Denbury Inc

F:HGJ1

Earnings Call Transcript 2019-Q4

[Operator]

Good day, ladies and gentlemen, and welcome to the Denbury Resources conference call. My name is Daryl, and I will be your operator for today's call. [Operator Instructions]

I would now like to turn the conference call over to your host, John Mayer, Denbury's Director of Investor Relations. Please proceed, sir.

[John Mayer, executive]

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 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 home page 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.

[Christian Kendall, executive]

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 and the full year, along with our plans for 2020; then hand the call over to David, who will discuss our operations; and finally, to Mark, to walk through our financial results.

Denbury's results for both the quarter and the full year were outstanding. We achieved or exceeded each of our key goals for the year. Most importantly, we set new company records for safety performance, ensuring that our employees and contractors were safer than they have ever been. Safety is the cornerstone of exceptional operations. And while I'm thrilled with the progress we've made, I'm sure that we'll get even better.

Our development projects were successful, generating high returns as we continue to drive even more value from a great set of long-lived, oil-weighted assets. We found new success with exploitation. And late in the year, we entered into an exciting joint venture that will accelerate our exploitation program in the Gulf Coast. We made good progress on our CCA EOR development project, and we reduced our costs even further with a voluntary separation program implemented late in the year that will reduce our ongoing costs by over $20 million per year or about $1 per barrel.

Our strong operational performance paved the way for great financial results as well. We continue to generate significant free cash flow and $165 million delivered for the full year was well above our guided range, aided by strong production performance and a relentless focus on costs. We made significant improvements to our balance sheet, reducing debt by $250 million while extending maturities of another $350 million in debt and our bank facility was undrawn at the end of the year.

Denbury's operating margin remained very strong in the fourth quarter at nearly $28 per BOE or 50% of revenue. The operations team's high focus on managing costs in smart, sustainable ways resulted in total OpEx at the low end of our guided range for the year, helping us maximize the value generated from every barrel of oil we produce.

Taking a high-level look at production in 2019, our performance was solid across the board. Our full year production was in the upper half of our guidance range even after the midyear sale of our Citronelle Field. What makes these production results even better is that we achieved them with very low capital spend even below the low end of our guidance. We exercised great discipline in our capital program, ensuring that capital is carefully allocated to the highest return projects, and our results in both capital spend and production validate the success of this discipline.

Looking now at our plans for 2020 as we considered our key 2020 priorities of spending within cash flow, addressing near-term debt maturities and reducing debt, we have reduced our base capital budget by nearly 25% from the already low level spent in 2019. Our base capital range of $175 million to $185 million provides for the execution of multiple high-return projects and should also drive around $100 million in free cash flow if prices remain in the $50 range.

In 2020, we also plan to continue to progress our flagship project, initiating EOR development in the massive Cedar Creek Anticline. However, because most of the project spend and activity is in the second half of the year and considering the current uncertainty in the oil market, along with our priority of addressing our near-term debt maturities, we've decided to defer our investment decision on the incremental $140 million to $150 million needed for CCA until the second quarter of 2020. I'm optimistic that we'll proceed with the project this year, but I think the wisest choice at this time is to defer the investment decision, especially because the execution plan permits us to do so without impacting the project.

Because our very low capital level this year is well below the mid-$200 million range that we believe is needed to hold production flat, we expect continuing 2020 production to be slightly lower year-on-year. After accounting for the Citronelle sale as well as the expected 50% working interest sale of the fields associated with the Gulf Coast JV, we expect full year production to be in the 53,000 to 56,000 BOE per day range, with the midpoint just 4% below the corresponding 2019 production level.

With 100% of our fields held by production, our ability to flex development capital is a great characteristic of our business, one that has helped us consistently spend within cash flow through a wide range of oil price environments.

Next, I'll outline our key priorities for 2020. First, and as I mentioned earlier, it is essential that we maintain our focus on operational excellence. We have made great strides as reinforced by our 2019 results, but we will continue that focus to improve safety, improve reliability, reduce costs and become even more efficient. Second, we will take steps to address our near-term maturities and continue our great progress on reducing overall debt. Third, we will continue to drive value from within our great asset base both through incremental EOR development and through our exploitation program, which will be accelerated upon commencement of the Gulf Coast JV. Finally, as I mentioned, we'll continue down the path to bringing EOR to our massive CCA asset, but will make the ultimate determination on proceeding with the bulk of that capital in the second quarter.

