Denbury Inc.

Thank you, Cathy. Good morning, everyone, and thank you for joining us today.

With me on the call from Denbury are Chris Kendall, our President and Chief Executive Officer; and Mark Allen, our Chief Financial 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 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.

Good morning, everyone, and thank you all for joining us today. I'd like to start by outlining my priorities for Denbury.

Then I'll dive into the second quarter results and our plans for the rest of the year. Internally, I often talk about the three fundamentals I believe we must deliver for Denbury to be successful.

We must profitable, we must be sustainable, and we must grow. While these are certainly interdependent, they are each individually absolutely critical to our success.

As we pursue these fundamentals, my first and most immediate priority is realigning Denbury for profitability and sustainability in a long term $50 oil price world. The keys to this realignment are reducing our cost structure, maximizing the value of our assets, and improving our balance sheet.

To reduce our cost structure, we are intensifying our effort to challenge every dollar we spent across the company. I expect that the bulk of our cost savings will come from our G&A and LOE spend.

As this is a work in progress, we have not incorporated any reductions into the projections and guidance that we are providing today. But I plan to share more details on our progress in the near future.

To maximize the value of our broad asset base, we must consistently execute at a high level and thoroughly exploit the potential of our assets. Through a focus on excellence and execution, we'll improve field reliability, increase project delivery consistency, and above all, deliver strong safety environmental performance.

We have already made good gains that I'll share with you in the call, but I leave we have – but I believe we have the potential to improve even further. As we talk about maximizing the value of our assets, it's important to remember that our currently producing assets comprise a portfolio of some of the most prolific conventional oil fields in North America.

And we continue to find new ways to enhance their performance. Later in the call, I'll tell you about our highly economic Hastings flood redevelopment project that was completed in the second quarter.

I'll also tell you about some 1of the other high return projects we've planned within our currently producing assets. In addition to maximizing the value of our producing assets, we are taking advantage of opportunities with our non-productive assets.

As an example, we've expanded the acreage included under our previously announced plans to sell non-productive surface acreage in the Houston area. Based on an updated market analysis and the interest we've seen, we believe this land has greater value than previously expected, increasing the opportunity to improve our liquidity with no impact to our operations.

The marketing process will take place over the next several quarters. By realigning our cost structure and maximizing the value of our assets through consistent execution and exploitation, I believe we will go a long way toward making Denbury profitable and sustainable in a long term $50 oil price world.

Again this is my immediate priority. While we have adequate liquidity and our debt service is manageable with no near term maturities, to be considered sustainable in a $50 oil price environment, we must improve our balance sheet.

Improving our balance sheet can take many forms. And there is not likely to be one silver bullet that immediately fixes everything.

But we'll continue to seek opportunities to meaningfully improve our balance sheet. My second high level priority is to illuminate Denbury's value, more specifically, the significant value that I believe is not recognized by the market.

A key example of this is our substantial CO2 supply and distribution capability in the Gulf Coast. Another is the tertiary flood potential at Cedar Creek Anticline, which by itself holds potential EOR reserves greater than Denbury's entire proved reserve base and is just 110 miles away from our Greencore Pipeline.

I'd also like to point out several unique qualities I see in Denbury that impact our value and that you'll see reflected in our quarterly results as well as in our path forward. Our product mix is consistently heavily oil weighted at around 97%, one of the highest levels in the industry.

As an investor looking for long term oil exposure, you will not find a better positioned company. Our strong asset base has a low decline rate.

And even that low decline can generally be mitigated through a low level of incremental capital investment. Our exposure to cost inflation with increasing industry activity is minimal and disconnected from the rest of the industry, as the services that we need for our business are both geographically distinct from the high activity areas of the country, and the services themselves are different from those in high demand.

Another one of Denbury's great characteristics is our ability to significantly flex our capital spend with only a minor near term impact on production. Looking at where oil prices are and what we've accomplished so far this year, we've decided to reduce our 2017 full-year capital from $300 million to $250 million.

Our strong production and project execution performance has put us in position to meet or exceed the midpoint of our prior production guidance, even before including production from our recent acquisitions. When we include those acquisitions, we now project a full year production range of 60,000 to 62,000 BOE per day.

Now let's move on to the second quarter. The second quarter was very strong for Denbury.

