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Ladies and gentlemen, thank you for standing by. Welcome to the Denbury Resources Second Quarter 2019 Results Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. And I would now like to turn the conference over to our host, Director of Investor Relations, Mr. John Mayer. Please go ahead.
Thank you, Jeff. 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; and David Sheppard, our Senior Vice President of Operations. 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, and thanks to all of you for joining us today. I'm pleased to announce that Denbury's second quarter of 2019 was truly outstanding. The team and I are looking forward to sharing details with you this morning. But before we do, I'd first like to talk a bit about the current macro environment. Specifically, I'd like to review how Denbury's strategy, assets and expertise align to counter many of the challenges facing the energy industry today.
When I step back and think about those challenges, I see 2 key themes emerging. The first centers on how energy companies will meet clear investor demands to operate sustainable businesses that can return capital to shareholders. The second involves the industry's ability to consistently provide a significant portion of the world's energy in a manner that addresses increasing environmental concerns around the production of fossil fuels. I can say with confidence that Denbury is ideally placed to meet these challenges. The company is in a strong position to meet shareholder demands for return of capital. Our long-lived, low-decline, low-capital intensity, higher-margin assets have provided us the flexibility under which we have been able to consistently and reliably generate free cash. We have subsequently used that free cash to optimize the balance sheet, reducing our debt commitments by over $1 billion since the end of 2014. We will continue to prioritize debt reduction through the use of free cash in the near future. At its core, our business involves the utilization of CO2 for enhanced oil recovery, injecting millions of tons of CO2 into our reservoirs every year. Over 3 million tons per year of that CO2 is currently captured from industrial sources that could otherwise have been admitted into the atmosphere. Putting that number in perspective, we're injecting the emissions equivalent of nearly 700,000 cars every year. As Denbury grows over time, we expect that number to increase significantly, with our major new development at Cedar Creek Anticline flooded with 100% industrial-sourced CO2. This oil recovery technique, using industrial-sourced CO2, provides the lowest carbon footprint from oil production in the industry. As the only U.S. public company at scale with CO2 EOR as a primary strategy, this places Denbury in a unique and beneficial position within the industry, particularly given that our growth plans are based around utilizing increasing levels of industrial-sourced CO2. Looking further into the future, I believe that carbon capture, transportation and secure geologic sequestration will become an essential business, and Denbury's assets and expertise position the company to be a leader as this market develops. Turning now to the quarter. Denbury's performance was outstanding by all measures, and I could not be more proud of the work accomplished by our teams across all facets of the business. Most importantly, we maintained safe working conditions for our employees and contractors and upheld our duties as stewards of the environment, driving our performance higher in all key HSE metrics. Total production was slightly up from the first quarter of 2019, supported by great results at Bell Creek where we reached a new EOR production record. This performance has given us the opportunity to increase the midpoint of our full year 2019 guidance range even after the midyear sale of our Citronelle Field and its associated production. I'm pleased to share that we accomplished these strong production results, all while maintaining our originally guided annual capital range. Importantly, we remain on track for the remainder of the year at the midpoint of that range. Operating costs across the business were significantly reduced in the quarter, and we now expect annual LOE to be in the lower half of our previously guided range. We further reduced our G&A levels, which are now around half of what they were as recently as a few years ago. We continued making progress towards our CCA enhanced oil recovery development, which is on track for field pipeline installation next year. We completed an initial test of a promising exploitation concept at Conroe. We've made good progress on noncore asset divestitures, selling Citronelle and contracting $38 million in incremental Houston area land sales. We executed a debt exchange that significantly reduced our near-term subordinated debt maturities without increasing interest expense. Our oil levered production with high Gulf Coast premium pricing exposure resulted in strong realizations of nearly $61 per BOE, high operating margins and $38 million in free cash flow generation. Finally, and importantly, we continue to make progress on our priority of reducing leverage, with total debt-to-EBITDA now reduced to just over 4.1x or 3.6x on a second quarter annualized basis. Over the next few slides, I'll review the quarter in more detail.
