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PDC Energy Inc (PDCE)
Q4Â 2019 Earnings Call
Feb 27, 2020, 11:00 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
Good day ladies and gentlemen and welcome to the PDC Energy fourth quarter 2019 earnings conference call. [Operator Instructions.]
I would now like to turn the conference over to your host Mike Edwards Senior Director of Investor Relations. You may begin sir.
Michael G. Edwards -- Senior Director Investor Relationss
Thank you. Good morning everyone and welcome. On the call today we have Bart Brookman President and CEO; Lance Lauck Executive Vice President; Scott Reasoner Chief Operating Officer; and Scott Meyers Chief Financial Officer. Yesterday afternoon we issued our press release and posted a slide presentation that accompanies our remarks today. We also filed our Form 10-K. The press release and presentation are available on the Investor Relations page of our website which is pdce.com. I'd like to call your attention to slide two of that presentation and our 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 of that presentation where you'll find the reconciliation of those non-U.S. GAAP financial measures.
With that we can get started. I'll turn the call over to Bart Brookman our CEO.
Barton R. Brookman -- President and Chief Executive Officer
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 PDC we have listened adapted 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 of our business plan; next generating sustainable free cash flow while we continue to maintain balance sheet strength and our commitment to returning capital to our shareholders while we focus on social responsibility and EH&S. As you are acutely aware our industry is facing a unique set of dynamics and challenges. However I assure you at PDC we are poised for both financial and operational success. Now let me hit some 2019 highlights. Free cash flow of $40 million for the year with $200 million of free cash flow in the second half of 2019. Capital spend of $790 million. That is $50 million under our original guidance. I should note strong per-well cost improvements in both basins particularly in the second half of the year which influenced the 2019 capex and also improved 2020 spend levels. Production for the year was on target at 49.4 million barrels of oil equivalent again right in line with our expectations. Lifting costs were a solid $2.88 per barrel. That is a 12% improvement from 2018 levels. And the balance sheet remains strong a leverage ratio of 1.4 as we closed out 2019 and $155 million was expended on our stock buyback program.
Finally for 2019 I'd like to thank our environmental health and safety team in both of our operating areas for setting new records in environmental protection and safety performance outstanding job. Now 2020 what I believe will be a breakthrough year for the company. Let me tell you why. Projected free cash flow of $250 million. That is at $52.50 oil and $2.00 natural gas. Free cash flow yield over 12% three times the average of the S&P 500. Capital spend of $1.05 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 of oil equivalent per day or 76.6 million barrels of oil equivalent for the year. And we expect lifting costs and G&A combined will be under $5.00 per BOE with lifting costs anticipated at $2.80 per BOE and G&A at $2.00 per BOE a 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 the ability to enhance free cash flows in future years improved returns to our shareholders and strengthening an already robust balance sheet. He will highlight and reemphasize the key drivers that differentiate PDC's story.
With that I will turn the call over to Scott Reasoner for an operational update.
Scott J. Reasoner -- Chief Operating Officer
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 PDC records from a safety perspective we did this while continuing to capture efficiencies from both a time and cost perspective while working tirelessly to integrate the SRC assets systems and data throughout the second half of the year truly a great job to the PDC team our new members that came over from SRC and those helping in the transition. To carry on Bart's themes PDC's 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 reflect 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 LOE per BOE was toward 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 at about 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 and I'll 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 LOE per BOE. The main takeaway on slide eight is that overall we experienced flatter-than-anticipated declines in each basin which obviously benefit both charts shown. 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 improved the timing of some well connects and reduced our flaring both providing a shot in the arm to volumes despite having no turn-in-lines since late summer. Shifting gears to 2020 we outline our 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 $52.50 WTI and $2.00 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 PDC and SRC invested in 2019. I want to call out that we plan to invest 55% to 60% of our total budget in the first half of the year as we resume activity after a lull 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 we've provided price sensitivity for each commodity. From a production standpoint we've narrowed our prior range of 200000 to 220000 barrels of oil equivalent per day to 205000 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 78000 and 82000 barrels per day. I do want to call out that we expect a 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 BOE 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've provided similar 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 1.5 completion crews. We anticipate 150 to 175 spuds and 200 to 225 turn-in-lines primarily on our Kersey 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 is outlined from a turn-in-line perspective using only our current DUCs and approved permits. Specifically all of our 2020 turn-in-lines are currently drilled but uncompleted while we have permits in hand to meet our 2020 spud count. In 2021 our currently approved permits and 2020 drilling program are projected to take us into November on our current turn-in-line schedule. Not shown on this graph are 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 COGCC. Again the main takeaway especially as our top focus is on execution is that we have supreme confidence in our ability to deliver our multiyear outlook while still exiting 2021 with tremendous flexibility and approximately 150 Wattenberg DUCs in hand.
