PDC Energy, Inc. (NASDAQ:PDCE) Q2 2019 Earnings Conference Call August 8, 2019 11:00 AM ET
Michael Edwards - Senior Director, IR
Scott Reasoner - SVP & COO
Barton Brookman - CEO, President & Director
Lance Lauck - EVP, Corporate Development & Strategy
Scott Meyers - SVP & CFO
Conference Call Participants
Michael Kelly - Seaport Global Securities
Leo Mariani - KeyBanc Capital Markets
Irene Haas - Imperial Capital
Brian Downey - Citigroup
Michael Scialla - Stifel, Nicolaus & Company
Paul Grigel - Macquarie Research
Welles Fitzpatrick - SunTrust Robinson Humphrey
Good day, ladies and gentlemen, and welcome to PDC Energy's Second Quarter 2019 Conference Call. [Operator Instructions]. As a reminder, this conference is being recorded. I would now like to introduce your host for today's conference, Mike Edwards, Senior Director of Investor Relations. Sir, please begin.
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 10-Q. The press release and presentation are available on the Investor Relations page of our website, pdce.com.
I'd like to call your attention to our forward-looking statements on Slide 2 of that presentation. 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. And I'll turn the call over to our CEO, Bart Brookman.
Thank you, Mike, and good morning, everyone. Over the past six months, we have spent a tremendous amount of time with the PDC investors. We appreciate your time and the constructive and objective feedback we received from so many of you regarding the strategic outlook for the company and our discussion on the condition of the E&P sector. Around this feedback and in line with our core strategy for PDC, today, you will hear the actions we have already taken as well as some of our future plans to ensure we continue pursuing the four strategic objectives we rolled out earlier in the year.
Let me quickly refresh your memory around those objectives: first, the pursuit of free cash flow, year-over-year growth in free cash flow, along with strong consideration of returning capital to our shareholders; next, financial and operational discipline, ongoing focus on the cost structure of the company, improving LOE, lifting cost per barrel and overall G&A reductions for the organization; third, return on capital, an emphasis within our corporate metrics on free cash flow margin and delivering the best returns on our drilling programs; and last, solid respected growth, but more modest production growth expectations for the company.
Now let me call your attention to the first slide, which outlines some key steps the company has taken. Let me start operationally. We are decreasing our 2019 capital guidance range to $810 million to $840 million for a decrease of approximately $15 million at the midpoint. This is primarily being driven by reducing the Wattenberg rig count from 3 rigs to 2, effective September of this year. Entering 2020, PDC will have 2 rigs running in both the Wattenberg and in the Delaware or 4 rigs total for the company.
But we are pleased, our 2019 production guidance range has been adjusted upward to 48 million to 50 million barrels of oil equivalent. This is in spite of some incredibly difficult midstream conditions in the Wattenberg Field. I would like to extend a thank you to our Wattenberg and Delaware operating teams for their ongoing focus on maintaining the company's production. And as Scott Meyers will show in a moment, our outlook for 2020: continued strong free cash flow, improving cost metrics and modest production growth.
From a financial perspective, seven weeks ago, we implemented a reduction in force to reduce the size of the PDC organization. We also made reductions to our non-payroll G&A. Our second half 2019 G&A expected run rate now stands at $2.60 to $2.80 per BOE. And we anticipate G&A per BOE of $2.50 to $2.75 in our preliminary 2020 outlook. The current PDC organization and its cost structure continues to include expenditures and long-term IT solutions in our accounting and LAN systems. All of these investments are expected to drive an even more productive and efficient PDC over the next several years.
From a free cash flow standpoint, in spite of very poor realizations in natural gas and natural gas liquid pricing, we anticipate approximately $300 million of free cash flow through the end of 2020. And our return to shareholder commitment, we have successfully exercised approximately 60% of our stock buyback program, 3.7 million shares of PDC stock has been repurchased year-to-date.
Also, on some key business development updates. Everyone is aware we monetized our midstream assets in Delaware. $264 million has been received in the door and an additional $82 million is expected next summer. We also recently divested some nonstrategic acreage in the Delaware Basin for $35 million. This acreage was set to expire in 2019.
And last, I am happy to announce the final two partnerships have been settled and all partnerships further -- for the company and their settlements will be behind us by year-end. We have rolled up 77 legacy drilling partnerships in the past 10 years. I want to thank our business development, legal and accounting teams for their ongoing efforts to finalize these transactions.
