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Ladies and gentlemen, thank you for standing by, and welcome to the Fourth Quarter and Full Year 2018 Results, 2019 Outlook and Penn Virginia Combination Update. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Denbury Director of Investor Relations, Mr. John Mayer. Please go ahead.
Thank you, Greg. Good morning, everyone, and thank you for joining us today. With me on the call are Chris Kendall, our President and Chief Executive Officer; Mark Allen, our Executive Vice President and Chief Financial Officer; Matthew Dahan, our Senior Vice President of Business Development and Technology; David Sheppard, our 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. Should 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.
Thanks, John. I appreciate all of you joining us today. I'd like to welcome 2 members of the Penn Virginia leadership team: John Brooks, CEO and President; and Steve Hartman, Senior VP and Chief Financial Officer. They'll be available to address questions during the Q&A portion of our call. Our prepared remarks during the call will initially cover Denbury's 2018 fourth quarter and annual results and 2019 plans. I'll follow that with an updated look at our previously announced acquisition of Penn Virginia, which you'll see continues to be a compelling combination even at today's lower oil prices. At the conclusion of our prepared remarks, we'll have the Q&A session. 2018 was a great year for Denbury. We set multiyear records for our company in each health, safety and environmental category. We entered into a merger agreement with Penn Virginia in late October, with the vision of combining 2 complementary platforms that will be well positioned strategically and financially to deliver value to both sets of shareholders.
Most exploitation and expansion of existing fields continue to be highly successful, and sanctioning of the CCA EOR project laid the groundwork for adding resources well in excess of Denbury's current total proved reserves. We grew the reserve base, adding more reserves than we produced in the year.
We generated -- we reduced net G&A by 30%, and we generated more than $80 million in free cash for the year while reducing net debt by over $280 million. We improved our leverage ratio by almost 2.5 turns, and we extended our bank line into 2021, finishing the year with a completely undrawn credit facility. Based on the actions we've already taken, we are well positioned for success in 2019. Shareholder meetings for the Penn Virginia merger are planned to be held April 17, and we'll be reaching out to shareholders of both companies in the meantime as we seek their approval of this unique and exciting combination. We set our budget around generating positive cash flow at $50 oil, with upside to significantly greater free cash flow at prices above $50. We will continue to raise the bar for HSC performance, seeking to build on the record level set in 2018. Even with capital well below 2018 levels, we'll be testing promising new exploitation concepts as well extending upon the successes we've already achieved, demonstrating the resilient nature of our asset base. We'll continue to invest in our long-life fields, notably progressing the CCA EOR project, the 6 phase at Bell Creek and the new development area at Heidelberg. Finally, we'll remain fundamentally focused on improving our financial profile, building on our significant success in achieving a stronger balance sheet over the past few years. Slide 8 provides a closer look at how we expect to generate free cash flow in 2019 at $50 oil and how that free cash flow is enhanced by higher prices. The significant decline in oil prices from October through the end of December last year was one of the fastest and sharpest declines the industry has ever experienced. And through the first 2 months of 2019, oil prices have recovered nicely. But with the recent volatility, we still feel it makes sense to base our 2019 plans around the $50 oil price.
We're committed to continuing to invest within the boundaries of our cash flow. As you can see here, even by reducing our capital budget to a range of $240 million to $260 million, we're still able to generate significant free cash flow with oil at $50, increasing nicely at higher prices. For example, at $50 oil, we estimate that we will generate free cash flow of $50 million to $100 million. And at $60 oil, we expect that to increase to the range of $120 million to $170 million. Turning your attention to the right side of the slide, we lay out in more detail the 2019 estimated sources and uses of cash. Assuming a $50 oil price, we expect to generate operating cash flow of $420 million to $470 million in 2019, which assumes $30 million to $40 million of interest being capitalized.