Production was on track with our expectations, field level cash costs per BOE were down by over $1 from the first quarter, and overall cash costs were down by over 4% from the first quarter. Project execution in the first half of the year was exceptional, highlighted by our Hastings redevelopment project that was completed on budget and on schedule.

On the A&D front, we closed the Salt Creek acquisition at the end of June. Looking to the remainder of 2017, I expect production from Hastings to increase with continued response from our redevelopment of that flood.

Phase 5 development at Bell Creek should be completed this month. And we should have an initial production response from that project around the end of the year.

Another nice project that will be completed in the fourth quarter is a recycle facility expansion at Oyster Bayou that should boost production there around year-end. The West Yellow Creek development should also be completed, with first production expected around year-end as well.

Finally, our Grieve development is progressing on schedule for a mid-2018 start-up. Combined, all this work should position us to deliver a year-on-year production increase in 2018.

Before I go deeper into our production performance, I'd like to provide you a bit more information on the Hastings redevelopment that I've mentioned. And you can see more detail on Slide 6.

One of the main fault blocks in Hastings – we call it fault block B/C – had not performed as we'd hoped since we started the flood there in 2014. Our development team looked at the past performance and multiple options to improve recovery and recommended a complete conversion from a typical pattern style layout with simultaneous CO2 injection into multiple strata, as we've shown in the graphic on the left of the slide, to what we call a top-down flood with dedicated producers as shown in the graphic on the center of the slide.

The conversion consisted of utilizing 34 wells from the existing flood along with 22 additional wells and all the flow lines and facilities work required to make the change. Our modeling predicted a significant and sustained production increase.

We began project execution at the beginning of January. And the project was completed on budget and on schedule in June.

As you can see in the production chart in the upper right, response was nearly immediate with gross production from the fault block increasing by over 1,700 barrels per day. We expect production to continue to increase as the fault block responds to the new flood configuration.

When I discuss our CO2 usage later, most of the increase that you'll see is associated with this very exciting work at Hastings. Project economics on this $26 million investment are projected to have an IRR above 100% at today's prices.

This project is a powerful example of the type of improvements we can make in these great oil fields, improvements that are low risk, highly economic, and capital efficient. Also at Hastings we recently closed on the acquisition of a 25% reversionary interest previously held by Venoco, the party we originally purchased Hastings from with a purchase price of around $500,000.

While not an immediate cash flow impact, this is a great pickup and should further enhance Hastings' value to Denbury in the coming years. Moving to our total production on slide 7.

I'd like you to first take a look at Oyster Bayou's performance, both compared to the first quarter and even looking all the way back to the second quarter of 2016. Production in this field, which was previously in decline, has instead increased over the past year.

We achieved this increase mainly through continuing to optimize the operating pressure of the surface equipment, improving facility uptime, and making some low cost enhancements to our compression throughput capacity. As I mentioned earlier, we plan to further enhance throughput capacity and increase field production with a highly economic recycle facility expansion project around the end of this year.

Looking at our overall production picture, total production for 2Q averaged just under 60,000 BOE per day, flat with first quarter production levels and in line with our expectations. As you'll see in the table on Slide 7, in addition to what I just mentioned about Oyster Bayou, production increased from the first quarter at Hastings, Heidelberg, and our Gulf Coast non-tertiary fields and was held flat at Delhi and Cedar Creek Anticline.

We are also optimizing production at our Gulf Coast non-tertiary fields, specifically Conroe, Webster, and Thompson. And I expect combined production from those fields to increase in the second half of the year.

As I mentioned earlier, Phase 5 at Bell Creek will be completed this month. And we expect to see a response there around year-end.

And we should begin production from West Yellow Creek around that time as well. Finally, the acquisition of working interest in Salt Creek is expected to add just over 1,000 barrels per day to our average production rate for the year.

Overall, I'm very pleased with what both the field operations teams and the technical teams have accomplished to optimize our production with limited capital. And the results are evident in what I'm showing you today.

Looking at operating costs on Slide 8. LOE in the second quarter was a bit lower than expected at $111 million or $20 per BOE and was down about $3 million from Q1.

Most of this decrease was due to lower CO2 cost, which was reduced mainly due to the combination of lower oil prices and a lower utilization of industrial source CO2. Looking forward, we project unit LOE will remain relatively flat in the third quarter, then decrease in the fourth quarter with the full year expected to be near $20 per BOE.