The other component to our ability to execute in Wattenberg is obviously the midstream environment. 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 Kersey area which we show in black were dramatically down in the quarter from levels of nearly 400 psi to the 250 psi range. As our activity begins to shift away from Kersey compared to previous years we thought it would 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 Latham II 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 operating plan for the year. Currently we're 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 adjust our capital plan in this manner. Our turn-in-line activity is entirely focused in the Block four area and we project our completed well costs including facilities to come in between $9.5 million and $11 million for an MRL and XRL respectively. This is a considerable improvement to 2019 when our budgeted well costs were $10.5 million and $12 million respectively.
On slide 13 we outline some of the factors that are driving our cost improvements. Obviously an improved services environment has contributed but in sum we project our drilling completion and facility costs to come in between $1100 and $1200 per lateral foot in 2020. This represents an improvement of more than 30% since entering the basin in 2017 and is captured through the efficiency gains highlighted throughout the slide. Our drilling costs per foot and spud to rig release times are directly correlated. These costs reflect our activity focusing in on the more complex deeper Block four area in 2020 compared to 2019's 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 deem to be truly differentiating compared to our industry peers and the general market.
With that I'll turn the call over to Scott Meyers.
R. Scott Meyers -- Chief Financial Officer
Thanks Scott. I'll quickly cover our 2019 results before providing some more detail on our 2020 financial guidance. But first I want to piggyback on your integration comments by also thanking our team for the incredible work they've done over the past several months. As we enter 2020 we successfully launched an ERP system while working through a merger and executing on our day-to-day responsibilities. This hard work is not done yet but I truly appreciate the time and the sacrifices of 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-plus percent decreases to our weighted average realized price per BOE outweighing the production growth for the respective periods. To this slide we've added a graph showing our quarterly G&A per BOE 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 it 2019 was a strong year on many fronts and we were forced to make some very difficult decisions along the way to help deliver the trends shown on the graph and a fourth quarter G&A run rate below $2.75 per BOE. As we'll 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 stated a plan to deliver free cash flow and referenced various often-changing inflection points in doing so. At PDC we're extremely proud to have delivered free cash flow in 2019. Throughout the year we made several operational decisions that demonstrates our flexibility and commitment to the year end goal of delivering free cash flow and we maintain this flexibility into 2020 and '21. Finally our EBITDAX and adjusted cash flows are reflectively 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 LOE 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 LOE which was down 9% for the fourth quarter and 12% for the full year on a BOE basis.
Importantly our LOE by basin indicates that each area is hitting their targets as Wattenberg came in below $2.50 per BOE and Delaware was right at $4.00. In 2020 we look to once again deliver Wattenberg LOE per BOE of less than $2.50 while we expect an uptick in Delaware to the $4.50 range as we expect an increase in water-handling costs associated with our Block four area. Shifting gears to slide 18 provides detail on our balance sheet and financial strength both of which we consider to be peer-leading and contributing factors to what differentiates PDC. As a note all numbers here are as of 12/31/19 and reflect the PDC-SRC combination. Late last week we announced the results of our tender offer for the 6.25% $550 million senior notes from SRC. As a reminder approximately $450 million of the notes were tendered with the remaining $100 million outstanding. As shown on the graph we simply placed the $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 levered ratio of 1.4 and our projections to generate significant free cash flow we are very comfortable leaving this debt as pre-payable and maintaining the flexibility to buy back shares or retire debt. In terms of our share buyback program we were obviously blacked out for much of the second half of 2019 due to the merger announcement but we still managed to utilize over $150 million to buy back nearly five million shares. Since closing in mid-January we've bought back over 600000 shares for just over $12 million. We fully anticipate being able to complete the remaining $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 billion to $1.4 billion and free cash flow of approximately $275 million. Since that time we've seen a lot of volatility in the crude space as it is settled with both a 6-handle and a 4-handle in 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 in our acquisition model back in August to the current level of approximately $1.3 billion. As you can see we showed the impact to our sales net of derivatives for each oil 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 that we've made to our capital plan checked all of these boxes.