On Slide 8, we've updated our free cash flow projections based on actual results through the first half of 2019. Assuming $55 WTI for the remainder of the year, we forecast full year free cash flow of between $120 million and $150 million. In line with our priority of improving the balance sheet, we used $120 million in cash as part of our second quarter debt exchange, which we expect to be funded through current year free cash flow. These cash flow projections are enhanced by our strong hedge position, which protects about 70% of our 2019 production. Mark will share more detail on that shortly. Denbury's 97% oil weighting once again contributed a very strong operating margin. Our second quarter revenue per BOE was nearly $61, resulting in an operating margin of just under $33 per BOE. This high operating margin, combined with our low capital spend, supports the strong free cash flow that Denbury consistently delivers. Capital spending is exactly where we wanted at this point in the year. As planned, we made the bulk of our 2019 CCA CO2 pipeline pipe investment in the second quarter. By the end of the third quarter 2019, we expect all pipe will be completed and prepared for installation in 2020. Our key tertiary capital project at Heidelberg is substantially complete, and our Bell Creek Phase 6 project should be completed this quarter. Our primary capital plan for the second half of the year include the continuation of our Mission Canyon exploitation program; additional drilling in the Charles Formation; another well in Bell Creek, targeting an untapped accumulation in the Phase 1 through 4 area. With the completion of our major expenditures for the first half of the year, we expect capital to reduce in the second half and that total full year capital will be near the midpoint of our guidance range. I'm very pleased with the continued reliability and predictability of our production, with second quarter 2019 production slightly ahead of our previously guided expectations of being flat with the first quarter 2019. Production performance has been strong across the board, highlighted by record production levels at Bell Creek, and I'll go into more detail on our work there shortly. As we discussed in the first quarter call, we expect third quarter production to be lower than the second quarter, mainly due to an extended period of planned maintenance at our primary north region CO2 source as well as seasonal temperature effects in the Gulf Coast. However, we expect fourth quarter production to rebound primarily driven by response from our Heidelberg redevelopment, completion of the north region CO2 supply maintenance and the impact of new exploitation wells to be drilled throughout the third and fourth quarters. We've maintained the focus on continuing to optimize our portfolio, and as a result, sold the noncore Citronelle Field in Alabama at the beginning of the third quarter. This field was producing about 400 net barrels per day at the time of the sale. Considering our strong production performance so far this year, we're increasing midpoint of our guidance range by 250 BOE per day, after accounting for divested Citronelle production for the second half of the year. And we're also tightening the guidance range to 57,000 to 59,500 BOE per day. I'm excited to say the performance at Bell Creek just keeps getting better. The second quarter 2019 production of nearly 6,000 barrels per day made it the company's highest producing EOR field. As we expected, Phase 5 performance has been the best of any phase completed to date, and we have now substantially completed the development of Phase 6, which has similar characteristics to Phase 5 spending up additional field production growth in 2020. The Gulf Creek team has also looked back at the initial development phases of the field, and by using high-resolution seismic imaging, has identified untapped incremental oil accumulations, one of which we drilled in the first quarter. That well has been a strong producer at around 500 barrels of oil per day, and we've identified a handful of additional similar opportunities that we plan to begin testing later this year and into 2020. Our operating teams made excellent progress in reducing costs in the second quarter. Unit costs were lower than anticipated at $21.70 per BOE, about 8% below the first quarter level. The key improvements were realized in CO2, power and fuel and workovers, which are based on value-adding, sustainable LOE management strategies. CO2 costs have benefited from ongoing utilization optimization in several fields, along with an improved tariff structure in the Rockies. We negotiated electricity demand charges in several fields, lower natural fuel gas -- gas fuel prices and fewer well failures in the Gulf Coast are also pushing cost lower. Given the momentum of our per BOE cost reductions, we expect that our full year 