Briefly looking at Slide 9 with details on our CO2 utilization. Our total injected CO2 volumes in the second quarter increased as expected to 608 million cubic feet per day, about 30 million cubic feet per day above the first quarter level.

We anticipate CO2 usage will continue to rise in the second half of 2017 as we inject additional volumes to support growth in some of our existing tertiary fields, mainly as I mentioned earlier, at Hastings as well as at Bell Creek with a Phase 5 expansion. CO2 cost averaged $0.38 per MCF during the second quarter, down about $0.03 from the first quarter.

Although we began receiving small volumes of CO2 from Mississippi Power's Kemper County Plant during the first half of 2017. In June Mississippi Power announced a suspension of activities involving the lignite coal gasification portion of the Kemper County facility.

Based on this information, we don't expect CO2 deliveries from Kemper in the near term. There is no conclusive answer to Mississippi Power's long term plans for Kemper at this time.

But it is possible that they may decide to permanently shift the plant to natural gas fuel instead of coal, which would eliminate this source of CO2 to Denbury. If this were to occur, we are still very confident in Jackson Dome's ability, together with our other anthropogenic sources, to fully support our plans.

Jackson Dome is currently producing at less than 60% of its capacity, mainly due to the CO2 use efficiencies we've gained over the past few years. Turning to our 2017 capital program on Slide 10, we spent $71 million in development capital during the quarter, including the work at Hastings that I spoke about earlier, bringing our year-to-date development expenditures to approximately $125 million, on track with our revised spending level of $250 million.

As I mentioned previously, based on the efficiency of our recent investments and in light of the lower prices we've seen since setting the budget, we decided to reduce our 2017 full year capital budget from $300 million to $250 million, consisting of $195 million of development capital, plus $55 million of other capitalized costs. The capital budget reduction was accomplished mainly by deferring a few projects primarily associated with development work at Heidelberg and at Delhi.

These projects have very attractive rates of return at current prices. And we plan to move forward with them as soon as capital is – as soon as capital was available, most likely in 2018.

Before I wrap up, I'd also like to update you on one additional matter. We previously stated we were in the process of searching for a new Chief Operating Officer to assume my previous role.

In conjunction with my transition to CEO, I have reevaluated and realigned our operations leadership team. And I believe we have an exceptionally strong team leading our operations.

This team is well suited to drive all our objectives moving forward. And I don't see the business need to replace the COO position at this time.

Now I'd like to turn it over to Mark to update you on the financial side of the business. After Mark speaks, we'll open the lines for any questions.

Thank you, Chris. My comments today will summarize some of the notable financial items in our release, primarily 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 12.

On a GAAP basis we recorded net income of $14 million for the second quarter. But after excluding noncash fair value commodity derivate adjustments, we realized non-GAAP adjusted net income of $8 million from the first quarter with the increase primarily due to lower costs.

On Slide 13 our non-GAAP adjusted cash flow from operations, which excludes working capital changes, improved by $3 million from the first quarter, due primarily to lower costs. But offset in part by a lower current income tax benefit in this quarter.

Our second quarter average realized oil price before hedges was $47 per barrel, a 6% decrease from the realized prices in the first quarter. When you include the impact of our hedges, our per barrel realized price was around $45 for both periods.

And our combined revenues and commodity derivative settlements were consistent between the first and second quarters of 2017 at $245 million. Slide 14 provides a summary of our realized oil price differentials relative to NYMEX oil prices.

Our overall realized oil price differential improved by roughly $0.50 per barrel from the first quarter to slightly over $1 below NYMEX prices for this quarter. This is the lowest differential we have had since the third quarter of 2015.

We currently expect our overall oil differential for the third quarter of 2017 should remain in a similar range to what we realized in the second quarter, in the minus $1 to [minus] $1.50 per barrel range. Moving to the next slide.

I'd like to review some of our expense line items. Since Chris already covered LOE, I will start with G&A.

Our G&A expense was $26 million for Q2, slightly below the $28 million in Q1. This slight decrease was primarily due to lower compensation related costs, partially offset by compensation associated with retirement of our previous Chief Executive Officer.

For Q2 net G&A related to stock based compensation was approximately $5 million. We currently expect that our G&A will continue to be in the mid-$20 million range, roughly $25 million for the third and fourth quarters with stock based compensation averaging between $4 million to $6 million.