The blue graph at the top of the page clearly lays out and breaks down between the reduction in activity and the reduction in well costs per each basin. As you will see approximately $175 million of the $250 million of capex reduction at the midpoint is associated with Wattenberg. As Scott highlighted earlier we plan to exit 2021 with nearly 150 DUCs 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 E&P space is. 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 a half month of the SRC results due to our mid-month flows. Also our cost guidance does not include the approximately $30 million of 1-time deal costs which will be expensed in the first quarter but does include our $10 million of transition costs that will be incurred over the first seven months of the year. Scott and I have already shown favorable trends in both LOE and G&A on a BOE basis over the past year but this slide really demonstrates the efficiency gains of the new PDC as a result of the merger. As you can see we expect a combined LOE and G&A to be less than $5.00 per BOE in 2020. This represents a year-over-year improvement of more than 20%. For G&A the 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. Expect us to get our run rate G&A in the second half of the year and carry 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.
Lance A. Lauck -- Executive Vice President Corporate Development and Strategy
Thanks Scott. In this last section of today's 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 billion and $2.3 billion. With our current 2020 capital plan of $1 billion 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 of 2019 through year end '21. As you may recall from our August 2019 rollout of the merger with SRC we projected that would generate free cash flow of $200 million in the last two quarters of 2019. We're happy to report that we've checked the box on that projection. Looking now over the next two years we project to generate $650 million in 2020 and 2021. Our price deck assumes $52.50 WTI and $2.00 in 2020 and then $55.00 WTI and $2.50 for gas in 2021. For both years we hold NGL prices flat at approximately $11.00 per barrel.
We've included the table below that provides adjusted cash flow sensitivities based on price changes to each of the three commodities. Our adjustments to cash flows in 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% in 2020 growing 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 as free cash flow over capital investments. As we model out our 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 are mapping our capital program to provide more ratable and consistent growth in free cash flow and production. The result is that we project to deliver free cash flow in seven of the eight next quarters 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 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 PDC's already strong balance sheet to a leverage ratio of approximately 1.0 as we exit 2021.
Next on slide 23 we compare two of the most important metrics that our 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 E&P 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 E&P companies. We also project that our 2020 free cash flow yield of 12% equates to about three times that of the composite S&P 500 Index. As PDC continues to execute on this plan to deliver substantial free cash flow over the next couple of years we believe we will differentiate our company among our peer group the select large-cap E&P 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. While we are extremely thankful for a year end 2020 projection of 1.4x 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 that Bart opened the call with. We are confident over the next few years that our intense focus on execution will lead PDC 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 through completing our share buyback program. We also positioned the company for future consideration of a dividend. The strength of PDC's portfolio can be seen in our year end 2019 SEC crude reserves pro forma SRC which are slightly over 900 million barrels of oil equivalent. Additionally the value of PDC's portfolio can be seen in our strong pro forma B-tax PV10 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. What 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.
Questions and Answers:
Operator
[Operator Instructions.] And your first question comes from the line of Welles Fitzpatrick with SunTrust.
Welles Fitzpatrick -- SunTrust -- Analyst
Hey, good morning. Just a quick clarification on the '21 soft guide to 5% to 10% growth. Is that I know it can't be X-2-X because of the merger. But should we think of that as a 1Q to 1Q? And I just ask because if it's year-over-year it looks like it might be it might imply flattish off the 4Q '20 number.
