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Ladies and gentlemen, thank you for standing by and welcome to the Denbury Resources Third Quarter Earnings Release for 2018. [Operator Instructions] As a reminder, today's conference is being recorded. I would now like to turn the conference over to the Director of Investor Relations, Mr. John Mayer. Please go ahead, sir.
Thank you, Brad. Good morning, everyone, and thank you for joining us today. With me on the call are Chris Kendall, Denbury's President and Chief Executive Officer; Mark Allen, Denbury's Executive Vice President and Chief Financial Officer; Matthew Dahan, Denbury's Senior Vice President of Business Development and Technology; David Sheppard, Denbury Senior Vice President of Operations; John Brooks, Penn Virginia's President and Chief Executive Officer; and Steve Hartman, Penn Virginia's Senior Vice President and Chief Financial Officer. Before we begin, I want to point out that we have slides which will accompany today's discussion. If you encounter any issues with slides advancing during the webcast portion of the presentation, please refresh your browser. For those of you that are not accessing the call via the webcast, these slides may be found on our homepage at denbury.com by clicking on the Quarterly Earnings Center link under Resources. I would also like to remind you that today's call will include forward-looking statements that are based on the best and most reasonable information we have today. There are numerous factors that could cause actual results to differ materially from what is discussed on today's call. You can read our full disclosure on forward-looking statements and the risk factors associated with our business in the slides accompanying today's presentation, our most recent SEC filings and today's news release, all of which are posted on our website at denbury.com. Also, please note that during the course of today's call, we will reference certain non-GAAP measures. Reconciliation and disclosure relative to these measures are provided in today's news release as well as on our website.
With that, I will turn the call over to Chris.
Thank you, John. I appreciate all of you joining us today. Before I begin discussing our results for the third quarter, I want to welcome the Penn Virginia leadership team, including John Brooks and Steve Hartman. They'll be available to address questions during the Q&A portion of our call.
Our prepared remarks during the call will first cover Denbury's third quarter results. Then, I'll provide a deeper look at our recently announced acquisition of Penn Virginia. At the conclusion of our prepared remarks, we'll have a Q&A session. Denbury had another very profitable quarter, demonstrating the cash flow-generating power of this business. We continued to be disciplined with our capital spending, and year-to-date, we've generated more than $100 million of free cash flow. Realized prices were very strong this quarter, over $71 per barrel excluding hedges. And our corporate NYMEX differential was positive, nearly $2 per barrel, the best we've had in several years.
As we guided at our second quarter earnings call, our production was lower than last quarter, and we've tightened our full year production guidance range to between 60,100 and 60,600 BOE per day, which includes an adjustment for the sale of Lockhart Crossing Field in the third quarter.
We remain on track to spend within our $300 million to $325 million capital budget guidance and expect to complete 2018 in the upper half of that range. Through the first 9 months of the year, we spent about $216 million in capital. Our operations teams continue to achieve great results in keeping people safe and taking care of the environment, and our year-to-date health, safety and environmental performance is exceptional, with each of our key safety and spill metrics at company record rates. One of Denbury's strengths is our peer-leading 97% oil weighting that drives our strong operating margin. Looking back at the third quarter of last year, our operating margin doubled from just over $20 to nearly $41 per BOE. We're focused on maximizing our profit per barrel and are realizing one of the highest operating margins in our peer group. We are pleased to get back to our Mission Canyon drilling program during the third quarter. The current program is focused on delineating the Pennel-Coral accumulation as well as testing 4 new prospects in Cabin Creek, Little Beaver and Cedar Creek fields. We recently brought our initial test well in Cabin Creek online as well as 2 southern delineation wells in Coral Creek.
Our Cabin Creek test results are promising, with an initial production rate of over 1,000 barrels of oil per day. Although quite early, these results are encouraging, and we believe we can add up to 5 wells to our program in Cabin Creek.
