Q4 2020 Range Resources Corp Earnings Call
[music].
Welcome to the range resources fourth quarter 'twenty 'twenty earnings conference call all lines have been placed on mute to prevent any background noise.
Emmons made during this conference call 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.
The speakers remarks, there will be a question and answer period at this time I would like to turn the call over to Mr. Lee Sando, Vice President Investor Relations at range Resources. Please go ahead Sir.
Thank you operator, good morning, everyone and thank you for joining range as year end earnings call.
Speakers on today's call are Jeff Ventura, Chief Executive Officer, Dennis Degner, Chief operating Officer, and Mark <unk> Chief Financial Officer.
Hopefully you've had a chance to review the press release and updated Investor presentation that we've posted on our website.
You will also find our 10-K on range as website under the investors tab.
Or you can access it using the SEC's Edgar system.
Please note, we'll be referencing certain non-GAAP measures on today's call.
Our press release provides reconciliations of these to the most comparable GAAP figures.
For additional information, we've posted supplemental tables on our website to assist in the calculation of EBITDAX cash margins and other non-GAAP measures.
With that let me turn the call over to Jeff.
Thanks, Laith and thanks, everyone for joining us on this morning's call looking back at 2020 range made steady progress on key objectives, we enhanced margins through cost improvements and thoughtful marketing strengthened our balance sheet by reducing debt for the third consecutive year.
<unk> 2020 drilling program safely and efficiently and lowered the capital intensity of our business with a peer leading maintenance capital program.
Range also continued to advance on key environmental fronts, becoming the first north American producer to set a goal of net seaworld direct emissions.
We believe each of these accomplishments show continued progress towards positioning the company to return capital to shareholders.
Looking first at margins, we can discuss unit cost range.
Range reduce cash unit costs by about 10% last year compared to average 2019 cost.
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 that don't require change in commodity price.
While we made improvements in 2020 on gathering and transportation expenses LOE and G&A, we remain focused on becoming even more efficient in the years ahead.
On the pricing side of the margin equation I believe our mix of production and delivery of Ngls into the international markets provides range, an unappreciated advantage in terms of pricing.
For context, if we look at pricing for 2021, Ngls, we expected unhedged realized price comfortably above $20 per NGL barrel for range approaching $4 per Mcf equivalent based on today's strip.
Our ability to sell purity NGL project products into the international markets paired with improved NGL fundamentals helped support range of strong free cash flow at strip pricing.
Turning to the balance sheet range made significant progress bolstering our financial position over the last couple of years.
Not only have we improved our cost structure and streamlined our operations, we have reduced debt by over 1 billion strength in door maturity profile and improve like quip liquidity, while reducing share count.
Reflects our commitment to thoughtful and disciplined capital allocation.
Looking forward, we expect free cash flow at strip pricing to further strengthen our position and move us towards our longer term financial targets.
Operationally the team continues to innovate and reduce normalized well cost.
As a result of efficient operations coordinated planning and a laser focus on capital discipline. The team was able to deliver the 2020 operational plan for $19 million less than budgeted in March of last year.
This is the third consecutive year range has achieved these types of savings spending less than budgeted, which is a reflection of our cost leadership and disciplined 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 2021 shows the continuation of efficient operations with average well cost below $600 per lateral foot, which is the best amongst peers.
Range, a class, leading D&C costs, coupled with our shallow base decline and our substantial core inventory all come together to support a very low and sustainable maintenance capital.
Range is base decline entering 2021 is approximately 19%, allowing for maintenance capital on the low $400 million range.
This low capital intensity that is unmatched amongst small and mid cap E&P companies provides us a solid foundation for generating significant free cash flow.
Importantly, this maintenance capital figure is sustainable for a couple of important reasons first the lateral footage and range is drilling completing and turning in line for this year is all very similar to what we've accomplished in 2020.
Leaving us well positioned to continue into 2022 and beyond with equal or better capital efficiencies.
This is unlike what we've seen from the industry more broadly which has relied on DUC drawdowns from massive outspends to provide a short lived boost to efficiencies that is not the case for range.
And second range has a core inventory of oil wells measured in decades, which provides us a long runway of consistent repeatable results inefficient capital deployment.
These positive differentiators on sustaining capital bear out in our reported results taking a simple look at relative efficiency using actual D&C capital per unit of production range, let all Appalachian producers in 2020, and we expect similar results going forward.
As others exhaust their core inventories in the years ahead range, we remain well positioned with multiple decades of inventory.
<unk> of the value of our inventories can be found on our year end Reserve report.
At $2 75, natural gas and $50 oil the PV 10 of range as proved reserves was $8 6 billion.
For context after backing out our year end debt balances this equates to over $22 per share.
But as many of you know the SEC definition of proved reserves only allows for five years of development and beyond this five year window range has thousands of additional core Marcellus wells not included.