Due to the accounting for the debt exchanges we completed over the last couple of years, approximately $85 million of interest we pay on our bonds is reflected as a reduction of debt in our financial statements instead of interest expense. So we backed that amount out of operating cash flow to show the actual level of cash we have available. Walking down the numbers and assuming the midpoint of our development capital and capitalized interest, we end up in a free cash flow range of $50 million to $100 million. One other thing I'd like to point out on this slide is that, generally, an unhedged $5 move in oil prices would create an approximate $100 million change in cash flow. As shown here, our level of free cash is not increasing at that same level as we step up in oil price as the floor prices on our hedges are set at levels averaging higher than $55 oil. Even at these reduced capital budget levels, we're able to invest in important projects, including the completion of Phase 6 development at Bell Creek, additional development at Heidelberg, up to 4 exploitation wells at CCA, testing a new exploitation concept at Conroe and flow testing our recently drilled Cotton Valley well at Tinsley. We've also extended much of the planned 2019 investment in the CCA EOR project into 2020, and we'll be procuring the line pipe for the CO2 pipeline in 2019. Production for the fourth quarter of 2018 was about 700 BOE per day above the third quarter, reaching 59,900 BOE per day and resulting in full year production of just over 60,300 BOE per day, in line with our recent guidance and up slightly from 2017. Production from Bell Creek continues to grow with high performance from Phase 5. Field production there reached a record 4,400 BOE per day in the fourth quarter, with gains expected to continue into 2019. As a result of reducing our capital investments by as much as 25% from 2018, we expect slightly lower production in 2019 and are projecting full year production between 56,000 and 60,000 BOE per day. Similar to 2018, we expect the quarterly production profile to be seasonally lower midyear, increasing into the fourth quarter. Operating costs at $22.24 per BOE for the full year were in line with our prior guidance. Total LOE was $128 million, up about $5 million from the third quarter, primarily due to increased CO2 costs and higher workover activity levels. The increase in CO2 costs from the third quarter was primarily due to the planned maintenance on part of our Gulf Coast pipeline system as well as higher nonoperated CO2 cost associated with higher purchase volumes in the fourth quarter of 2018. We expect both workover activity and nonoperated CO2 cost to moderate with lower oil prices in 2019. Our operations teams are highly focused on managing and reducing LOE, and this is evident through holding our power, labor, repair and maintenance and chemical cost flat since the fourth quarter of 2017. While I'm confident that our teams will be successful in reducing the total LOE, just as we've had success in reducing costs in other areas, producing fewer barrels in the year could apply upward pressure to the per BOE LOE metric. So at this point in the year, we're guiding to a fairly broad full year range of $22 to $24 per BOE. We grew reserves in the company in 2018, more than replacing production, to reach 262 million BOE. Strong SEC oil pricing, up over $14 year-on-year, increased the company's PV-10 value by about $1.5 billion to reach $4 billion at year-end 2018. When considering the effect of oil price on Denbury's PV-10, a good rule of thumb is that a $10 oil price change results in about $1 billion PV-10 change and the 2018 results are right in line with that concept. As we planned our 2019 capital budget, with the backdrop of lower oil prices in the fourth quarter of 2018, our development team found a solution that could spread much of the CCA EOR project spend outside 2019, completing the pipeline installation in 2020 and minimizing our 2019 capital exposure in this uncertain oil price environment.