Net interest expense was $24 million this quarter, down $3 million from last quarter due to higher capitalized interest. Additional information on our interest expense and cash interest is shown in the lower portion of this slide.

We currently expect our capitalized interest to be in the $5 million to $8 million range for the third and fourth quarters of 2017. Our DD&A expense this quarter was $51 million, unchanged from the first quarter.

Going forward, we expect our DD&A expense will increase to around the $55 million range or slightly higher for the third and fourth quarters of 2017. Our effective income tax rate this quarter was 42%, slightly higher than our 38% estimated statutory rate, due primarily to the impact of alternative minimum tax credits recorded during this quarter, which we expect to utilize in generating a tax refund for 2017 and 2018.

For the remainder of 2017 we currently anticipate our tax rate will be somewhat higher than our statutory rate, based on volatility for stock compensation items and the impact of alternative minimum tax credits. However, we still anticipate little or no current income tax expense.

Slide 16 details the current summary of our oil price hedges. Since our last quarter call, we have added to our hedge positions for the remainder of 2017 and 2018, utilizing a combination of fixed price swaps and three-way collars.

For 2018 these hedges represent roughly 40% of our second quarter of 2017 production levels. We plan to continue adding to our positions over time, depending on market conditions.

Moving to our balance sheet. We had total debt principal of approximately $3 billion as of June 30, 2017, with $490 million outstanding on our bank credit facility and nearly $500 million of remaining borrowing base availability.

As you may recall, in the spring bank line redetermination, we revised our covenants to remove any covenant concerns through the remaining term of our facility in December of 2019. Our cash flow from operations before working capital changes was essentially on par with our capital expenditures for the first six months of this year, therefore, a $189 million increase in bank debt from year-end 2016 was due primarily to $89 million for the Salt Creek and West Yellow Creek acquisitions; $50 million for working capital outflows, which we expect should mostly reverse by the end of the year; and $39 million due to other debt reductions with the major item being interest on our second lien debt that is treated as a reduction of debt.

When we set our capital expenditure balance at $300 million early this year, we estimated that our spending would be balanced with cash flow at an oil price that averaged in the low to mid-$50 per barrel. As oil prices have been lower through the first half of this year and are currently projected around $50 for the remainder of this year, we decided to lower our estimated capital spend by around $50 million, bringing our capital spend and estimated cash flow closer into balance.

Based on our projections, we would expect to end the year with bank debt between $425 million to $475 million and availability on the bank line approaching $550 million. In addition, as Chris mentioned, we have signed an agreement to be in actively marketing for sale certain non-productive surface acreage ideally suited for commercial development in the Houston area, which we anticipate would be used to pay down a portion of the outstanding borrowings on our bank credit facility within the next 12 months.

The next regularly scheduled borrowing base redetermination is set to occur on or about November 1, 2017. And now I'll turn it back to John for some closing comments.

Thank you, Mark. That concludes our prepared remarks.

Cathy, can you please open the call up for questions?

Good morning, Chris, to you and your team over there.

Good morning, Charles.

I'd like to ask about that Hastings flood and specifically Slide 6. And you have to forgive me, I paid attention to what you were talking about, but I don't think I got it all with what you guys are doing there.

So I hope you can elaborate on what you're doing. And specifically or maybe as a follow-up, if this new kind of development concept, this new pattern, flood pattern has any applicability for other assets in your portfolio?

You bet, Charles. Thanks for the question.

So if you go back to Slide 6 and just kind of look at our two graphics there. And what we're representing on the graphic on the left side, what we called previous, is where – so Hastings is a Frio flood to where you have this great reservoir that has stacked pay throughout.

And so what our previous configuration did really was injecting CO2 into multiple horizons simultaneously and then producing from multiple horizons simultaneously as well. And that's what we're trying to show on the left side.

Now what happens in some of these cases where you have variability between the rock quality in those different horizons is that the CO2 may move very quickly through some of the higher quality rock. And when you're injecting into one wellbore, then the CO2 is going to go that way and preferentially avoid maybe the lower quality rock, which still has great remaining oil saturation.

And so that's what we're showing with the graphic on the left. So what we did to change this – and you noted that we did add a couple dozen wells that generally existed in the field and had to be configured to produce this way.

But rather than having the injection into the multiple zones, we are targeting injection into zones where we can also target production from the same zone. So it takes more wells.