Now some second quarter highlights. Production: 12.4 million barrels of oil equivalent, 137,000 BOE per day. That was a 32% improvement from the same quarter of 2018. Oil production increased 25% from the same quarter last year and was 40% of our total company mix. This is slightly lower than expectation, primarily due to the ongoing high line pressures in the Wattenberg Field. Overall, for the quarter, we spent $277 million. We spud 53 wells, turned-in-line 35, and we remain extremely pleased with our per-well results in both basins.
Adjusted cash flow from operations: $207 million and lifting costs, $2.76 per BOE, a terrific number. Our liquidity quarter-end: $1.3 billion and leverage ratio of 1.4. Overall, the financial condition of the company remains very strong. And last, Scott Reasoner will cover the continued efficiency gains in drilling and completions we are experiencing in both basins.
Now let me quickly steer you through next year. We are planning on running the 4 rigs corporately, two in Wattenberg and two in Delaware, while we catch up on our DUCs in the Wattenberg Field. We have adjusted our natural gas and natural gas liquids realizations. And free cash flow is now anticipated at approximately $150 million with a production growth profile in 2020 of approximately 10%, all this while we achieved free cash flow margin, around 15%, and ongoing improvements in our G&A structure. Again, this is an early forecast, but I can assure you the company will remain diligently focused on free cash flow, quality returns on our drilling projects, capital discipline, cost management and more modest production growth as we enter 2020.
With this, I will now turn this call over to Scott Reasoner for a lot more detail around our operations.
Thanks, Bart. And building on your comments, I'm extremely happy with the way our teams have performed this quarter and what I'd call one of the most challenging midstream environments I've seen in a long time. Most importantly, our emphasis on health and safety led to zero reportable incidents occurring in the quarter. This takes a tremendous effort by our operations and EH&S team. As you can see on Slide 7, we show the breakdown of our second quarter production and capital investment by basin. Overall, our second quarter production was a little over 136,000 barrels of oil equivalent per day with our oil production of approximately 25% compared to 2Q 2018. In Wattenberg, our 105,000 barrels of oil equivalent per day represents 5% sequential growth from the first quarter, which is a true accomplishment, given the current midstream constraints.
I'll go into more detail on this in a moment, but overall, we're benefiting from 20% to 25% of our volumes moving via Aka as well as our favorable proximity in the field and ability to offload our production in certain circumstances. Our second quarter Delaware volumes grew by more than 25% compared to the first quarter and came in at 43% crude. One of the items I'll touch on more in a bit is the 33% improvement in Delaware drill times this quarter compared to a year ago. Note, we did invest approximately $10 million in our midstream infrastructure in the quarter. However, with the divestment of these assets, we expect zero capital outlay in the back half of the year.
Moving to Slide 8. You can see graphically the strong trend in our daily production volumes as well as the favorable impact to our lifting cost per BOE. From the production standpoint, our corporate growth is up over 30% in the last year. Our Delaware sequential growth is really just a product of consistently turning-in-line wells since the start of the year. In Wattenberg, we highlighted our completion efficiencies on last quarter's call. We were able to maintain those efficiencies through the second quarter, which has resulted in more completions, turn-in-lines and production in the first half of the year than originally expected. We look for this to continue in the second half of 2019, but remain committed to the original level of completion activity, which should result in a lower level of turn-in-lines in the fourth quarter.
I'll cover the capital implications on this in a second. And Scott will go over some of the production and financial impacts for both 2019 and 2020 in a few moments.
In terms of LOE for the quarter, our corporate rate of $2.76 per BOE represents a 20% decrease from the second quarter of last year and 12% decrease from just last quarter. While this is primarily a product of increased production, it also involves a bit of work we did in optimizing our field and contract labor. We expect LOE per BOE to remain below $3 for the rest of 2019 and into 2020.
Shifting gears, I want to spend a few minutes talking about our 2019 capital program year-to-date and for the remainder of the year. As Bart mentioned, we lowered our full year CapEx program to a range of $810 million to $840 million, excluding corporate capital. Looking at the graph, you can see that we've invested approximately 65% of this program in the first half of the year. There are a couple of key takeaways with this. First, the front-loading of capital in the first half of 2019 is largely how our development plan was budgeted to begin the year, especially in the Delaware. Our Wattenberg program is probably running about $15 million ahead of schedule due to the increase in completion efficiencies. However, our planned number of completions hasn't changed. It's just the timing. Second, there are several key major steps we have taken or plan to take in the back half of the year to meet our full year capital program. We've outlined these steps in the gray arrow. In the third quarter, our reduction in CapEx is primarily related to the Delaware. Back in June, we reduced our rig count from 3 to 2, and we'll continue to operate 2 rigs through the remainder of the year. In early July, we released our completion crew for the year, so we expect very limited completion investment through year-end.
