Q4 2019 Earnings Call
Excuse me, ladies and gentlemen, this the operator today's conference call is scheduled to begin momentarily. So that time your life will again be placed a musical thank you for your patience.
[music].
Good day, ladies and gentlemen, and welcome to the P.D.C. Energy fourth quarter 2018 earnings Conference call.
As time, all participants are in listen only mode.
Later, we will conduct a question and answer session and instructions will follow what that time.
As a reminder, this conference call is being recorded.
I would not only to turn the conference over to your host Mike Edwards Senior director of Investor Relations you may begin sorry.
Thank you.
Good morning, everyone welcome.
Call today.
Brookman, President and CEO, Lance Lauck Executive Vice President, Scott Reasoner, Chief operating officer.
Scott Myers, Chief Financial Officer.
Yesterday afternoon, we issued a press release and posted a slide presentation that accompanies remarks today.
We also filed a form 10-K.
The press release in presentation are available on the Investor Relations page of our website, which is P. D C E dotcom.
I'd call your attention to slide two of that presentation.
Forward looking statements.
We will present, some non U.S. GAAP financial numbers today. So I'd also like to call your attention to the appendix slides that presentation.
Where you'll find the reconciliation of those non U.S. GAAP financial measures that wouldn't get started don't turn the call reports Brooklyn or CEO.
Thank you, Mike and welcome everyone.
Today, we have quite a story to share with you.
Our message we are positioned to deliver exceptional performance metrics long term.
At PTC.
Yes.
Our business plan.
Finalized the Src merger and as you will see our intense focus on five key areas is very real.
Those being.
First the execution.
He was flat.
Next generating sustainable free cash flow.
Well, we continue to maintain balance sheet strength.
And our commitment to returning capital to work shareholders.
Well, we focus on social responsibility.
E H units.
Sure it shouldn't be aware.
Our industry is facing a unique set of dynamics and channel.
However, I assure you at PTC, we're poised for both financial and operational success.
Now, let me hit some 2019 highlights.
Free cash flow of $40 million for the year.
200 million a free cash flow in the second half of 2019.
Capital spending of $790 million that is $50 million under our original guidance should know strong per well.
Oh, well cost improvements in both basis, particularly in the second half would be or which influenced a 2019 capex and also improved 2020 spend levels.
Production for the year was on target at 49.4 billion barrels of oil equivalent again right in line with our expectations lifting costs were a solid two dollar an 80 cents per barrel that is a 12% improvement for 2018 levels.
And the balance sheet remains strong leverage ratio of 1.4, as we close out 2019.
$155 million was expanded upon or stock buyback program.
Finally for 2019, I'd like to thank our environmental health and safety team and Baltimore operating areas for setting New records and environmental protection.
Safety performance.
Standing job.
No.
2020, what I believe it will be a breakthrough year for the company.
Let me tell you why.
Projected free cash flow of $250 million that is at 50 to 50 oil into dollar natural gas.
Free cash flow yield over 12% three times the average of the S&P 500.
Capital spend of one we know $5 billion.
That is $250 million less than our merger rollout in late August.
In 2020, we plan to strengthen the balance sheet and Opportunistically continue with our stock repurchase program.
Production is anticipated to be 210000 barrels oil equivalent per day or 76.6 million barrels born.
I don't want for the year.
And we expect lifting costs and GE any combined will be under $5 previously.
Lifting costs anticipated at $2, an 80 cents per building in January $2 per really.
Solid improvement.
Lastly, our board recently proposed several key modifications to our corporate governance structure and made substantial improvements to the executive compensation program.
I refer you to our latest press release for details on these changes.
As I close my remarks today, I really encourage you to listen closely to Lance's comments later in the call where he will outline our two year outlook, which demonstrates the sustainability of our business plan.
Ability to enhance free cash flows.
For years.
Improved returns to our shareholders and strengthening an already robust balance sheet.
We'll highlight and reemphasize the key drivers differentiate PTC story.
With that I will turn the call over to Scott Reasoner for an operational.
Thanks, Bart and good morning, everyone.
Before reviewing our 2019 results and 2020 operational plans I want to spend a minute thanking our employees for a tremendous year.
Not only did we set new PTC records from a safety perspective.
We did this while continuing to capture efficiencies from both the timing cost perspective, well working tirelessly to integrate the src assets systems and data throughout the second after the year.
Truly a great job to the PTC team, our new members that came over from Src.
And those helping in the transition.
To carry on barge themes Ptcs primary focus is truly on the execution of our capital and operating plan.
As evidenced by our full year results on slide seven.
I'm extremely proud that our full year capital investments, which reflects both our efficiency gains and capital discipline.
Came in well below our full year guidance range.
For the year, we invested approximately $790 million to drill approximately 160 wells and turn in line 135 wells.
From a lifting cost perspective, our full year, although we per meal, we was towards the bottom of the guidance range and indicative of both the operating environment improvements we're witnessing.