Because the availability of CO2 to flood CCA will be quite a bit greater in 2021 than in 2020, we expect the production build-up should be minimally impacted by the timing shift, and Phase 1 should reach the same peak production level right about the same time as before the capital shift. We plan to procure the line pipe for the pipeline in 2019 and hit the ground running for the installation in 2020. We're still analyzing financing options, including self-funding or a JV structure for this investment. We continue to have very good results with exploitation at CCA. We've drilled 7 successful Mission Canyon wells to-date, with an average 30-day initial rate of over 800 barrels per day. We now have successful Mission Canyon wells as far south as Little Beaver and as far north as Cabin Creek, extending over 40 miles. We believe we have as many as 14 additional locations, and we plan to drill up to 4 wells in 2019 as we continue the program. In our last update, we mentioned water influx encountered in 2 Mission Canyon delineation wells. In the fourth quarter, we encountered a similar issue on the down to Pennel extension. In December 2018, we reentered 2 of the 3 wells and isolated portions of the well bores, and were able to initiate relatively low volumes of oil production from these wells and are evaluating sidetrack options for the third. Our learnings from these wells have been incorporated into our plans for additional drilling. On the whole, the Mission Canyon program has been highly successful, generating greater than 50% return at $50 oil on our total investment to-date. We were successful with our first Charles B well in Cabin Creek. As you see in the inset map, the Charles limestone interval sits about 250 feet above the Mission Canyon. While the Mission Canyon has a strong aquifer drive, Charles B has a weak aquifer, and we expect Charles B wells to flow at a lower initial rate but at a sustained oil cut. This was the case in our first well, where the oil cut has remained in the 75% range, given that great upside for eventual secondary or tertiary development. We think we have up to 14 wells in the prospective range for the Charles, which runs in the northern part of CCA, beginning at Cabin Creek and extending all the way north to Glendive. We're excited about taking the successful concepts we have proven in CCA, using today's off-the-shelf horizontal well technology to place long laterals in oil-bearing reservoirs that are too thin or that don't have the reservoir qualities to support the economic vertical wells and applying that technology to unswept reservoirs in several of our great Gulf Coast fields. These unswept reservoirs are typically lower-quality rock than the historic producing intervals. And as a result, they were not effectively produced during early field life and were not significantly impacted by aquifer movement in the field. We plan to start this exploitation program in our Conroe Field in the horizon called the 2A Sand. The first well will be fairly simple, low cost and horizontal, estimated at $3 million to drill and complete. We plan to drill the well in the second quarter of 2019. With success, we think we have more than 20 possible well locations in the Conroe 2A sand, and we see additional potential in the 1A and 3D sands in Conroe as well. And as I mentioned, we think this concept can be applied to multiple Denbury Gulf Coast fields. We finished drilling our Cotton Valley Haynesville test well in the first quarter and logged about 100 feet of net Cotton Valley pay as well as about 100 feet of net pay above the Cotton Valley that could be oil-bearing. No pay was logged in the higher-risk Haynesville target just below the Cotton Valley. Our next steps are to flow test in the second quarter to determine well productivity and plan potential future development. Also in the Tinsley Field, we completed our second Perry well in the fourth quarter of 2018. Peak production of under 200 barrels a day was below our target threshold to continue Perry investment, and we plan to pause this program while we shift focus to higher-value Gulf Coast opportunities. And now I'll turn it over to Mark for our financial update.
Thank you, Chris. In addition to the normal financial update, I'll provide certain 2019 guidance information that will address Denbury's business on a standalone basis. A little later in the call, we will also review updated summary projection information on a combined basis with Penn Virginia. On Slide 19, we provide a summary of our 2018 cash flow from operations and a reconciliation of our free cash in excess of capital expenditures. As shown on the top portion of this slide, cash flow from operations in 2018, before changes in assets and liabilities and adjusted for special items, was $527 million. After reducing that amount by $86 million for interest that's reflected in our financial statements as repayment of debt, we generated net cash flow of $441 million and free cash of $81 million after development capital and capitalized interest. This free cash allowed us to build a small cash position, ending the year with $39 million of cash on hand. Moving to Slide 20. Our leverage profile and debt reduction continue to be top priorities for us. We are extremely pleased with the progress we've made during 2018, reducing our net debt by over $280 million, fully repaying our bank line and extending its maturity to 2021. As our plans put Denbury in position to generate meaningful free cash in 2019, we will continue to evaluate options for improving the balance sheet and weigh those against other uses or accumulating cash for future development capital. Slide 21 show the improvement we have made in our leverage metrics. Our trailing 12 months debt-to-EBITDAX ratio improved significantly from 2017, coming down to 4.2x at year-end 2018. And if you exclude hedging impacts, our trailing 12-month ratio was 3.3x. For 2019, based on recent oil price futures, we would expect our leverage ratio on a standalone basis to remain relatively stable in the 4x -- low 4x range. Slide 22 provides a summary of our oil price differentials. Excluding any impact from hedges, for the fifth consecutive quarter, our realized oil price was higher than NYMEX prices, averaging $1.69 above NYMEX. Our differential in Q4 was slightly better than we guided last quarter as the LLS premium for our Gulf Coast production strengthened in the fourth quarter, helping to offset the weaker differentials for our Rocky's production. Based on our expectation for differentials in Q1, we currently estimate an overall positive differential similar to what we realized in Q4. Moving to the next slide, I'll review some of our expense line items. Chris already covered LOE, so I'll start with G&A expense, which was $10 million for the fourth quarter, down significantly from $22 million in the third quarter. The significant decrease from Q3 was due primarily to downward adjustments in estimated performance-based compensation, which was impacted by the negative movement in oil price and our stock price during the fourth quarter. On a full year basis, our G&A expense was down over $30 million or 30% from 2017, due to continued focus on costs as well as workforce reductions in 2017. Our net G&A related to stock-based compensation was approximately $3 million in the fourth quarter.
