© 2024 Alpha Spread Limited. All Rights Reserved.
www.alphaspread.com is not operated by a broker, a dealer, or a registered investment adviser. Under no circumstances does any information posted on www.alphaspread.com represent a recommendation to buy or sell a security. The information on this site, and in its related newsletters, is not intended to be, nor does it constitute, investment advice or recommendations. The information on this site is in no way guaranteed for completeness, accuracy or in any other way. In no event shall Alpha Spread Limited be liable to any member, guest or third party for any damages of any kind arising out of the use of any content or other material published or available on www.alphaspread.com, or relating to the use of, or inability to use, www.alphaspread.com or any content, including, without limitation, any investment losses, lost profits, lost opportunity, special, incidental, indirect, consequential or punitive damages. Past performance is a poor indicator of future performance.
This means that the stock is removed from a stock exchange and can no longer be traded.
Delisting typically occurs when a stock no longer meets exchange requirements. Other reasons for delisting may include legal violations, bankruptcy, a decrease in the number of shareholders, and acquisition by another company.
You don't have any saved screeners yet
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Greetings. Welcome to the Denbury Resources Third Quarter 2019 Results Conference Call. [Operator Instructions] Please note this conference is being recorded. I will now turn the conference over to your host, John Mayer, Director of Investor Relations. Thank you. You may begin.
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; David Sheppard, our Senior Vice President of Operations; and Matthew Dahan, our Senior Vice President of Business Development and Technology. 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 this 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. Good morning, everyone, and thank you for joining us today. In my comments this morning, I'll start with an overview of the quarter, then hand the call over to David, who will discuss our operations and finally to Mark, to walk through our financial results. Denbury's third quarter results once again demonstrate our commitment to execution, cost efficiency and capital discipline. Our key safety metrics are at all-time record low levels. Our capital program is delivering strong results with our successful recent projects at Bell Creek and Heidelberg highlighting both the technical quality of our teams as well as our consistent ability to execute capital projects on time and on budget. We made steady progress on our key greenfield EOR project at Cedar Creek Anticline and remain on schedule for the CO2 pipeline installation next year and commencement of CO2 injection in early 2021. As a result of this great execution, we're on track to meet the midpoint of our previously raised production guidance, even after incurring unexpected weather downtime in the third quarter from Tropical Storm Imelda. We expect to complete the year at or below the midpoint of guidance for every cost category, including LOE, capital and G&A, highlighting our commitment to cost efficiency and capital allocation discipline. We also continue to make great progress on the balance sheet. The recent exchanges that Mark will tell you about later in the call helped us reduce our debt by nearly $90 million, continuing a strikingly effective effort that has now reduced our total debt by $1.2 billion since the end of 2014 and reaffirmed my great confidence in our ability to continue to reduce debt to our target levels. As you've seen with recent industry natural gas and NGL realizations, there are vast differences in value in the components of a BOE. Our 97% oil-weighting once again contributed to a very strong operating margin. Our second quarter revenue per BOE was over $56, resulting in an operating margin of nearly $28 per BOE, or roughly 50% of revenue. This high operating margin, combined with our low capital spend, supports the strong free cash flow that Denbury consistently delivers. Our ability to consistently generate free cash flow is one of Denbury's most positive and distinguishing characteristics. We generated $44 million of free cash flow in the third quarter and we're on track to achieving $140 million to $150 million of free cash for the full year. This is not unusual, as over the past 5 years Denbury will have generated over $600 million in free cash flow. The nature of Denbury's assets and how we run our business make for a great fit in today's environment where investors are demanding capital discipline and greater returns. Before I hand the call over to David, I want to emphasize how fundamentally different Denbury is from the rest of the industry, well beyond the ability to consistently generate free cash. As the only U.S. public company of scale where injecting CO2 into the ground to produce oil is our primary business, we are a key part of the solution to reducing atmospheric CO2 emissions, while at the same time providing a vital energy source for the world's economy. This is a solution that has broad appeal and I see great opportunities to expand our impact in the coming years. As I've mentioned in the past, and expect to continue to highlight in the future, I believe that carbon capture, transportation and secure geologic storage will become an essential business and Denbury's assets and expertise position the company to be a leader as this market develops. In summary, I'm very excited about where this unique company is headed. We continue to perform safely, to consistently deliver on our promises to deploy our differentiated CO2 EOR focused strategy, and every day to make steady progress towards securing our long-term success. Now I'll pass the call over to David for an update on Denbury's operations. David?
