free to follow up with additional questions. Thank you.
Thank you for your participation in today's conference you mean disconnect at this time.