On the standalone basis, we expect our 2019 annual G&A expense to be relatively consistent with 2018, generally in the upper teens to $20 million per quarter, with Q1 typically a bit higher than the other quarters. We expect stock-based compensation to represent roughly $15 million of our 2019 expense. Net interest expense was $18 million in Q4, essentially flat with the third quarter. On the bottom portion of this slide, there's a more detailed breakout of the components of interest expense, and you'll see the cash interest continues to remain steady. Capitalized interest was also flat at $10 million for the fourth quarter. And we currently expect our capitalized interest for each quarter in 2019 to be in the $7 million to $10 million range. Our depletion, depreciation expense in the fourth quarter was $60 million, a larger-than-expected increase from last quarter due to incremental cost subject to depletion and the acceleration of depreciation of certain costs in Q4. For 2019, we currently expect to average in the $60 million range for each quarter. Slide 24 provides a current summary of our oil price hedges. Since our last update in Q4, we have added more LLS swaps to both 2019 and 2020. We currently have hedges approaching 70% of estimated 2019 production. And as shown on the bottom portion of the slide, our hedges are providing some nice floor levels to protect our cash flow in 2019 while still providing significant upside participation if prices move higher. And now I'll turn it back to Chris.
Thanks, Mark. Many of our investor conversations over the past few months have been regarding the Penn Virginia merger. Most investors see the logic of the combination and the tremendous opportunity that it presents for both companies. We continue to believe that this combination will create a company that is distinctly resilient, sustainable and valuable. Let me take a few minutes to reiterate the reasons why we entered into this transaction and address some of the questions we're hearing from investors. Denbury and Penn Virginia are 2 complementary businesses, and we think combining the strengths of our respective assets and capabilities creates a unique opportunity to deliver value. For Denbury, adding scale in the Eagle Ford provides a platform for the next generation of enhanced oil recovery. At the same time, Penn Virginia will be benefiting from Denbury's industry-leading EOR expertise and access to our extraordinary CO2 resource, providing a step change to EOR. As we outlined earlier, Denbury has a highly resilient set of long-life, low-decline assets, which create a stable production base with strong cash flow. At the same time, the remaining primary development on Penn Virginia's acreage provides opportunistic, high-return, flexible investment optionality. The combined operating model is flexible, growing and sustainable. Even before considering incremental EOR production, we expect that the combination will provide 5% to 10% annual production growth, remaining heavily oil-weighted and generating strong operating margin and free cash flow. The financial profile of the combined company is strong, with total liquidity over $600 million, and improved access to capital as well as a lower overall cost of capital for the combination. And as we look ahead, our shared discipline around managing CapEx within cash flow, combined with the strength of that cash flow, should put us on a path to reduce total leverage to at or below 2.5x by the end of 2021. As we've continued our preparations for the merger, our conviction in the potential has grown. EOR production in the Eagle Ford is still growing significantly, and I'll touch on that in more detail in a few slides. Taking into account the decline in oil prices, we updated the preliminary combined pro forma estimates that we initially provided back in early November. Market conditions at that time were such that we prepared those projections based around a $60 to $70 oil price range. Over the last several months, we've reworked those projections for both companies at much lower levels. And the information here now assumes an oil price range of $55 to $60 over the next few years, which is representative of recent oil prices and future strip prices. As we stated before, we believe this combined company can produce attractive organic growth while generating a significant amount of free cash at current oil prices, a shift that many companies are currently trying to achieve. The biggest changes made to the model are adjusting capital expenditures to fit the current price environment and the result in production growth and cash flow. And we have also provided another year of projections beyond what we showed previously.