Thank you, Chris, and good morning, everyone. Disciplined capital spending during the third quarter has kept us right on track to deliver full year capital expenditure at or below the midpoint of our 2019 guidance with approximately 76% of our 2019 capital budget deployed at the close of the third quarter. At Bell Creek, our Phase 6 development was completed during the quarter with production response expected in the first quarter of 2020. In our Gulf Coast region, the Heidelberg Christmas Yellow and Brown redevelopment project was completed in the quarter and is responding in line with forecast. Rolling and coating in the pipe for the CCA CO2 pipeline has been completed and a pipe has been placed in storage awaiting installation in 2020. We recently drilled 2 successful wells as part of the Mission Canyon program at CCA and continue to evaluate additional exploitation opportunities across our portfolio, which I'll discuss in more detail shortly. Turning to Slide 12, aside from the impact from Tropical Storm Imelda, third quarter production was in line with our expectations. Despite the impact from the Tropical Storm Imelda, full year production continues on track close to the midpoint of our guidance range. As we mentioned on our second quarter call, we anticipated an extended period of plant maintenance at our primary north region CO2 source, which significantly impacted quarterly production at Bell Creek. The maintenance period was conducted over a period of about 6 weeks, during which time no CO2 volumes were provided to the field. We estimate the resulting impact of quarterly production at Bell Creek approached 1,000 barrels per day. Following this maintenance period, CO2 purchase has resumed and we are pleased to see production coming back nicely with current rates reaching the same levels as those seen prior to the CO2 supply interruption. Further, and as previously disclosed, our producing fields around the Houston area, predominantly [indiscernible] and Conroe, experienced power outages and flooding associated with the Tropical Storm Imelda during September. The total impact of the storm on third quarter production was approximately 400 BOE per day, at the lower end of our previously guided range, as power was restored more quickly than expected at the fields. No significant damage occurred at any of our fields and near full production was restored by the end of the third quarter. We expect fourth quarter volumes to rebound from the third quarter levels, primarily driven by continued response from the Heidelberg redevelopment, restoration of full Bell Creek production following completion on the north region CO2 supply maintenance and resuming the Mission Canyon exploitation program. Based on current expectations, we continue to forecast our full year 2019 production close to the midpoint of our previously increased guidance range of 57,000 to 59,500 BOE per day. Lease operating expenses during the third quarter remain consistent with the prior quarter at $118 million, with a slight increase on a per BOE basis due to change in production volumes during the quarter. [ CO2 calls ] were down in the quarter due to the maintenance period at our primary north region CO2 source, but were offset by minor increases in other categories. Our ongoing cost management strategies continue to provide reliable predictable spin levels and we continue to expect that full year 2019 LOE will fall in the lower half of the previously guided LOE range of $22 to $24 per BOE. As we begin to look towards 2020, we are focusing on sustainable improvements that will continue to drop cost out of our production operations. I will share more in the coming quarters as we implement new technologies and systems that we expect to increase efficiency and reduce cost. Turning your attention to Slide 14. Third quarter 2019 net tertiary production at Bell Creek field was around 4,700 barrels per day, down from the record levels in the second quarter, primarily due to the north region CO2 source maintenance I previously mentioned. Since CO2 purchase resumed at Bell Creek, production has recovered to prior peak rates. Production growth is expected to continue at a modest rate through 2020 as Phase 6 begins to respond in the first quarter of the year. During the fourth quarter, we plan to drill a second well in Bell Creek targeting untapped accumulations in a previously completed phase of the development. This well would be a follow on to the very successful well we drilled in Phase 4 earlier this year as highlighted in last quarter's call. In the third quarter, we drilled 2 additional exploitation wells in the Mission Canyon formation at Cedar Creek Anticline, one in Cabin Creek and the other in Coral Creek. Both wells have been completed, the first in late September