Overall, the remainder of the year's spend in Delaware's consistent drilling capital with a very limited completion spend in the third quarter. Our Wattenberg program will continue to utilize three drilling rigs and one completion crew through the third quarter. In the fourth quarter, we expect another incremental step-down in our quarterly spend as we expect to release 1 rig in Wattenberg and idle our completion crew for a period of time in late third or early fourth quarter. As a reminder, reducing our rig count has no impact on our production profile, as we plan to utilize our DUC inventory to maintain our completion schedule.
The last thing I want to highlight on this slide can be found in the table on the top of the page. Both PDC and other operators have talked extensively about several key events impacting the industry. We continue to experience high line pressures in the Wattenberg, while Plant 11 is being brought into full operation. And we have not been immune to gas and NGL price erosion, as industry has witnessed throughout the country.
What I did want to call your attention to is the third column titled PDC Action. Here, you can see the numerous proactive steps we have already taken in ensuring we execute on our 2019 plan. On top of this, our original 2019 budget and 2020 outlook already contemplated the front half-weighted program we've outlined today. Scott will have more on this in a moment.
Now turning to Slide 10. Throughout the first half of the year, high line pressures negatively impacted all of our wells. However, oil production from our older horizontals and legacy verticals, particularly the lower GOR northern part of the field, felt the brunt of this. In addition, the very strong new wells that are most capable of producing against line pressure are located on the west side of our Kersey block, which has a slightly higher gas mix compared to the rest of the acreage block. Both of these point to the outperformance of our gas expectation and the slightly lower oil percentage produced in the first half of the year and expected through the year-end.
As you would suspect, our Wattenberg story for the second half of the year is largely dependent on the performance of DCP's Plant 11. Commissioning of the facilities initially began in late June but were recently taken off-line while DCP finalized remaining construction projects. The restart of Plant 11 occurred on Tuesday of this week. July and early August have seen very high line pressures, but we remain optimistic about improved performance in the second half of the year. I want to complement our midstream and operating teams' efforts in projecting production. As with the past, they continue to stay in close touch with DCP and Aka, attempting to take all factors into our expectations. They have done a great job in estimating throughout -- throughput with facility start-up, equipment run times, system hydraulics, offloads between systems and well performance at changing line pressures, all being linked to our updated 2019 production estimate of between 48 million and 50 million barrels of oil equivalent. An area of upside to our projections is flush. We do not attempt to project it into the equation.
In the Delaware, we're excited to see the trend of continued improvement in both our average drilling days and drilling cost per foot, both of which are down 33% compared to the second quarter of 2018 and 15% from last quarter. The graph at the bottom left-hand side of the slide shows the differences in drilling days by area. The added time in drilling Block 4 is a function of deeper depths, overpressured rock and more complex geology. I mention this because much of our activity has been in the North Central area this year and is shifting to Block 4 next year.
Last, we updated the results from our first Bone Spring well, which has a peak 30-day average IP of 175 barrels of oil per thousand feet and nearly 70% oil. We found that due to rock quality of this bench, we're also experiencing a slightly lower decline than other wells in the area.
I will now turn the call over to Scott Meyers for a financial update.
Thanks, Scott. In terms of our U.S. GAAP metrics, the 32% increase in production compared to the second quarter of 2018 outweigh the 22% decrease in realized price per BOE between periods. As a result, you can see that we had a modest increase to our total sales on a year-over-year basis to nearly $340 million. Net income for the quarter was just over $1 per share, with the increase compared to a net loss in the second quarter of 2018, primarily driven by a change in value of unsettled derivatives and a large impairment last year. We'll cover G&A in more detail in a moment, but it is worth noting that our three month and six month G&A per BOE in 2019 decreased compared to both comparable 2018 periods. In terms of share count, you can begin to see the effect of our stock repurchase program. However, given the timing of our buybacks, you will not see the full impact until the third quarter.
Last, our net cash from operating activities for the quarter was $260 million compared to $175 million in the second quarter of 2018. This increase was driven by the accounting treatment of our Delaware Basin midstream divestitures. Essentially, $160 million of the $345 million of proceeds were allocated based on the fair value of the tangible assets sold, with the remaining to be amortized on a units of production basis over the life of the dedication of the acreage agreements. Stripping out all the accounting noise would have resulted in a net cash from operating activities of approximately $160 million, a slight decrease due to an increase in working capital between periods outweighing the increase in sales shown above. Our non-U.S. GAAP metrics can be seen on Slide 14. As a reminder, a reconciliation of these figures can be found in our appendix. We have year-over-year increases, both for the quarter and the six month period, on adjusted net income, adjusted cash flows and adjusted EBITDAX.
