Denbury Resources (DNR) Philip M. Rykhoek on Q2 2016 Results - Earnings Call Transcript

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Denbury Resources, Inc. (NYSE:DNR)

Q2 2016 Earnings Call

August 04, 2016 11:00 am ET

Executives

John Mayer - Assistant Controller, SEC Reporting, Denbury Resources, Inc.

Philip M. Rykhoek - President, Chief Executive Officer & Director

Mark C. Allen - Chief Financial Officer, Senior Vice President, Treasurer & Assistant Secretary

Christian S. Kendall - Chief Operating Officer

Analysts

Tarek Hamid - JPMorgan Securities LLC

James A. Spicer - Wells Fargo Securities LLC

Gary Stromberg - Barclays Capital, Inc.

H. H. Hardee - RBC Wealth Management

Jeffrey Robertson - Barclays Capital, Inc.

Operator

Ladies and gentlemen, thank you for standing by, and welcome to the Denbury Resources Second Quarter 2016 Results Call. And as a reminder, this conference is being recorded. I'll now turn the conference over to John Mayer from Denbury's Investor Relations Group. Please go ahead, sir.

John Mayer - Assistant Controller, SEC Reporting, Denbury Resources, Inc.

Thank you, Kathy. Good morning, everyone, and thank you for joining us today. With me on the call from Denbury are Phil Rykhoek, our Chief Executive Officer; Mark Allen, our Chief Financial Officer; and Chris Kendall, our Chief Operating Officer.

Before we begin, I want to point out that we have slides which will accompany today's discussion. 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 events 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 Phil.

Philip M. Rykhoek - President, Chief Executive Officer & Director

Thank you, John. Good morning, everyone. Welcome to our second quarter call. I'm very pleased with the second quarter results on several fronts and continue to be encouraged by the constant improvement in our business as we forge a path forward to ensure the future success of Denbury.

From the outset of this downturn, we resolved to focus on factors that we could control and that would ultimately make Denbury stronger; namely, reducing costs, optimizing our business, reducing our debt and preserving our cash and liquidity. These four items have been and remain our primary objective in the building blocks upon which our future success will be based and I'm pleased and proud to say that we made meaningful and lasting positive changes and improvements in all of these fronts.

If you go to the next slide, one of the many indications that our business improving processes are working is that the production forecasting is generally becoming more reliable although we still haven't figured out how to predict or control Mother Nature.

For the second year in a row our Houston area floods were impacted by severe weather and I understand that in the second quarter this area had the highest quarterly rainfall in its 127-year recorded history. Chris will provide more detail as for the impact, but damage to our primary tank battery at Conroe and extensive flooding at Thompson caused us to shut-in both fields in mid-April and it reduced our second quarter production by approximately 1,450 BOEs per day and is expected to impact our annual production by about 675 BOEs per day. The production impact from these unforeseen events is significant and ongoing. We're currently working to restore full production, which is expected to be back online in Q3.

One other event that will impact 2016 production is the previously announced sale of our Williston Basin assets for $58 million. These non-core assets produced an average of approximately 1,300 BOEs per day during the first half of the year. This sale is expected to close within the next 30 days and that would expect to impact our annual production by approximately 500 BOEs a day.

So, as a result of the weather-related downtime and the pending sale, we are decreasing the midpoint of our production guidance by 1,000 BOEs a day. Other than that, production is on track and we expect to be at the midpoint of our adjusted guidance. Chris will provide you an update with more detail, but generally things are progressing as planned.

Moving on to the next slide, as mentioned previously, controlling our cost is and has been a high priority and we continue to make improvements in our overall cost structure. This slide reflects the cash cost per BOE for the last 18 months. These are the recurring total out-of-pocket cash cost to run our business, Including all costs, except for replacement cost or refining and development cost. As you can see from the slide, we have lowered these costs by over 25% since 2014 and 15% during the last 18 months.

At our field level, our cash cost during the most recent quarter totaled $21.64 per BOE with a balance of $10.68 per BOE relating to corporate overhead and interest. We estimate that our current planning and development costs are in the mid-teens so that would give us a field level breakeven in the mid to upper $30s and a fully loaded breakeven in the mid-to upper $40s.

LOE increased slightly on a per BOE basis this quarter primarily as a result of increased workovers, which we anticipated and suggested in our last call. Chris will talk about that also in a little bit.