and the latter coming online mid-October. Combined, the wells have an estimated IP of 1,000 barrels per day. To date we have drilled a total of 12 horizontal wells within the Mission Canyon, achieving greater than a 90% rate of return for the total program. This program is a great example of the value that can be generated from within Denbury's asset base through combining the expertise of our teams with today's great technology. Continuing to progress our plans for Charles B development, our full core of the Charles horizon was taken while drilling the previously mentioned Cabin Creek Mission Canyon well. We have also recompleted and tested 3 vertical wells in the Charles B benches. The core and all 3 vertical tests provided valuable information that will enhance our development plan improve -- and improve project economics. During last quarter's call we had discussed plans to drill a Charles B dual lateral well late in 2019, but decided to defer that project while we incorporate the results from the core analysis and other test. My final slide outlines our recent redevelopment of the Heidelberg field in the Christmas Yellow and Brown horizons. Similar to our previous Frio [ BC ] project at Hastings Field, the redevelopment project in Heidelberg used field-specific learnings to optimize recovery through a series of new wells and workovers of existing wells. Although similar in some ways to the Hastings project, this redevelopment is different in that we utilize a top-down injection approach versus the Hastings bottom to top process. The project is expected to be highly economic even at $50 oil prices. The development work has been completed and we are seeing production response in line with our forecast. Current production rates from the project are around 800 net barrels per day and we expect to exceed 1,000 barrels per day by the year-end. Next, I'll turn it over to Mark for a financial update.
Thank you, David. My comments today will highlight some of the financial items in our release, primarily focusing on the sequential changes from the second quarter of 2019. I will also provide some forward-looking guidance for the fourth quarter and full year 2019 to help you in updating your financial models. Starting on Slide 18, third quarter 2019 adjusted net income was $41 million or $0.08 per diluted share, slightly better than analysts' expectations. This quarter's $35 million of noncash income from fair value changes in commodity derivatives was the largest difference between adjusted and GAAP net income. Diluted earnings per share this quarter reflects the full impact of our convertible notes issued in June whereby the shares to be issued upon full conversion are added to the shares outstanding, and the interest expense on the convertible notes net of taxes is added back to net income. More detail on this 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 $126 million for the third quarter, down $19 million from last quarter, driven primarily by lower realized oil prices in production. We generated free cash flow of $44 million in the third quarter after considering $21 million of interest that is included as repayment of debt in our financial statements and $60 million of combined development capital and capitalized interest. With $109 million of free cash flow year-to-date, we are well positioned to achieve our expected $140 million to $150 million of free cash flow during 2019. Our third quarter average realized oil price of $59 per barrel after hedges was down 4% from our realized price in the second quarter as oil prices and differentials weakened from last quarter. Slide 20 provides a summary of our oil price differentials, excluding any impact from hedges. Our realized oil price average $1.30 per barrel above NYMEX prices this quarter, which is down a little more than $1 per barrel from last quarter, but slightly higher than the guidance we provided in expectation of weaker differentials in both our Gulf Coast and Rockies production. Looking ahead to the fourth quarter, we expect that our overall oil differential will decline from the levels realized in the third quarter due to further weakening of the LLS differential and moderately lower differentials in the Rockies region. We currently estimate that our overall fourth quarter NYMEX differential will be in the range of flat to $0.50 below NYMEX prices. Slide 21 provides review of certain expense line items. As David already addressed LOE, I will start with G&A. Our G&A expense was $18 million for the third quarter, essentially flat from the prior quarter and in line with our expectations. On a year-to-date basis our G&A expense was down 11% from the prior year period. We expect G&A expense in the fourth quarter of 2019 to be similar to the third quarter in the upper teens, with