Turning to Slide 15. We have a similar story of increased production between periods driving some strong trends this time in our operating cost per BOE. As we highlighted in the press release last night, the LOE for the quarter of $2.76 per BOE represents a 20% improvement from the second quarter of 2018, and it served as the main catalyst in reducing our production cost on a BOE basis.
At the bottom of the table, in the bottom graph on the right-hand side of the slide, you can see we break out our LOE per BOE by basin. Wattenberg LOE of $2.46 per BOE represents a 25% improvement from the second quarter last year and has been on a steady decline over each of the past five quarters. Delaware LOE of $3.76 per BOE is a modest improvement from last year and a 37% improvement from the first quarter of 2019. The improvement in 2019 is primarily the result of the timing of the turn-in-lines and the production growth between periods.
Next, I want to spend a few minutes talking about our second quarter and full year expected G&A. Our second quarter G&A of approximately $3.45 per BOE is a slight improvement from -- to our first quarter but similar in the sense that both quarters contained nonrecurring legal-related expenses that we've clearly broken out. Approximately $0.35 per BOE or $4 million to $5 million in the second quarter is related to the shareholder activist campaign settlement of our final partnership agreements net of insurance credit and severance. Excluding these items, the run rate of G&A of approximately $3.10 per BOE in the second quarter compares to $3.28 in the first quarter.
As Bart mentioned, we did institute a reduction in force nearly seven weeks ago that impacted approximately 15% of our corporate headcount. We also significantly reduced our future hiring plans and had considerable cuts to our non-payroll G&A. These were all very difficult decisions for the organization, but at the end of the day, we staff and prepared for a multiyear plan centered on significant growth which has now changed. We are confident that the updated cost structure is among peer leaders in the industry and more appropriate for our future plans.
We expect G&A in the second half of '19 to average between $2.60 and $2.80 per BOE, which will result in full year guidance of $3 to $3.20 per BOE. The updated range is not only all-cash and noncash G&A but also includes all the onetime expenses in the first half of the year and still compares favorably to our original guidance of $3 to $3.40 per BOE. In terms of 2020, our current expectations are to come in between $2.50 to $2.75 per BOE, which again contains all costs, both cash and noncash.
Slide 17 covers our leverage, liquidity and hedges, which I encourage everybody to look at. However, I want to focus on our stock repurchase program. We've executed $125 million of the $200 million program or over 60% year-to-date. Just over $100 million of this occurred in the second quarter with the remainder occurring in early July.
Last, you can see we project to deliver between $160 million and $190 million in free cash flow in the back half of the year. This enables us to comfortably complete the remaining $75 million of the existing program well before the target completion date of 2020.
Previously, our -- we provided our updated guidance on Slide 18. Obviously, there's been a variety of changes to our 2019 plan that we've already covered today and in our press release last night. When you take a step back, we have reduced our full year capital guidance range, increased our full year production range, reduced our estimated LOE and G&A ranges and we've also updated our commodity price risk -- or price realizations and our projected commodity mix.
With half the year in the books and changes to full year guidance implies certain things about the anticipated second half performance. Slide 19 is a little busy, but it does a good job of explicitly walking you through our previous guidance, updated guidance, first half actuals and implied second half results. This is a bit of a step-out in terms of level of detail that we typically provide but feel it's very important to align expectations and consensus for the remainder of the year. On the right-hand side of the slide, we have highlighted a few key metrics that should help from a modeling perspective. Note, we expect modest growth in the third quarter and a relatively flat fourth quarter. As Bart and Scott covered, our second-half production profile is largely dependent upon DCP performance. We believe our updated estimates reflect a realistic, gradual improvement and performance throughout the remaining of the year that is consistent with our ongoing communications with DCP. We've covered the operating cost and free cash flow in pretty good detail, but I do want to highlight the change in realized prices.
Other operators are suffering a similar fate in the gas and NGL world. We estimate the decrease in realizations in the second quarter and project it for the second half of the year to cost us approximately $90 million in cash flows compared to our original guidance. However, we have taken decisive action in modifying our plan to ensure we execute to the best of our abilities and now expect to be just north of cash flow-neutral for the full year in a $55 oil price environment.