Before I hand the call over to David, I'd like to talk about a shift in the industry that I see as exciting and extremely beneficial for Denbury. This shift is driven by an increase in the urgency of meeting the dual challenge of fueling the world's economy and continuing to improve the quality of life for all, while mitigating climate risk by reducing atmospheric CO2 emissions. The role that oil and gas companies play in this challenge is essential, not only because we find and produce these hydrocarbons, but because we can be a key part of the solution to reducing CO2 emissions as well.

Denbury is uniquely well positioned to be a meaningful part of this solution. Our current EOR business already makes a significant impact, injecting over 3 million metric tons of industrial CO2 per year. This is equivalent to taking 700,000 cars off the road. We see our impact growing significantly as more captured industrial CO2 becomes available.

Equally exciting is the emerging carbon capture use and storage business, or CCUS, where industrial CO2 is captured and is not necessarily only used for EOR, but may also be stored in nonhydrocarbon underground reservoirs. Denbury is uniquely qualified to become a leader in this business, both through our expertise and our assets. Our technical and operational expertise comes through 2 decades of experience in a business that is fundamentally focused on CO2. We safely and efficiently move about 0.25 million tons of CO2 each day through pipelines, compressors, pumps, production equipment and into and out of wells and reservoirs.

We have a workforce that is trained and ready to apply the same expertise and high standards that we use in EOR to a CCUS business. On the technical side, our staff has experienced in the unique challenges of handling CO2 and ensuring that it is safely contained in underground reservoirs. Our in-house 4D seismic expertise is a powerful advantage that we have refined over 2 decades of EOR operations, helping us frequently monitor how CO2 is moving in reservoirs, a vital step in ensuring that CO2 remains effectively sequestered after injection.

Denbury's assets are perfectly situated for CCUS. In particular, our Gulf Coast pipeline system was strategically located to be close to both current and expected industrial CO2 sources along the Gulf Coast, and our 24-inch CO2 pipeline through Louisiana and Southeast Texas has the capacity of transporting at least 20 million tons of CO2 per year from industrial sources to sequestration reservoirs, while generating significant and sustained cash flow.

Because CO2 EOR and CCUS are both highly-impactful solutions to reducing CO2 emissions, they receive broad and bipartisan support from the U.S. and local governments. And recent steps by the U.S. government further demonstrate that support through the expanded and extended 45Q tax credit. When this tax credit was enacted in 2018, it provided for a credit of $35 per ton for CO2 captured for EOR use and $50 per ton for that captured and placed in non-EOR sequestration.

Lack of clarity and other provisions of the original tax credit did not spur significant CCUS investment, but Denbury and many others have been working with other stakeholders to improve and clarify 45Q to where it can be a useful incentive for investment in this critical effort. I'm excited to say that I see very good recent progress on this front.

Earlier this month, the IRS provided clarity on 2 key outstanding provisions, and we expect the remaining outstanding items to be clarified in the near future. Once this clarity is finalized, I believe that a very exciting new business opportunity will rapidly emerge. I expect that multiple new capture projects will be sanctioned, both along the Gulf Coast and across the U.S. The opportunity to provide a full capture solution, receiving captured CO2 from industrial emitters then safely and efficiently transporting it to storage sites, injecting it into those reservoirs and monitoring its placement will be a necessary and valuable service. I believe Denbury can quickly become a leader in this evolving new area, providing new opportunities to expand our future growth potential.

Now I'll pass the call over to David for an update on Denbury's operations.

[David Sheppard, executive]

Thank you, Chris, and good morning, everyone. Before I go into the quarterly results, I would like to provide an update on an incident that occurred this past weekend, Saturday, February 22, relative to our Delta Tinsley CO2 pipeline in Mississippi.

On Saturday evening, our CO2 operations center detected a pressure loss on our 24-inch Delta Tinsley CO2 pipeline, immediately triggering our emergency response protocol. The effective pipeline segment was isolated within minutes of detection. And as a precaution, the area surrounding the leak site was evacuated, including residents of a small nearby town, Satartia. No injuries to local residents, our employees, our contractors were reported in association with the leak. The site was declared safe and the evacuation was lifted early the following morning, allowing residents to safely return to their homes. The area surrounding the leak is secure and poses no threat to the public.