stock-based compensation again representing roughly $3 million of that amount. Net interest expense was $23 million this quarter, a slight increase from last quarter due primarily to the amortization of noncash debt discount for the notes we issued in the June 2019 exchange transactions. On the bottom portion of this slide, there is a detailed breakout of the components of interest expense and you will note cash interest remain consistent. Capitalized interest was approximately $9 million for the third quarter and we currently expect our capitalized interest to be in the $7 million to $9 million range for the fourth quarter of 2019. Our depletion and depreciation expense this quarter was $55 million, a decrease of $3 million from the prior quarter due primarily to the curtailment of CO2 production in the Rockies as a result of plant maintenance at the CO2 source plant. As this item only impacted the third quarter, we expect DD&A will be back in the $60 million range for the fourth quarter of 2019. The next slide provides a current summary of our oil price hedges. Since the second quarter call, we have added to our hedges in the fourth quarter of 2019 and have continued to layer in hedges for 2020. We plan to continue to layer in additional hedges as we see attractive pricing levels. The weighted average floor price for our 2020 oil hedges is currently about $59 per barrel, similar to our average realized oil price through the first 9 months of 2019 with more than 3/4 of our contracts providing for upside exposure. Turning to our next slide, between August and October of this year we completed a series of open market transactions and privately negotiated exchange agreements that contributed to an $87 million reduction in our debt since June 30. During this period, we repurchased $54 million or approximately 15% of our previously outstanding senior subordinated notes in exchange for $11 million of cash and the issuance of 13.7 million shares of Denbury common stock. These transactions, together with the debt exchanges in June, resulted in total debt principal reduction of $138 million since year-end 2018 bringing our total debt principal reduction to $1.2 billion since year-end 2014. Our bank borrowing base was recently reaffirmed as part of our semiannual redetermination process and we ended the third quarter with $50 million drawn on our $615 million bank line giving us $510 million of liquidity after considering letters of credit. Based on projections using recent oil prices, we expect to generate sufficient free cash to pay down the $50 million borrowed on our bank line by the end of 2019. Through the third quarter, our trailing 12 months leverage ratio was 4.1x, and has held relatively stable over the past year. We are pleased with continued progress we've made with our leverage metrics over the last couple of years, and reducing our leverage and improving our debt maturity profile remain top priorities. We will continue to seek appropriate opportunities to further reduce leverage and extend maturities well in advance of our first maturities in mid-2021. In support of this effort, we are actively pursuing several initiatives, one of which is the evaluation of JV options for our CCA CO2 pipeline, which would mitigate all or a significant portion of our pipeline capital spend in 2020. In addition, we continue to progress noncore asset sales, such as our noncore productive acreage positions primarily around the Houston area. We completed $9 million in acreage transactions during the third quarter and closed an additional $5 million in October, resulting in a total of $20 million of closed acreage transactions to date. We have an additional $32 million currently under contract and several more tracts in various stages of negotiation and we continue to expect significant value from the remaining acreage. In addition, we are open to considering other JV transactions and noncore asset sales that could enhance liquidity and further our debt reduction efforts. And now I'll turn it back to John for some closing comments.
Thank you, Mark. That concludes our prepared remarks. Operator, can you please open the call up for questions?
[Operator Instructions] Our first question is from Charles Meade with Johnson Rice.
Mark, I'd like to ask a question -- I would like to ask a question picking up on the point you ended there about the JV or what you guys are evaluating for the financing the CCA CO2 pipeline. So you mentioned a JV and you mentioned that you're evaluating things that could take all or most of your pipeline CapEx for '20 out of your hands. Can you just give us an update on how long this process has been going, how your views have evolved and what you think? What are kind of the leading candidates in the timeline for resolution are?