But it's much more efficient. And that's kind of in a nutshell how I see that.

Now your second question about applicability to other fields I think is a great question, because what I see here is where we have stacked pays, and you really want to maximize the sweep efficiency that you get in each reservoir, this is a great approach. And so we're already down that road looking at exactly the question that you asked.

Don't have any examples to provide yet. But certainly we have other Frio floods around and including Oyster Bayou, off to the east side of Houston.

Got it. So if I understand you, Chris.

Basically you had open perfs for, let's say, all three of those zones in your injector well. And you had – down road you had open perfs to all three of those zones in the producer.

And I guess it makes sense that the highest permeability zone was taking all of the flood and producing.

That's exactly right.

Okay. Got it.

Last quick follow-up. You mentioned that you expect growth year over year – oil growth year over year at 2018.

Is there any – is it just a positive number? Or can you give some idea of what that – whether it'll be sequential growth?

Any added color there?

I see – we're not – so certainly we're not ready to come out with our 2018 production forecast yet, Charles. But I see it being sequential growth.

I see it not – I see it being positive. Really just not ready to dial in what that number is yet.

But I do see us in a position to deliver more in 2017 than we did in 2016 – or 2018 than we did in 2017.

All right. Right.

Thanks, Chris.

All right. Thanks, Charles.

Good morning.

Good morning, Tarek.

Morning.

On the Houston area asset sale could you just elaborate a little bit more kind of on the timing and process there? And then that $425 million to $475 million revolver number, I assume that does not include any proceeds from the asset sale in it?

You bet, Tarek. So I'll talk about the Houston asset sale.

And then I'll turn it over to Mark on the revolver. So what we're looking at in this Houston area asset sale that we've expanded this quarter is property that is around our Conroe Field north of Houston and specifically some property that is east of The Woodlands and a desirable area there.

As well as some property around our Webster Field south of Houston that is along the frontage on I-45. And that's a process that is in place.

As I mentioned, we've expanded it in this last quarter to include that – mainly that Webster property. And as that process works, I do see it taking several quarters to really go through every step of the way.

But we are excited about what we have there.

Sure and yeah. So what we plan or would expect within the next 6 months to 12 months.

We're obviously just getting into the process to consummate a sale. And as we have stated, we would expect to use the proceeds from that to pay down our revolver.

When we first discussed this, it was in relation to the Salt Creek acquisition, and said we could – thought we could recover at least that much and more. And so our expectations are continuing to increase.

And so that's how we would expect to apply the proceeds to the revolver some time over the next 6 months to 12 months.

So that's not – it's not assumed in the $425 million to $475 million?

No. That's just where we would expect to end the year.

Great. And then on the Cedar Creek fields, obviously an enormous resource base there.

Could you just talk a little bit about kind of how you think about sort of the cost and timeline to sort of bring EOR to that field? And is that sort of an opportunity for JV capital?

I guess just how are you thinking about it?

So, Tarek, I absolutely think it's an opportunity for JV capital. To me when I look at it and across our whole portfolio, just the giant 5 billion barrel plus in-place resource we have there is too big to not really focus on.

Also being so close to the termination of our CO2 line there at Bell Creek, as I mentioned, just another 100-plus miles to reach the field makes it tantalizingly close. So what we've done through the downturn is really continue every bit of the process that is needed to permit the pipeline and the work that we'll need to do in the field.

So that's gone on over the past couple years in any case. And really what I see us doing now is, first of all, making it work in a $50 world.

And so we are working through our development planning to look at economics in a $50 world. We don't want to be waiting for some higher price.

I am encouraged by the improvements in differential we're seeing up north. And I think that there have been some good changes there that I hope we'll sustain for the long haul.

But as we move forward to planning how we'd actually fund the project, there's some pieces of it, specifically that initial pipeline piece that I think are well suited to a JV type of arrangement.

Got it. And just last one for me, you talked a little bit about debt reduction.

Do you sort of have any kind of target in terms of total quantum of funded debt you're supposed to run the business with in a $50 world that you could talk about?

Tarek, this is Mark. I think when we think about debt, we primary think about some of the metrics, debt to EBITDA.

In order to have a conforming loan under the bank regulations these days, you're looking at something that's 3.5 times. And obviously we're well north of that today.

So obviously that's the first priority is to get back into a situation where we can be in a confirming or close to a conforming position. Longer term, obviously we want to do better than that.