We do not wish to speculate on the call to the incident at this time, but we are working closely with federal agencies to investigate the cause and to take the appropriate steps to promptly put the line safely back in service. As this pipeline supplies CO2 to our Tinsley and Delhi fields, we have suspended CO2 purchase volumes to those fields. The recycle facilities at both Tinsley and Delhi are operating as usual, but total CO2 injection rates are reduced due to the curtailment of CO2 purchase volumes. We expect to see some level of production impact in the first quarter. But as we are still assessing the situation, it is too early for us to estimate the impact.

Finally, I want to reiterate that as we move forward with the repair, the safety of the public and protection of the environment remain our top priority.

As I transition to discuss the quarterly results, I want to first express how pleased I am with the full year 2019 operations accomplishments. For 2019, we operated safer than ever before, setting a company record low total recordable incident rate and exceeded the midpoint of our original production guidance while spending at the lower end of guidance in both LOE and capital categories.

I would like to circle back to production to take a closer look at both the quarter and the full year. Production for the fourth quarter of 2019 was 1,070 BOE per day above the third quarter, reaching just over 57,500 BOE per day and resulting in full year production over 58,200 BOE per day within the top half of our original guidance for the year, despite the sale of Citronelle Field at the beginning of the third quarter, and in line with the midpoint of our midyear upper revised 2019 production guidance range. The sequential quarter increase was primarily due to rebounding production at Bell Creek where production had been reduced in the third quarter due to an extended period of planned maintenance at our primary North region CO2 source.

Bell Creek Phase 5 continues to perform as expected, and we recently begun seeing a production response from Phase 6 at Bell Creek, which I will touch on further in a moment.

Lease operating expenses during the fourth quarter decreased slightly from the prior quarter on both an absolute and per BOE basis, with quarterly LOE of $116 million or just under $22 per BOE. CO2 costs were up in the quarter due to the return of CO2 volumes at our primary North region CO2 source. However, decreases in other categories, notably workovers, more than offset the additional CO2 cost and drove LOE lower from the sequential quarter.

Full year LOE per BOE was $22.46, at the lower end of our original guidance of $22 to $24 per BOE. As we enter 2020 with production rates declining slightly year-over-year as a result of lower maintenance capital spend, we continue to focus on sustainable improvements that will drive cost out of our production operations and are once again guiding LOE to be $22 to $24 per BOE for the year 2020.

Slide 16 provides an update of our planned EOR development at Cedar Creek Anticline. During 2019, we completed rolling and coating of the pipe for the CCA CO2 pipeline, which is awaiting installation. Total spending in 2020 for the CCA EOR project is projected to be $155 million, with $140 million to $150 million of that amount conditioned upon board approval in the second quarter. Subject to the approval, we intend to begin installing the pipeline in the second half of 2020, with CO2 injection commencing in early 2021. In connection with the first 2 phases, we anticipate storing approximately 90 million metric tons of an industrial sourced CO2, contributing to the carbon-negative story Chris outlined earlier.

Turning your attention to Slide 17. Fourth quarter 2019 net tertiary production at Bell Creek field rebounded to over 5,600 barrels per day, up from just under 4,700 barrels per day in the third quarter as production increased nicely with CO2 purchase resuming subsequent to the North region CO2 source maintenance I mentioned previously. Phase 5 in the field is performing in line with expectations and we have recently begun seeing a production response from 2 producing wells in Phase 6, with production growth in Phase 6 expected to continue to grow at a modest rate through 2020.

Late in the fourth quarter, we drilled a second well in Bell Creek, targeting untapped accumulations in a previously completed phase of the development as a follow-on to the successful well we drilled in Phase 4 earlier in 2019. Completion operations have recently concluded and we are eagerly awaiting production results. The team continues to look for prospects within the existing producing developments and has been bringing forward highly-economic, high-probability exploitation opportunities. Current plans include drilling a well and a separate accumulation during the third quarter of 2020.

We continue to evaluate multiple exploitation opportunities across our portfolio, and our Brookhaven Case Sand project is another great example of the value that can be generated within our great assets. The Case Sand target was identified through seismic data evaluation within an actively producing area of the field. We drilled and completed our first well in the Brookhaven Case Sand during the fourth quarter of 2019 for a cost of approximately $3 million and are seeing highly-successful early production results with an estimated IP30 of around 400 BOE per day and a 95% oil cut.