Before turning it over to Mark and Dennis I'll reiterate that I think range has made great progress in 2020 in the face of a difficult commodity environment.
Looking forward as prices are set to improve in 2021 and 2022 on improving fundamentals, we see range generating significant free cash flow, putting us on the path towards reaching our long term leverage targets in the not too distant future is debt reduction and strip pricing is the expectation.
Our focus will remain on safe efficient and environmentally sound operations.
Prudent capital development and interest generating sustainable returns to shareholders.
Importantly, these are all reflected in our updated commodity or update on compensation metrics.
Our latest slide deck shows a summary of the short term and long term incentives that will be reflected in our next proxy report aligning our incentive programs with shareholders as we seek to continue our steady progress against key initiatives over to you Dennis.
Thanks, Jeff.
As we entered our 2020 program a year ago, our operational focus was clear deliver.
Deliver on maintenance level production plan anchored by improvements in capital efficiency.
And in doing so align our operational cash flow with annual capital spending.
Our 2020 operational cadence cost control and production levels were consistent with these objectives.
And our capital spending below budget from the third consecutive year speaks to the commitment of our team in achieving them.
Our operational program was executed while coming in $109 million or 20% below our average capital plan of $520 million set at the beginning of January.
And was also $19 million below our revised capital plan of $430 million that was suggested in March.
The program resulted in 67 wells turned to sales for the year with approximately half of the activity focused in our dry gas acreage position.
Maintaining production levels, while spending significantly less capital was a notable achievement by our operations technical and support teams.
The initiatives that underpin. These results were driven by calculated scheduling adjustments made with a new multi disciplinary assay development software tool.
Continued improvements to operational efficiencies for both drilling and completions.
The use of innovative in emissions, reducing technologies, such as using an electric fracturing fleet.
On our focus on reducing service costs throughout the year.
As we look forward into 2021, our capital spending will be approximately $425 million with 95 per cent of the capital directed towards drilling and completions related activity.
Which is consistent with last year's budget.
Also consistent with prior years, our activity in capital cadence will be weighted towards the first half of the year with approximately 60% of the capital allocated across the first and second quarters.
With the remaining 40% covering the second half of the year.
The capital plan for 2021 is projected to maintain production at approximately $2. One five bcf equivalent per day and maintains ample inventory and momentum to sustain capital efficiencies into future years.
Production for the first quarter is projected at 2.6 Bcf equivalent per day.
This is below the full year average as Q4 turned in line counts and scheduled maintenance on portions of the dry gas gathering system are affecting Q1.
Drilling and completions activity in the first half of the year is expected to result in building average daily production in subsequent quarters delivering maintenance level production for 2021.
A key to our success in 2020 and for the year ahead, as our peer leading well cost.
Our goal at the beginning of 2020 was to beat of $610 per foot target and several drivers resulted in range eclipsing the skull.
An optimized development plan was deployed for the year utilizing a new collaborative digital platform previously mentioned.
Along with our strategic focus on inventory planning, which resulted in some substantial improvements in this metric.
In addition to this the team successfully drilled more lateral foot per day plant.
And completed more frac stages per day versus prior years.
Enhanced levels of diesel fuel displacement in our operations were also achieved.
With the increased utilization of our natural gas dual fuel drilling rigs and electric Frac fleet.
Further reducing cost and emissions.
The direct sourcing of sand for our completions, along with our record setting water savings and volume handled also benefited our well cost efforts.
In aggregate these operational actions resulted in a reduced normalized well cost in excess of 10% across all areas.
As we look forward into 2021 hour program will consist of 59 wells being completed and turned to sales.
Approximately 60% of our turn in lines are expected to be in our wet and super rich acreage with the remaining 40% located in our southwest dry gas position.
Our planned average horizontal length per well for 2021 is projected to be similar to last year with our turn in line, averaging approximately 12000 feet.
In the year ahead, we will continue to capitalize on the efficient practice of returning to pads with existing production.
With approximately two thirds of 2020 once turned in lines scheduled on existing pad sites.
Moving back to pads with existing production has become a fundamental and repeatable part of our program year in and year out, allowing us to reduce cost maximize infrastructure utilization.
And is complemented by our use of dual fuel drilling rigs and an electric fracturing fleet.
To put color around this are contracted electric Frac fleet pumped over 2000 frac stages in 2020.
And displaced over $3 8 million gallons of diesel fuel, while running on 100% of ranges field gas.
Coupled this effort with range as large contiguous acreage position and this translates into approximately $4 $5 million in savings for the year, while significantly reducing emissions for those operations.
Extended lateral links highlighted range as 2020 drilling performance with almost half of our wells exceeding 14000 feet and horizontal linked.
Including the three longest wells in ranges Marcellus program history, each exceeding 19000 feet.