2019 LOE will fall in the lower half of the previously guided LOE range of $22 to $24 per BOE. During the second quarter, we tested our first horizontal well in the Conroe Field. We're pleased with the initial results of this test well, with the high oil cut at around 50% and a peak production rate of over 200 BOE per day. We next plan to drill a second well in an adjacent fault block that considers learnings from the first well. It's likely that the second well will be drilled in 2020. As I previously mentioned, we believe that this exploitation concept can be applied across many of our Gulf Coast fields, and our teams are conducting the technical work to prepare for next steps in this player. At Tinsley, we tested the Cotton Valley interval of our recently drilled exploitation well. While we're pleased to achieve a 2.5 million cubic feet per day gas rate and a high liquid yield of 100 barrels of oil per day, these test results, coupled with current commodity prices, would make a standalone lower Cotton Valley development fall below our investment threshold. We are working plans to test the identified uphole pay intervals, which we believe to be higher in liquid content. Once we've completed those plans and tests, we'll determine the next best steps, which could include self-development or potentially farming out the discovery to a third party. In late August, we plan to resume exploitation drilling at CCA. Over the past 2 years, our exploitation investments at CCA have proven very successful with strong production and outstanding economics. Later this year, we plan to drill 2 new Mission Canyon wells, one in Cabin Creek and another in Coral Creek as well as new Charles B well, also in Carbon Creek. We are intrigued by the performance of the initial Charles B well. While its initial oil rate was lower than a typical Mission Canyon well, its sustained high oil cut makes the horizon a good candidate for both water and CO2 flooding. Moving to our divestment program. We made good progress on monetizing noncore assets in the second quarter. Starting with our Houston area property sales, we now have an additional $38 million in multiple parcels at Conroe and Webster under firm contract, with closing structures that result in the receipt of proceeds in 2019 through 2022. This brings our total sold or under contract to a total of $53 million to date, with significant remaining value on the property still being marketed. Also as I mentioned earlier, on July 1, we divested off our noncore Citronelle Field for $10 million in cash and the elimination of an abandonment obligation estimated at about $40 million or $9 million when discounted to today's dollars. This field was expected to produce an average of 400 net barrels per day in 2019. However, we considered that noncore, both due to its higher operating cost and our technical and economic analysis, that it was not a good candidate for a CO2 flood. We'll continue to evaluate the remaining mature properties for sale or retention and will proceed in a manner that generates the greatest value for the company and our shareholders. In summary, I'm thrilled with our performance so far this year. Our business at Denbury continues to outperform, our assets are located in the right basins to optimize our unique CO2 EOR techniques and our teams across the company are highly skilled and experienced. And importantly, we remain focused on the challenges that lie ahead, with Denbury's unique capability to not only meet those challenges, but to benefit from them. Next, I'll turn it over to Mark for a 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 first quarter of 2019. I'll also provide some forward-looking guidance to help you in updating the financial models. Starting on Slide 18. Second quarter 2019 adjusted net income was $59 million or $0.13 per diluted share, ahead of analyst expectations and a nice improvement from first quarter earnings. This quarter, we recognized a noncash gain on debt extinguishment related to our debt exchange transactions of $100 million and noncash income of $26 million for fair value changes and commodity derivatives. We were the primary -- these were the primary differences from our GAAP net income. Please note that in computing diluted income per share going forward, interest on the convertible notes will be added back to net income and the potential shares to be issued upon conversion will be added to the shares outstanding. More detail on that calculation is included in our press release. Turning to Slide 19. Our non-GAAP adjusted cash flow from operations, which excludes working capital changes, was $145 million for the second quarter, our highest level of adjusted cash flow since the third quarter of 2015. Adjusted cash flow was up $26 million from the first quarter of 2019, driven primarily by higher oil prices and lower lease operating expenses.