Separately at Coral Creek, we encountered anomalously high water production that we believe is caused by reservoir fracturing. We're currently diagnosing the issue, and we'll develop an intervention plan and update you at the next opportunity. Finally, on the rest of our exploitation program, we're currently drilling the second Perry well at Tinsley, and we expect to begin drilling activities on both the Cotton Valley well at Tinsley and the Hartzog Draw Deep test in the fourth quarter, with initial results expected in the first quarter of 2019. Turning to Slide 8. As expected, production for the third quarter was lower than the previous quarter at 59,200 BOE per day. Seasonal summer temperatures impacting injection efficiency across the Gulf Coast, downtime at Oyster Bayou and Cedar Creek Anticline and the Mission Canyon drilling pads were the main factors for the decrease in quarter-on-quarter production.
Looking ahead to the remainder of the year, we expect fourth quarter production to rebound as cooler temperatures return across the Gulf Coast as we experience improved run time at Oyster Bayou and CCA and as Mission Canyon drilling activity has resumed, although the delay in Coral Creek production will reduce Mission Canyon's fourth quarter contribution. Our operations teams keep a high focus on actively managing LOE, and I'm pleased to see the results in an oil market under increasing cost pressure. Total LOE was up less than $3 million quarter-on-quarter to $123 million, mainly driven by increased workover activity. LOE on a unit basis typically runs at a higher level before winter due to planned maintenance activities and seasonal variations. In the third quarter, LOE was $22.50 per BOE, and we anticipate finishing the full year at around $22 per BOE. Turning to Slide 10. We've added a new check to our watch list as we completed the extension of our bank credit facility during the third quarter. This extension resulted in us maintaining the same liquidity as before, and we repaid all of our bank debt with the issuance of a new second lien note maturing in 2024. Mark will cover this in more detail shortly.
Last quarter, we discussed the sanctioning and status of our CCA development project, and I'd like to give you an update on where this project stands. We have bid the construction of 110-mile CO2 mainline from Bell Creek to CCA with prequalified contractors, and we expect to award the contract in the coming weeks. Long lead time materials have been secured, including pipe and valves. The pump station compression has been bid, with an award of these units scheduled for later this month.
Importantly, we received our BLM environmental assessment finding of no significant impact in mid-September, which cleared the biggest regulatory milestone for the project. We continue to be on track to commence pipeline construction in 2019. During the quarter, we completed additional minor Houston surface acreage sales. We continue working sales of several significant parcels, most of which we expect to close in 2019.
Now I'll turn it over to Mark for our financial update.
Thank you, Chris. My comments today will highlight some of the financial items in our release, primarily focusing on the sequential changes from the second quarter. I'll also provide some forward-looking guidance to help you in updating your financial models. Starting on Slide 12, one of our important objectives this year was to extend the maturity of our bank credit facility while maintaining our same level of liquidity. We accomplished this in early August, extending our bank line to December 2021. We also issued $450 million of new second lien notes with a 2024 maturity and completely repaid our bank line, thereby improving our maturity profile. At the end of the third quarter, we had total debt principal of approximately $2.5 billion, with no amounts outstanding under our bank credit facility, and $67 million of cash on hand. Our next slide show the continued improvement in our leverage metrics. Our trailing 12-month debt to EBITDA has improved to 4.1x, another 0.5 turn better than last quarter. If you exclude hedging impacts, our trailing 12-month ratio would be 3.3x.
On the right side of this slide, you can see that our third quarter EBITDA, excluding hedges, was $210 million, and if you annualize that amount, our third quarter of '18 debt to annualized EBITDA would be 2.9x.