As well as our favorable commercial service agreements.
Finally total production came in about a 135000 barrels of oil equivalent per day with oil production of more than 52000 barrels per day.
These represent 26 and 13% annual growth respectively.
As Bart alluded to our 2020 guidance range and long term outlook equates to growth more in the 5% to 10% range.
In all have more on this in a moment.
In terms of the fourth quarter, we continued to see positive trends in both our daily production and Delaware We previously.
The main take away on slide eight is that overall, we experienced flatter than anticipated declines in each basin.
Which obviously benefit both chart show.
I'll cover the DJ in more detail shortly but effectively lower line pressures provided a boost to volumes as we were able to service wells that had been previously impacted by the high pressures. While also seeing an uplift from the 12 turn in lines in the quarter.
Meanwhile, our team had a great quarter down in the Delaware as they improve the timing of some well connects and reduced our flaring, both providing a sharp me arm to volumes, despite having no turn in lines since late summer.
Shifting gears to 2020, we outline our core capital budget and production guidance on slide nine.
As Bart mentioned, we're extremely proud of our estimated free cash flow for the year of approximately $250 million, assuming 50 to 50 MW T R and two dollar Nymex.
Our capital investment range for the year is $1 billion to $1.1 billion.
Representing a year over year decrease of approximately 15% compared to what PTC and Src invested in late in 2019.
I want to call out that we plan to invest 55% to 60% of our total budget in the first half of your as we resumed activity after a wall in the fourth quarter of 2019.
Compared to the outlook, we provided back in August our price assumptions are down across the board.
Similarly, our capital investment has been reduced by $250 million at the midpoint, while our projected free cash flow is down only $25 million.
You can see on the bottom right hand side of the slide that Weve provided the price sensitivity for each commodity.
From a production standpoint, we've narrowed our prior range of 200 to 220000 barrels of oil equivalent per day to 205 to 215000 barrels of oil equivalent per day at the midpoint. This equates to a 5% to 10% growth compared to 2019.
Combined volumes.
I want to highlight specifically that our full year range reflects the mid January close date of the Src merger.
This is most impactful in the first quarter obviously.
But please keep in mind that our reported numbers will not have a full quarter of the combined company.
In terms of oil we expect to produce between 78 and 82000 barrels per day.
I do want to call out that we expect a 10% 10% to 15% sequential decline in the first quarter due to the reduced second half activity and the mid month Src close.
On a true pro forma basis, our first quarter decline for both total be a week and oil production volumes would be approximately 5% to 10%.
Importantly, we project, our fourth quarter 2020 oil volumes to reflect 10% to 15% growth compared to the fourth quarter of 2019.
You'll see in the coming slides that we provided some more detail for our first quarter expectations in each of the Wattenberg and Delaware.
Covering the Wattenberg first.
We expect to invest approximately $750 million or 70% of the full year budget to run three rigs and wanting to have completion crews.
Dissipate 150 to 175, Spuds and 200 to 225 turn in lines.
Primarily on our currency and recently acquired Src acreage positions.
What I really want to call your attention to is the graph on the right hand side of the slide.
Which outlines the next two years of projected activity in the basin.
The key points here are our recent DUC count and number of approved permits.
Later in the call Lance will outline our multiyear outlook.
And our intent is to show you that from the Wattenberg, we can achieve everything that has outlined from a turn in line perspective perspective, using only our current ducks and approved permits.
Specifically all of our 2020 turn in lines are currently drilled but uncompleted well we have permits in hand to meet our 2020 spud count.
In 2021 are currently approved permits and 2020 drilling programs projected take us into November on our current turn in lines schedule.
Not shown on this graph or a good number of projects that are far along in the permit process.
We obviously have a little work to do in terms of our 2021 drilling program, but generally speaking those wells are not planned to be turned in line until 2022 and more importantly, we continue to see approved permit flow from the CEO GCC.
Again, the main take away, especially as our top focuses on execution is that we have supreme confidence in our ability to deliver on our multiyear outlook, while still exiting 2021 with tremendous flexibility and approximately 150 Wattenberg ducks in hand.
The other component to our ability to execute in Wattenberg is obviously the midstream environment I.
I mentioned the earlier I mentioned earlier the uplift we saw to our fourth quarter volumes. Thanks in part to the improved line pressures.
And you can see that pretty clearly on the graph at the bottom of slide 11.
Average line pressures of our currency area, which we show in black were dramatically down in the quarter from levels of nearly 400 PSR to the 250 PXI range.
As our activity begins to shift away from currency compared to previous years, we thought it'd be relevant to show average line pressures throughout the field as you can see there are small differences between each area.
Finally, with the upcoming in service dates of the Cheyenne connector and late them too. We expect further improvements to line pressures and third party midstream performance throughout the year.