R. Scott Meyers -- Chief Financial Officer
Welles this is Scott. It's really year-over-year and as far as the overall math there I'm not 100% sure I can confirm all of your thoughts. I think when we look at it it's truly though the year-over-year gain.
Scott J. Reasoner -- Chief Operating Officer
So I do know we have a frac holiday scheduled in the Delaware at the latter half of 2020 Welles and I think that will have a flattening effect on the Delaware production.
Lance A. Lauck -- Executive Vice President Corporate Development and Strategy
And likewise on the Wattenberg part because we only have one frac crew running in the second half of this year.
R. Scott Meyers -- Chief Financial Officer
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 of this year.
Welles Fitzpatrick -- SunTrust -- Analyst
Okay that makes perfect sense. And then as you go into '22 obviously the '20 budget's two-thirds Wattenberg. Is that more a function of the DUCs or do you think that that heavy Wattenberg weighting will continue into '21?
Lance A. Lauck -- Executive Vice President Corporate Development and Strategy
Yes Welles this is Lance. As we model out 2021 you'll see really that same rough allocation of capital between Wattenberg and Delaware as we go forward. That's our plan that we have going forward pro forma the SRC merger.
Welles Fitzpatrick -- SunTrust -- Analyst
Congrats on the strong multiyear update. Thank you.
Operator
Your next question comes from the line of Brian Downey with Citigroup.
Brian Downey -- Citigroup -- Analyst
Morning. Thanks for taking the question. 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 pace given that you're expecting to be positive from 2Q through 4Q this year. It sounds like you've repurchased a bit here year-to-date in terms of healthy free cash flow during 4Q 2019 but I'm wondering if there's a governing factor on how you're thinking through the repurchase pace versus debt reduction in 2020.
Barton R. Brookman -- President and Chief Executive Officer
Yes 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 where the prices are more depressed. We have accelerated that program. And at these prices clearly some share buyback is probably going to get a little bit more weight in my eyes than the debt reduction. But we're going to continue to watch that watch the market. We don't want to do anything all at one time. We're going to spread it out over the year. But I will say that at these prices stock buyback is very high on our list.
Brian Downey -- Citigroup -- Analyst
Appreciate it. And then Lance I was curious. You had mentioned the year end pro forma PV10 of $5.8 billion. If you had it off-hand I was curious how much of that was PDP PV10. It looked like in the 10-K the disclosures were only the PDC stand-alone values. I was curious whether the PDP to total PV10 ratio is materially different for the acquired SRC assets.
Lance A. Lauck -- Executive Vice President Corporate Development and Strategy
I don't have that breakout in front of me. Our key theme on that is when you look at the combined company a little over 900 million barrels to have a PV10 value all in of $5.8 billion 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 we're 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 and all in with that future capital spend. And then through that you'd have a PV10 value of $5.8 billion.
R. Scott Meyers -- Chief Financial Officer
So is the 37% PD is that for the combined companies?
Lance A. Lauck -- Executive Vice President Corporate Development and Strategy
Yes the 37% proved developed is on the volume basis and for the combined companies.
Brian Downey -- Citigroup -- Analyst
Right so 37% on the volume basis. But to your point if you don't have the development capex around that I'd expect the PDP value to be skewed higher than 37% of that $5.8 billion.
Lance A. Lauck -- Executive Vice President Corporate Development and Strategy
Yes exactly.
R. Scott Meyers -- Chief Financial Officer
You're spot on Brian.
Lance A. Lauck -- Executive Vice President Corporate Development and Strategy
PD per BOE of that of the PDP would be greater than that of the PUD but all in is $5.8 billion so good question.
Brian Downey -- Citigroup -- Analyst
Great. I appreciate the comments.
Operator
Your next question comes from the line of Oliver Huang with Tudor Pickering Holt.
Oliver Huang -- Tudor Pickering Holt -- Analyst
Good morning and thanks for taking my questions. When we're thinking about your updated two-year outlook what is the best way to think about flexibility of activity within that time frame just given commodity volatility? Would it be more practical to think of any downward shifts if commodities were to warrant it within the program toward getting the to 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 current price deck was closer to call it $45.00?