Sure, Charles. This is Mark. We -- as we kind of talked about before, we kind of envision our Northern Rockies pipeline system there being -- contributing what we have in place and joining with the partner to help us complete construction or pay for construction of the remaining portion up to CCA and then have joint ownership in the pipeline infrastructure there going forward. We are running a competitive process so I have to be -- probably can't say too much. But we're actively involved in that. We are I would say pleased with the level of interest that we've seen to this point. I would expect over the next couple of months here that we'll continue to work through that process. And as we think about forming our 2020 capital plans, we'd like to have something in place there so that we know how much flex we have in terms of whether we're going to spend that on our own or if we're going to have a partner there. And so I would say at this point we're pleasantly surprised and -- not necessarily surprised, but very pleased with the amount of interest and will continue to evaluate that here over the next couple months at least.
That's helpful color, Mark. And then if I could turn back to the asset base and ask a question about those 2 most recent Mission Canyon wells, I recall that you had a -- you had an earlier -- I guess you had early success with Mission Canyon. Some of your follow-up wells you had I believe some water. You -- maybe you drilled them a little too low on structure. Can you tell us with these 2 most recent wells, and I get they were in Cabin Creek and Coral Creek, do you feel like you've kind of solved the remaining piece of the puzzle -- remaining pieces of the puzzle to really make this Mission Canyon zone work?
Yes, Charles, this is Matt Dahan. Yes, to answer your question, last year, we drilled a couple of wells that were disappointing as far as the oil production rates go. And following that learned some lessons on where to position wells, how to better drill them. And that sets us up for success on the remaining inventory.
Okay. And so what we're seeing here is kind of -- is -- should be roughly a baseline for what we should expect going forward?
Yes, certainly well within the range of what we've seen on the successful wells.
Our next question is from Brad Heffern with RBC Capital Markets.
Just as a follow on to that last question, can you remind us what the remaining inventory of Mission Canyon locations is?
Yes, we believe that's upwards of 12 wells.
Okay. And then you mentioned 2020 CapEx earlier in the call. Can you just give thoughts on what it looks like sort of the base CapEx is, what the trajectory is going to be excluding the pipeline? And then maybe a reminder of if you did fund the pipeline 100% how much that would add to that total?
Sure, Brad, and this is Chris. Just jumping into the latter part of your question first. We see that pipeline spend in 2020 as being in the I'd say the $100 million to $120 million range. So that's the piece that we see conflicting [ around ] depending on how the process that Mark mentioned proceeds. What I say generally about 2020, as Mark said, we don't plan to communicate our 2020 full plans until we get into fourth quarter earnings, similar to what we've done in the past. But what I would share a few things -- I'm sure our priorities and how we use those to shape our plans for next year. Number one, the priority is to continue to protect the balance sheet, so you should see us continue to work towards a cash neutral or positive position just as we did this year. And that is our top priority. Then second, we really have a great desire to push CCA forward. We see this as a foundational project for the next phase of Denbury's life. It's a huge resource base. It's just -- it's a great set of fields that we can continue to develop over many years. So that's going to be a priority and that's why we want to have that in front of even how we look at maintenance capital for example. When we think about production, honestly we're thrilled about production this year, just stepping back a little bit and looking year-to-date how well we've done versus the prior year with honestly a very limited capital -- maintenance capital budget. If you take our midpoint at about $250 million, our maintenance capital is probably in the low $200 millions considering the pipeline spend we've had so far this year. And our production -- the continuing production adjusted for sales, adjusting for the storm that David mentioned and the CO2 outage is down just under 2% year-on-year with a very low capital -- maintenance capital level. So we feel good about that. Feel great about what our teams have been able to do. I'd expect to see more of that as we look at next year. And again, that maintenance capital level is going to be flipping a bit depending on whether or not we put the CO2 pipeline JV into the mix there.