This resulted into a corresponding 12% reduction in drilling cost per lateral foot drilled which fell below $200 per foot for the year.
On the completion side, a 10% improvement in fracturing crew pumping efficiency was also realized.
Sending a performance record for range, resulting in averaging over seven frac stages per day for the year.
These improved operational efficiencies.
The benefits of using range supply natural gas for the electric Frac fleet and an expanded ability to self source sand for completions continues to drive down our peer leading well cost.
In 2020, but water operations teams focused on expanding and improving the reuse program and reducing water logistics cost.
Through creative initiatives by the operations and technical teams.
Record low for cost per barrel of water was realized with a 36% reduction compared to the prior year.
For example, the volume of water reused from range flow back operations and producing wells along with third party sources represented 60% of all water used in 2020.
That compares to 43% in 2019.
The savings associated with the water reuse program not only exceeded the plan, but it also match the cost savings seen in 2019.
All while under maintenance production activity levels.
Range as water reuse program provides for lower operating costs and is a key component of our broader ESG efforts, reducing the volume needed from area freshwater sources.
Lastly, similar progress was captured by reducing the cost associated with water transportation.
Resulting in a 75% reduction in freshwater transported by truck.
Reduced trucking not only lowers costs. It also means less rose maintenance reduced emissions and fewer trips for our service partner drivers.
This year, we project additional advancements in our water program logistics and cost structure as we've implemented a new customized water tracking and collaborative software tool.
This smart software will allow greater visibility of our water logistics at any given moment, reducing unnecessary movements.
Wasted time and associated cost.
This will allow our logistics and operations team to make informed real time decisions about water movements throughout the field, creating an even safer low cost program.
Before turning to marketing I would like to give a special mention to our production and facilities teams.
In 2020, the team was able to further reduce L. O produced water cost in excess of $2 million.
They worked closely with our midstream partners to increase field runtime.
In translated this into a record low lease operating expense of eight cents per Mcf for Q4.
We see this low level is durable and repeatable as we continue our focus on enhancing high field run time.
While further optimizing flow back operations and produced water management.
Range has made significant progress toward reducing cash unit cost over the past few years.
The largest of which has been the 17th improvement we've made to transport and gathering since the end of 2018.
This expense is expected to move up slightly in 2021, as we move more of our existing NGL production to Marcus Hook for export and also as processing costs follow the direction of improving NGL prices.
However, both are expected to be more than offset with higher NGL revenue this year.
Beyond 2021, we expect transportation and gathering expense to decline in absolute terms.
Assuming continued maintenance of the existing production levels.
By 2025 annual gathering expense relative to 2021 is expected to decline by approximately $70 million.
And by over $100 million by 2030.
These are large and significant cost reductions and importantly, they are simply an output of existing arrangements not targeted dollar amounts our goals, we are setting for ourselves.
In addition range will have elections on multiple firm transport projects over the several years ahead, where we can decide to retain or capacity expire depending on market conditions.
These elections relative to 2021 represent over an additional $175 million by 2030.
Regional basis in the third and fourth quarter was impacted by a Ted Coke capacity reduction.
Maintenance at Cove point.
And infrastructure upsets associated with seasonal hurricane storms.
By the end of Q4, the upset infrastructure was returned to service with <unk>, adding back approximately one bcf per day of capacity to their system.
The impact of normalizing weather and return of capacity as represented in the improvement to range is differential from 57 cents on the fourth quarter to an expected 20 to 25 cents under Nymex in the first quarter of 2021.
As we look forward with operations at flat production scenarios strong LNG exports.
Infrastructure returned to service.
Along with the gas demand needed to achieve go forward storage levels.
And we expect Appalachia gas pricing to experience meaningful improvements year over year.
On propane fundamentals historical high LPG exports and made the ongoing winter propane drawdown season, one for the record books.
Thus far this winter storage draw downs have been twice that of last winter and 65% greater than the five year average.
Driving propane stocks to a reduced level versus the prior two years and 10% below the five year average.
This low storage level combined with bullish demand forecast associated with cold weather across the U S Midwest and northeast in February.
As elevated propane prices by 70% versus the third quarter of 2020, and improving our expected pre hedge NGL price above $25 per barrel for Q1 2021.
Continued European and Asian, LPG demand should support international prices and U S export economics in the coming quarters.
As we've outlined on prior calls range is strongly positioned to continuously capture the best value for its LPG production through the flexibility of Marcus Hook exports.
Starting in April range will access an additional 5000 barrels per day of NGL transportation capacity on Mariner East.
As we continue to expect near term and long term benefits of NGL exports out of the northeast with.
With continued international demand growth for NGL products.
We will have the capability to export over 80% of range as propane and butane in 2021, leading to strong year over year improvements in NGL pricing and margins.