Nevertheless, our overall cash cost came down by another $0.60 per BOE this quarter, as lower G&A costs, which are down 29% year-over-year on a per BOE basis, more than offset the slight increase in LOE. The overall downward trend in cash costs has been a big positive for Denbury in the last two years. It's a tribute to all of our employees who are working hard to do more with less.

As most of you know, our production is almost entirely oil, 96% of our total production this quarter. Because of this high oil percentage, our operating margin significantly benefit from increases to oil price. And by operating margins I'm talking about oil and gas, less operating costs, marketing costs and production taxes. As a result of the roughly $12 per barrel increase in NYMEX from Q1 to Q2, our operating margins increased almost the same amount, $11.26 per barrel.

As you will note, in our prior analyst presentations we outlined how the operating margin per BOE is competitive with or near the mean of our peer group even at the low oil prices we experienced during the first quarter. When oil prices increase, our margins will increase more than our peers because of our high oil weighting and therefore we would expect to move into the upper quartile of the peer group.

Said another way, yes, our expenses per BOE are high compared to the peer group but so is our revenue per BOE, and we think you must look at the combined impact of revenue and expenses when evaluating oil and gas companies, not just the cost side. If you do so, you will find our business is very competitive with our peers. In fact, our average gross margin per barrel this quarter was almost the same as two of the best well-known shale companies. And to take it one step further, the operating margin at one of our better fields, which is about $10 per barrel higher than our corporate average, was about the same as the operating margin from their best core assets. Why? Because we have such high revenue per barrel due to our high oil weighting and the location of our production.

While we are focused on reducing our overall costs, we have a concurrent focus on optimizing our business and improving our floods as we progress through our field-by-field reviews. We have begun compiling revised development plans and incorporating them into our comprehensive forecast as we begin to look forward into 2017 and beyond. And we should be ready to share those results when we release our 2017 guidance.

One thing I can share with you now, which has become evident in our preliminary analysis, is that we have eliminated almost all constraints with our CO2 supply or transportation. Our CO2 usage dropped by 53% in the last 18 months and the associated savings not only benefit our ongoing cost control initiatives and operating costs, but the reduced usage is very impactful when looking forward at longer-term models because historically CO2 or the bottlenecks and transporting it was often a limiting factor in our long-range plans.

We also anticipate that we will begin taking CO2 from Mississippi Power later this year, which will provide us with a significant and steady long-term supply of CO2 at a reasonable price. Once Mississippi Power is fully up and running, and assuming we maintain our current usage, the percentage of our CO2 coming from man-made as opposed to natural sources could increase from about 25% to date to 50% to 60%. As this proportion of man-made CO2 increases for our floods, result is that we become a net reducer of carbon and therefore we will become an increasingly positive environmental story. Obviously that will place us in a unique and potentially favorable position in our industry.

You will likely see a little higher CO2 price per MCF in our op cost as that percentage of man-made CO2 grows but that will be offset by savings in our capital program as we will need fewer new wells at Jackson Dome. We anticipate minimal capital spending on our CO2 sources during the next several years as a result of the anticipated increased anthropogenic CO2.

With regard to debt, which Mark will cover a bit more, we have done little since our exchange and repurchase program earlier this year which reduced our debt by $540 million or 16% since year-end. We plan to remain opportunistic in our debt reduction program, although our future activities will somewhat depend on our debt and equity trading prices. We do have $385 million of junior lien capacity left and roughly $155 million available to repurchase debt on the open market, based on the bank credit facility covenants.

We feel positive about our liquidity and improved debt metrics although we would like to do more to reduce our leverage and we'd expect to overtime. We have significant hedges in place through mid 2017, so if this recent dip in prices is sustained we are confident in our ability to keep our bank debt around current levels or lower and therefore protect our liquidity.

In summary, things are looking positive for the future, although of course we could always use a little help with the oil price.

So, with that introduction, I'll turn it over to Mark for more detailed review of our numbers.

Mark C. Allen - Chief Financial Officer, Senior Vice President, Treasurer & Assistant Secretary

Thanks, Phil. My comments today will summarize some of the notable financial items in our release, where I'll primarily be focusing on the sequential changes from the first quarter. I will also provide some forward-looking guidance to help you in updating your financial models to reflect our current outlook.

Starting on slide nine, our non-GAAP adjusted net income for the second quarter was $29 million or $0.08 per diluted share. This was significantly better than the analyst consensus estimates. On a GAAP basis, we had net loss of $381 million for the quarter.