Capital expenditures have been moderated for both standalone companies, and the current estimates assume a 2-rig program in the Eagle Ford for 2019 and '20, shifting back to a 3-rig program in 2021. For Denbury, we assume the same development plans for 2019, as we presented earlier, and the continued development of CCA on par with our current plan. As you can see, development capital remains well within operating cash flow while production is expected to grow 5% to 10% on a compound annual level over this time period. The positive attributes around high oil mix and top-tier operating margins have not changed. And although our deleveraging plan is adjusted slightly in the revised plan, we still believe achieving a very respectable 2.5x by 2021 is a great place to be, and we believe there will be opportunities to improve upon that and drive it even lower over the longer term. The next slide revisits the transaction consideration and subsequent ownership of the combined company. The shareholder meetings have been scheduled for April 17, and we expect the proxy information to be mailed to shareholders in the near future. We have updated the numbers on the bottom of this slide to reflect the most recent information around reserves, production and cash flow and CapEx numbers for 2018, which also helps illustrate the increased size and scale of the combined company. The cash and stock transaction provides immediate liquidity and the potential to realize upside value given the unique strength of the combined business. Slide 29 is a review of the financing we have in place for the transaction and a pro forma view of the combined company's capital structure. Just a reminder that we have fully committed financing from JPMorgan to cover a $400 million senior secured second-lien bridge loan and a new $1.2 billion senior secured bank credit facility. This will allow us to cover the $400 million cash payment and resources to refinance Penn Virginia's existing debt as needed. We would expect to have over $600 million of liquidity available upon closing the transaction, which will be immediately accretive to Denbury's debt metrics and will provide a solid foundation from which to continue to improve the combined companies' leverage profile and sustainability. Turning to Slide 30. We've shown most of this slide before but we included it again here to highlight the strong growth in the Eagle Ford EOR opportunity. The number of wells on EOR has grown by 100 since our last count to 300. And total EOR production in Eagle Ford reached 18,000 barrels of oil per day in 2018. We see that number continuing to grow as the play gains momentum. We also see unique advantages in using CO2 compared to rich hydrocarbon gas, including greater oil recovery and applicability in areas where rich hydrocarbon gas is not effective. And importantly, using CO2 provides the potential for large quantities of man-made CO2 to be stored underground, providing much-needed capability for industrial generators of CO2 to reduce their emissions. A key difference between CO2 and rich hydrocarbon gas is that CO2 is miscible in that's able to combine with the oil into 1 fluid at a much lower pressure than rich hydrocarbon gas. This helps in a couple of ways. First, there's a larger pressure range to work with before reaching a well's fracture pressure. And second, the surface injection pressure can be much lower, reducing the cost and complexity of surface facility's equipment. The bottom line is that we see CO2 as having unique benefits for use in the Eagle Ford, including superior access to parts of the play that may not be floodable with rich hydrocarbon gas injection. That concludes our prepared remarks, and I'll turn it back over to John.
Thank you, Chris. That concludes our prepared remarks. Greg, can you please open the call up for questions?
[Operator Instructions] Your first question comes from the line of Charles Meade from Johnson Rice.
I want to thank you for putting in that Slide 31. I'm not going to ask a question about it because I already have asked you a question about that, but I think it's a really helpful one. But I want to start actually with a big picture question about your CapEx, really, as a standalone Denbury for 2019. I get the idea of setting a CapEx budget that's consistent with $50 oil. What's a little more difficult or what's not as obvious to me is why you would choose to run or choose $50 million to $100 million of free cash flow at $50 rather than invest that in projects? My kind of back-of-the-envelope math says that actually your debt metrics would be better if you actually spent that $50 million to $100 million rather than just let it pile up on the balance sheet. So can you talk about your thought process in that regard?
Sure, Charles. I'll start, and then I'll ask Mark to jump in after I say a few words. But when we're preparing the budget for this year and the backdrop of that collapse in oil that we saw in the fourth quarter, there's just tremendous volatility in what you see with oil. And we wanted to, number one, be confident that we were coming into this year in a position that could put us into a strong position. When we found the opportunity to move CCA pipeline installation into 2020 without really impacting the project, which I think is a remarkable achievement by our technical teams, we also saw that, that would put some additional capital needs on 2020. And so building some cash as we come into the year is not necessarily a bad thing when we look at 2020. The flip side is that we also have the opportunity to continue to use some of that cash to work on the balance sheet as we see opportunities come up in the course of the year.