As we wrap up operations and marketing I'd like to congratulate our team for all they have accomplished in 2020 and for delivering on our operational safety and environmental goals all during a very unique year.
I'll now turn it over to Mark to discuss the financials Mark.
<unk>.
Thank you Dennis.
We all know it would be an understatement to simply call 2020 and eventful year.
Nevertheless for range. It was an extremely constructive eventful year during which the team successfully executed on key financial objectives. During some unusual global events.
The main themes discussed on the third quarter call continued through year end and into 2021, including cost reduction debt reduction improving the debt maturity profile and enhancing liquidity.
All of which were achieved while maintaining best in basin capital efficiency and doing so in a responsible safe manner, one of our core values.
Results for the fourth quarter and full year reflect range is ability to navigate fluid market conditions maintain focus on shareholder returns and deliver on financial and operating objectives.
Starting the financial discussion today I want to ensure the recently announced accounting corrections are transparent and well understood.
In the 10-K, we corrected a deferred tax are reported in the 2020 quarterly statements. There was identified while preparing yearend financials.
This mistake resulted from a misinterpretation of how the cares act was modest modified future utilization of net operating losses.
As you know accounting rules provide a strict framework of how deferred tax assets and liabilities are quantified and the misinterpretation led to incorrect noncash deferred taxes reported.
The correction, which we set forth in detail in the 10-K is likewise noncash and there was no change on the NOL balance range holds for future use against taxable income.
Changes in policies and procedures are already underway to prevent an issue like this from recurring.
Moving to financial results on.
Underlying the financial foundation of any E&P is capital efficiency.
Full cycle costs operating costs, plus sustaining capex dictate repeatable returns and cash flow.
The quality of range of inventory and low base decline, allowing range to adapt its investment program throughout 2020.
We started the year with a capital investment program targeting flat production at a spend of $520 million.
Early in 2020, we reduced planned capital investment to $430 million.
And at year end closed out at $411 million on capital or 21% better than originally budgeted while maintaining Marcellus production.
On the team is able to achieve drilling and completion costs below $600 combined with top tier recoveries per foot.
There is a dramatic uplift on investment returns.
Equally important our improvements in cash unit costs.
Fourth quarter unit costs of $1 84 per unit were in line with the preceding quarter.
And improved by an aggregate 20.
Or 10% compared to full year 2019.
2000, and unit costs multiplied by total production equates to over $150 million in annual improvement.
Driven by reduced gathering processing transport.
Lease operating costs.
And G&A.
Year over year savings in <unk> is due in part to the sales Louisiana.
Allowing certain gathering and transportation contracts in northeast, Pennsylvania to expire.
And to a lesser degree changes in NGL prices.
Lease operating expenses declined to eight per unit on extremely efficient operations with specific improvements in water handling and the divestment of higher cost assets.
Recurring cash G&A expenses declined to $31 million on the fourth quarter.
Or $124 million per year, which is down 10% from full year 2019.
Overhead cost savings come from every line item, but the most significant contributor is a more focused efficient workforce of 533 full time employees, which is down 33% from 2018.
Cash interest expense was $46 million on the fourth quarter.
Higher interest expense as a result of refinancing initiatives during 2020, which reshaped the debt maturity profile of the company and enhance liquidity.
Liability management projects reduced bond maturities through 2024 by almost $1 2 billion.
While at the same time, improving liquidity to approximately $2 billion. Following the January bond offering.
Cash flows are expected to retire debt maturities in coming years and are backstopped by ample liquidity.
Additionally, recent bond issuances are coal such that we have the ability to redeem <unk> refinance these series when economic.
There has been substantial improvement in the debt markets and is evident in the trading levels of range as bonds to both access to and cost of capital has improved.
Despite a challenging backdrop during 2020 range is liquidity and running room before debt maturities was materially improved.
Effective liability management temporarily increased interest expense.
However, this avoided higher cost forms of capital that would have diluted shareholder ownership and participation in what we see as a steadily improving natural gas and natural gas liquids business.
Further improving the balance sheet through absolute debt reduction remains a principal objective.
Shareholder value creation through the generation of free cash flow and it's prudent redeployment is our focus.
At current commodity prices by the end of 2022 ranges leverage is approaching target levels, even without incremental action.
It should be clear by our past practice, however that we will not stand idly by we will continue to explore virtually every option that improves financial strength reduces costs.
The risks the company and expands free cash flow per share.
Our steady full cycle unit cost improvement provides stable and competitive base to generate material free cash flow.
We believe total unit cost levels achieved over the last six months.
Total, meaning capital spending and fully loaded cash unit costs represent a leading breakeven cost among southwest e&ps.
Looking forward through 2021 on into 2020 to a healthy and more prudent message appears to have taken root in the industry.
And that of prioritizing shareholder returns, while responsibly, managing environmental social and governance matters.