We are pleased with the progress we have made with our leverage metrics, and these metrics are continuing to trend in the right direction. Based on recent futures prices, on a stand-alone basis, we would expect our leverage ratio to continue to trend down to the 3.5x range on a trailing 12-month basis as early as the middle of 2019. Slide 14 provides a summary of our oil hedge price differentials -- sorry, just oil price differentials excluding any impact from hedges. For the fourth consecutive quarter, our realized oil price was higher than NYMEX prices, averaging $1.84 above NYMEX, benefiting from continued improvement in the LLS premium through our Gulf Coast production. For Q4, we expect that our overall oil differential will remain positive to NYMEX but somewhat lower than Q3 in the positive $1 to $1.50 range. Slide 15 provides a current summary of our oil price hedges. Since our second quarter conference call, we have added additional volumes to our 2019 hedge positions, such that we now have 31,500 barrels of oil per day hedged for 2019, representing slightly more than half of our third quarter 2018 oil production level. We also added a few hedges for 2020. A portion of the newest hedge positions are our LLS fixed-price swaps locking in prices at $71.40 per barrel, with the remaining hedges representing LLS 3-way collars setting a floor price of $65 per barrel while allowing for upside exposure above $85. We plan to continue to add to our 2019 and 2020 hedges as we deem appropriate and depending on market conditions. Moving to my last slide, I'd like to review some of our expense line items. Since Chris already addressed LOE, I will start with G&A. Our G&A expense was $22 million for Q3, slightly up from Q2 but in line with our expectations. Through the first 9 months of the year, our G&A expense on an annualized basis is trending roughly $20 million below last year's level. Our net G&A related to stock-based compensation was approximately $4 million this quarter, and we currently expect our G&A for the fourth quarter of 2018 to remain in the lower $20 million range, excluding acquisition transaction costs and the stock-based compensation representing roughly $3 million to $5 million of that amount.
Net interest expense was $19 million this quarter, an increase of roughly $3 million from last quarter, mainly related to the write-off of debt issuance costs associated with the amendment to the bank credit facility. On the bottom portion of this slide, you will see there is a more detailed breakout of the components of interest expense that shows cash interest continues to remain steady.
Capitalized interest was roughly flat at $10 million for the third quarter, and we currently expect our capitalized interest to be in the $6 million to $8 million range for the fourth quarter.
Our depletion and depreciation expense this quarter was $51 million, a slight decrease from the prior quarter. We expect this expense will be in the $53 million to $57 million range for the fourth quarter of 2018.
And now I will turn it back to Chris.
Thank you, Mark. Now that we've covered our quarterly results, with the remainder of our prepared remarks, we'll shift to the future and talk about the combination of Denbury and Penn Virginia. Much of the feedback we've received clearly recognizes the incredible opportunity set that the combination opens for both companies. As with any significant event, I'd expect plenty of questions, and we've received a few that I'd like to talk about now. One question I've been asked is whether this transaction signals a strategy shift for Denbury. This transaction is not a shift in strategy. It is a reinforcement that I see fitting perfectly with Denbury's strategy, and here's why. At our core, we are an oil-focused, enhanced oil recovery specialist, committed to generating more cash than we spend. We've developed conventional EOR projects across the country, and we see the next big opportunity for EOR in the unconventional Eagle Ford. Primary development of Penn Virginia's unconventional position adds significant and flexible short-cycle growth capacity and generates even more free cash flow than Denbury does all on its own, all while providing the foundation to apply Denbury's EOR expertise in this emerging exciting arena.
I've talked quite a bit EOR in the Eagle Ford, and the next few slides lay out in detail why we are confident in the opportunity. First and most importantly, EOR in the Eagle Ford has already been tested and proven to be commercial, with 25 different projects across the play.
If you look at the maps on Slide 19. The current projects are shown in purple, with the Penn Virginia acreage in blue. The trends in projects in the same thermal maturity zones leads right to Penn Virginia's acreage, with a dozen EOR projects underway next door in Gonzales County. Incremental CapEx to implement EOR is relatively low, in the $1 million to $1.5 million range per well, delivering strong economics.
The performance of these EOR projects has been remarkable, with a projected increase in EUR ranging from 30% to 70% above primary recovery. Applying that factor across the prospective portions of Penn Virginia's acreage, we believe that incremental recovery of 60 million to 140 million barrels is possible. Slide 20 goes into more detail on the process. I won't go through all these points now, but take a look at the chart from an actual pilot on the upper right. And you'll see an example of the production response from EOR in the orange line significantly better than the typical primary production performance.