As you can see from our GAAP reconciliation, the market value change in our derivative contracts resulted in a before tax non-cash loss of $150 million, primarily related to contracts that settled during the quarter as well as increasing NYMEX futures prices.

We also recorded another ceiling test impairment this quarter of $479 million at the trailing 12-month oil price used in our calculation was lower this quarter as compared to last quarter. Depending on oil prices and other factors, we could potentially have another write-down in Q3. However, at this time, we would not expect any such write-downs to be as significant as our Q2 write-down.

Another adjustment to our earnings this quarter was $30 million associated with legal settlements, of which $27.5 million related to our settlement with Evolution that we previously announced in connection with our settlement agreement to resolve all outstanding disputes and claims.

Also, we completed our privately negotiated debt exchange agreements in Q2 resulting in a $12 million pre-tax gain on debt extinguishment. The amount of actual debt reduction we achieved was much larger than the gain reflected this year. In fact, it was over $440 million. But based on the size of the concession we achieved from our noteholders, our accounting for this transaction created some unusual impacts that I will cover in more detail later.

Turning to slide 10, our non-GAAP adjusted cash flow from operation, which excludes working capital changes, was $93 million for Q2, up $36 million from the first quarter, which was primarily due to a $13 per barrel higher oil price realization this quarter. I want to point out that this number is not adjusted for special items during the quarter. So if you add back the $30 million in legal settlements, you would get a normalized adjusted cash flow number of around $120 million.

Our second quarter average realized oil price, excluding hedges, improved to $43 per barrel, up 41% from Q1. We recognized $52 million in cash receipts on settlements from our hedges this quarter which made our average per barrel realized price including hedges almost $53 per barrel compared to $43 per barrel last quarter or an increase of about 23%.

Slide 11 provides a summary of our realized oil price differentials relative to NYMEX oil prices. Our overall realized oil price average, $2.18 per barrel below NYMEX in Q2, which was $0.84 better than our NYMEX differential in Q1. Differentials improved across the board for all of our production areas as we saw LLS prices improved in our Gulf Coast and the general improvement in the oil markets as prices firmed up in Q2. We currently expect that our overall oil differential for Q3 should remain in a similar range to what we've seen for the first half of this year.

Moving on to the next slide, I'd like to review some of our expense line items. First, our LOE improved by $2 million or 2% from Q1. Chris will go into more detail on our LOE and our expectations for the rest of the year. We have continued to make great strides in this area.

G&A expense was $23 million for Q2 in line with our expectations and down from $34 million in the first quarter with the primary change being approximately $9 million of severance cost in the prior quarter. We currently expect that G&A will increase to the mid to upper $20 million range each quarter for the remainder of the year. This increase is principally tied to higher stock-based compensation and long-term incentive compensation that we recently granted in July under our customary annual grants to all employees, which was roughly six months later than the normal course as we moved to a mid-year cycle for these grants. For the second quarter, net G&A related to stock-based compensation was proximately $3 million. We expect this number to increase to between $6 million to $8 million per quarter for the second half of 2016.

Interest expense, net of amounts capitalized, was $36 million, a decrease of $6 million from Q1, which was due primarily to $7 million of interest in Q2 that was treated as debt reduction in connection with the accounting for our debt exchange transactions.

I will discuss this in more detail in just a minute when I cover our capital structure. But, going forward, we currently anticipate that approximate $13 million of our interest expense each quarter under our new second lien notes will not be reflected as interest expense in our financial statements.

Our interest expense was also impacted by the reduction in debt due to open market repurchases of our senior subordinated notes in the first quarter of 2016. This was partially offset by a $5 million write-off of debt issuance cost in conjunction with the reduction in our bank facility associated with our May 2016 re-determination. Capitalized interest in Q2 was just over $6 million, and we currently expect capitalized interest to remain around the same quarterly level for the remainder of the year.

Our DD&A expense in Q2 was $67 million, a decrease of $11 million from the first quarter, due primarily to the full cost ceiling impairment we reported in Q1 and lower production. With the additional impairment recorded this quarter, we expect our DD&A expense will be in the $55 million to $65 million range in the third quarter of 2016.

Our effective income tax rate for Q2 was below our statutory rate of approximately 38% due primarily to the full cost full ceiling test write-down recorded during the quarter. For 2016, we anticipate our effective tax rate will be between 36% and 38% with minimal or no current taxes.