We generated free cash flow of $38 million in the second quarter after considering $22 million of interest that is included as repayment of debt in our financial statements, $77 million of development capital incurred and $8 million of capitalized interest. On second quarter, average realized oil price before hedges was approximately $62 per barrel, a 10% increase from our realized price in the first quarter. We paid approximately $2 million on hedge settlements this quarter as compared to receiving $8 million in settlements of last quarter, making our average realized price per barrel, including hedges, 7% higher than last quarter. Slide 20 provides a summary of our oil price differentials, excluding any impact from hedges. For the seventh consecutive quarter, our realized oil price was higher than NYMEX prices, averaging $2.35 above NYMEX, our highest level since the second quarter of 2013. The premium prices we received for our Gulf Coast production strengthened from the first quarter, and in the Rockies, our differential also continued to improve from the levels realized last quarter. For the third quarter, we expect that our overall oil differential remain positive to NYMEX, but lower than the levels realized in the second quarter due to the weakening of the LLS differential in the Gulf Coast region and moderately lower differentials in the Rockies region. We currently estimate that our overall Q3 NYMEX differential will be in the range of flat to NYMEX to $1 above NYMEX prices. On Slide 21, we review some of our expense line items. Since Chris already addressed LOE, I'll start with G&A. Our G&A expense was $18 million for the second quarter, down about $1 million from last quarter. Our G&A related to stock-based compensation was approximately $4 million this quarter, and we expect G&A expense will generally be in the upper teens to $20 million range per quarter for the remainder of 2019, with stock-based compensation anticipated to represent roughly $4 million per quarter. Net interest expense was $20 million this quarter, an increase of about $3 million over last quarter primarily due to lower capitalized interest. On the bottom portion of the slide, you will see there is a detailed breakout of the components of interest expense and you will note cash interest remained steady. Capitalized interest was approximately $8 million for the second quarter, and we currently expect our capitalized interest to be in the $7 million to $9 million range for the third quarter of 2019. In connection with the recent notes exchange transactions, the new second lien notes and convertible notes issued were recorded on our balance sheet at a total discount of approximately $110 million to their principal amounts. These debt discounts will be amortized as interest expense over the terms of the notes. Therefore, future interest expense reflected in our income statement will be higher than the actual interest payments for the new notes by approximately $4 million per quarter for 2019 and 2020 and $5 million per quarter in 2021. Our depletion and depreciation expense this quarter was $58 million, a slight increase from the prior quarter. We expect this expense will increase somewhat and will be in the $60 million range for the remaining quarters of 2019. The next slide provides a current summary of our oil price hedges. The remainder of 2019 is protected with hedges covering around 70% of the midpoint of our 2019 estimated production range, including weighted average price floors of roughly $57 for WTI and $64 for LLS per barrel. Since our first quarter conference call, we have continued to layer in hedges for 2020, and now have more than 22,000 barrels of oil per day hedged for the year or roughly 40% of the midpoint of our 2019 estimated production range. For 2020, our hedges have weighted average floor prices approaching $59 for WTI and $63 for LLS. And similar to 2019, over 2/3 of our contracts provide for upside exposure of close to $66 for WTI and $72 for LLS. We plan to continue to add to our 2020 hedges as we deem appropriate and depending on market conditions. During June and July, we completed a series of debt exchanges that reduced the principal balance of our subordinated notes by $120 million and extended maturities on debt principal of $348 million to 2024. The details of the exchanges are shown in the lower right portion of this slide. But in summary, we exchanged a total of $468 million of existing subordinated notes for $103 million of new 7.75% senior secured second lien notes due 2024. $246 million of new 6.375% convertible senior notes due 2024 and $120 million of cash. In addition, in order to create a more liquid issue of secured debt due in 2024, we also exchanged $429 million of our previously outstanding 7.5% senior secured second lien notes due 2024 for roughly the same amount of 7.75% senior secured second lien notes also due 2024. We ended the second quarter with $80 million drawn on our $615 million bank line, giving us $480 million of liquidity after considering outstanding letters of credit. Our debt principal is just under $2.5 billion, which is right around a $1.1 billion principal reduction over the last 4.5 years. Based on current 2019 projection, using recent oil prices, we expect to generate sufficient free cash to pay down the $80 million on our bank line by the end of 2019. Our last slide shows the improvement in our leverage metrics over the past year. Our trailing 12 months debt-to-EBITDAX ratio has improved to 4.1x, a half turn better than the comparable metric a year ago. And if you exclude hedging impacts, our trailing 12-month ratio would be 3.6x. We are pleased with the steady progress we have made with our leverage metrics. And based on recent price features, we would expect our leverage ratio to continue to hold around 4x or possibly slightly lower throughout 2019. We also want to highlight the strong coverage ratio we have when measuring PV-10 value of our oil and gas reserves against our debt principal. Note that we -- the PV-10 we are using here is our year-end 2018 SEC proved reserves, which is over 80% proved developed producing. Reducing our leverage and improving our debt maturity profile remain top priorities. We are pleased with the results of the recent debt exchange transactions, which largely address near-term subordinated debt maturities. Although bond market conditions are challenging at the current time, we plan to continue our disciplined focus while seeking opportunities to further reduce our leverage and extend maturities of our second lien debt well in front of the first maturities in 2021. In the back half of 2019, we also plan to evaluate options for funding all of our portion of our TCA CO2 pipeline, which can include a JV structure with our entire CO2 pipeline system in the Rockies. We are also continuing to progress sales of noncore assets such as our nonproductive acreage positions, and believe we are close to signing additional contracts that will further highlight that potential value. And now I'll turn it back to John for some closing comments.