All of the Eagle Ford EOR projects to date have this rich hydrocarbon gas for injection, and I'll talk more about injected gas in a moment.
Slide 21 shows why we're focused on the Eagle Ford. Compared to other unconventional basins, the Eagle Ford has superior gas contact area, geology and gas containment. Its proximity to our CO2 pipeline and Gulf Coast assets enhances its attractiveness. On Slide 22, you'll see a compilation of the 8 longer-term EOR projects conducted in Gonzales County. This chart focuses on the production rate impacts from EOR normalized to EOR start date. The set shown is on the same thermal maturity trends as of Penn Virginia acreage, and the initial EOR production nearly tripled pre-EOR rates. The last slide I'll show you on EOR is our game plan for attacking this great opportunity. Part of our reason for targeting Penn Virginia is the more than 400 producing wells that are EOR candidates across the acreage, and we'll immediately begin planning a series of pilots at points across the thermal maturity window. Next year, we plan to begin implementing these pilots, targeting the beginning of full development in 2021.
One essential element is the option to use Denbury's CO2 as a miscible injectant rather than rich hydrocarbon gas, which to date has been the only injectant used in Eagle Ford. While rich hydrocarbon gas may prove ultimately to be the better economic choice for Eagle Ford EOR, simulations predict that CO2 should recover even more oil than rich hydrocarbon gas, and we will test both in our field pilots.
An opportunity cost of using rich hydrocarbon gas for EOR is that you're unable to sell the gas you're injecting into the wells. Using lower-cost CO2 for injection has the potential to both improve recovery and allow our produced hydrocarbon gas to be sold. Also, because CO2 can be compressed into a liquid, it can be injected into wells at much lower pressure than required for hydrocarbon gas. Denbury has a unique advantage with our own CO2 supplier, as our 6-plus Tcf resource at Jacksonville, Mississippi is connected by a pipeline all the way to our fields south of Houston. A pipeline extension to the Penn Virginia acreage would be around 110 miles, similar in length to our planned CCA pipeline. But before I finish with EOR, there are 4 points I'd like you to come away with. First, EOR in the Eagle Ford is very real, working right now, right with us in Gonzales County.
Second, the EOR upside is significant, extending the life of wells and recovering 30% to 70% more oil.
Third, Denbury will attack the Eagle Ford EOR opportunity immediately, driving it towards commercial development by 2021.
And finally, only Denbury has the capacity to deliver significant quantities of low-cost CO2 for injection, with the potential to recover even more oil. Next, I'd like to share with you some exciting preliminary pro forma estimates for the combined company. We've talked about the significant size and scale that this combination creates, and I believe these financial numbers will help put it into context. The estimates provided here assume a $60 to $70 oil price range, and I emphasize that the various assumptions that go into determining the numbers on this slide are preliminary and subject to change, as noted on this slide.
We believe the combined company will grow production at a greater than 10% annual rate from 2019 and 2020. After 2020, we expect sustained production growth, underpinned by continued unconventional Eagle Ford development, coupled with EOR development in the Eagle Ford and response from our Cedar Creek Anticline EOR project.
Consistent with Denbury's past practice, we expect to set our capital budget at a level that allows us to spend within cash flow. Excluding the onetime capital cost to build the CCA CO2 pipeline, we expect to spend between $750 million and $850 million in 2019. We expect a slightly lower amount of capital in 2020 and beyond.
Based on these estimated capital spend and production levels, the net result is significant free cash flow generation. Depending on prices and other assumptions, we expect to generate up to approximately $200 million of free cash flow in 2019 and a range of $300 million to $600 million-plus in 2020. The amount of free cash flow this combined business can generate shows how powerful and sustaining the combination can be. Further into the future, this unique company continues to deliver. Beginning in 2022, EOR production from our world-class Cedar Creek Anticline asset will begin a ramp of steadily increasing and long-lasting production. Meanwhile, production from EOR development in the Eagle Ford should also begin to ramp in 2022.