On slide 13, we have our current summary of oil price hedges. Since our last quarter call, we have added some collars in the last half of 2016 and the first quarter of 2017 and we started to layer in some collar structures in the third quarter of 2017. We currently have approximately two-thirds of our estimated oil production hedged through the first quarter of 2017 and half of our production hedged in the second quarter of 2017. We may continue to add to these positions over time depending on market conditions.

Moving on to our liquidity and capital structure, liquidity on our bank line remains around $700 million. We have no near-term debt maturities, and our total debt principal was reduced by approximately $540 million through Q2 resulting from our privately negotiated exchange agreements and open debt market repurchases.

In May 2016, we exchanged approximately $1.1 billion of existing senior subordinated notes with a limited number of holders for $615 million of new 9% second lien notes plus 40.7 million shares of Denbury common stock. This resulted in a net reduction of $443 million in our debt principal.

In addition to the open market purchases of debt completed in Q1, we recently spent around $14 million to repurchase an additional $20 million of our senior subordinated notes. Although our debt principal was reduced by $443 million in the exchanges, the total debt balance for financial reporting purposes only reflects a reduction of $188 million as the level of concession we received from our noteholders required a unique accounting treatment. You can see what I'm talking about if you look at the details of our capital structure, which I believe is included on slide 23 in the Appendix.

Under this accounting treatment, a portion of future interest associated with the 9% second lien notes is reflected as an additional long-term debt rather than a gain on extinguishment. As a result, $255 million of future interest on the 9% second lien notes has been recorded as debt and will be reduced as semiannual interest payments are made over the next five years, which means that approximate $51 million of interest expense per year will not be reflected as interest expense in our financial statements.

Unfortunately, this distorts the actual interest and debt in our financial statements, but through our disclosures, we will reflect our actual debt principal and cash interest numbers to revive transparency and comparability.

My last slide covers the change in our bank facility borrowings since year-end 2015, which has increased from $175 million to $320 million. As you can see, our capital spending was $114 million for the first half of the year, including $13 million related to capitalized interest and acquisition costs, which was less than our $115 million of cash flow from operations before working capital changes.

As such, the primary drivers of our bank debt are our subordinated debt repurchases and working capital changes. The working capital changes are generally a result of the timing of interest payments, cash outflows to cover accrued capital, LOE and compensation that existed at the end of the year that was paid out in 2016. Based on our current projections, we anticipate that our 2016 year-end bank debt balance would be in the range of $275 million to $300 million.

And now, I'll turn it over to Chris for an update on operations.

Christian S. Kendall - Chief Operating Officer

Thanks, Mark. The second quarter of 2016 was another strong quarter for Denbury's operations. We maintained operating expenses at historically low levels, reached greater levels of efficiency in CO2 usage, and after adjusting for the extraordinary weather events in the Houston area, held production on track with our expectations. As Phil mentioned, our work on field development plans is progressing well and I'm excited about Denbury's broad portfolio of development opportunities, both within our existing CO2 floods as well as our future floods.

Starting with a look at operating costs on slide 17, our total LOE in the second quarter was at its lowest level in over six years right at $100 million, down $2 million from the first quarter, as we continued to focus on reducing each aspect of our operating costs. On a per BOE basis, LOE rose slightly from $16.23 in the first quarter to $17.04 per BOE in the second quarter, driven by the weather-related production downtime and increased workover activity. Non-workover expenses were flat with the first quarter at just over $15 per BOE. We continued to drive power and fuel costs lower, now at $5.02 per BOE through our focused efforts to optimize that major expense category.

Our unit CO2 cost rose $0.16 to $2.13 per BOE, primarily due to lower oil production volumes coupled with slightly higher CO2 royalty costs related to higher NYMEX oil prices as well as a higher percentage of industrial source CO2 in our supply basket as we drove our use of CO2 to low levels. On a cash basis, our second quarter CO2 cost was flat with the first quarter at $12.5 million and 31% below the $18.2 million spent in the second quarter of 2015.

With the sustained success of our cost reduction efforts, we are now targeting the lower half of our previously guided full-year LOE range of $17 to $18.50 per BOE, compared to our full-year 2015 LOE of $19.37 per BOE.

We continue to make great strides in optimizing the use of our strategic CO2 assets. As you see on slide 18, our total CO2 injected volumes are down 53% by over half 0.5 billion cubic feet per day from the first quarter of 2015. Our measure of CO2 efficiency, the quantity of CO2 required to produce a barrel of oil has improved by 50% over the same timeframe. We are very encouraged by the performance of our tertiary assets and have not seen any significant negative production effects from lower CO2 use.