Scott J. Reasoner -- Chief Operating Officer
Yes this is Scott. I'll start and there may be some others that jump in on that. When you talk about our flexibility we have a tremendous amount of flexibility. If you start with the drilling contracts they're short term. The completion agreements that 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 difficult always as we continue to watch these prices fluctuate to say what you would do with just prices falling because typically what happens at the same time the prices fall the capex costs come down as well. So that rolls into the discussion as something that's really important that you can't those don't move independently. They're interdependent and I think that's one of the things that I always point to. 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 mental state is something that we stay focused on. If the and I'll just make an assumption here. If prices happened to fall and capital costs didn't come down we'd definitely be looking at our programs to say what could we do to deliver as much cash flow as possible. So not giving any specifics there I think that's the best I can do and I think Scott Meyers has got a couple of comments.
R. Scott Meyers -- Chief Financial Officer
Yes I'd just add a little color. Without changing the capital program or costs at all if you look at our on the slide 22 we give you the changes to our cash flow in each year. And $45.00 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 had a $45.00 environment. So that shows you that that's the flexibility that we have and we will absolutely continue to watch the free cash flow numbers so we can continue to buy back 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 that we're getting in the second quarter form 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 have it.
Barton R. Brookman -- President and Chief Executive Officer
Oliver this is Bart. Just a couple more adds to this because I think given today and the current market it's a fair question. To just reinforce what these guys said a lot of flexibility. We have the ability to take our growth level which I think is 7% this year maybe closer to 10% next year. But we have the flexibility probably most in the Wattenberg with the DUC counts and our rig count but we'd give strong consideration to both basins. But we can take that down in the low single digits and even take it close to zero if we have to to honor that free cash flow. And we have the flexibility to do that. But I also think it's very important to note that both basins right now and we've run every sensitivity possible as we're watching this current market both are projected to deliver a value well above our cost of capital even at a $45.00 oil price which is supported by some of the things Scott Meyers just said.
Oliver Huang -- Tudor Pickering Holt -- Analyst
Okay that's all very helpful. And for a second question I know SRCI had an ongoing process for the Mountain View CDP. Wondering if you could provide an update on that front and how that fits into your go-forward plan just given how gas prices remain extremely depressed and the acreage is in a much gassier region of the DJ.
Scott J. Reasoner -- Chief Operating Officer
This is Scott again. I'm we're staying in constant contact with the COGCC. As you can imagine a very important process is understanding more and more of this permitting process as 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 or when you talk about the CDP we are in a position at this point where they've said it's probably not going to happen until the Professional Commission comes in which is scheduled for July. And there's reasons for that that surround the current rules that are being redone that type of thing. So we're not expecting that until 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 the Commission docket and into an accepted process we're looking at others from our own acreage position. It's something they want in terms of that's much of the intent of 181 is around things like a CDP. It's something that the Commission wants. They're just delaying that until a Professional Commission's in place.
Oliver Huang -- Tudor Pickering Holt -- Analyst
Thank you very much.
Operator
Your next question comes from the line of William Thompson with Barclays.
William Thompson -- Barclays -- Analyst
Hey, guys, I appreciate the comprehensive two-year outlook and the cash flow-sensitive figures on slide 22 which are really helpful on a day like today. Using that my basic math shows about $100 million of free cash flow at $45.00 WTI $1.75 gas and $9.00 NGL realizations in 2021. I think we all agree we hope that's not the outcome. But just curious on how you think about balancing buybacks and debt reduction. Does one take a priority over another? Understand that's probably not a sustainable outcome.
Barton R. Brookman -- President and Chief Executive Officer
Yes right now where we're sitting at with our internal price view and what 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 $40.00 or $45.00 environment we need to examine how the capex is going to change what price relief we're going to get to vendors so that we can still deliver the free cash flow. So there is a balance act there. But when we look at our hedge policies and our procedures we don't go over two times debt to EBITDAX in a $40.00 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 like I said is on the top of the list. But we'll continue to watch and make sure that we don't risk the balance sheet. 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.