Next, our updated multiyear outlook. The most important takeaway on this slide and perhaps the entire call is the changes we've made to our 2019 plan have not negatively impacted our 2020 outlook. Our original guidance and outlook already contemplated a first half-weighted 2019 program and a frac holiday in each basin. So while there were refinements to the operating plan, the overall impact was relatively muted. The greater change between this outlook and what we've previously shown is price-related and can be seen in the blue box on the left-hand side of the slide. We updated our 2020 outlook to reflect a more appropriate NYMEX natural gas price while also updating CIG and Waha differentials. We also reduced our NGL realizations and updated our oil mix to reflect everything Scott Reasoner addressed in the Wattenberg.
All-in, the changes result in lower projected sales next year, partially offset by the G&A and LOE reductions. We are very proud to project free cash flow of approximately $150 million or a free cash flow margin of more than 15%, while maintaining our previously disclosed 2020 ranges for production and capital investment.
With that, I'll turn the call over to the operator for Q&A.
[Operator Instructions]. Our first question comes from Welles Fitzpatrick with SunTrust.
The downshift in the rig count in the Wattenberg, does that lower the desire to look for potential acquisitions? I mean at 2 rigs, and call it, 900 locations, at least by my math, that gets you to about a decade of running room, if that's right?
Lance, you want to go.
No, Welles. This is Lance. The slowing of the rig pace in the Wattenberg really gives us a chance to be sort of even more capital-efficient because we're pulling down some of our DUC inventory and completing those and turning those to sales. So we have the strength of the production growth going forward. And I think, as we've said before, when we look at the Wattenberg Field, we continue to look for opportunities for business development there. For example, the Nobel trade that we did, not too long ago, really blocked up those positions and all. So we'll continue to do those things as part of our normal course of business. So that's something we'll continue to do with time and continue to monitor that inventory life that we have there.
Welles, I also think we're taking a break in 2020. We're going to catch up on DUCs. And then probably late 2020 or sometime in the first half of 2021, and again, we're looking at all this -- we'll most likely deploy a third rig in there. Again, it's very early in that model but -- so relative a year ago, we were probably looking at 4 rigs running next year in the Wattenberg. Here, we are with two. So that's obviously the slowing down of our capital spend. But I do believe we're going to have to put a third rig back out at some point in time, most likely before the summer of 2021.
Okay. No, that makes sense. And then kind of sticking with '20. Obviously, gas and NGL prices aren't going to be great through year-end, and that new guidance is really helpful, but can you give your thoughts on 2020, given Cheyenne, given the new frac capacity coming on. I mean how do you guys see that developing as we go through next year?
Welles, good question. I think we're all watching for and waiting on FERC approval of the Cheyenne connector. Hopefully, that happens the next few months. I think Tallgrass as talked about in their call, then that puts it probably somewhere in the first quarter of next year that you'll see that start-up of the Cheyenne connector still obviously is dependent upon the timing of the FERC approval for that. I think in the meantime, while the parties are doing, the midstream groups are utilizing the existing space that's still available within the basin for processing and for takeaway. But I think one of the key things that the whole basin looks forward to on the residue side is that Cheyenne connector coming online first quarter, so next year. So that's sort of how we see that, and from our perspective, just continuing to work closely with the ECP as our primary provider and knowing that they have a very proactive plan to ensure that they get as much volumes as possible out of the basin in the meantime.
And our next question comes from Mike Kelly with Seaport Global.
Bart, I think I'll go ahead just to address the elephant that entered the room yesterday and that's the speculation that you and SRC are going to get married sometime this fall. And my question is kind of, just high-level thoughts, why or why not it would make sense for you guys at this time to consider a merger with the Wattenberg pure play?
Thanks. And yes, I expected the question, Mike. I think the keyword you used is speculation. I'm not really in a position and we make it a policy to not make comments on rumors. I think it's important for -- the way I would answer that is the Board and the SMT will make -- can take very strong consideration of multiple scale-building options that we have, not only in Colorado but also in Delaware, and that's an ongoing process for us. So again, I'm not in a position to make any comments around a rumor that Bloomberg issued a report on.
Okay. Fair enough. Switching gears a little bit to the 2020 outlook, and I thought it was great to see that activities have slowed a little bit in the second half of this year, but 2020 still looks really strong. And I'm curious we fast-forward that a year or look at 2021, just would love to get your insights on how that is set up, given that you will be drawing down DUCs in 2020 to make 2020 still look pretty good. 2021, does that -- are there some negative consequences because of that? Or do you still see the potential kind of growth that double-digit level and have that sort of stout free cash flow in 2021 with the current model?