Moving to the Delaware Slide 12 highlights our 300 million dollar operating plan for the year.
Currently we are operating one rig and one completion crew in the basin with expectations to bring back a second rig late in the third quarter in preparation for 2021.
Obviously with the gas market, where it is we feel very fortunate to have the flexibility to our just to adjust our capital plan in this manner.
Our turned in line activity is entirely focused in the block for area and we project, our completed well costs, including facilities to come in between nine and a half and $11 million for an MRL and X or l., respectively.
This is a considerable improvement to 2019, when our budgeted well costs were tenant a half than $12 million respectively.
On slide 13, we outlined some of the factors that are driving our cost improvements.
Obviously, an improved services environment has contributed but in some we project our drilling completion and facility costs to come in between 1100 and $1200 per lateral foot in 2020.
This result represents an improvement of more than 30% since entering the base in 2017.
And is captured through the efficiency gains highlighted throughout the slide.
Our drilling cost per foot and spud to rig release times are directly correlated.
These costs reflect our activity focusing in on the more complex deeper walk for area in 2020.
Her to 29 teams activity largely in our north central position.
All in all I'm very excited to continue our integration efforts and focusing on executing on the 2020 plan that we deemed to be truly differentiating compared to our industry peers and the general market.
With that I'll turn the call call over to Scott Myers.
Thanks, Scott how quickly cover or 2019 results before providing some more detail on our 2020 financial guidance, but first I want to piggyback on your integration comments by also thinking our team the incredible work they've done over the past several months.
As we entered 2020, we successfully launched an ERP system, while working through a merger and executing on our day to day responsibilities.
This is hard work is not done yet, but I truly appreciate the time and sacrifices up the entire team.
Quickly covering our GAAP metrics you will see total sales are down for both the fourth quarter and the full year as a result of the 20 Pos plus percent decreases to are weighted average realized price per Boe eat outweighing the production growth for the respective periods.
New this slide we've added a graph showing our gn our quarterly Gnh per BOE, we both in terms of run rate and all in.
Obviously 2019 had a handful of what we will consider nonrecurring expenses related to the Src merger, Delaware Midstream divestiture partnership settlements and shareholder activism.
No matter, which way you look at 2019 was a strong year on many fronts and we're forced to make some very difficult decisions along the way to help deliver the trends shown on the graph and a fourth quarter DNA run rate below $2.75 per Boe.
As will cover more in a minute, we expect a bit of noise in the first half of 2020 as we continue our integration efforts, but look for this trend to continue moving in the right direction into 2021.
Moving to slide 16, I'd like to remind you that the reconciliations of our non U.S. GAAP metrics, including free cash flow can be found in the appendix.
For the quarter, we generated just under 160 million of free cash flow, which pushed our full year free cash flow to just under $40 million.
Many companies have stays a plan to de Levered free cash flow and reference various often changing inflection points in doing so at PTC. We're extremely proud to have delivered free cash flow in 2019.
Throughout the year, we made several operational decisions that demonstrates our flexibility in commitment to the year end goal of delivering free cash flow.
And we remain we maintain this flexibility into 2020 and 21.
Finally, our EBITDAX and adjusted cash flows are relatively flat between both the comparative fourth quarter and full year periods as the impact from prices and volumes once again offset each other.
Scott already covered elderly, but from an all in production cost standpoint, you can see on slide 17 that our total spend of 269 million in 2019 represents a very modest increase from 2018.
Which has resulted in an impressive 15% decrease per Boe between periods.
The decrease in production taxes, obviously plays a role in this but we're happy to see the overall trend in our Ela, we which was down 9% for the fourth quarter and 12% for the full year on a Boe basis.
Importantly, our Ela, we by basin indicates that each area is hitting their targets as wattenberg came in below 250 per Boe and Delaware was right at $4.
In 2020, we look to once again deliver wattenberg Lee of per BOE, we have less than 250, while we expect a uptick in Delaware to the 450 range as we expected increase in water handling costs associated with our block for area.
Shifting gears to slide 18 provides detail on our balance sheet and financial strength, both of which we considered to be peer leading in contributing factors to what differentiates PTC.
I did note all numbers here or its 12, 31, 19 and reflect the PTC Src combination.
Late last week, we announced the results of our tender offer the six and a quarter of 550 million senior notes from Src as a reminder, approximately 450 million of the notes were 10.
With the remaining 100 million outstanding.
As shown on the graph, we simply placed a 450 million plus interest and fees on our revolver and maintain a total liquidity of over $1 billion.
I want to emphasize that given our liquidity the trailing 12 months leverage ratio of 1.4, and our projections to generate significant free cash flow, we're very comfortable leaving this debt as pre payable and maintaining the flexibility to buy back shares were retired debt.
In terms of our share buyback program, we were obviously blacked out for much of the second half a 19 due to the merger announcement, but we still managed to utilize over $150 million to buyback nearly 5 million shares.