Our next question is from to Tim Rezvan with Oppenheimer & Company.
I had a couple of different points. I want to quickly -- on CCA I think David had mentioned that I guess you have the pipes in there, they're in storage now. So are we -- barring like a catastrophic decline in oil, is it kind of you guys are ready to go on that in 2020, JV or not that's going to move forward?
This is David. The short answer is yes, we are ready to move forward with that project. Currently there's about 105 miles of 16-inch pipe that's rolled, coated and stored as well as 18 miles of 12-inch that's rolled, coated and stored to as well. Our current plans are to deliver that pipe to the field and begin installation in the third quarter of 2020. We've currently gone out for pipeline construction bids, those are in-house. Now we're evaluating those. There's a high level of interest in those bids, so we've seen a great response to that. So yes, the project is on full go.
And then just what I'd layer on top of that, Tim, is from a permitting standpoint we see a clear path as well.
Okay. And what are the permitting side that are still out there?
No, all permits are in hand.
Like you have permit in hand...
Yes, we have what we need in hand.
Okay. Okay. And then on a different topic in CCA, I notice third quarter production declined sequentially I think it was 7%. I don't know if you touched on that and I missed it, but can you talk about what happened on that kind of bigger decline than we've typically seen?
Yes, good question, Tim. Of course, there was not from decline in the mix there. Obviously there are 2 other elements in that. First of all is Mission Canyon and that decline is involved there, probably about 300 barrels that's associated directly with Mission Canyon decline in the quarter and also there was some saltwater disposal maintenance that was ongoing throughout the quarter. That has been cleared up and all is back on line now.
Okay. So then going forward should we think about the 3Q being more of a run rate or back to the sort of second quarter level?
Yes, I'd say we're definitely seeing production back above what the third quarter run rate was, and so you should see something moving back north. Of course, we have the 2 Mission Canyon wells that come online too as well, so those will be contributing in the fourth quarter, so it should be coming back up strongly.
Okay. And if I could just sneak one last one in for Mark, I appreciate the comments kind of on the balance sheet at the end, I know there's a lot of focus for investors on the second lien coming kind of due in 2021. Is it fair to say that you think you may be better served kind of getting some of these other asset sales or JVs kind of over the finish line before you look to kind of refinance? I'm just trying to understand kind of what investors can expect? Because it's obviously a big focus for people and they're trying to understand and come up with a value for the equity.
Sure. Yes, I think the sentiment that we've seen here for the last while hasn't really changed much and so obviously it's been to the negative side and that's affected equity prices and bond prices. And so we do think, yes, obviously it's not a great environment, so you haven't seen a lot of transactions getting done in the capital markets, but -- so we do believe it makes sense to continue to execute where we can and what makes sense for us to do. We continue to believe our second lien is a very secure instrument and we have a lot of optionality here in terms of how we can address things going forward. And so we're going to keep that moving in the right ways and continue to work the balance sheet in the best ways that we can. So yes, hopefully along the way we see some improvement in market sentiment as well, but we're going to continue working it, Tim, and we think we have a lot of things that we can do to progress the balance sheet here.
Our next question is from Jason Wangler with Imperial Capital.
You kind of walked through pretty nicely the opportunity at CCA and having the pipe and the permits. Is it just -- there's a lot of moving parts there as far as if you wanted to move any faster or any gating factors that are kind of there that makes the 2021 event before you start injection?
This is David once again. Yes, from a pipeline installation window, that is one of the throttles in the system. Here, once again, we will start that in the third quarter there that pipeline install will be completed in December of 2022 as well. We'll actually go through commissioning, that line will start injection in that first quarter of 2021, so that is the main kind of milestone there we need to achieve.
And I guess is that -- the permits are put there for environmental or other type of reasons I guess to start third quarter I guess is what I was asking unclearly.
That is correct. You're spot on.