I'm sure you can see why we're excited about the opportunities this provides for both companies. These combined assets could underpin a future of sustainable, long-term, high-margin growth with significant free cash flow, something that very few companies are able to achieve. And with that, I'll turn it back over to John for some closing comments.
Thank you, Chris. That concludes our prepared remarks. Brad, can you please open the call up for questions?
[Operator Instructions] Our first question today comes from the line of Charles Meade with Johnson Rice.
I recognize this might be a little bit of a flyer, but you guys -- it's been several days since you guys announced this deal, and I imagine that you've had discussions with a lot of your shareholders and a lot of the Penn Virginia shareholders. And Chris, you addressed some of those issues in your prepared remarks when you talked about the strategy shift. But can you -- at least one of the Penn Virginia shareholders has been kind of, of vocal opposition, but sometimes the noisy people are a minority. So can you give us a sense for the tenor of the conversations you've had both with your shareholders and any you've had with the Penn Virginia shareholders so far?
You bet, Charles. What I'd say is there's a lot of reactions that we've had, I'd say generally, that they have been positive. I'll just give you an example of one that we had last week that I found pretty interesting. One of our shareholders called and he said, "Hey, when I look at this transaction, it checks all the boxes. It spins off huge free cash flow. It gives you an option to work your EOR magic in the Eagle Ford. It gives you great investment options. It grows at a good pace. It keeps you at the top on oil weighting, and it helps your balance sheet. So what am I missing?" And my answer to him is, "You're not missing anything. You understand this." And I believe that the important thing for us, as leaders of Denbury, together with the leaders from Penn Virginia, is just to communicate what the beauty of this transaction is and to actually get out on the Street and talk to folks and go through the details, just like I went through in the earlier section of the call here. I know that there's been a short-term reaction on the equity side, but we've seen the same type of reaction on other equity deals that were done during the same week. And we believe that that's a short-term reaction. We believe that once investors, either on Penn Virginia's side or on Denbury's side, learn about the deal, learn about what it does for the long-term future of both companies and realize the long-term view is much more important than any short-term reaction on stock price, then I think that they'll come around.
Got it. You gave a lot of detail -- frankly, I couldn't keep up with it all -- on what the '19 and '20 and beyond looks like, but it was all good. I also appreciate everything you've done on the CO2 in the Eagle Ford detail. But if I could just go back to actually the legacy assets on which you guys have at Denbury, and specifically the Mission Canyon. So I know you spent some time on this in your prepared remarks, but maybe if you could just characterize for us how this surprising result with this, as you call it, anomalous water rate, can you characterize for us, is this the sort of thing that is making you tap the brakes on adding that second rig? Or is this the kind of thing that is something that you're going to figure out in short order, and it was just a blip?
You bet, Charles, and I don't see us looking to tap the brakes on the second rig. We're working through a variety of extensions out here in Mission Canyon. I'm going to let Matt Dahan, he's in the room with us, speak to that further.
Yes. I mean, I would add that we are currently drilling with 2 rigs, so there's -- we certainly didn't tap the brakes. We did in these Coral Creek wells encounter some fractures that we hadn't seen in previous wells, so we're currently running some -- planning to run some diagnostic logs to help us understand where that water is coming from. And then, we'll see whether or not we can take action to mitigate it.
We do have question from the line of Tim Rezvan with Oppenheimer.
I got a bunch. I'll ask a few and then hop back in if I need to. Can you give numbers on the Houston surface acreage sale and the Lockhart sale? Your Q is not out yet.