Got it. Chris, so just to make sure I understand you right. So by -- once you saw this opportunity to shift the CCA CapEx into -- some of it from '19 into '20, you kind of just left the rest of the capital budget as it was, and you're just accumulating that cash. Is that a fair read?
Not exactly, Charles. We took a pretty hard scrub through all of our projects' portfolio and high-graded projects that we really wanted to get done, whether they're just foundational projects, like what we're doing at Bell Creek or Heidelberg, or they're opportunistic projects like this exploitation test at CCA that is -- I'm sorry, at Conroe that if successful, opens a whole new world of exploitation along the Gulf Coast. But even with that, we pulled back. Just an example, we pulled our CCA exploitation down to 4 wells from the number -- the 10 or so that we drilled in 2018. We're holding those by production. We have the opportunity there. Just when we looked at what we wanted to do, pulling some of that back and high-grading the projects made sense to us.
Got it. That's helpful to understand your process of thinking there. And then if I could just pick up on that exploitation, in particular, the CCA and your -- this Charles B zone. I think you did a good job addressing what's going on there in your prepared comments. But I find myself wondering you've got this Charles B zone and you've got your little stratigraphic stack on that same slide, are there more? I mean, so you did this with the Mission Canyon, now you've done it with the Charles B. Should -- is it going too far to say that we should look for similar things in the Lodgepole, Interlake, Stoney Mountain and Red River?
Certainly, Charles, we think there could be more. And the Charles interval has several benches in it. Charles B is one of those. And so we think there's potential there as well. Of course, as we go down into the Lodgepole, Red River and so on, those get to be reservoirs that have been historically produced. So the opportunities we're seeing are in these upper intervals, at least right now. But certainly, we see more than what we've tapped into so far. And I think that there's very interesting potential in that, Charles, as we look across CCA and at those different benches that we have there.
Your next question comes from the line of Tim Rezvan from Oppenheimer.
Joe Beninati on for Tim this morning. My question is on the LOE front. I know, Chris, you gave some color on your prepared remarks. But just looking at the broad range of 2019 guidance, could you maybe talk a little bit more specifically on how some of the exploitation projects would actually move the needle on bringing that back down?
Sure, Joe. And when I think about the LOE and what some of these incremental opportunities can do for us, they tend to be lower LOE type of projects. And so the more of those that we can pull into the mix, the better impact we'll have on those -- on that per barrel metric for LOE. And that's something that we don't just look at in exploitation. Other areas where we can enhance production in our existing fields just with the fixed cost that you have there, anything that we can do to improve that is going to help. That's why we've put a pretty big range around it. I see a lot of opportunity to move that to the positive, either through doing better with our production than we have in the range there or saving money through adding production that's lower cost, like you mentioned.
Your next question comes from the line of Jacob Gomolinski from Morgan Stanley.
Can you just talk to some of the JV options at CCA that you're considering?
Sure. A bit preliminary, but in general, what we're thinking about is bringing a partner in to help us with the pipeline cost. And we'd be looking at something that would represent a payment over time as opposed to us incurring all the expense upfront. And so we think there is several parties that would be interested in doing that with us. And so that's actually the primary scenario.
Okay. And then I guess, just as you think about sort of the CapEx level, it looks like ex capitalized items or in other items, you had about $200 million of CapEx for the year with just barely, slightly declining production. I think you had mentioned in the past $275 million of maintenance CapEx or in that ballpark. So I'm just trying to get a sense of where that maintenance figure might be now? And what might be driving any potential changes, if there are any?
I think what we've said recently, Jacob, as we've thought about it and looked at that exact same question is that we're probably in this $300 million or somewhere north of $300 million is where that maintenance capital level goes. It's some -- it's a little bit hard to pin down because at any given year, of course, we have investments that generate returns in that year, like these exploitation wells. We have investments that generate returns years down the road, like at CCA. And then we have some in between, like what we're doing at Bell Creek. And so you're going to always have an overlapping of the term of when those investments make an impact. But when we've tried to boil it down and we look at where we've been with capital over the past few years as low as the low $200s million and then as high -- well, really as high as just in this range where we are in 2018, $300 million or a bit north of $300 million to me feels like the right ballpark. But again, we need to look at any given year and see how much of that capital is actually applied to production in that year and balance that.