Okay. And then just maybe one more. In Mission Canyon, you mentioned the 12 locations and obviously had a couple of good results there. I mean as you think about next year and obviously again a lot of moving parts with CCA specifically, how many do you think you'll try and go after next year? And what do you think ultimately that you want to try and do to get the well up and running in the next couple of years?
Sure. This is Chris. Just in thinking about that, Matt mentioned we have about a dozen locations left and we've learned a lot as we've gone and we feel good about the inventory there. When we think about 2020, a lot of it's going to come in and out depending on how we set up our capital program. Fundamentally, I'd like to continue a program at a pace that lets us continue to add these in a way that makes sense and is probably proportionally similar to the $20 million to $30 million that we spent this year looking at our capital budget here. So it's something that we'll have to honestly really wait until we get to the point where we're finalizing the budget and we decide how many of those to tee up for next year.
Our next question is from Tarek Hamid with JPMorgan.
This is Jon Dorfman on for Tarek. Just wanted to get a quick refresher, I know you touched on it last call, but just your availability to buy back junior lien debt or junior debt in general, if you'd just touch upon that.
Sure, it's Mark. We have -- our credit facility, there is basket there, it's about $94 million we have remaining cash to address that would be the short answer. We also have some baskets under second lien and things, but I think the biggest governor right now is what we have under the bank facility.
Okay. No, that's helpful. And I believe a good chunk of that is related to leverage ratios?
Yes, so it has to be less than 4x or deleveraging, it's kind of what part of the basket is geared around.
Okay. And then I did notice in the release, and you talked about it a little bit with the surface acreage, I think you touched upon and said $32 million in contract and more in negotiation. Could you just kind of provide us a little bit more on the timeline for those contract in hand, kind of when you expect to complete those transactions and then kind of any color on the magnitude of what's left after that?
Yes. This is David Sheppard. Yes, some more color on that. There's $32 million and a contract at acreage largely at our [ Keystone ] or Conroe track. There right now we expect that first tranche to close in 2021 for about $16 million worth. The second tranche will be in 2022, equally $16 million. The balance of the acreage we do have remaining, it is in Webster, some components still in Conroe 2 as well, but the larger balance would be in the Webster, in that area. A lot of ongoing negotiations there, a lot of high-value property still remaining to come.
Our next question is from Sean Sneeden with Guggenheim Securities.
Just on LOE, you mentioned it kind of jumped up on a unit basis there I think due to kind of lower volumes in the quarter and some higher workover activities and the plant is kind of getting back to kind of low [ 20s ] for the year and hopefully a good Q4. Is that generally a good run rate to think about for 2020? And I guess in particular when you kind of look at the individual line items, you did see higher workover and some higher labor numbers. Do those kind of normalize as you kind of go into next year? Or how should we kind of think about that?
This is David once again. Yes, I -- just directly there are a extreme focus on managing our calls. We have to do that and we're going to do that. As I said in the prepared remarks, we're really implementing some systems and technology, they're going to help in a perpetuate sustainable cost reductions there. And I'll talk about a couple of those in a general nature, but we expect largest is going to be associated with a EAM implementation, a enterprise asset management system and enhancing some of our supply chain focus there. Secondly, we're really in the midst of deploying a mobility application tool that's really going to help reduce the amount of repetitive manual data entry that we have in our system plus make our workflows more efficient. Two, we continually look at workovers, things of that nature as well to deliver the most effective workover for the lowest cost and achieve the objectives that we need to achieve. So our focus is to maintain that unit basis or even suppress it down over time.
Got it. That's helpful. And then, Mark, I think Tim kind of asked a question about the second lien, so maybe just kind of a follow-up to that, but you've been pretty successful about chipping away the unsecured maturities and you're expected to pay off the RVL by year-end. I guess do you feel like cleaning up the remaining portion of kind of the near-dated unsecured maturities is kind of needed before you start to tackle the rest of the second liens? Or how are you guys kind of thinking about that as you enter next year?