We have plans to drill on an additional 2 wells during 2020 in the same seismic feature identified by our teams. We are not only excited about this opportunity, but we are also looking forward to applying these learnings as our teams continue to look for ways to extract additional value from our assets.

In December, we announced that we have entered into an agreement to farm down half of our nearly 100% working interest in 4 conventional Southeast Texas oilfields for $50 million cash and a carried interest in 10 wells to be drilled by the purchaser. The fields included are: Webster, Thompson, Manvel and East Hastings, and the sale is currently expected to close within the next few weeks.

The agreement is structured such that the purchaser will fund 100% of the capital to drill and complete an initial 10 horizontal wells across the fields, with the first of the 10 wells to be spudded within 6 months of closing and with all 10 wells to be completed within 18 months after closing.

On these initial 10 wells, we will receive a 6.25% overriding royalty interest prior to payout. And subsequent to payout we will bear our 50% working interest in each well. As part of the agreement, we will retain ownership of the future Webster unit CO2 flood, though the purchaser can elect to participate at their working interest level, which also includes reimbursement of project cost incurred prior to the farm down agreement. If the purchaser declines to participate in the CO2 flood, we have the right to repurchase their working interest in the unit.

During 2019, we continue to progress the sale of our valuable surface land. We have completed the sale of multiple parcels, primarily around the Houston area, totaling approximately $20 million through year-end 2019. Currently, we have another $32 million under contract, which provides for a substantial portion of cash proceeds to be received no later than mid-2021, with the remainder to be received by mid-2022. We are actively working with the buyer to potentially close the first portion of this sale before the end of 2020.

We continue to see significant interest in the remaining surface acreage, and we believe future land sales could generate an additional $30 million to $50 million of cash over the next few years beyond the roughly $50 million we currently have under contract or have sold.

Slide 21 outlines our change in reserve volumes and values during 2019. We ended the year with 230 million BOE approved reserves, with proved developed reserves comprising about 90% of the total. The most significant changes from year-to-year were due to current year production and the change in commodity prices. As we have stated previously, 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 2019 results are in line with that concept, with the average first day of the month NYMEX oil prices decreasing by about $10 from the prior year. Offsetting these decreases was a roughly $370 million increase due to accretion of discount.

Next, I'll turn it over to Mark for our financial update.

[Mark Allen, executive]

Thank you, David. My comments today will highlight some of the financial items in our release, primarily focusing on the sequential changes from the third quarter of 2019. I will also provide some forward-looking guidance for 2020 to help you update your financial models.

Starting on Slide 23. Fourth quarter 2019 adjusted net income was $47 million or $0.09 per diluted share, slightly better than the analyst expectations. This quarter's largest differences between adjusted and GAAP net income included $64 million of noncash expense from fair value changes in commodity derivatives, a $50 million gain on debt extinguishment related to the private debt exchanges completed during the quarter and $19 million of severance-related expense associated with the company's voluntary separation program.

Turning to Slide 24. Our non-GAAP adjusted cash flow from operations, less special items, which excludes working capital changes in severance-related expense, was $134 million for the fourth quarter, up $8 million from last quarter. We generated free cash flow of $56 million in the fourth quarter after considering $21 million of interest that is included as repayment of debt in our financial statements and $57 million of combined development capital and capitalized interest.

For full year 2019, we generated free cash flow of $165 million as our results remained strong and our capital spending came in below the low end of our capital budget range. This free cash flow was used primarily to help reduce our debt by $250 million in 2019. Our fourth quarter average realized oil price of $58 per barrel after hedges was down 2% from our realized price in the third quarter, primarily due to weaker differentials.

Slide 25 provides a summary of our oil price differentials. Excluding any impact from hedges, our realized oil price averaged $0.44 per barrel below NYMEX prices in the fourth quarter, which is down around $1.75 per barrel from last quarter, but in line with the guidance we provided and expectation of weaker differentials for both our Gulf Coast and Rockies production.

Looking ahead, to the first quarter of 2020, we expect that our overall oil differential will decline slightly from the levels realized in the fourth quarter due to further weakening of the LLS differential and moderately lower differentials in the Rockies region. We currently estimate that our overall first quarter 2020 NYMEX differential will be in the range of $0.50 to $1 below NYMEX prices.