You bet, Tim. So what I'd say, so far on the Houston acreage sale, we're just totaling around 5 million so far between the second and third quarter. We have a queue of significantly larger parcels that are getting closer to a signature point, but we're just not quite there at the point where we can talk about it today. I would expect you to see those coming through here as we go into the rest of the fourth quarter. And then, and the actual closing for many of them will start to roll up in 2019. Lockhart, there's a few elements to that, and you recall when we talked about our mature asset sale that there are couple of different things that we need to look at when we sell a field in these mature areas. One is, with them being EOR fields, it's not just the sales price that we have, it's also the CO2 sales potential that has to be attached to the field no matter who it goes to. And so what I'd share on Lockhart is that the sales price for the field was $5 million. The value of the CO2 contract for us over the life of the field still looks to be several million dollars higher than that, so you'd want to consider that in the value. And then we've also -- by selling a field when we're closer to the end of its life there, we have a several million dollar abandonment liability that we've transferred. So I'd say, Tim, you can kind of think of those 3 elements together: the sales price of $5 million, a CO2 sales contract over time that just counts to something greater than that and then the shifting of the abandonment liability.
I appreciate that color. Shifting to the Eagle Ford Shale EOR commentary, I appreciate the detail. People have been really looking for that. You gave some pro forma numbers for '19 and '20. Does that reflect the EOR implementation from your CO2? And I'm just wondering kind of when and how you would fund that pipe? And will that be kind of a similar cost to the 150 million you've cited in CCA?
You bet. So first, the numbers that you're seeing as estimates for '19 and '20 don't really have any revenues from EOR in the Eagle Ford at all associated with them, so that would be a completely separate path that you'll see there. Second, and an important point to clarify, and I'm glad you brought it up, is that there are really 2 great ways that I see to conduct EOR in the Eagle Ford. The one that's being used now with rich hydrocarbon gas is working, and you're seeing that. And so I think that that's an exciting path. And what I would say is through this combination, that Denbury and Penn Virginia are not biased towards CO2 or rich hydrocarbon gas. We're biased towards whatever drives the greatest value for the combined company. But what we do bring is that opportunity with CO2, even though, as you mentioned, there's a pipeline that we'd need to connect to get CO2 on a steady-state distribution. And so our piloting that we're going to run through in 2019, 2020 is going to test both of these because a lot of the benefits that you have with CO2 have to -- they have to overcome the costs that you'd have of the pipeline that you mentioned and the other surface facility work that you'd need. And so I think that at the end of the day, we're going to have to compare what that looks like and maybe the incremental recovery you get from that versus the rich hydrocarbon gas, which is available in the field and have some different qualities to it. But then, at the end of the day, it's going to be an economic question. What I like is just this combination gives us a unique option to go either way with it.
Okay. I guess, we'll wait and see. And then, if I could sneak in one last one. On the updated production guide for 4Q, is it safe to say that the reduction is mostly due to the disappointing wells 4 and 5 in Mission Canyon?
Yes, it is.
Okay, Okay. And then, it seems like it was a bit of a step-out well. Does that change your view on kind of the risk inherent in kind of what you think of as the derisked area?
I don't think so. I'm going to let Matt speak further to that.
Yes, I mean, if you look at our map on Slide 7, you'll see that the Mission Canyon is actually several different accumulations, so we're out there testing multiple ones this year. And we were disappointed certainly in the Coral Creek wells but very, very encouraged with our Cabin Creek wells. So you've got -- we've got a very good response there, and we'll add additional locations to test in the future at Cabin Creek.
And we do have a question from the line of Richard Tullis with Capital One Securities.
Just a couple of questions. I could start with the outlook for the 10%-plus annual growth for 2019, 2020. Chris, what's the expected contribution in that growth rate from the Penn Virginia properties?
Well, Richard, what I'd say is what's in this pro forma would be very much in line with what you've seen from Penn Virginia's own disclosures, so I'd expect it to be along those lines. We at this very early stage in the process have not dialed that any further than what you've already seen. So I'd look at that and I'd look at what you've been previously thinking about how Denbury is growing and looking at those 2 together.
Okay. And then, so it sounds like extending the pipeline to the Eagle Ford to utilize your own CO2 source could be a nice option, and I realize you still need to go through the testing phase. But roughly, when could you have enough data, Chris, to make a decision on moving forward with that sort of option?