This reflects the maturing of the business, where cash flow growth and returns are the key measures as opposed to units of production.
So what does that imply for a range, assuming a maintenance capital program.
To illustrate the free cash flow generation potential of range as business.
Using the midpoint of 2021 guidance for all costs, including exploration on brokerage marketing.
Fully loaded cash unit costs total an estimated $1 99 per unit.
Add to that maintenance capital to arrive at full cycle economics.
Taking this year's D&C capital budget and divided by annual production and you get approximately 50.
Those total approximately $2 50 per unit.
As an example assume $3 net realized price and you have 50 per unit or free cash flow are nearly $400 million for the year in free cash flow.
Obviously, there is working capital and periodic one off items that affect this illustrative math.
Example, does not take into account reduced interest expense through continuing debt reduction nor additional capital and operating cost efficiencies some of which are contractually declining costs like gathering expense.
Range is well positioned to reduce leverage and target cash returns to shareholders in the not too distant future.
Our strategic actions over the last three years have been focused on reducing risk, while maintaining and enhancing the intrinsic value of the asset base.
We believe range holds the largest portfolio of quality inventory in Appalachia.
Exposure to that inventory on a per share basis has been preserved and enhanced by our strategic actions in 2020.
Our portfolio also includes diversified takeaway, reaching a variety of customers and pricing points.
Paired with a consistent and data driven hedge program, which de risks the downside, while preserving exposure to an improving market.
We believe steps taken represent material progress in positioning range is a more resilient business.
<unk>.
Participate and improvements in both natural gas and natural gas liquids pricing.
On the topic of hedging Youll note that we maintained both our commercial and risk management approach, while hedging 2021 volumes.
We believe this was a balanced approach to risk management and participation in rising prices.
For over a decade, we have a steady practice of hedging a significant portion.
Over 70% of.
With natural gas production.
While we have a glide path or a common range in which we add positions over the course of the year.
Based on data, indicating prices needed to rise to balance the market. We intentionally moved at a deliberate pace during 2020 as we added 2021 hedge positions.
We plan to follow a similar principles this year and adding hedges for 2022 and beyond.
By that I mean, we will seek to prudently derisk cash flows while not hedging away the improved supply demand balance into backwardation price curves.
The well defined and we believe achievable objective that all of us at range work toward daily.
To sustain our highly investable business that will be resilient through cycles return cash flow to shareholders.
And responsibly create compelling value not only compared to other independent producers that across industrial sectors.
Jeff back to you.
Operator, we'll be glad to answer your questions.
Thank you Mr. Ventura the question and answer session will now begin if you would like to ask a question. Please keep on pressing Mr. Keith on one if you are on speakerphone. Please pick up your handset before asking a question.
I would like to withdraw your question you may do so by pressing the pound key.
Once again, please press star one to ask a question.
The first question comes from Sue loss Kinder with Northland Securities. Your line is now open.
Hi, Thanks, guys. Good morning, a question on the asset sales program, if any given the stronger fundamentals here are you going to be more picky.
About the bids you get or and if you can characterize the A&D market currently.
Good morning, Steve Marshall This is mark I'll start that one on.
The good news for range is the significant improvement in liquidity in the balance sheet. So therefore, we are in a position of strength.
Making choices that are most economic choices on day.
<unk> specifically.
Our economic basis, they are not.
Need base to refinance or repay indebtedness so.
More directly to your point the A&D market Theres been a few transactions you've got some decent comps in the area of what assets are going forward.
Pick your measure, but dollars per flowing predominantly PDP base valuations. So you do have to take a step back and say what is most accretive for your shareholders. What contributes the most cash flow free cash flow to your shares and would you rather be a seller or a buyer in this market. So.
There's been good interest from some of our non core areas, but for the time B I think we're focused on just maximizing cash flow.
On a good position as I started off with given where the balance sheet. Currently so we keep a lot of options open to us.
Okay great.
Just mentioned I guess being a buyer is that on the table.
We will consider virtually all options, it's about free cash flow per share it's about deleveraging.
About the strategy going forward from maximizing shareholder value. So again, you just run the economics or is it better to be a buyer or seller.
Right now Mike.
Towards being a buyer.
And clearly anything we would do would be in the Appalachian basin in and amongst us deleveraging and cash flow accretive all those things that Mark just mentioned.
Great. Thanks, and if I just ask a follow up on FTE do you feel differently about.
<unk> onto it long term given I think some of the tightness in the market at least in the fourth quarter of last year.
Yes. Good morning, this is Dennis.
I think as you look back over the landscape of 2020, certainly lends itself to.
Making the decisions along the pathway of those explorations that make most sense with our.
<unk>, our margins and our returns so earlier on.
The ft packages that were acquired associated with our production are going to be more in line with plants that early came on with let's just say early program production growth. So those those programs are going to most likely get us too to the Gulf.