Slide 26 provides a review of certain expense line items. Since David already addressed LOE, I will start with G&A. Our G&A expense, excluding $19 million of severance-related expense associated with the previously mentioned voluntary separation program, was $10 million for the fourth quarter of 2019, a decrease of $8 million from the prior quarter, with a significant portion of the decrease due to lower compensation and employee-related costs. On a year-to-date basis, also excluding severance-related expense, our G&A expense was down about 10% from the prior year period.

Ongoing annual savings from the voluntary separation program are estimated at $21 million, spread across G&A expense, lease operating expense and capital. We expect G&A expense in the first quarter of 2020 to be between $17 million and $20 million, with stock-based compensation representing roughly $3 million of that amount. For subsequent quarters, we expect G&A will be somewhat less, with our expected annual G&A expense in the range of $60 million to $65 million. Recall that our G&A in the first quarter tends to be higher than other quarters due to the higher payroll taxes and other compensation-related items associated with bonus and award payouts in Q1.

Net interest expense was $21 million this quarter, a decrease of $2 million from last quarter due primarily to lower cash interest. On the bottom portion of this slide, there is a detailed breakout of the components of interest expense. Capitalized interest was approximately $9 million for the fourth quarter, and we currently expect that our capitalized interest will be in the $8 million to $10 million range for the first quarter of 2020.

Our depletion and depreciation expense this quarter was $63 million, an increase of $8 million from the prior quarter. This increase was due in part to higher depletion on CO2 assets during the quarter as the prior quarter's depletion was abnormally low as a result of lower CO2 production in the Rockies region from the planned maintenance at the primary CO2 source plant, with the remainder attributable to higher oil and natural gas property depletion as a result of higher net property balance and a higher depletion rate. We currently expect that DD&A for the first quarter of 2020 will be at a similar level as the fourth quarter of 2019.

The next slide provides a current summary of our oil price hedges. We are approximately 70% hedged using the midpoint of our estimated 2020 production, with 80% of our contracts being collar structures that provide for downside protection and upside participation. The weighted average floor price for our 2020 oil hedges is above $57 per barrel for NYMEX contracts and around $61.60 per barrel for LLS-based contracts.

Based on our current assumptions and projections, we estimate that at a $50 NYMEX oil price, our hedge portfolio would generate around $105 million of cash proceeds in 2020. If NYMEX prices were to average $55 per barrel for 2020, we would expect those cash proceeds to decrease to around $37 million. We typically estimate that every $5 change in oil price, excluding hedges, results in a $100 million change in cash flow. So you can see that our hedges are providing significant protection such that the amount of cash flow loss between a $55 and $50 oil price is closer to $25 million than an unhedged $100 million.

Turning to our next slide. During October and November of 2019, we repurchased, principally through exchanges, $100 million of our senior subordinated notes for $11 million in cash and the issuance of 38 million shares of the company's common stock. We also use free cash flow generated during the quarter to repay outstanding borrowings on our bank credit facility, contributing to the $154 million reduction in our debt since September 30.

These transactions, together with other transactions throughout the year, resulted in a total debt principal reduction of $250 million during 2019, utilizing $136 million of cash and 38 million shares of Denbury stock. In the aggregate, we have reduced our total debt principal by $1.3 billion since year-end 2014. We ended the year with no amounts drawn on our $615 million bank line, giving us $528 million of liquidity after considering letters of credit.

Moving to Slide 29. At year-end 2019, our trailing 12-months leverage ratio was 3.7x compared to 4.2x at year-end 2018. We are pleased with the continued progress we have made with our leverage metrics over the last several years and reducing our leverage and improving our debt maturity profile remain top priorities.

As we have discussed in the past, and as demonstrated by our $100 million repurchase of senior subordinated notes during the fourth quarter, we continue to focus on improving the company's balance sheet, and we are currently assessing various alternatives to further this effort, primarily focused around maturity extension and/or debt reduction with our top priorities being 2021 and 2022 second lien debt maturities, including potentially using access to unused first lien capacity to help refinance the second lien debt. We also continue to evaluate capital enhancing opportunities such as asset sales and/or joint ventures, particularly for our CCA CO2 pipeline that could enhance liquidity and further reduce debt.

And now I'll turn it back to John.

[John Mayer, executive]

Thank you, Mark. That concludes our prepared remarks. Operator, can you please open the call up for questions.