As we use even less CO2 from Jackson Dome and extend the life of this strategic low-cost CO2 asset, we'll be well-positioned to enhance Denbury's growth by taking on more cost advantage development with the same base CO2 resource. In addition, as Phil mentioned, our supply strength will be further enhanced by the new volumes that we expect to begin receiving from Mississippi Power later this year.

Turning to production on slide 19, I'll start with some more detail on the Houston area weather events. As I mentioned in our first-quarter call, a series of strong thunderstorms in April damaged a primary tank battery in Conroe and flooded the Thompson field. While the Conroe repairs preceded as planned, in May additional significant rainfall caused historic flooding at Thompson to levels not seen in over 100 years. Once these floodwaters receded, we began making the repairs needed to restore production and expect to have nearly all affected production back online this month. Because these repairs have carried past the second quarter, we estimate a production impact of around 1,100 BOE per day for the third quarter and a combined annual production impact of around 675 BOE per day for both events.

And just to emphasize how extraordinary the recent flooding in Thompson has been, each of the three separate flood events in the 13-month period, beginning with the May 2015 flood, reached levels not seen in over 20 years. And as I mentioned, the most recent flood crested at a level that was last seen more than a century ago.

Looking at total production, we produced just over 64,500 BOE per day in the second quarter, about 7% below the first quarter. Aside natural production declines and the weather impact I just discussed, most of the remaining decline was due to seasonal CO2 facility processing constraints at Tinsley, downtime at Oyster Bayou for workover activity and maintenance, and the amount of production allocated to a net profit interest at Cedar Creek Anticline based on improved field profitability.

Even including the impact at Tinsley and Oyster Bayou that I just mentioned, our tertiary fields delivered strong performance during the second quarter with just a 3% overall decline from the first quarter. Production from our other key tertiary fields, Delhi, Hastings and Heidelberg was essentially flat quarter-on-quarter as our teams have done a great job managing those floods. And Bell Creek reached a new tertiary high at 3,160 barrels per day for the quarter where we continued to optimize Phase 3 of the flood and are just starting to see a response from Phase 4.

Our NGL project at Delhi is on budget and approaching completion with first production expected on schedule by the end of this year. I'm looking forward to the multiple enhancements this project will bring to the field. In addition to the NGL sales, the field will benefit from a higher purity CO2 stream that will improve the flood efficiency and we will self generate more electrical power using natural gas delivered by the new plant.

Looking at total production for the remainder of the year, we're well on our way to restoring the weather impacted production and I'm confident that we're on track to meet our adjusted full-year guidance.

I'd also like to give a quick update on our production that is shut-in as either uneconomic to produce or to repair. At the end of the first quarter, we had 2800 BOE per day shut-in, about half of which was economic at $50 per barrel or below.

When we approached our price threshold during the quarter, prices did not sustain that level and as a result, we brought only a small amount of production back online and now have 2600 BOE per day shut-in due to economics, about 40% of which is economic at $50 per barrel or below, increasing to about two-thirds economic at $60 per barrel and below with the remainder economic above $60 per barrel.

Once the Williston sale closes, the shut-in quantity will reduce to around 2400 BOE per day as we have about 200 BOE per day shut-in there. As a reminder, much of this production can be brought back online quite quickly once price is justified.

Finally, our 2016 capital development program is on track. At midyear, we spent just over half of our capital budget, around $101 million, excluding capitalized interest and acquisitions, down about 50% from the $200 million spent in the first half of 2015. We expect full year capital expenditures of around $200 million, right in line with our plans.

That completes the operations update and now I'll turn it back over to John.

John Mayer - Assistant Controller, SEC Reporting, Denbury Resources, Inc.

Thank you, Chris. That concludes our prepared remarks. Kathy, can you please open up the call for questions?

Question-and-Answer Session

Operator

Certainly. And our first question will come from Tarek Hamid with JPMorgan. Go ahead, please.

Tarek Hamid - JPMorgan Securities LLC

Good morning.

Philip M. Rykhoek - President, Chief Executive Officer & Director

Good morning.

Christian S. Kendall - Chief Operating Officer

Good morning.

Tarek Hamid - JPMorgan Securities LLC

Can you touch a little bit more on the Thompson Field restart? Sort of doing the math it looks like we should expect production resume in September. If you can sort of confirm the timeline there and also any incremental cost we need to assume with the resumption of production there?