80% of our production gets out of the northeast. So we're going to have 50% of it getting down to the Gulf coast and we're going to have the remainder of getting to the Midwest and other market. So we will look to continue to maximize the portfolio to make sure that it's taking into account cost and also how do we get to premium markets, but those early learn your packages that will start.
To expire will also be some of the more smaller in nature that will also allow us to be strategic on is we hold onto them or not.
This could certainly lead into a broader basis type discussion, but as you look back on 2020, and the <unk> capacity that was taken out of service due to some infrastructure upsets along with Cove point maintenance as we look forward. There is around 3% to four Bcf a day band plus takeaway capacity, that's going to be available.
Couple that with flat maintenance programs that range is executing along with many others in a flat production production profile. We see this gives us a lot of optionality as we look forward, whether it's how we manage basis are also those FTE packages moving forward.
Great. Thanks, everybody.
Thank you. The next question. The next question comes from Doug Leggate with Bank of America. Your line is now open.
Oh, Thanks, good morning, everybody.
Thank you for your questions.
Thanks, guys.
You, obviously made terrific progress.
Reducing your cost per module as you pointed out most efficiently chemistry.
My questions is on the.
On the sustainability of that when you look at the quality of care.
Great.
You've talked about locations.
No.
Poor stock into what can be sustained at that level of capital efficiencies on my first question is will proportionately the inventories laid out.
It can be sustained or not.
So on a.
Capital efficiency with that small.
Yes.
I'd like to refer you to slide 15.
We put us from third party data on the bottom right on that slide and according to that.
Third party data there is.
Over 16 years of about 17 years of inventory.
On generates good returns below $275 40, so it's clearly a high quality in terms of the well well count and we would agree and of course, we have more of that up there along with the map on the left so we've got plenty of locations on when we turn it over to Dennis to talk a little bit about well costs, yes. Good morning, Doug.
The cost structure, we see as very very durable and repeatable and a lot of it comes down to what we see is a couple of key drivers and one is going to be the efficiencies that we've captured year over year.
No doubt, we talk about it every single quarter, whether its drilling our fastest stays on the lateral by our drilling team or whether it's drilling our longest laterals two.
2000, Twenty's saw us in some regards heavy repeatable drilling efficiency in the lateral from a let's just say footage per day, but really what we saw as we were able to repeatedly and successfully drilled longer laterals, reducing our cost per foot on an additional 12%. So that was an incremental bolt on versus prior year's completion side continues.
To chip away at completion efficiencies, we saw our crew pumping efficiency go up 2% part of that was due to the efficiencies associated with both of our providers, but also pretty heavily contributed by our electric fracturing fleet in 2020. So team continue to do good work there.
And the other part is water savings.
We hit three records in 2020 per range on cost per barrel amount of barrels that were handled and also.
Production in some of our trucking logistics from our freshwater perspective, and all of that just translates into a production and cost.
So part of the reason we see this being durable going forward is because we see as building upon that but also the last component is as we continue to look at new technology.
Part of what helped US in 2020 was a scheduling tool that we put together. It's collaborative allows multi multi disciplinary team input very quick responsive type communications allows the team to make real time Choi.
Choices around how we look at capital allocation, what wells, we drill and how we keep the gathering system fully utilized coupled that with water logistics software that we have now deployed that will help us further reduce.
Any wasted time understand our water movements in the field and it really turns into additional cost savings and then lastly, it really all starts with our team. We can have some of the best tools in the world, but it really starts with the creativity of our teams and their ability to continue to drive innovative solutions. So.
We're very optimistic when you look back on <unk>.
Slide nine and you see what our cost track record has been just the past two years you could look farther back and we'd have a similar story, we expect to see similar cost reductions and improvements as we go forward in the years ahead on the inventory that Jeff touched on.
John I appreciate it Jeff.
So based on that.
Go ahead John.
I was just going to say, having a big blocky position in our core area with a high quality team being able to go back to existing pads with that theme allow we can do that from a long long time.
So it goes on with Michael appreciate it on just thinking about 15 so on.
Thank you from all of my.
My follow up is on the breakeven.
Because obviously as you move into this kind of ex sustaining capital.
The free cash flow to help us calibrate John.
It looks like your fixed cash costs. Some later on marquee seven top 99 into.
Interest would be on almost 30 clients so I guess.
Thank you.
Sustaining capital will be about another.
30, I guess on a few.
Second basis, and then finally, you've got the.
The basis differentials.
It gets us to about $2 50 to $2 60, and I'm. Just curious if you could tell us what you think your sustaining breakeven gas price. So we can calibrate our free cash flow.
Sure, Doug I think you're right in where we stand today I think the important factors to consider is how that trends in 2022 23 and shortly thereafter. So one important thing to note is what our realized prices look like.