[Operator]

[Operator Instructions] Our first question comes from the line of Charles Meade of Johnson Rice.

[Charles Meade, analyst]

I really appreciate the way you guys have already answered a lot of questions about how you're going to address this CCA pipeline decision. And I think it makes sense that you guys -- you pushed this later in the year when you get to see a few more cards. But I guess my question is around what are those cards? And what are the relevant pieces? And how are you going to navigate through that? I mean, I can think about if we have the situation where oil prices move higher, you guys successfully executed JV and you refi your second lien. Okay, that's -- we're definitely going to see that CapEx roll into the picture.

Conversely, if you -- like Mark said, you have to use some of that first lien capacity to deal with the second lien, and oil prices stay at current levels I could see it wouldn't go forward at least this year. But is -- can you talk about what the moving pieces are to you? And whether I have the right read, so far, on the way it looks for you guys?

[Christian Kendall, executive]

Yes. You bet, Charles. And I think that you've got it pretty much on track with what you've already said. I'll just share a few additional thoughts.

As we've talked about CCA in the past, we love this project. It's a real cornerstone of what we want Denbury to be pointed towards in the future. So it's a priority. But at the same time, when we look at just where this year started and we see a pretty choppy market out there with the coronavirus fears running pretty hard right now, combining that with just how the project timing is and when we look at the timing of the installation of the pipe, for example, that's a second half event. And to us, it just made perfect sense with the market. And then with the other -- some of the other activities that we're looking at that you mentioned still wanting to see where they progress.

So just a great example is the very exciting JV that David talked about on the Gulf Coast. But -- so we have that under contract. We expect it to close in a few weeks. We'd like to see that get done, just as one example. And of course, we'll continue working on other elements around the balance sheet that makes sense. But I do think that your read on it is pretty accurate.

[Charles Meade, analyst]

Chris, thanks for adding that one piece about the Gulf Coast JV. And then a lot of interesting things to talk about operationally. But Chris, I want to go back to one of the points in your prepared remarks when you talked about the carbon capture use of stores. This is something I don't want to say has exploded. But this has really risen in prominence over the last 12 or 18 months. And I think it gets investors excited about the Denbury story. But I'm curious, from your point of view, what time line should we be thinking about for this to actually contribute to revenue or margin at Denbury?

[Christian Kendall, executive]

That's a great question, Charles, on the time line. And certainly, like you, we see this in the news every day. Just this morning, I see more companies that are starting to point towards that as a means of getting themselves into a better carbon footprint profile.

Interestingly, though, when you think about Denbury and what we do and so many of the other companies that really have a different business model, for us, CCUS is a perfect fit. It is literally just an extension of what we're doing technically and operationally, and it uses assets that we have that are strategically positioned and were thought through many years ago to be able to do just what we want here.

So we feel great about where our position is in this. And even the pent-up potential capture that we're aware of is very significant. Just as an example, on the Gulf Coast, right now we know of specific projects that are pending approval that will be capturing CO2 to the tune of about 14 million or 15 million tons per year. So if you compare that to the 3 million tons per year that we're currently using of industrial CO2 as a company, it's a multiple of 4 to 5x that, that we see as potential being approved when we see these 45Q tax credits get clarified, just a big business.

Now as to the time line, those are projects that will take time to develop. So I would certainly say, I would not look at the next -- at this year or the next couple of years as years that you'd expect to see significant cash flow gains. But I would expect that you'd see us moving in the direction to where those projects are sanctioned and we're participating in some fashion. And so you'd have a view to what that future cash flow looks like.

It's somewhat longer term, but just as you mentioned, the big push, not just on oil and gas companies, but on any industrial emitters is pretty heavy. And we see with the 45Q coming together shortly that there will be some announcements coming that will be capturing CO2 from these new projects.

[Operator]

Our next question comes from the line of Mike Scialla of Stifel.

[Michael Scialla, analyst]

You said your base plan, I believe, is built on $50 WTI. I just want to see what your thoughts are. Would that base plan change at all if, say, oil turns out to average somewhere in the low 40s? Or is that base plan pretty well set at this point?

[Christian Kendall, executive]

Mike, I'd say it's pretty well set. I mean, always we're going to be looking at the market and making adjustments that we need to, depending on where the market is headed. But I'd really point back to Mark's comment about our hedge book. We took a good chunk of last year building up a very strong hedge book and having 70% of our production built into that. We're feeling pretty insulated against a range of oil prices that we see right now.