Christian S. Kendall - Chief Operating Officer

Sure. So looking at Thompson, like I mentioned earlier, the production is being brought up back online right now and through this month and probably into September. And so I think that your math is about right. We've looked at some of the costs and we are spending a bit more on contract labor but I really don't see the cost is being significant when we look at the big picture of our performance. I don't expect it to really show up in our overall financials.

Tarek Hamid - JPMorgan Securities LLC

Great. And then with some of the efficiency savings you've got on CO2 fields, sort of how do you weigh as you think about the budget for 2017 on CapEx, incremental CO2 floods versus trying to bring back some of the shut-in production, is it an if/and or is it a potentially both depending on the commodity levels?

Christian S. Kendall - Chief Operating Officer

I'll start and I'll let Phil maybe finish it out. But I think what we're going to do is look at every opportunity to create value here going into 2017. We have a portfolio of opportunities that we can bring forward on the capital front. We have the shut-in production that has its own set of economic factors that'll really help us drive what to bring on and how much to spend on each.

Just a reminder on the shut-in production, a lot of the shut-in production doesn't really require additional capital to bring back on, it's just needing to meet a threshold where we can turn the right economic results for those particular areas of the field. And so that could be done just when we reach a threshold of production.

Philip M. Rykhoek - President, Chief Executive Officer & Director

Yeah. The only thing I might add is we're very focused on economics. So it really depends on which ones make the most value. So we'd love to increase our EOR production, but hey, if we can get conventional production that makes more money we're happy to do that. So we're looking at value. So we'll just analyze that based on what it cost to bring it on and what return we get from that.

Tarek Hamid - JPMorgan Securities LLC

Got it. Thank you very much.

Philip M. Rykhoek - President, Chief Executive Officer & Director

Thanks.

Operator

Thank you. Our next question will come from James Spicer with Wells Fargo. Go ahead, please.

James A. Spicer - Wells Fargo Securities LLC

Yeah, hi. I wonder if we could get your latest thoughts on maintenance capital spending, i.e. capital spending required to stabilize production and then what we might expect as a decline rate in 2017 if you were to maintain spending at the current rate of $200 million?

Philip M. Rykhoek - President, Chief Executive Officer & Director

Yeah. Well, as we mentioned we're really working on our plans now. So this is just maybe a little bit preliminary. Historically, I think we used to say it took $400 million to $450 million to keep production kind of flat. And I'm very confident that we've improved on that. I don't know that I can give you a precise number date, but I'd say, it's somewhere between $300 million and $400 million. So that kind of gives you – it's kind of wide range, I understand, but until we kind of work through some of the numbers, that's probably the best I can do today. So if we were to only spend $200 million next year, I think you'd probably see a somewhat similar decline, single digits for sure, but there would be some decline at $200 million.

James A. Spicer - Wells Fargo Securities LLC

Okay. That's very helpful. Thank you.

Operator

Thank you. Our next question will come from Gary Stromberg with Barclays. Please go ahead.

Gary Stromberg - Barclays Capital, Inc.

Hi. Good morning.

Philip M. Rykhoek - President, Chief Executive Officer & Director

Good morning.

Gary Stromberg - Barclays Capital, Inc.

Just a question on the revolver. I know it caps on repurchases, I think the $225 million. Can you just let us know where that basket stands today?

Philip M. Rykhoek - President, Chief Executive Officer & Director

I think we're around $155 million. I think there is around $155 million.

Gary Stromberg - Barclays Capital, Inc.

$155 million of $225 million has been used or is available?

Philip M. Rykhoek - President, Chief Executive Officer & Director

Available.

Gary Stromberg - Barclays Capital, Inc.

Got it. Okay. And then can you just give us some thoughts around capital structure over the next couple of years? You have the $615 million of the 9s issued in exchange for subordinated debt. What are your thoughts on using the remaining $400 million of that second lien debt for further debt reduction?

Mark C. Allen - Chief Financial Officer, Senior Vice President, Treasurer & Assistant Secretary

Yeah, I think as we've stated before and continue to state that we would like to continue to find ways to reduce debt. That is one vehicle we have available to us. So we'll likely continue to pursue all of our options there.

Gary Stromberg - Barclays Capital, Inc.

Okay. And then I guess, last one for me is, with the sale of the Williston Basin assets, will that have an impact on the borrowing base and any preliminary thoughts for the borrower determination?