Since closing in mid January we've bought back over 600000 shares with just over 12 for just over $12 million, we fully anticipate being able to complete the remaining six or 360 million of the 525 million buyback program by the end of next year.
Turning our attention to 2020, Scott Reasoner, just laid out our 2020 plan, which has quite a few changes beneath the surface compared to our initial outlook provided last August.
On slide 19, we do our best to explain these changes both in terms of expected capital investment and projected adjusted cash flows to give a little background in August we assumed capex of 1.2 to 1.4 billion and free cash flow of approximate.
Hundred 75 million.
Since that time, we've seen a lot of built volatility in the crude space at is as it is settled with both a six handle and a four handle and the last month alone.
Gas and NGL realizations have obviously deteriorated compared to our initial assumptions.
The graph on the bottom of the slide does a great job of walking you from the midpoint of our expected adjusted cash flows of just under 1.6 billion inner acquisition model back in August to the current level of approximately 1.3 billion [noise].
As you can see we showed the impact to our sales net of derivatives for each foil gas and Ngls.
From the start of the budgeting process, our emphasis was finding the appropriate balance between generating our stated free cash flow goal.
Delivering a smoother cadence of activity that results in consistent quarterly free cash flow and obviously the best operational plan for the company long term.
We feel the current budget and adjustment the we've made to our capital plan checked all of these boxes.
The bluegrass at the top of the page clearly lays out and breaks down.
Between the reduction activity in reduction well cost per each basin as you will see approximately 175 million or the 250 million to capex reduction at the midpoint is associated with Wattenberg.
Scott highlighted earlier, we plan to exit 2021, with nearly 150 docs in Wattenberg, implying we still maintain a lot of flexibility to continue to adapt to price volatility and delivering differentiating free cash flow as opposed to solely relying on price improvements as much of the MPC.
Basis.
Before turning the call over to Lance I want to provide an overview of the anticipated cost structure in 2020.
Please remember when looking at our 2020 guidance, we had to exclude approximately half month of the Src results due to our mid month close.
Also our cost guidance does not include the approximate 30 million of onetime deal costs, which will be expense in the first quarter. But does include our 10 million of transaction our transition costs that will being heard over the first seven months of the year.
Scott and I have already shown favorable trends in both Ela wheat, and gnh on a daily basis over the past year, but this slide really demonstrates the efficiency gains of the new PDC as the result of the merger.
As you can see we expect the combined Ellen LSB and DNA to be less than $5 per Boe in 2020.
This represents a year over year improvement up more than 20%.
Fourg DNA that quarterly cadence will be a little choppy in the first half of the year as we pay the remaining of the deal costs and finalize the integration.
We expect us to get our run rate DNA in the second half the year and carried that momentum into 2021. When we expect these cost trends to continue moving in the right direction.
With that I'll turn the call over to Lance to cover our multiyear outlook.
Thanks, Scott in this last section of todays call, we're providing several updates to our multiyear plan that we project will deliver tremendous value through consistent sustainable free cash flow generation.
Return of capital.
Improvement on an already strong balance sheet and modest oil production growth.
Beginning on slide 22, we highlight each of these strong attributes.
For 2020, and 2021, we project to invest between 2.1 and $2.3 billion.
With our current 2020 capital plan of one to 1.1 billion. This implies an increase of approximately 10% at the midpoint in 2021.
To modestly increase our activity in both the Wattenberg and the Delaware.
This increase will enable us to deliver consistent free cash flow on a quarter over quarter basis.
In terms of total free cash flow you can see that we project to generate 850 million for the second half for 2019 through year end 21.
As you May recall from our August 19 rollout of the merger with Src, we projected that would generate free cash flow of $200 million in the last two quarters of 29 team.
We're happy to report that we've checked the box on that projection.
Looking now or the next two years, we project to generate 650 million in 2020 and 2021.
Our price deck assumes 50 to 50, WT, ATI and $2 and 2020.
And then $55 WT into 50 for gas and 2021.
For both years, we hold NGL prices flat at approximately $11 per barrel.
We've included table below that provides adjusted cash flow sensitivities based on price changes to each of the three commodities.
Our adjustments to cash flows and 2021 are greater than 2020, primarily due to having less hedges in place next year.
It's important to note that we project a very strong free cash flow yield of 12% and 2020.
Going to 18% in 2021.
This projected two year free cash flow yield of approximately 30% demonstrates the sustainability of our free cash flow.
Additionally, we also project to generate a two year free cash flow margin of 30%, which we define us free cash flow over capital investments.
As we model out or development plans over the long term our goal is to deliver more consistent financial results on a quarter over quarter basis to do so we're mapping our capital program to provide more ratable and consistent growth and free cash flow and production.
The result is that we project to deliver free cash flow in seven of the eight next quarter's beginning in the second quarter of 2020.