William Thompson -- Barclays -- Analyst
Okay that's helpful. And then it looks like the line pressure's continuing to turn in the right direction. I know you're waiting on the Cheyenne Connector and Latham II. Where are you in terms of DCP quota constraints? And is there a rough estimate of how much production between PDC and Carrizo sorry SRCI are shut in and how quickly that can come back on?
Lance A. Lauck -- Executive Vice President Corporate Development and Strategy
Yes so this is Lance. So where we sit with regard to the status DCP right now has capacity in the basin of approximately 1.4 BCF per day. The current throughput of the field is less than that currently. So that's one of the reasons why we're seeing some of the line pressures come down. Clearly then with Latham II and the Cheyenne Connector they'll probably be in the 1.6 BCF to 1.65 BCF a day of total capacity. Based upon the fact that they now have additional space in their system they've come off allocation for all the producers so that's a positive thing for all of us because it gives us opportunity to produce more volumes. As far as our return to production wells we are clearly in the middle of returning those to production. And you'll recall those are wells that SRC had that had shut in due to the allocations from our midstream provider. So we've turned-in-line some of those wells and we have several more to go over time. Scott can you cover the numbers on that?
Scott J. Reasoner -- Chief Operating Officer
Yes 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 they were under-designed for the productivity of the actual wells. With the high line pressure that we were faced with that wasn't abnormal. So we're working through those types of things. Some of the wells need swabbed in 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 quarters of this year. Probably will be done sooner than that but that's what our schedule is at this point. At the same time we're doing that obviously the SRC team continued to frac wells right up to the first of the year and have started those wells are coming online. And we've added a frac crew since that time so we've got two frac crews running now. With all those turn-in-lines coming down the path drill-outs really expecting things to start I don't want to say surging but definitely turning the corner in terms of volumes uplift over the next several weeks and in through the end of the year then at that point. So hopefully that gives you a good summary.
William Thompson -- Barclays -- Analyst
And just quickly remind us of the production profile of those wells that come back online. I know some of them are of a low oil mix but I'm just curious on the oil projection because I think or if I recall correctly some higher gas production comes on first and then the oil's a little bit later so they might benefit in the back half of the year? Is that the way to think about it?
Scott J. Reasoner -- Chief Operating Officer
Yes and that's a really complex subject when you start talking about the profile. The percentage of the wells that SRC tended to have shut in were the higher GOR wells which is a really smart move. They were producing wells that made the most oil. So the wells that we've been turning-in-line have been tremendous wells. They tend to be more gassy. At the same time we're doing that the first batch of PDC wells that we've fracked here were in the plains area so they tended to be gassier as well. So I think you're going to see a bit of a gassier period. But then we roll back into Kersey with a completion process so the oil 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 where really we're expecting oil gradually through the year to increase in its percentage. And that obviously will offset some of that additional gassiness in the Wattenberg as well with the idea that we're working in Block four there primarily or primarily in the oilier part of the field where we truly get the best economics.
Barton R. Brookman -- President and Chief Executive Officer
And Will this is Bart. Just tying back to what Oliver was referencing on the plains drilling which is gassier I should note those were still I think in our portfolio. Those were tremendous return projects as the deepest hottest highest GOR portion of the DJ. But the reserves per well are phenomenal and they do have a slightly higher GOR. 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 incredibly relieved 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 forecast. I know they've worked with other operators. I do think there's even some additional benefits with some of the capital slowdown that's happening across the industry. But right now for PDC we have an intense focus really on three areas. PDP optimization. The wells that we manage the wells we inherited from SRC that were online. Those have extra opportunity in the lower-lying pressure era. We have the shut-in wells that we inherited from SRC. As Scott said we've got an intense focus on those. Our production engineering department is full steam ahead on bringing those back online.