Mark C. Allen - Chief Financial Officer, Senior Vice President, Treasurer & Assistant Secretary

Yeah. The amount of value attributed to that under our bank borrowing base was very minimal. So I wouldn't expect that to have any significant impact. Our next redetermination will be coming up early part of November. The biggest factor will be whatever the banks set their price decks at and so that's going to be the biggest factor. I do think things are generally up from where they were in the spring, however with the recent dip in prices here, it could bring some more conservativeness from the banks into the redetermination process this fall. But right now, we don't expect any significant changes.

Gary Stromberg - Barclays Capital, Inc.

Okay. Great. That's all I have. Thank you.

Operator

And we'll go next to Will Hardee with RBC. Please go ahead.

H. H. Hardee - RBC Wealth Management

Yes. Could you give me some clarification on the Thompson Field. You say potentially the September start up production will resume. Can you give me a level that you all are looking for at the end of the year and how does that compare to what it's been prior to the flood?

Christian S. Kendall - Chief Operating Officer

Will, this is Chris. And what I'd say is that if you think of the field, it's spread out over a pretty broad area and our teams are making repairs across the field and bringing it on incrementally week after week. And so while we expect most of the repairs and the production to be back online this month, there is some that will come into September and it's something that we're watching day-by-day and week-by-week and ultimately we expect it to get back to its pre-storm level of about 1,300 BOE per day.

H. H. Hardee - RBC Wealth Management

Okay. And then just on the Conroe Field, same question.

Christian S. Kendall - Chief Operating Officer

Conroe Field is generally ahead of the Thompson Field. We didn't have the same level of weather impact, certainly the initial storm damage. And the historic levels at Conroe have been in the 2,800, 2,900 BOE per day. So that's the target that we're heading that towards.

H. H. Hardee - RBC Wealth Management

Okay. Thank you very much.

Operator

Thank you. Our next question comes from Jeff Robertson with Barclays. Go ahead please.

Jeffrey Robertson - Barclays Capital, Inc.

Thanks. Maybe for Chris or Phil. If you look at trying to grow volumes and put incremental capital to work, can you talk a little bit about the opportunities on non-tertiary assets to grow volumes, and how those cost might compare to either increasing CO2 or investing more in tertiary to try to grow tertiary volumes, and also the time that is needed under the way you all are currently injecting CO2 to realize some growth in tertiary volumes?

Philip M. Rykhoek - President, Chief Executive Officer & Director

On the tertiary, in 2016 most of what we're doing is maintaining and we're not really doing a lot of expansion, although expansions are generally pretty accretive and work at pretty low prices. So, 2016 we kind of had to focus our capital budget on the NGL plant at Delhi that took such a big chunk that for the most part, most of the other work was kind of maintaining the floods, some conformance work and kind of minor things.

We can expand the floods at pretty low prices and it just depends on the economics of a conventional well. They could be competitive, I mean, they could be better, they could be worse. It really just depends on where it is and what the well is. The wells at CCA that we drilled to enhance the water flood have been pretty economic at relatively low prices so they would be right there and competitive with expanding the floods.

To start a new flood from scratch, we probably need something at least in the $50s per barrel and probably more like $60 per barrel or something like that for that to make as much sense because there is just a little bit of upfront capital there. There is a lot of work left at half a dozen of our fields that we can focus on as prices stay low.

Jeffrey Robertson - Barclays Capital, Inc.

Thanks, Phil.

Operator

Thank you. And we have no one else queuing up. Please go ahead with any closing remarks.

John Mayer - Assistant Controller, SEC Reporting, Denbury Resources, Inc.

Before you go, let me cover a few housekeeping items. On the conference front, Mark Allen will be attending EnerCom's Oil & Gas Conference in Denver, Colorado the week of August 15. In addition, Phil Rykhoek and Chris Kendall will be attending the Barclay's CEO Energy Power Conference in New York City, the week of September 6. Further details of these conferences and the webcast for the related presentations will be accessible through the Investor Relations section of our website at a later date.

Finally, for your calendars, we currently plan to report third quarter 2016 results on Tuesday, November 8, and hold our conference call that day at 10:00 A.M. Central. Thanks again for joining us on today's call. We look forward to keeping you updated on our progress.

Operator

Thank you. Ladies and gentlemen, that does conclude our conference for today. Thank you for your participation and choosing AT&T Executive Teleconference. You may now disconnect.

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