Thank you, Mark. That concludes our prepared remarks. Jeff, can you please open the call up for questions?
[Operator Instructions] Our first question comes from the line of Charles Meade with Jason Rice (sic) [ Johnson Rice ].
There's a lot of question you guys have given us a lot to chew on and you've made some -- a lot of -- pulled up a lot of good points in this last quarter. But I'm just going to pick 2 real quick. One, could you talk about what your CO2 CapEx is going to look like, using kind of 2Q '19 as a baseline? What's it going to look like for quarter in the back half of this year? And then I know there's a big kind of decision point about how you financed the CCA pipeline. But assuming that you don't have any kind of outside partner there, what would be -- what would the gross CapEx per quarter look like in '20?
You bet, Charles. So take the first question first. I'll just look in our CO2 CapEx for 2019. The vast majority of what you see there is the CCA pipeline and the procurement and coding of the line pipe this year. And the bulk of that, which I believe we're looking at about $30 million, the bulk of that, over $20 million, has already been incurred through the first half of this year. So you'd see that weighted disproportionately towards the front of the year with the remainder to be spent in the final 2 quarters of the year. We're not really at a point to give the quarterly guidance for how we'd see 2020 shape up, but again, the bulk of the investment you'd see around that in 2020 would be the installation of the pipe. And so that's about $100 million line item that we'd see taking place over the course of the year. And then of course, the great question that you added in there is, how does that fit into how we'd set up our capital for next year. And for that, I'd dial back a bit and just have -- ask you to take a look at this year and how our operations have performed, and how -- what I see is our team's doing a great job at holding our production close to flat at an ever reducing level of capital. If I peel that $30 million of CCA pipeline capital out, we're spending about $220 million, let's say, on maintenance capital this year and holding production close to flat. We're committed to driving free cash and living within cash flow. As we approach 2020, you'll see the same thing. And of course, we're going to have to see where prices are at that point to decide how to allocate capital. But as we look at our 2 key commitments here, one is to live within cash flow; the other is to progress this great CCA project, which built to us as very strong at $50 oil. The interest that we've had from the outside in terms of helping fund that in various ways is very high. And we're going to continue to work that through the remainder of this year and look at just what is that best option there. As we've said before, we're open to funding it ourselves depending on cash flow, but we're also open to bringing in some outside money. And that's just a decision we're going to have to take as we get closer to the end of the year and see how prices start to shake out.
Got it. Got it. That's helpful, Chris. And then if I could ask about the Conroe 2A, the 2A test. Can you talk about how that came in versus your [ previewed ] range of possible or expected outcomes? And about -- maybe as part of that calibrate, what should we be looking for as you try the next fault block over?
Charles, this is Matt Dahan. I'll take that one. The well came in just slightly under what -- kind of our midpoint of our expectations were, mainly due to a little bit lower reservoir pressures than anticipated. But extremely pleased with the oil cut and as we look at taking those lessons to the next fault block, targeting some intervals with higher pressure, a little bit higher-quality rock and maybe a little bit -- slightly different completion technique. So we expect next year to drill that well and look for some better results than on the first one.
Our next question comes from the line of Jason Wangler with Imperial Cap.