We currently project that we will return free cash flow to investors over the next two years to not only complete our 525 million dollar share repurchase program, but to also retire approximately $300 million in debt.
We model that these financially disciplined steps along with modest EBITDAX growth will improve pdcs already strong balance sheet to a leverage ratio of approximately one point, though as we exit 2021.
Okay.
Next on slide 23, we compare to the most important metrics that are industry is being measured upon.
We not only compare PDC to our current peer group of similar size companies, but we also compare our company to a group of select large cap BMP companies and then very importantly, the composite S&P 500.
For comparison, our projected 2020 free cash flow yield of 12% is nearly double our peer group and what we consider to be an elite group of large cap MP companies.
We also project that are 2020 free cash flow yield a 12% equates to about three times that of the composite S&P 500 index.
SPDC continues to execute on this plan to deliver says substantial free cash flow over the next couple of years. We believe we will differentiate our company among our peer group.
The select large kept BNP group and to the broader S&P 500.
In terms of leverage we also believe that targeting and beating S&P 500 levels is needed to compete for investment dollars.
Well, we are extremely thankful for a year in two.
2020 projection of 1.4 times, which is better than both our peers and select large cap group, we have our eyes set on a leverage ratio of 1.0 or below to compete head to head with the S&P 500.
We expect to achieve our target at year end 2021.
Finally, I'd like to finish by highlighting the value proposition the bar open the call with.
We are confident over the next few years that our intense focus on execution will lead PTC to generate consistent sustainable levels of quarterly free cash flow.
We plan to utilize this free cash flow to not only fortify our balance sheet and strive for investment grade metrics, but also to return a significant portion to our shareholders do completing our share buyback program.
We also positioned the company for future consideration of a dividend.
The strength of Pdcs portfolio can be seen in our year end 2019, FCC proved reserves pro forma Src, which are slightly over 900 million barrels of oil equivalent.
Additionally, the value of Ptcs portfolio can be seen in our strong pro forma be tax PV 10 proved reserve value of $5.8 billion.
Finally, and importantly, we are committed to corporate social responsibility as we safely and responsibly develop and produce energy.
Well it truly differentiates PDC is that we expect to deliver sustainable long term through the commodity cycle free cash flow and modest long term oil growth.
While improving upon an already strong balance sheet.
With that I'll turn the call over to the operator.
At this site if you like to ask a question. Please press star and the number one on your telephone keypad again that is far wants to ask a question well pause for just a moment. So compiled the Q1 day last time.
And your first question comes from the line of wireless Okay, What's franchise.
Hey, good morning.
Well.
Just a quick clarification on the 21 kind of soft God to 5% to 10% growth is that I know it can't be accidentally because of the merger, but should we think of that is kind of a one key to one Q and I just ask because of its year over year. It looks like it might be it might imply flattish offsets for Q 20 number.
It's really well this is Scott, it's really year over year in as far as the overall math there I'm not 100% sure I can confirm all of your thoughts.
I think when we when we look at it it's truly though the year over year gain.
So I do know we have a frac holiday scheduled in the Delaware.
The latter half from 20 to 20 wells than I think that will have a flattening effect on the Delaware production and likewise on the Wattenberg part because we only have one frac pre running at the second half of this year. So.
With that being said the dip would not be expected to be as big as the dip is this first quarter.
Again, one of the big things for the budgeting process was to try to get some of the stability in our quarterly numbers as we go so that we can generate free cash flow in all quarters going forward. After the second quarter this year.
Okay that that makes perfect sense and then.
As you go into 22, I mean, obviously, the 20 to 20 budgets.
Kind of kind of kind of.
Two thirds wattenberg as it is that more a function of the ducs or do you think that that.
Heavy wattenberg waiting all continuing to 21.
Yeah Wells. This is lance as we model out 2021, you'll you'll see really that same rough allocation of capital between Wattenberg and Delaware as we go forward, that's kind of our plan that we have going forward pro forma the Src merger.
Okay perfect. That's that's all I have congrats on the the strong multiyear up it.
Thank you.
Your next question comes from the line of Bryan County with Citigroup.
Good morning, Thanks for taking my questions. Just curious looking at today's share price and macro concerns and given some of the hedges you have this year I'm curious, how you're thinking of the alignment of potential share repurchases and your anticipated free cash flow pay.
Given that you're expecting to be positive from twoq through Fourq you. This year it sounds like you've repurchased a bit here year to date in Princeton healthy free cash flow. During Fourq, you 19, but I'm wondering if there's a governing factor out how you're thinking through the repurchase pace versus debt reduction.
Thanks.
Yeah, I mean, we we're absolutely committed to having our share buyback executed by the end of 21 with that being said we have been doing a tiered program when the prices a little more depressed we have accelerated to that program and at these prices clearly.