Sure, Sean, good question. And [indiscernible] said I think we continue to do where activity is where we feel we can make the biggest benefit today and continue to progress the balance sheet forward. If you look at Slide 23, and you really look at our maturities here over the next few years, we've got the sub notes down to $50 million in '21 and $70 million in '22. Hopefully, we're reaching a point where people aren't seeing a real challenge with those, but we have a lot of first lien capacity to address things. And so yes, we do have to address the second lien maturities here with that, but like I said, we see several different ways to progress that and opportunities that we have. Our ultimate goal is continue to delever the balance sheet. And so like I said in the past that when people think about Denbury, they aren't concerned about our leverage. We are a company with a lower declined asset base where we can probably handle a bit more leverage than other companies in the space, more share-based, higher decline type assets. But that being said, we want to take this to a different place and I think the thing as you look out here, we have time to do that. And just as we've done since 2014, we're going to continue to progress the balance sheet in a positive way. So yes, I understand the concern, but I think as I look at it, I see many manageable opportunities in front of us.
And that makes sense. If I can just sneak one more in, Chris, I know you're still going through the budgeting process, but I guess conceptually about 2020, is the kind of the bookings that you're kind of thinking about in terms of kind of free cash flow profile of kind of being neutral to positive, is that kind of the CCA pipeline, whether it's funded internally or by external capital?
That's exactly how I'm thinking about it, Sean, is that we're going to -- when we get into the end of your time frame, look at what we expect prices to be next year. Of course, we have a nice hedge position built that will help us even if we trend a bit lower into the year. But with a look at that, look at being cash flow neutral or positive and then whether that pipeline cost, like I mentioned $100 million-$120 million flips and around is going to be -- to me, that's going to put your bookings on it.
Our next question is from Richard Tullis with Capital One Securities.
Sorry if I missed this, what are the other noncore assets beyond the surface acreage that Denbury could look to as monetization candidates?
Sure, Richard. The main one that I think about is the set of mature assets that we had worked through last year. And those -- that set of assets that are really not core to our future growth, I think about that as a key alternative as we look at what those other possible asset sales could be.
Okay. Okay. Your comments in the opening remarks about the low carbon footprint were interesting. At a high level, what low carbon business opportunities could be developed by Denbury say over the next several years, including additional enhanced oil recovery opportunities on your current or possibly new acreage?
Sure. I think that is one of the things, Richard, that really sets Denbury apart here is number one, we have the expertise in EOR and so our teams, both in the headquarters and out in the field are used to designing for and dealing with CO2 and then -- and pipelines and facilities and in wells and in reservoirs. So just a great set of expertise there. Along with it, all the assets that go along with that expertise, especially the pipeline infrastructure that we have along the Gulf Coast industrial corridor.
So going to your question I think about where does this lead, and there's a strong push within government policy -- U.S. government policy right now to provide tax credits to those who capture and sequester CO2. And there's an aspect of that in EOR as you can imagine, as we've talked about. But even beyond that, when you look at the future, there will be a great need, one of the great solutions to reducing carbon emissions in the atmosphere is through other forms of geologic sequestration that include putting CO2 into saline aquifers. And what I think is where that will go, and with the incentives that are provided by the government policy and these -- the tax credits that will be available, can make that a very attractive business and one that matches exactly with what Denbury does in terms of the assets that we have and the expertise that we have. It's still a few years down the road I think in terms of where we would be in terms of turning that into a business. But I see that in the future.
We have no more questions at this time. So I would like to turn the conference back over to John Mayer for closing remarks.
Before you go, for your calendars, we currently plan to report our fourth quarter 2019 results on Thursday, February 20, and hold our conference call that day at 10 a.m. Central. Thanks again for joining us on today's call.
This concludes today's conference. You may disconnect your lines at this time, and thank you for your participation.