The operating cost reductions looks pretty significant obviously you kind of highlighted -- pointed to the lower end of the guidance in the back half of this year and for the rest of the year. Can you just talk about kind of what you were seeing there, what were you able to take advantage of?
Yes. Jason, this is David Shepard. I'll take that question. Good morning to you. Yes. We've made some significant progress and sustainable LOE, kind of cost reductions. I would say it's really centered around several things. From a power fuel perspective, we always look at electricity. We have taken the benefit of renegotiating some of our demand charge contracts. So we'll see that continue to come into the mix here for years to come. In the Rockies too as well, we've renegotiated a better tariff strategy too as well for our CO2 supply there. So we'll see that same -- similar benefit over a very long period of time. From a well sort of perspective failure rate, that's something we always look to improve. We did see the benefit here in the second quarter of some lower kind of workover numbers primarily associated in the Gulf Coast too as well. I see that probably ticking up just a little bit in the third quarter. And from what we see compared to the second quarter just because we have some known failures. But I think that will -- I'm certain that will be a sustained reduction over a period of time. I'd say that we have some other projects in the works too as well. We're just looking at our systems, our processes, our chemicals, our management tool as well. So there is more to come in this particular area.
Okay. That's helpful. And then maybe, Chris, for you, just on the exploitation program. As you think about going into the next year and having some more significant CapEx, is that still going to be a pretty meaningful portion of your spend? Or how do you kind of think about that as you look to next year?
You bet, Jason. And I'd say, our priority next year is going to still stay very focused on working the balance sheet and driving CCA forward. So that's what we're going to look at first. Obviously, we love our exploitation program. The successes we've had have been powerful and have done some very nice things for us, in particular, up in CCA there. And that's why we're continuing into the latter half of this year with more activities there. Real question, though, as you start to look into 2020 and look at where we want to allocate capital, that's one that we're going to -- again, as I told Charles, we're going to get to closer to the year, see how capital is shaping up, see how prices are shaping up and decide where to go. We're also looking at some alternatives where we may be able to bring in some outside participation to help progress that along in a way that's attractive to Denbury and its shareholders. Keep all those options open as we go into the second half of this year here.
Our next question comes from the line of Michael Scialla with Stifel.
I wanted to see if you could talk about your ability to pay down additional debt with free cash flow. Mark, you said you could pay down the bank line with the free cash flow you're projecting for the second half of this year? If you were to do that, what would be the plan for free cash flow next year? Can you attack any of the longer-term debt or what you would do there? And where do you see debt-to-EBITDA going next year based on strip prices?
Yes. I think -- so we do have some limitations, we -- work around. So obviously, we use $120 million here to pay down some debt, and in the exchange, we have roughly $28 million remaining under the bank line in terms of additional capacity, under a basket to pay down debt and potentially more under certain scenarios with coverage ratios and deleveraging aspects that could be in this -- an additional $76 million. So obviously, those are baskets we set quite a while ago. And I think they can always be revisited but those are kind of the parameters that are in place today. I would say obviously we have the sub-debt maturities in '21 and '22, I think down to pretty moderate to reasonable levels. Our focus as we look at things, really, kind of turns to second lien and we'd like to work on extending that debt is our desired situation. Obviously, the debt markets are a bit challenged right now and -- but you don't have to do anything right today. But that's where our thoughts turn. And there could be some opportunities obviously where debt is trading to take advantage of lower prices and discounts. But obviously, we have to balance that with liquidity. Liquidity is very important, just where prices are going, managing cash. And so we will take all that into consideration, just as we have done in the past. If you look back over the last 4.5, 5 years, living through this pretty volatile oil price environment, I think we've been able to manage through pretty good and we plan to continue to do the same. So yes, we want to continue to reduce leverage and we'll continue to look at the company's best options for doing that, depending on market conditions and where we are at any point in time.
And Mike, this is Chris. Just what I'd add to what Mark just said is, even going back to the question of whether we fund the CCA pipeline internally or externally, how we look at attacking the debt will play a part in that as well, and if we can see some benefits to funding the pipeline externally and attacking debt with the money that we would otherwise have spent. But that's something that we'll look at strongly.