Meyers, you want to take that?
Sure. Yes, I mean, when we look at our preliminary, again, very preliminary 2021, internally, we try to look five years out to make sure one decision in this year doesn't have a ripple effect down the line. And pointing back to our North Star slide, we see us for the next five years to be able to have free cash flow growth year-over-year. And so to your first question, is there a deterioration of free cash flow, and the answer to that is, no. Secondly, we continue -- as we go through the years, we continue to drive down our BOE costs, and I think that improvement helps delivering the free cash flow. And then again, I think we'll see modest production growth over the next five years, targeting a lot lower than what we traditionally had grown at, more than the 10% range compared to our historically 25% to 30% range. So we do think we're set up in this environment to deliver modest growth, strong cash flow for many years to come.
Okay. I think 10% growth and growth of free cash flow works.
And our next question comes from Leo Mariani of KeyBanc.
I was hoping you could give a little bit more color around your thoughts on the midstream situation. I think you guys described it as very challenging situation here of late. Certainly, it's my understanding that you obviously have quite a bit of midstream capacity getting added to the basin that is really between now and I guess second quarter of next year. I know that it's hard to predict the future, but what are your all's expectations in terms of how you might see things maybe improve over that period of time?
Leo, this is Lance. I think we just sit back and look for example, just the DCP, which is our primary midstream provider. I think today, they're running about 1.1 Bcf of gas a day between all their processing and some bypass that they have in the basin. And if you add up all the different initiatives that they talked about in their call yesterday, they get by mid-2020 about 1.7 Bcf a day when you look at processing, bypass and offload. That's nearly a 50% increase in overall capacity there in the basin. So DCP is definitely taking a very proactive look in infrastructure expansion, and you can really see their commitment to the DJ Basin. So when you put all that together, the key components of that is Plant 11, that is just turned into service earlier this week, getting that 200 million a day plant ramped up over time. They have 100 million cubic feet a day of bypass associated also with that plant.
And then as we all read about very recently in their release that they had an offload processing agreement that they just executed with WES for up to 225 million cubic feet of gas a day to the Latham II facility. So putting all those things together, and you see how they stepped out over time, we're very pleased with where they sit from that perspective because that deal, they did with WES fast-forwarded by a few months, the ability to have that incremental capacity available in 2020. So from that standpoint, we're very pleased with that work. I think the key things when you look at takeaway, Leo, is number one, is I think we're all looking forward to the Cheyenne connector construction that's sometime there in the first quarter that we currently kind of project internally and are thinking about internally. And then the second thing is there's a couple of big NGL expansions that DCP has here coming on for the fourth quarter of 2019, both on front range as well as their DJ Southern Hills extension. So you put all those things together, they have a pretty good map what the future holds. And then keep in mind, 20%, 25% of our volumes from the basin travels to Aka Energy and part of that gets offloaded to the Anadarko system. So we've got some diversification in the basin that we think helps us out.
Okay. That's a great summary. And I guess maybe I'm just really trying to get a sense how you think that dovetails into PDCE production. Presumably, you guys do have a number of wells that are constrained. I mean do you think that, just over the next couple of quarters, some of those constraints are lifted, allowing for some of those wells to either come back online if they're idle or just kind of produce it at better rates. Just trying to get a sense of how that can kind of impact the Wattenberg production over the next few quarters?
Leo, this is Scott. I'm going to take that, and maybe Lance will jump back in here. But the idea of our line pressure coming down is, as we described, is critical for the second half of this year to make in our expectations through the year. And I would say it also affects our oil production as I tried to describe in my comments. So those two factors for Plant 11 running efficiently are really important for us, and we're already seeing with two days run time, line pressure come down just a little bit, which is a really positive thing for our guys in the field to start recognizing that's going to happen and also making the adjustments that are necessary. Obviously, these will run steady from this point on or fairly steady for them to really make a difference.
When you look at where we kind of expect line pressure to go, we expect it to come down something maybe 50 pounds, and again, I'm speculating on where that could go as much as possibly 100 PSI. The impact on our wells, it's hard to tell yet. We've tried to bake, as I described, all of that into our expectations for the second half of this year. And then going into next year, the idea Lance was describing that Cheyenne connector getting done and the additional capacity that comes on line there, the volumes coming on associated with that as well that creates a very complex project to try to figure all that out, and that's where our teams have to work hard to understand what they think is going to happen. I'm hopeful that if we get steady runtimes, we can see where that is and start to look -- really understand that more clearly as we roll into our 2020 budgeting process, which is happening soon. But for now, I think that the numbers that we put out there for next year, that both Martin and Meyers were pointing toward, are accurate as we can get them without seeing the actual impact of the plant running for some period of time here.