And then this is very important. The new wells two frac crews out for us right now. Those new wells the last three years we have basically been bringing those wells on in a much more constrained fashion. And our teams will be going more to a normal flowback. So I'd just encourage everyone to understand that we have a very intense focus on this. There is really some great opportunity here. The challenge we did the best we can do in this new regime to model this all into our guidance but I think everyone is aware some of that brings real challenges in the forecast. So again as we go through the year I'm hopeful that things are going to get better and there's some opportunity for the company in that area.
William Thompson -- Barclays -- Analyst
Excellent. Thank you.
Operator
Your next question comes from the line of Kevin MacCurdy with Heikkinen.
Kevin MacCurdy -- Heikkinen -- Analyst
Hey, guys. To follow up on the previous question do you have the production breakdown between legacy PDC versus synergy for the first quarter?
R. Scott Meyers -- Chief Financial Officer
This is Scott and I really don't. It's the combination and we're quickly as a company moving away from that type of look. The biggest issue we have in the first quarter is as we've described a number of times that the 14 days 13 or 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 and one on the PDC side we're quickly moving away from that. And then I guess that's the best answer I can give you.
Kevin MacCurdy -- Heikkinen -- Analyst
Okay, thanks guys. That was my only question.
Operator
[Operator Instructions.] And your next question comes from the line of Dun McIntosh with Johnson Rice.
Dun McIntosh -- Johnson Rice -- Analyst
Most of my questions have been asked but maybe if we could just sorry if I missed this walk through your thoughts around DUCs. You've got 165 going into the year and the replacement of DUCs and how that fits in with the permitting process under the new 181 regulation and just how you all are looking at the political landscape over the course of '20 and into '21.
Scott J. Reasoner -- Chief Operating Officer
So this is Scott and I'll see if I can answer it. There's a number of different questions and I'm not sure if I caught all of them in there so if I don't catch them all let me know. But I think when we look at our overall DUC position we're set up as I described with that coupled with the drilling permits etc. that we have to really being effective through this year. We do need to see permit flow to be effective in 2021 on the drilling side. And we've got continued flow through there. We are using up some of our DUCs as we move along through the end of 2021. But we continue to maintain a good level through that process and I think that shows the idea that we're not just using up our DUCs 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 that we do continue to see permits flow. We'd always love to have them faster. But our team stays in direct contact with them as I was describing with the idea that we continue the dialogue around which ones are needed first what that means in terms of what we need to do in order to provide the data whatever it is that if they're lacking some of that or the encouragement at least that these are the ones that we do need. So we definitely keep that discussion going. And we're also doing that with Weld County now as they have added their process the Weld well process and permitting process. So it's a little more complex but it feels like the momentum is moving forward. We'd obviously like I said we'd love to have it move quicker. Hopefully that caught most of your questions.
Dun McIntosh -- Johnson Rice -- Analyst
Yes thanks guys. Hit all the points. Sorry if it was a little confusing. But congrats on the quarter go ahead?
Scott J. Reasoner -- Chief Operating Officer
I just didn't want to miss your question.
Dun McIntosh -- Johnson Rice -- Analyst
Okay. All right. Thank you.
Operator
And at this time there are no further questions. I would now like to turn the conference back to Bart Brookman for closing remarks.
Barton R. Brookman -- President and Chief Executive Officer
Yes thanks Zenyetta and thank you everybody. Obviously a very challenged sector right now. A tough market but I'm proud of the team I'm proud of our plan and I can promise you the PDC team is standing strong right now and looking long term as we navigate through these tougher times.
Operator
[Operator Closing Remarks]
Duration: 60 minutes
Call participants:
Michael G. Edwards -- Senior Director Investor Relationss
Barton R. Brookman -- President and Chief Executive Officer
Scott J. Reasoner -- Chief Operating Officer
R. Scott Meyers -- Chief Financial Officer
Lance A. Lauck -- Executive Vice President Corporate Development and Strategy
Welles Fitzpatrick -- SunTrust -- Analyst
Brian Downey -- Citigroup -- Analyst
Oliver Huang -- Tudor Pickering Holt -- Analyst
William Thompson -- Barclays -- Analyst
Kevin MacCurdy -- Heikkinen -- Analyst
Dun McIntosh -- Johnson Rice -- Analyst