Some share buyback is probably going a little bit more weighted my eyes in the debt reduction, but we're going to continue to watch that watch the market. We don't want to do anything Oh, all at one time, we're going to spread it out over the year, but I will say that at these prices a stock buyback is very high on our list.
Okay.
Appreciate it and then Lance I was curious you had mentioned the a the year end pro forma PV 10 of $5.8 billion off you had it off hand off curious how much of that with PDP PV 10 at it looked like in the 10-K. The disclosures were only the PDC standalone values I was curious whether the PDP that total.
Maybe 10 ratio was materially different for the acquired FRC assets.
You know I don't have that breakout in front of me.
Our key theme on that is when you when you look at the combined company little over 900 million barrels.
To have a PV 10 value all in.
Of 5.8 billion dollar shows the real strength of the company and the value that we have just on a proved reserve base alone there.
When you look at the proved reserves were about 37% proved developed as a company. So when you think about the $5.8 billion that includes the capital required to develop the puds. That's in the proved reserve base. So it's all inclusive of an all in with that future capital spend and then through that.
The PV 10 value of $5.8 billion. So as a 37 pursue PD is that for the.
The combined companies the 37% proved developed is on the volume basis and further mine confidence.
Right. So 37 on the volume basis, but to your point if you are.
Don't have the development capex around that I expected PDP value to be skewed higher than and 37% or that I pointed.
You're spot on Brian Phoebe Privia, we have that.
The PDP would be greater than that of the pilot, but all in this 5.8 billion. So good question.
Great I appreciate.
Kind of thing.
Your next question comes from the line of Oliver Wang with Tudor Pickering Holt.
Good morning, and thanks for taking my questions.
Welcome.
I'm wondering when we're thinking about your updated to your outlook. What is the best way to think about flexibility of activity within that timeframe, just given commodity volatility would it be more practical to think of any downward shift if commodities were to warrant within the program towards getting the.
The call it $500 million to $650 million range of cumulative free cash flow that would satisfy the repo and pay down some debt or would there be some other governor that we should focus on more if the cranks price deck was closer to call it $45.
This is Scott I'll start there may be some others the jump in on that.
When you talk about our flexibility we have tremendous amount of flexibility are are you start with the drilling contracts or short term.
The.
Completion agreement. So we have are also short term and I would say that gives us the flexibility we need as well as our acreage is HBP, primarily so we've got the flexibility in terms of operationally to make the adjustments that are appropriate. It's just difficult always as we continue to watch these prices fluctuate to say what you would do.
[music] with just prices falling because typically what happens at the same time like the prices fall the capex costs come down as well so that rolls into the discussion is something that's really important to you can't do those don't move independently their interdependent.
And I think Thats one of the things always point too when you start talking about specific prices.
I guess, the best way for Us to say this is we're very focused on delivering cash flow and that type of that type of mental state is something that we stay focused on if the.
I'll just habit make an assumption here at prices happened to fall in capital cost Didnt come down we definitely be looking at our programs to say what could we do to deliver as much cash or cash flow as possible.
So.
Not giving any specifics there I think that's the best I can do and I think Scott Myers Who's got a couple of calls yet just just add a little color without changing the capital program or cost at all if you look at our and on the Slide 22, we give you.
The changes to our cash flow in each year and $45 for the two years, we would still have approximately 300 million of free cash flow without any changes to capital investments.
Clearly, we would not execute the same plan we have today, if we if we had a 45 dollar environment. So that shows you that that's that's the the flexibility that we have and we will absolutely continue to watch the free cash flow numbers. So we can continue to buyback the shares execute the program and repay debt and also.
Don't forget our free cash flow number does not include the 80 plus million dollars that we're getting in the second quarter from our midstream sale that we completed last year. So we have lots of flexibility here.
We're looking for some improvement, but we're going to weather the storm, while we haven't.
Oliver This is Bart just a couple more ads to this because I think given today.
The current market, it's a fair question.
Just reinforce what these guys said a lot of flexibility.
We have we have the ability to take or take our growth level with just under 7%. This year, maybe closer to 10 next year, but we have the flexibility.
Probably most in the Wattenberg.
The DUC count sooner rig count, but we'd give strong consideration of both basins.
But we could we can take that down in the low single digits and even take it close to zero. If we have two to honor that free cash flow, we have the flexibility to do that but I. Also think is very important to note that both basins right now and we've run every sensitivity possible as we're watching this this current market.
Both both our projects are delivering value well above our cost of capital.
Even at a $45 oil price, which is supported by some things Scott Miller said.
Okay. That's all very helpful and for a second question I know Src I had an ongoing process for the mountain view I CDP wondering if you could provide an update on that front and how that fits into your go forward plan, just kind of given how gas prices remain extremely depressed and acreage isn't as much.
Catherine region of the DJ.
Its something this is Scott again, I'm I'm, a we're staying in constant contact with the CEO GCC as you can imagine Missouri.