There is of course a basis differential for gas.
The Ngls one really important thing to look at is what's the uplift I mean, if you just look at current NGL prices for calendar 'twenty. One you are talking $23, a barrel, which equates to $4 an mcf so theres a positive realized.
Parental there when you're looking at units of production on an equivalent basis.
So.
One fact that theyre at the top line as you move down the cost structure, we've talked about it quite a bit but there are built in contractual savings on gathering processing transport, there's some detail given in the press release, but just through 2025, you have substantial savings.
Youre looking at $70 million incrementally and then another 100 million total.
Savings on unit costs.
Thereafter, we have options as Dennis just mentioned about whether or not it's economics on what additional long haul transport go or whether our margins are best pertaining that so again options to further reduce that as we just moved down the line items of the unit cost interest expense I mean, if we just look at cash flow using the example, you gave the <unk>.
Pricing.
Breakeven cost is the same as the simple math I gave during the scripted portion.
If you use that and look at what cash flow does just over the next couple of years. That's also illustrated in the new deck on Slide 14, you are looking at roughly again illustrative math youre looking at close to $700 million.
In debt reduction over two years, well, let's just make the math simple on assume.
Coupon that's $35 million in savings just over two years or since improvement Thats ongoing thats continuous this is compounding growing cash flow reducing unit costs. So I think as a starting point, we would agree with where you're at.
<unk> I think in terms of each of these unit costs is contractually build tenant on a positive feedback loop.
Really helpful guys. Thanks again for linear on thank you.
Thanks, Doug.
Thank you. The next question comes from Brian singer with Goldman Sachs. Your line is now open.
Thank you good morning.
Good morning, Brian.
You discussed the long inventory at it will exceed your proved reserves and I wondered from a gas perspective, what your outlook is for the ability for industry to stimulate demand within the region and then how you think about the cost benefit around that time lag as you await the region too.
And maybe this is.
Similar words to what you need range as growth down the road versus the opportunities to monetize via further divestitures.
Well, let me start off we'll probably all I'll pile in with different comments, but one youll see natural gas, replacing coal coal continues to get retired a few there is a slot on thinking the ducks somewhere it talks about gas at one point being third Colby.
Coal being about two thirds of the powder stock balance on the low twenty's.
Given.
The advantages of gas being so much cleaner.
Yeah.
Of course part of that'll be renewables, but gas has been capturing about two thirds of that I think with time. So coal will continue to decline and that will that will happen within the region.
Ultimately in some cases on nuclear replacement.
Coupled with growth in interest in basin power generation. So there's good opportunities there to grow on also on the deck, we talked about as a country LNG exports also continuing to grow and we think that will grow significantly with time you really have.
Same situation globally from the country, you've got still a lot of coal being burned internationally places like China and elsewhere.
Ultimately I think natural gas okay.
Yes, Mark as well so.
We've got information on the deck.
We think having a long life core inventory is key and we see others exhausting their core inventory in some cases.
In a relatively short timeframe within Appalachia on slide 15, again bottom right. It shows some of the peers have import inventory of two years.
Five years, so having that core inventory I think will put us in a good price world as Mark mentioned earlier, we're always open to whatever is best for our shareholders.
Optimizing the value of the inventory depends.
Depending on what opportunities are available, but mark Dennis.
Yes, Brian.
This is Dennis real quickly I think in addition to Jeff's comments.
We currently have clear line of sight on Shell's Cracker facility is being local demand infrastructure development in that getting into service here.
The new engineered future PTT is another name that clearly they're an organization that is looking to build some infrastructure for local demand as well when you look at the pipe takeaway capacity that's been developed not only for the natural gas side, but also on the liquid side to get to Marcus hook. It really starts to create an advance.
<unk> from range based upon our contiguous acreage position and we like the ability of how that ties back to our not only our future development of the inventory Jeff touched on but also the NGL realization capture that we're going to be able to see in the future.
And then to add to the LNG discussion Youre also seeing some.
Some discussions take place about potential future LNG development that could take place on the east coast again thinking about logistics out of out of Marcus Hook in that region starts to make not only range advantage, but also.
Adding to that EOG stack, where we can contribute in a positive way so.
Pretty constructive outlook.
That's great. Thank you for that and then my follow up Mark I thought I heard you use the phrase and return cash to shareholders as a goal and I Wonder if you could add any more color on what your thresholds would be from either a leverage credit credit rating or or other other perspective, where you would where you would consider that and then what the mechanism would be to consider.
Sure. So our stated long term objective from running the business is substantially below two times so.
As we approach that we are at a position where we can articulate more clearly more definitively what that framework looks like what's the reinvestment rate of cash flow what is the form of returns of capital to shareholders.
Dividend be it a variable dividend share repurchases, what's the most economic and appropriate.