Like I said, if things go too far, we're going to, obviously, continue to look at that. But I would think that we would focus on the base plan that we have and not want to flex it significantly, unless we see prices move well outside the range that we currently have.

[Michael Scialla, analyst]

Great. Understood. And I want to see if you could talk a little bit more about your exploitation projects? Obviously, some pretty exciting results out of Brookhaven. And also wanted to see if you could talk about what your JV partner will be doing? And what's the working interest that they picked up in those fields? Any particular exploitation projects you could talk about there?

[Matthew Dahan, executive]

Yes. Mike, this is Matt Dahan. I'll take those questions. Starting in Brookhaven, very excited to, once again utilize our existing seismic database to find additional potential. As David mentioned earlier, we have 2 wells to drill there, and we continue to look within Brookhaven and across the rest of our portfolio, particularly in Mississippi for similar opportunities.

As far as the JV goes in the Gulf Coast, they picked up 50% working interest. They're committed to drill 10 wells and carry us on those 10 wells. And then post payout, we'll back in for our 50%. There's been identified upwards of 60 locations in multiple intervals across the 4 assets. So they have to spud the first well within the -- in the 6 months after closing, and 18 months to complete all 10 wells.

[Christian Kendall, executive]

And Mike, just jumping in on Matt's comment there. I just see what that joint venture is going to do is really allow us just to accelerate what we'd already started down there, looking for these nice remaining accumulations of oil that are in these great reservoirs. So it just -- really, just pushing it at a faster pace.

[Michael Scialla, analyst]

Maybe just one follow-up on that. Is it the -- in terms of the locations and the prospects that you've identified, will Denbury have any say in where those are drilled? Or will that be determined by the partner?

[Matthew Dahan, executive]

They'll make the initial proposal, but Denbury will review everyone before we drill.

[Operator]

Our next question comes from the line of Brad Heffern of RBC Capital Markets.

[Brad Heffern, analyst]

A question on the production guide. So it looks like versus the adjusted number for 2019, it's down between 2% and 7%. I was curious if that's consistent with the decline level you would expect from this capital spend? Or if there's anything unique about 2020 in terms of field downtime? Or CO2 source downtime? Or anything that's affecting the numbers?

[David Sheppard, executive]

Brad, this is David Sheppard. I'm going to take that question. Yes, I mean you're right on track with the adjustment for our Citronelle sale in our Navitas, Gulf Coast farm down, and you're seeing about 1,300-barrel a day, roughly, impact on an annualized basis. But as you think about one of the great attributes of our company is our ability to flex capital and that flexing of capital to match the current commodity prices in the market.

For flexing, we're choosing to flex that capital down this year because of where the market is, our maintenance capital is projected to be about $170 million for 2020. And if you think about that in succession in 2019, we spent about $220 million on maintenance capital. And so both of those numbers are below what we guide to be in that middle to upper $200 million range for maintenance capital. And so with that being said, we're only down about 4% at that reduced consecutive level of maintenance capital spend.

So I think the assets are very resilient for that level of spend and what we're putting into them. And there is no substantial impact from any external calls, as you may have suggested earlier, for instance CO2 source impact.

[Brad Heffern, analyst]

Okay. Got it. And then I guess on the Houston acreage, I noticed that you put a dollar value on the remaining assets, I think for the first time, that $30 million to $50 million figure. I was just curious sort of what's giving that confidence in that range? And does it suggest any additional line of sight into a new contract there?

[David Sheppard, executive]

Brad, this is David, again. I'll take that as well. And so yes, we've seen a lot of interest in the remaining balance of our prospective acreage sales there. So we're currently in negotiations on several of those tracks. None of them have landed in the contract phase yet. But it does reinforce our total original value estimate in the 80-ish to almost $100 million value range. So I'm pleased with where that's at today.

[Operator]

Our next questions come from the line of Gail Nicholson of Stephens.

[Gail Nicholson Dodds, analyst]

When you guys look at kind of Phase 6 at Bell Creek, could you just talk about how we should think about that ramping throughout the year? And where you anticipate being -- where volume to be in 1Q at Phase 6 versus 4Q in Phase 6?