Yes.
Yes. Obviously, a lot of moving parts there. Do you -- given all that, do you have any projections on where you think debt-to-EBITDA could go next year?
I would say, for the rest of the year, we kind of see that holding in relatively stabilized. I think if we -- it really just depends on where the oil price environment goes to. Mike, as you know, where we've been at various oil price, I think if you look at the slide that we show in the -- on the slideshow there, it kind of give some relativity in terms of where we've been looking back a year ago through last 12 months at various oil prices, where we are today. Obviously, if prices trend lower, it could tick up somewhat, and just to remind that roughly a $5 move in oil price is about $100 million of EBITDA, and -- so the unhedged. So we do have hedges in place next year that will protect us upon decent level at this point in time. But obviously, we'd like to continue to expand that. But if prices stay where the script is today, then it would likely trend up a little bit. But I don't think it goes crazy, Mike. It's between the -- slightly higher where we are today, between 4 to 4.5 range.
Okay. Got it. And then other question, you had obviously a nice response from Bell Creek. Was all of that due to the better rock quality? Or did you do anything different with Phase 5? And I guess how do you see the trajectory from that field over the remainder of the year? Is it a rollover before Phase 6 kicks in? Or did you see some more growth out of Phase 5?
Yes, Michael, this is Matt Dahan. So production increase, certainly Phase 5 has performed fabulous. This is one of the reasons we love this business. You can take a field that makes virtually nothing and now we're over 25,000 barrels a day in that phase alone. It is the best quality between phases 5 and 6 in the field. If you remember, this field was developed -- or this section was developed a little bit differently and that the spacing is wider, taking advantage of that higher-quality rock, reducing the CapEx to recover those reserves. We couple that with the Phase 4 well that we drilled. So Chris pointed out, taking advantage of our seismic, identified an area that was basically untapped. We precisely placed the well, over 500 barrels a day. We'll continue to see that well increase its CO2 response going forward.
Great. And is that seismic have any application to any other fields, maybe in terms of CCA as you go forward with that?
Oh, very much so. I mean we use seismic in the Gulf Coast. For the same reasons, understand where the CO2 is, and more importantly, where it hasn't gone and then make adjustments to the field performance. We have shot seismic in CCA, we'll continue to look at that going forward as we begin injection.
And our next question comes from the line of Richard Tullis with Capital One Securities.
Mark and Chris, if you could maybe provide a little more detail on how you're thinking the structure could kind of come together for a potential JV related to pipeline funding?
Sure. This is Mark. As you know, we have existing Greencore line in the Rockies that we transport CO2 through today to Bell Creek. We have the planned line going up to CCA. So if we wanted to -- one option, as we've kind of talked about before, put that all together as one system and have a joint venture partner, maybe 50-50 or something. Around that, we would contribute the existing line, the partner could fund the portion, $150 million-or-so for the CCA line, and we would go forward in joint ownership of that structure. Obviously, one thing we're focused on is we don't want to add more debt and so structure is important. But that is one potential opportunity or avenue that we see.
And Chris, in your opening remarks, you talked about -- and also in the release itself, talked about the changing landscape and what opportunities that presents to Denbury, given its long history of enhanced oil recovery, tertiary operations. As you look over the next several years, how do you envision Denbury evolving? Do those opportunities perhaps result in Denbury contracting out its expertise in those areas for a fee or in equity position or the projects? Or just, what are some of the potential options there?
Sure, Richard. I see tremendous opportunities for Denbury in this future. The changes that we feel and that I see in the world and in the industry are strong. And it's ironic, with so much noise out there, even in the day like today, for example, I would rather be Denbury than any other company because the nature of what we do so perfectly aligns with this drive to reduce carbon emissions. When we look at how CO2 EOR extracts oil, that technique being substantially better than any other oil recovery technique that's out there, and we are focused primarily on that technique. You have to feel good about where you sit in that role. And as I mentioned in my prepared remarks, as we go more towards using industrial-sourced CO2, where you're truly taking CO2 that would otherwise be emitted into the atmosphere and injecting it, that's a very strong move that supports this combination of providing energy that the world needs in the lowest carbon footprint way possible. So I feel great about that. Now where that goes? It can go in many different directions. Number one, it can be just more of what we're already doing in conventional fields, like you see in CCA. I think it can expand with EOR in other areas like shale, as we've talked about in the past. I think that it can -- the same skill sets that we have and use can be applied to transportation and other geologic sequestration of CO2. That's a skill set that I think Denbury has. To your question of whether we contracted out, that's a whole another way of thinking about approaching the business, and I'd obviously say we're not close to anything. I think the skills that we have just have a great opportunity that will open in the future.