Important processes understanding more and more of this permitting process is the rules change that type of thing so having good success, maintaining our relationship with them continuing to get permits to flow and so when you walk about when you talk about the CDP we're in a.
Position at this point, where they've said that it's probably not going to happen until the professional commission comes in which is scheduled for July and.
And there's reasons for that that's around the current rules that are being.
Really read on that type of thing so we're not expecting that till the second half of this year and it's something that as we move forward, we're going to continue to pursue because if we can figure out how to move that one off of offer the commission docket and into a and accepted process. We're looking at others from our own acreage.
Position.
Thats something they want in terms of that's that's.
Much of the intent of 181 is around things like CDP, it's something that the commission once they're just delaying that until a professional commissions in place.
Thank you very much.
Your next question comes from the line of William Thompson with Barclays.
Hey, guys I appreciate the comprehensive to your outlook.
And that cash flow subsidy figures on slide 22, which I really off on a day like today using that my basic math shows about 100 million a free cash flow at $45 Wi Fi dollars to be five gas and $9 NGL realizations in 2020 alone I think all agree we hope that's not the outcome, but just curious on how you think about balancing buybacks and debt reduction I just want to take it.
Prior you have another I understand that's probably not the sandbox.
Yeah, I mean, I mean, right now where we're sitting that with our internal price you and where we're feeling comfortable with our stock price where it is today right now we're very comfortable buying back shares obviously, if we start looking at a 40 or 45 dollar environment, we need to examine how the capex.
It is going to change what price relief, we're going to get to vendors. So that we can still delivered the free cash flow. So there is a balance act there, but when we look at our hedge policies and procedures.
We don't go over a two times debt to EBITDAX in a 40 dollar world for well over 12 months. So we have flexibility.
But we don't want to ever get into a box either so we're going to continue to balance it right now the share buyback living says on the top of the list, but we'll continue to watch and make sure that we don't risk the balance sheet. The part of the part of where we're at today is because we've managed the balance sheet over the last three or four.
Years, despite the different activity that we've done we will continue to focus on that so it gives us the flexibility in the future.
Okay. That's helpful and then.
Looks like the line pressures continued that trend in the right direction I know you're waiting on Cheyenne factor in lightweight them too.
Where are you in terms of deep DCP quarter constraints, just and their rough estimate how much production between PC increase though.
Our Arthur Src IR are shut in and how quickly that can come back on.
Yes. So this is lance so where we sit with regard to the status at DCP right now has the capacity in the basin of approximately 1.4 Bcf per day the.
The current throughput of the field is less than that currently so that's one of the reasons why were stance on the line pressures come down.
Clearly them with light them too and the shine connector they'll probably in the 1.6 to 1.65 Bcf a day of total capacity.
Based upon the fact that they now have additional space and their system they've come off allocation for all the producers. So that's a positive thing for all of us that gives us opportunity to produce more volumes.
As far as our returned to production wells, we are clearly in the middle of return in those two production and you'll recall those are wells that Src had that had shut in due to the allocations.
From our midstream provider. So weve turned in line. So those wells we have several more to go overtime. Scott can you cover the numbers on yeah. When when we entered the first of this year. We were at about 60 wells shut in remaining to be turned in line a number of those have already been returned to production.
Really made up of a combination of wells that needed potentially larger.
Meters that type of thing where were they were under design for the productivity actual wells with with the high line pressure that we were faced with that was not normal.
So we're working through those types of things some of the wells needs while been and then there's some that have a little bit more work might be sanded up that kind of thing so.
Really have those scheduled through the first.
Three three quarters of this year, probably be done sooner than that but that's kind of what our schedule is at this point at the same time, we're doing that obviously the the Src team continue to Frac wells right up till the first of the year. The started those wells are coming online and we've added a frac crew since that time, so we've got to Frac crews running now.
With with all those turn in lines coming down the path drill out really expecting things to start.
I want to say surging, but definitely turning the corner in terms of volumes the uplift over the next several weeks and then you know him through the end of the year then at that point. So hopefully that gives you a good summary.
Just quickly or remind us the production profile those wells I come back online I know some of them are of a low oil make oil mix, but I'm just curious on the oil project projection.
I think.
If I recall correctly or some higher gas production comes on first than they were also but little bit later, so that might benefit in the back half of the year.
Yeah, there to the wasting benefit and that's a really complex subject when you start talking about the profile.
The percentage of though the wells that Src tended to have shut in where the hired your wells, which is a really smart move.
We are producing wells the made the most oil so the wells that we've been performing in line has been tremendous wells they tend to be more gassy.
At the same time, we're doing that the first.
First the batch of PTC wells that we fracked here, we're in the planes area. So they tended to be gas here as well. So I think you're going to see a bit of a gassier period, but then we rolled back into currency with completion process. So the oil should should start flowing more the ratio of oil to gas should start coming back a little bit at that.