Okay. That's great color. And I guess just kind of shifting over to the buyback. Certainly from you all's prepared comment, it sounds like that pretty high probability that the authorization gets exhausted here in the second half of '19, particularly in light of the free cash flow projections. Obviously, you guys are expecting to have continued free cash flow in 2020. So just kind of wanted to get a sense of how you think about the free cash flow next year. Could that all just go to maybe an expanded buyback? Or is there potential for a dividend there?
I would say, I think the first step would be I want to finish our current program out. Is there opportunity for additional return to shareholders? I'd say the answer to that is absolutely yes. But obviously everybody has been looking at oil prices lately, and I definitely would like to see them settle down a bit then some of the turmoil we've seen in the prices lately. So I'm going to keep our options open for now. But in a consistent $55 world or higher prices, we definitely have the opportunity to return more to shareholders in the future.
And our next question comes from Brian Downey of Citigroup.
Just had a quick clarification on Slide 20. I'm wondering if the 2020 outlook contemplates any differences in Wattenberg, turn-in-lines versus the prior version. I'm asking because the capital investment didn't change despite the lower Wattenberg rig count. So curious if that has to do with DUC assumptions? Or if those changes are simply within the noises that had been there?
Your observation is correct. What we have there in Wattenberg is a crew running full year next year with a second crew for a part of the year. And in addition, we have a couple extra, a few extra, completions in the Delaware. So that's really what's driving the capital. We would expect it to be down because rig pace is driven back up because of those completions.
Got it. And then sticking with the Wattenberg. Wondering if the trends you're seeing on the higher gas volume is based on where you're drilling in Kersey led to any material go-forward changes? And how you're thinking about average Wattenberg oil gravity? Seems like your oil differential there didn't change that much and still better realization than most of your DJ Basin peers but just curious on the gravity front?
Yes. When you look at our gravity, it's really fairly predictable in there. I think when you look at our production right now and the idea that we're 40% oil going forward, it really is a function of the -- the capability of those wells that we have been drilling that are now the strongest wells and the geo are associated with them. And obviously, the API is a bit higher there than it would be in other parts of Kersey where we've been drilling but not substantially. And I guess, really, API is not -- the API gravity has not been driving the price of the product. It's really a function of the market, overall, of the general market for crude oil.
Brian, there's no question right now, though, that the oiler parts of the field were -- two things, we're experiencing the highest line pressure in those portions of the field, and those wells are much more sensitive as far as being curtailed in high line pressure. So we have upside as a company for the oilier portion of our production to be enhanced as we go maybe to the next year or two, as hydraulically and processing and takeaway, DCP continues to improve their operations. So we have that as an upside. And then you're absolutely right, as we migrate into the Plains Area for drilling, expect some higher GOR. Tremendous economics in those wells because the reserves are phenomenal, but -- so they will probably bring us slightly higher-gravity oil, but when you blend that with everything we're doing in the field, I don't think we're expecting a big shift there.
And our next question comes from Irene Haas with Imperial Capital.
Very quick question. Why did you guys accelerate your share buyback? Because I think a while back, you guys said that you are going to start it in the second half. That's all I have.
Yes. We saw an opportunity. We saw the share price and where the metrics were, and we wanted to make sure that the market saw our commitment to returning capital. There -- we had announced the program, but we really wanted to show that we are -- that this was a thing that we committed to and that we are going to be able to complete the program. So when we saw the opportunity, we started the program.
And our next question comes from Mike Scialla of Stifel.
Lance and Scott, you gave a lot of detail on the Wattenberg midstream, but I wanted to get your thoughts on DCP's commitment to move forward with Big Horn. Do you see that still happening? Or do you think the offload agreement is a replacement for that project?
Yes -- no, that's a good question, Mike. So the offload agreement with WES definitely pushes back the timing of the Big Horn Plant 12 construction, but they've also been very clear to us and to the market to state that as they look at volumes increase from the basin, they recognize that they have to increase the midstream capacity from the field. And so they speak of Big Horn as an option that they have as they see bonds from the field increase. They purchased the land. They have the permits for that plant. So it's still -- they are still debatable and they will monitor volumes from the field and make that determination working really side-by-side with the producers and what our forecast are going forward. So...