Okay. And then I guess, just 1 last housekeeping question. I know you had mentioned that at the time the RBL draw to finance that acquisition, I guess, at the end of 2017. Would you be able to kind of pay that down with the Houston surface acreage sale? Just curious if there was any potential updates on that sale process. Is it going to be sold as sort of one big package? Or if you're thinking about breaking it up? Or just really any updates on that front?
Thanks for asking that, Jacob. And we wanted to update you on that process. And so as we've communicated last, we still feel very confident in the value of the acreage that we're selling. It's generated great interest, and we see that moving forward positively. At the same time, the complexity of selling such large positions is just causing it to take a bit more time than we expected. So to-date, we had sent about $5 million across to the other side. Recently, we signed contracts probably in the $9 million or $10 million range that we expect to close here in the next quarter or 2. And we're going to keep a pretty cautious look at 2019 of how much we think we'll achieve from that, and that's probably in the $10 million to $15 million range, with the bulk of the remaining sales to be outside of 2019. Like I said, it's just a work in progress. It's going to take some time to bring all of that across the finish line.
Your next question comes from the line of Eric Seeve from GoldenTree.
Jake just asked my questions, but can you just repeat the numbers you just said regarding the timing of the Houston land sale? Do you say you've signed contracts for an incremental roughly $10 million that could close the next few quarters? And what was the comment about the remainder of the year?
You bet, Eric. So right now, that's all we're saying for the remainder of the year. We, of course, are working it right now and more could come in the course of the year. We still believe the overall value is at least as great as we originally talked about. And it's just that we expect a good part of that to fall outside of 2019. So when we think about 2019, we're thinking of this $10 million to $15 million range for what we'll actually realize cash in hand. And as we continue to work the process, we'll see more in the coming time after 2019.
Your next question comes from the line of David Meats from Morningstar.
I just wanted to chime in and find out about the scope of the EOR in the Eagle Ford. I'm looking at your Slide #31. And it looks like you have kind of a range of CO2 applicability. And I'm just wondering the numbers you gave on the prior slide about the projected EOR increases. Does that apply to like a particular area here, like maybe where it's more applicable? Or is that just kind of an average over the position? And are all those 300 wells that you guys have identified, do they all -- are they all viable for the kind of development in the oil price environment that we're looking at?
So David, a couple of things. First, the 300 wells identified are across the Eagle Ford. So those are operated by other operators at this point. And they're in various areas. And we showed them on the prior slide that were in the purple dots across that Eagle Ford trend. So that's in an area where you just -- you see the viability of rich hydrocarbon gas. And that's all that's being currently used in the Eagle Ford for EOR. As you look at the slide that you referenced, as we move to the northwest, to the lower GOR, a more black oil window of the Eagle Ford, that's an area where we steadily see increasing promise for CO2, just because of the nature of the injectant and how we see that behaving. So that's what we're portraying there. But the 300 is across the Eagle Ford, and that's the amount of -- the number of wells that you see right now.
Okay. That's super interesting. And just one more from me on the CapEx. It just kind of stands out on the Slide 25, where you have the projections that we got, decreasing capital and increasing production in 2019 and not really the other years. And I guess that shifting the CCA cap going to 2020 is a big part of that. But can you just give some more color on the kind of the different directions of the capital and the production?
Okay. David, we're trying to catch up with you on Slide 27, you said?
Yes. 27. Basically, just in 2019, you've got decreasing capital versus 2018. It's all pro forma. And the production is going up. So obviously, diverging direction. It just kind of stands out a little bit. I'm guessing that that's mainly the CCA pipeline...
That's absolutely correct. It's just that shifting the bulk of that spend from 2019 into 2022.
Okay. And so were that not changing, we'd be looking at probably an extra $100 million to $150 million in '19?
Yes, yes. If we were spending it in '19, yes. And that's the way it was shown before in the previous model. That's correct.
And at this time, there are no further questions. Mr. Mayer, please continue.
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