Point and I also want to point toward the Delaware were really were expecting oil kind of gradually through the year to increase in its percentage.
And that that obviously will offset some of that additional gas units in the wattenberg as well with the idea that we're working in walk for their primarily or in the primarily in the order oilier part of the field, we're where we truly get the best economics.
And well this is board just tying back to what all over was referencing on planes drilling which is gas here I should note. Those are still I think in our portfolio. Those are tremendous return projects is the deepest hottest highest fuel our portion of the of the DJ.
The reserve for well are phenomenal and they do have a slightly higher to your but again the economics of those as we move into that area are still very strong.
So just in summary on this whole DCP. We're we're we're incredibly relief that we are moving into a better pressure regime era. We believe this is long term with DCP. We have worked with DCP on our long term forecasts I know they've worked with other operators I do think there's even some of it.
Actual benefits with some of the capital slow down it's happening across the industry, but right now for PTC, we have an intense focus really on three areas.
PDP optimization wells that we may use wells, we inherited from Src that were online those have extra opportunity is lower pricing pressure era, we have the shut in wells that we inherited.
From Src as Scott said, we've got an intense focus on those are production engineering Department is full steam ahead on bringing those back online and then this is very important new wells to Frac crews outdoors right now those new wells. The last three years, we basically being bringing those wells on it much more can.
Three fashion and our teams, while we will be going more to a normal flow back.
So I just encourage everyone to understand that we have a very intense focus on this there is really some great opportunity here.
Alan We did the best we can do in this new regime to modeled as all into our guidance, but I think everyone is aware of some of that brings real challenges in the forecast so.
Again as we go through the year I'm hopeful that these are going to get better and there's some opportunity for the company in that area.
Hi, good color. Thank you.
Your next question comes from the line of Kevin Mccurdy would heikkinen.
Hey, guys to kind of follow up on the previous question do you had the production break down between legacy PDC.
Versus synergy for the first quarter.
No. This is Scott and I really don't it's a it's the.
Combination and we're quickly as a company moving away from that type of look.
It's the biggest issue we have in the first quarter is as we've described a number of times that the 14 days 13, 14 days get removed on the Src side.
But as a company we're quickly moving as we have a frac crew on the Src side, one on that on the deep.
PDC side.
More quickly moving away from that.
And I guess, that's the best answer I can give you.
Okay. Thanks, guys that was my only question.
Again, if you would like to ask your question. Please press star one on your telephone keypad again that is star one to ask a question.
And your next question comes from the line up done Mackintosh with Johnson Rice.
Hi, Good morning side, most of my questions have been asked but maybe a if we could just.
Sorry, if I missed this kind of walk through your thoughts around Ducs, you know you've got hundred 65 going into the year in and kind of their replacement of docs and how that fits in with the permitting process under the new 181 regulations and just kind of how you all are looking at the political landscape over the course of 20 and 21.
Now this is Scott and I'll see if I can answer that theres, a number different questions I'm not sure I caught all of them in there. So if I don't Ketchum, all let me know, but I think when we look at our our overall duct position. We're set up as I described with that coupled with the drilling permits et cetera that we have to really being effective through this year.
We do need to consider to see permit flowing.
The effective in 2021 on the drilling side and we've got we've continued to flow through there.
We are using up some of our docs as we move along through the end of 20 2021, but we continue to maintain a good level through that process and I think that shows the idea that were not just using up our ducs too.
To show the capital efficiency short term, we actually have a good plan longer term on that.
When you talk about the flow of permits at the commission and what that means in terms of the general political environment, whatever you want to call out we do continue to see permits flow, we'd always loved to have them faster on but our team stays in direct contact with them as I was describing with the idea that we continue the a dialogue around which ones are.
Needed first what that means in terms of what we need to do and in order to provide the.
The data whatever it is that if they can if they are lacking some of that or the encouragement at least that these are the ones that we do need. So we definitely keep that that discussion going on we're also doing that with Weld County now as they have added there their process the logo process and.
I'm permitting process. So it's a little more complex, but it's it feels like the momentum is moving forward.
Obviously like I said, we'd love to have it move quicker and hopefully that caught most of your questions.
Yes. Thanks, Scott you had hit all the flight sorry, sorry, if I was little confusing directocrats on a quarter and on this.
Go ahead.
I just didn't want to measure question Oh, Okay. All right. Thank you. Thanks Thomas.
And at this time there are no further questions I'll now like to turn the conference that's the Bart Brookman for closing remarks.
Yes, Thanks, Zenyatta and thank you everybody obviously.
Very challenged sector right now a tough market, but I.
I'm proud of the team I'm proud of our plan and.
I can promise you the PTC.
Team is standing strong right now looking long term as we navigate through these tougher times.
Okay.
Ladies and gentlemen. This concludes today's conference. Thank you for your participation and have a wonderful day you may all disconnect at this time.