I think as you've just considered the piloting that will be in 2019 and 2020, I would expect that you'd get to a point where you could make a decision at the end of that period on something like the CO2 pipeline. So I think it would be something that you commence outside of that range. So it's a few years off, Richard. That's one of the nice things that you see about EOR here is you have the ability to use either of these injectants, and the one that is available there right now has been proven to work.
All right. And just lastly, a question for John and Steve. So it looks like Penn Virginia is trending toward a pretty strong 2018 production exit rate. John, what do you -- what's the expected first year decline rate on that PDP production as you get into 2019?
Yes, I think we're looking at a 35 to 40 for the base decline rate for oil in '19.
And we do have a question from the line of Neal Dingmann with SunTrust.
Congrats on the deal. My question is sort of post the deal, and I think you've mentioned this even on your prior call. Maybe talk about it again, if you could, just the ideal leverage going forward. And then, maybe as a sort of second -- sort of similar part to that, I know currently, you've got a nice free cash flow positive profile. Is this something you'll try to get to sooner rather than later there? Or really just anything you can talk about regarding leverage and the free cash flow.
Sure, Neal. This is Mark. I think as we showed on the slide with some of the estimates, that getting to 2x or better in the near future is possible with this combination. And we see that -- long term, we think the industry has really shifted to like 1 to 2x instead of 2 to 3x historically, and I'd say we want to continue to push that forward and be on the conservative side of that. And then, once we get the balance sheet where we want it to be, that gives us a lot more optionality to address all the free cash that will be coming with the combined companies. So that's kind of our current thinking. And obviously, we've got to continue to get the balance sheet to where we want it, and then optionality increases substantially.
Sure. Great comments. And then just last, and I know you've also hit this a little bit. But any more color you could just on -- I know there's a potential for the EOR in the Eagle Ford. That potential, is that something that's a few years down the line? Or I just want a broad timing on something potential like that.
I'll tell you, Neal, what I believe is that this is an opportunity that can be attacked immediately, and it's being attacked already by adjacent operators right next door. So what we intend to do is come out of the gates with a broad set of pilots that look at different areas within the thermal maturity window that's across Penn Virginia's acreage, that looks at using CO2 or using rich hydrocarbon gas. One thing I'd just point out, even going back to Richard's question a few calls ago, is that we have the option of using either, and we have the option of using both CO2 and rich hydrocarbon gas. We can start with rich hydrocarbon gas and then convert at a later point if it proves to be better. But all of that makes us a relatively near-term option that I see and something that we're going to be moving quickly on from day 1. What I would hope that we would find is that we get to a point in commercial development in 2022, where you're actually seeing results in 2022. One of the interesting things, Neal, just comparing conventional EORs and unconventional EOR is we think about unconventional EOR as being a short-cycle EOR where your response is in months, not quarters or longer, and you're able to do quite a bit in a short period. So that's part of what excites us about it.
We do have a question from the line of Michael Scialla with Stifel.
I wanted to -- so you'd mentioned, Chris, that the EOR pilots, obviously some pretty impressive results there in the Eagle Ford with 30% to 70% increase over the primary production. I want to see how close those are to you, the Penn Virginia acreage, how analogous. You mentioned the thermal maturity was similar. Are there any other geologic differences between the 2 areas or any other reservoir differences that you view as as a potential risk?
Yes, we don't see -- this is Matt Dahan. We don't see any significant differences as you trend from those pilot. They immediately offset the Penn Virginia acreage.
Okay. Everything pretty much just same geology, same reservoir characteristics?
Yes, sir.
Right. Okay. And if I look at the combined companies, the numbers you put on Slide 24, general guidance looks like -- I'm coming up with the combined company -- it would be valued today at less than 4x enterprise value to 2019 EBITDA. Is that consistent with what you're projecting there?
Well, that's what we're seeing. And I think, Mike, part of what we need to do is just the value that we see in this combination is -- this has only been out for a week or so, so it's on us to get out and talk to investors and really share the value that we see in this. And I think it doesn't take too long when somebody sits down and really looks at it and thinks about it to see how that can -- how that value really, really adds up.