Mike, I look at that and say we've got PDCE in our SMID peers that I think we're all backing off on our drilling plans in some form or fashion. And then you've got Noble and soon to be OXY and what their plans are going to be, and that drives a huge part of the shift. So I think we're all anxious to see what happens with their drilling programs going forward. And some of that's been announced and some of it, I think, is yet to be announced. So with that, I think we'll dictate the long-term processing capacity in the whole basin.
Got it. And looking at Slide 11, you talked about some of the efficiencies you experienced in drilling in the Delaware Basin. Sounds like that might reverse a bit next year as you move more into -- the focus move is more to Block 4. And also want to just get your thoughts on, do you think a 2-rig program there and kind of 20, 25 wells per year is enough to really -- do you have enough scale that really drives the efficiencies you like to see in that program?
Yes, I can hit that and I would imagine Bart or Lance might both jump in there, Mike. When we look at that -- you're absolutely correct in terms of that -- the number of wells we can drill with a rig in Block 4 is a bit fewer than we can in the North Central Area, and it's because of the complexities of the rock, the overpressured zone, a bit deeper as well. And with that, we just want to make sure that we pointed that out as we roll into next year. We're hopeful that our efficiencies can continue to improve and take up that additional. It's about 2 or 3 days additional to drill in Block 4 over that North Central Area. I think that's important to recognize as people try to compare different companies, too, that there are differences in the way these rocks drill. And it changes the amount of time that it takes. When you talk about the overall expectations that we have for the rig count that we have out there, I think that 2-rig program for next year is something that puts us in that 25 wells per year. And that's an efficient process from a drilling perspective, but we're still not at a full year of completion -- running a completion crew through a full year, and that is not as efficient.
So if we had -- the ideal circumstance is in only considering operations -- I know our teams would love to run a full-time frac crew out there, and that would be another rig and maybe 1.5 rigs, depending on circumstances to how quick our pace is as we move forward and how efficient we get. Could take 4 rigs, I guess, is the way you could look at that. But overall, you can see that there's still room for improvement on an efficiency with a couple more rigs. And I think that says a lot about the future for us if we can get to that pace, either through more efficient drilling operations or picking up rigs. It would help some, but I think not a lot. I think, particularly right now, as there's excess frac capacity, it would help a little but not a substantial amount, I guess, is the best way to say it.
[Operator Instructions]. Our next question comes from Paul Grigel of Macquarie.
In the Kersey Area digging down there, could you talk through the inventory difference that make this down on the eastern side versus the western side and a little bit more detail on how big the GOR difference is between those two areas?
That's a very complex question. When you start to talk about the Kersey area, we -- our range of GORs -- and I'm going to see if I can recall it, it's in that 10 to 20 range depending on where you are. And it's something that when you start to try to project that -- the west side is much more gassy than the south and east side, I guess, is the best way to look at it. Moving forward, we'll be moving to a different part of Kersey that will be more oily, but it's a little ways out there yet. And I would say probably mid-'19 would be my best estimate. I don't have all those -- all that data sitting in there, but -- I'm sorry, mid-'20, yes, I'm a year off there. But mid-'20 is when we'll start to see that shift. So all of that plays into how we projected 2020's volumes though and the 40% oil.
Okay. That's helpful. And I guess maybe supplementing that, you have talked about some of the older lower-GOR wells being off-line from line pressure. I was wondering if you could quantify the impact in terms of number of barrels or barrel equivalents that maybe off-line.
That is a very difficult question, and our teams are constantly trying to figure that out. And I would say especially because we've had these high line pressure for extended period of time, it gets more difficult even because you don't have uninhibited or free flow of the wells in the past that you can still rely on to project the future. So I guess the best answer is we got quite a bit of production. I know that's not a very good quality, in terms of the number. But I think the best way for us to understand that, and I think our teams would agree with this, is really to see lower line pressure and get the benefit from that. And that's what we're hopeful for over the next 12 to 18 months.
Thank you. And I'm showing no further questions at this time. I'd like to turn the call back over to Mr. Bart Brookman for closing comments.
Thanks, Norma. And we'll keep this short, but thanks to everybody and the ongoing support. I hopefully gave a good update and probably equally important, some confidence around our longer-term outlook as we roll forward around our strategic objectives for the company. So appreciate the support.
Ladies and gentlemen, thank you for your participation in today's conference. You may now disconnect. Everyone, have a wonderful day.