[Matthew Dahan, executive]

Yes. This is Matt Dahan. I'll take a stab at that one. If you flip to Slide 17, you can look at the performance of each of the individual Bell Creek phases. And they're really very similar to one another. And we expect Phase 6 to perform as the other phases have, and it's really just ratioed on the amount of oil that we're targeting. So a little bit better than Phase 3, a little bit less than Phase 5. So it's going to fall there somewhere in between.

[Gail Nicholson Dodds, analyst]

Okay. Great. And then just looking at the other significant tertiary projects you had planned in 2020, when you look at the timing of those, what -- how much of volume metrics are you anticipating from those major significant tertiary projects to benefit 2020? And what's actually benefiting '21?

[Mark Allen, executive]

You want to take that?

[Matthew Dahan, executive]

Yes. It's Matt again. So our first project we're executing in 2020 is our Oyster Bayou redevelopment. But again, these are CO2 floods. So once the capital's spent, we have to inject CO2. So actually, little volumes coming in 2020, with the big push coming the following year.

[Gail Nicholson Dodds, analyst]

And then just looking at your other capitalized items guide at $40 million, that's down slightly versus, I think, it was like roughly $46 million in 2019 and 2018.

Can you just talk if there's incremental improvement there as we look forward into '21, forward?

[Mark Allen, executive]

Yes. This is Mark, Gail. And most of that probably was a result of the voluntary separation. And so some of our costs have come down there, so that we wouldn't expect that to change much going forward, unless we make other changes to the cost structure.

[Operator]

Our next questions come from the line of Richard Tullis of Capital One Securities.

[Richard Tullis, analyst]

Exciting comments, Chris, related to the potential carbon capture opportunities out there. What is the expected scope of potential initial investments required by Denbury in order to participate in those sort of endeavors? I know there's a couple of large caps and majors that have been partnering with some companies in the alternative energy space. What do you envision, say, from Denbury over the next couple of years?

[Christian Kendall, executive]

Sure, Richard. And that's a good question, and it's part of the reason that we're particularly excited about this is, when I think of the different ways of executing CCUS to me, still the most impactful ways of capturing and injecting large volumes of carbon dioxide are from single-point emitters that can capture large volumes of CO2, put them into a pipeline and transport them into an injection site. There are many other technologies for capturing CO2 from the atmosphere and other technologies. But to us, the one that is really shelf-ready and has a great potential to make an impact is through those -- capture from those emitters.

So when you ask about the types of investments that we'd be looking at making, the good news with Denbury is we've already made the vast majority of those investments. Our strategic Gulf Coast pipeline, that 24-inch line that runs across the Louisiana industrial corridor into Southeastern Texas, is right in the location where so many of these different projects are going to be developed. And so for us that investment has been made. We can tie into those projects and transport that CO2 to either an EOR site or a non-EOR captures or sequestration site.

But we don't -- so I don't see a huge investment at this time. I think there's investments on the sides of the industrial capturers, but that is typically scope that's borne by those companies. And the other side, most of the investment's already in place.

[Richard Tullis, analyst]

That's helpful. And then, just lastly for me, regarding proved reserves. Removing commodity prices from the equation, should we expect additional year-over-year decline at year-end '20 related to the base budget similar to maybe what we saw this year? Or in 2019?

[Matthew Dahan, executive]

Yes. This is Matt Dahan. Yes. I mean, as David pointed out, our production -- what our production guidance is, of course, those volumes are going to roll off in 2020. And then going forward, I mean, our production has been very stable. Our reserves have been very stable, and really looking at offsetting as CCA comes online, we're able to book reserves there. Hopefully, this year, when the pipe goes in and then some of these other projects that you see on the table, adding not only PDP production, but also, ultimately, some undeveloped reserves behind them, offsetting all that production.

[Operator]

We have reached the end of the question-and-answer session. I will now turn the call back over to John Mayer for closing remarks.

[John Mayer, executive]

That concludes -- before you go, let me cover a few housekeeping items.

On the conference front, we will be attending the Credit Suisse 25th Annual Energy Summit in Vail on Monday, March 2. The presentation for the conference 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 first quarter 2020 results on Thursday, May 7, and hold our conference call that day at 10:00 a.m. Central. Thanks, again, for joining us on today's call.

[Operator]

This concludes today's conference. You may disconnect your lines at this time. Thank you for your participation.