And we do have a question from the line of Eric Seeve with GoldenTree.
I have a few questions. One, on the Lockhart property sale, I'm just trying to understand how that's flowing through guidance. Was that sold? Can you just clarify when that was sold?
Middle of September? Yes, middle of September. We did a production breakout in the...
Yes, okay. So that was the production that's added for the 2.5 months in the quarter, and they won't add any in the fourth quarter. And that's part of the reason for production guidance?
Right, exactly.
And I presume that these are much higher-cost properties than the consolidated average?
Very much so. And that's what's generally across the more mature fields, as we said before, are at a higher -- they just end up in their life cycle being at a higher unit cost. That's right Eric.
Okay, terrific. And we'd love if you can provide any color on the sales process for the other mature properties, if that's still ongoing, or just what you're thinking there.
Sure. It's ongoing, Eric. We have slowed it down as we're prioritizing this Penn Virginia process. So it's a priority for us. It's just that a higher priority at this point is to get through the Penn Virginia transaction. We still think it's very important to continue to optimize our portfolio, and that's still part of our plan.
Okay, terrific. And then, just with respect to the '19 and '20 guidance, I appreciate that Penn Virginia has provided some color on what their stand-alone '19 looked like. But I don't think on the legacy Denbury side, you guys have done that in the past. Can you let us know just what -- how much sort of production from the stand-alone Denbury business, and how much CapEx from the stand-alone Denbury business you guys are assuming in '19 and '20 as part of this projection?
Sure. I'll start, and I'll let have Mark finish for me. But what I'd say, Eric, is that first of all, formal guidance for 2019 will be -- is yet to come from Denbury. As you know, we generally get to closer to the end of the year or even a bit into the next year to provide that guidance. So these are estimates that we have from where we stand right now. And what I would say is that the general low single digit percent growth that you have seen from us in past discussions is what you'd have here. Capital, I think we've talked some about. One thing that's important to know on capital is, as we've said, 2019, we have the chunky pipeline to the CCA investment, about 150 million. So we have that incrementally there on top of what would be probably a capital that's similar to what we have this year. Is that fair, Mark?
That's fair, yes.
I'm sorry. So you're saying for '19, other than the bump up in CCA spending, the CapEx on the remainder of the business in '19 would look similar to '18?
Yes, we'll look as we continue to refine our estimates and guidance for '19 and see where oil prices go. But our goal is to stay cash flow neutral or generating free cash. So that will obviously have some impact in the flexibility we have. But I would say this year, we're targeting $300 million to $325 million. So we would expect or we'd like to at least spend that next year on development projects, and then $150 million or so related to the CCA pipeline. And so you could add that together and stay within cash flow, but those 2 components would make most of what you would expect.
Okay. So $300 million to $325 million plus the $150 million is a good way to think about Denbury, even though formal guidance is not out yet? Is that right?
Right. And then obviously, looking at where cash flow is, too.
And at this time, I'll turn it back over to the host for today's call for closing remarks.
Before you go, let me cover a few housekeeping items. Denbury and Penn Virginia senior management will be meeting with investors in New York on Tuesday and Wednesday of next week. On the conference front, we will be attending the Bank of America Merrill Lynch 2018 Global Energy Conference on Thursday, November 15 in Miami; and the Capital One Securities 13th Annual Energy Conference on Wednesday, December 5 in New Orleans. The details for these conferences and the webcast for the related presentations will be available through the Investor Relations section of our website at a later date. Finally for your calendars, we currently plan to report our fourth quarter 2018 results on Thursday, February 21, and hold our conference call that day at 10 a.m. Central. Thanks again for joining us on today's call.
And ladies and gentlemen, this conference will be available for replay after 12:30 p.m. today through December 8th, 2018. You may access the AT&T Teleconference Replay System at any time by dialing 1 (800) 475-6701, entering the access code 426561. International participants may dial (320) 365-3844. That does conclude your conference for today. Thank you for your participation and for using the AT&T Executive Teleconference service. You may now disconnect.