Our next question comes from the line of Joe Beninati with Oppenheimer.
It's Joe on for Tim here. So if I could ask on the asset sale front, you guys have a pretty productive quarter in -- on the Houston land sales and obviously, the prices for those in the future would be TBD. But just kind of qualitatively, how far along in the process are you -- is that 50% of the way or just try to get a sense of what could potentially be going down the pipe in the future?
I think, Joe, you actually just nailed it that when we -- what I think about where we are in the process and we're happy with the results that we're able to report this quarter. But when I think about where we are in the process, I'd say we are about 50% through. We still have an awful lot of value out there that we're working through right now, and so there's still plenty of potential to come as far as I see in those asset sales.
Our next question comes from the line of Sean Sneeden with Guggenheim.
Mark, maybe just a follow-up on the prior debt question. But could you remind us, are there restrictions on your ability to repurchase any of the second liens at a discount at this point?
None that are coming into mind, Sean. I'd have to check just to make sure, but nothing's popping in my head right after that.
Got it. So it's only the unsecured bonds you have that kind of your firm basket in that sense. Is that right?
Yes, like I said, we'd have to double-check a couple of things there, but there may -- I think there is some difference between the -- so most of the focus obviously over the last several years has been around the subs. But -- so we need to check that, but I do think we have a little bit more flexibility there.
Understood. And then could you just remind us what you think you're kind of remaining secured debt capacity is now that you got the exchange at the end of the quarter?
Well. So yes. So we did -- we had $1.65 billion of basically junior lien debt, that's permitted under our facility. And so we've issued all, but just a little bit of that, I guess. So we've used most of that, that can -- that's what's available or what was permitted under the bank line. That can be reviewed and moved around based on ACNTA. But that's what we have remaining today.
Got it. That makes sense. And then Chris, I know you mentioned potentially bringing a partner and I think a lot of discussion was specifically around the pipe for CCA. But would you look at or entertain your partners on the development side for CCA, just given how big of any opportunity set it's for you?
You bet, Sean. I go back to Mark's comments earlier and just how our structure is set up, and one thing you'll find in the capital structure of the company and the various different agreements that we have is that we have a simplicity that allows us to do many different things. And so one of those is financing the pipeline, as we talked about. But I also think that as we look at how that could extend and how much more broad that could be, the possibility of participating in the development is something that is out there. I mean it's something that we're very proud of, and we'd want to take a hard look at that. But honestly, we just -- at this point in the development, we're going to be looking at different options and that's one that I think we consider as well.
Got it. That makes sense. And I would assume that potentially you could look at even overriding royalty or other kind of options that some folks in the market have done recently?
Yes. So that's why I actually started my answer by referencing the simplicity of the structure. After those recent industry moves to the overrides, we've taken a few inbounds on that. And that's another option that we see out there as well.
And there are currently no other questions in the queue. And I'd like to turn it back over to Mr. Mayer.
Thank you, Jeff. Before you go, let me cover a few housekeeping items. On the conference front, we will be attending EnerCom's The Oil & Gas Conference next week on Wednesday -- on Tuesday, August 13. The details for the conference and webcast for the related presentation will be accessible through the Investor Relations section of our website at a later date. Finally, for your calendars, we currently plan to report our third quarter 2019 results on Thursday, November 7, and hold our conference call that day at 10 a.m. Central. Thanks again for joining us on today's call.
Ladies and gentlemen, that does conclude our conference call for today. Thank you for your participation and using AT&T Executive Teleconferencing. You may now disconnect.