Return on that capital so as.
As we approach sub two times leverage as we approach and then hopefully gain on sustained investment grade balance sheet Youll see that.
Hopefully in advanced more clearly articulated we'll be able to share with those targets are.
In the shorter term what youre going to see is the board's expectation consistent with what I would just articulate and explain.
Now they've outlined ranges strategy being sub two times leverage in the form of new competition.
Targets long term performance share targets.
Well below two times youll see that fully disclosed on the proxies.
As we get a little bit closer and again I'll refer back to slide 14, just articulating how quickly range can get to that two and even sub two times just through current prevailing market prices could be near the end of 2022, so sometimes that we could further go into detail there.
Great. Thank you.
Thank you.
Thank you Leon name end of today's conference, we will go to Josh Silverstein of Wolfe Research from our final question.
Yeah. Thanks, good morning, guys.
Over the past three years your NGL realizations have been improving and this year, you're guiding towards a premium over over Mont Belvieu.
Is that wanted to do premium what you guys are receiving now.
Or do you think this continues to and I think you've mentioned before that there is some more upside to this so I'm wondering if that premium continues to grow as youre going into 'twenty two.
Hi, Josh.
Alan Engberg with B I head up our liquids business on I'll try to answer your question here.
The NGL market value right now is currently trading over $25 a barrel that's up $7 a barrel versus the fourth quarter.
39% increase just for context in 2020, our pre hedge realization was about 15.
<unk> 43 per barrel so.
Current strip we're looking.
At realizations from roughly $23 per barrel for 2021.
And again versus 2020, that's an increase of $7 three quarters. Some 75 per barrel. So it's a 50% increase which we just on that basis is about $280 million in additional revenue.
Now that's at current strip and our views at current strip is actually pretty conservative.
And just walk you through an example, I think that so propane stocks.
Have declined considerably this season right Im talking about the winter season.
Charles starting back on October 1st we've withdrawn from inventory at a rate that's <unk>.
Twice that of last year and significantly over the five year average.
Now February a lot of that is driven by just real good domestic demand that's up considerably versus last year, but also on the exports that have been very very strong.
If we look forward.
If we continue to export at let's say the average rate that we were exporting in the fourth quarter and in January of this year.
Between February because February has been a bit of an anomaly because of weather and some other factors.
But if we continue to export at the same rate, we're actually going to go into next year's winter season. So October one with the big inventory deficiency.
In fact, we will be at my projection is around 45 million barrels of inventory.
And Thats only 21 day supply.
The Mark typically wants to have 40 days of supply going into winter or call. It 80 million barrels of inventory.
So to get there.
We're going to have some kind of change in what's going to happen.
Prices are going to increase relative to where the strip is right now.
And relative to international pricing and that's going to lead to.
Some fewer or a reduction in actual exports.
Calculating around.
Eight to 10 Vlccs per month.
Would need to come out of the program.
To get us to the low end of where we need to be to start next winter, which is around 80 million barrels.
So again this all implies.
Better overall NGL realizations.
As Dennis mentioned earlier, we've added to our position and Marcus Hook, we can export more we expect our premiums relative to Bellevue continue to be strong.
And I think there is very positive.
Positive tailwind in place for us from a cash flow basis through the rest of the year.
Alright, thanks for that.
And then maybe just on the ethane side.
I don't think you guys are recovering anything additional this year and guidance, but I'm just wondering what price point on what May trigger you guys to be able to extract a little bit more do you think that won't be happening this year.
On an ethane front, Josh we kind of maintain a course of kind of a middle of the road extraction somewhere in the 60 to 65000 barrel per day trajectory.
We ensure that we're meeting all of our commitments that we have contractual through the through the program year, but it also leaves us optionality in the event as Alan was pointing to we see something constructive.
That allows us to take advantage of an opportunity we further add to the cash flow.
Bottom line as Mark touched on and improve our overall realizations. So we leave that flexibility in play.
Heavy export I'm, sorry, takeaway capacity on three of the four main outlets in the northeast gives us an opportunity to do so so we will look for those opportunities through 2021, just as we have in prior years.
Great. Thanks, Dennis.
Thank you.
Thank you. This concludes today's question and answer session I would like to turn the call back over to Mr. Ventura for his.
Concluding remarks.
To conclude with just a really brief summary of the range story, we have best in class drilling complete cost with the lowest decline rate in the basin leads to lowest maintenance capital couple that with the largest tier one inventory really leads to sustainable free cash flow for many years, we're doing that into a better macro pricing environment.
<unk>.
We are and we're focused on being an environmental leader amongst E&P companies and our compensation framework is aligned with shareholders and our strategic objectives. Thanks, everybody for participating in the call. This morning.
To follow up with our team for any additional questions.
Thank you for your participation on today's conference you May now disconnect at this time.
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