But short term we want to get back to where we can be respectable and considered sustainable. And so I think most people would point to that as being close to that.

So...

Got it. Thank you very much.

Thanks, Tarek.

Yeah. Great.

Thanks. Chris in the release you highlight that felt – or feel Denbury holds significant value that's not recognized by the market.

You've given us a good update on the surface land in Houston, certainly is the first step. But can you kind of give us a sense on what other things you may be considering?

I mean are you reviewing all assets in the portfolio, cap structure, what have you?

Sure, Paul. So, a couple of the additional areas that I think about a lot, and that's in addition to even just Cedar Creek Anticline that we just talked about.

Number one is exploitation of other horizons in the fields that we currently have. And so that's a process that we've been going through over the last, I'd say, nine months or so.

And we're starting to build a portfolio that I think is quite interesting. Obviously, we haven't shared it publicly yet.

But I do know that we have some capital still allocated to spend this year on testing some of that. So I think that's a piece that over time is going to increase.

The other one that I mentioned briefly is the CO2 supply and distribution capacity that we have on the Gulf Coast. One of the knock-on effects of the efficiencies that we've gained in our use of CO2 in the Gulf Coast over the past few years is a – really a complete shift of our picture from where we saw ourselves constrained by our CO2 supply to now where we see that as a resource that we can apply to do different things with.

And a small example of that is in West Yellow Creek, where we used it to enter that field. And one of the things I see, Paul, is an opportunity to do that on a larger scale along the Gulf Coast, as well as the potential to market the CO2 to third parties.

And we've seen multiple different opportunities for doing that in some fairly significant quantities. So part of the work that we'll be doing along those fronts is really working to, what I call illuminate that value.

But it's not something we think about every day. We're thinking about oil and gas.

But we have a great capacity to move quite a bit more CO2 than we currently are.

Okay. Thank you for that.

And then as a follow-up, looking on Slide 7. The Tinsley field both year over year and quarter over quarter has seen some declines.

Can we circle back on that? And maybe help us understand what's different about the Tinsley field versus some of the other successors you're having?

Sure. And what I'd say, Paul, is as you look across the portfolio of our fields, you're going to see fields that still have – that are still on a growth trajectory.

And you're going to see some that are near their peak and where we do things to keep them around their peak. And then some enter decline.

And a couple years ago, Tinsley entered decline. And then so we started seeing it move in this direction that you're seeing here.

What I will tell you is our teams are highly focused on production there, because it is such a substantial piece of our production. And I've seen some very good work on what we've done with the facilities.

Actually one of the challenges we've had at Tinsley is facility up time and some of the challenges we have there. Small project this year to improve that.

I actually think that the production that we'll have in Tinsley over the next period is going to start to look better than what you see here. But again when you look at our portfolio, there will be some fields that are declining and others that aren't.

And we work to move it all into a positive net direction.

Yeah. Okay.

Great. Thanks for that.

Hi. Thanks for taking my question.

I guess first one is there are a few large EOR assets that are presumably on the market right now. Would those – would something – would a larger sized deal be of interest to you, since you may be kind of a natural fit?

And if so how would you pursue something larger?

Jason, thanks for calling. Definitely we're aware of assets that are on the market right now and others that we believe will be on the market.

And when we look at our path forward, certainly those potential acquisitions play a part in that. And you can see that at least on a smaller scale, we made a move with Salt Creek here in the last quarter.

I think that today's market is special when I think that there are opportunities that have not been around for many years. And they – now there is an overlap of the bid and ask that did not exist in the past.

So I do think we have that opportunity. That's something that we're going to keep looking for.

I think the larger acquisitions, specifically where they make operational sense to us and where we can drive growth, are very attractive. And so that's something that we're going to keep looking at, Jason.

And then funding it, I think that's – we'll have to find the right acquisition and look at how we'd approach that. I'm going to let Mark finish my answer on this here.

But kind of at a fundamental level, even though our stock price is currently challenged right now, so equity is not a great tool to use today, I think that for the right acquisition, we'll find a way to put it together.

Sure, Chris. And we've talked about this a bit in the past in different vehicles.

Obviously you've seen some people use third party providers and even sidecar approaches and what not. Not that that's our primary desire.

But if we found something or thought something was strategic and made sense for the long term, we would look at various options. And as Chris said, where our equity is today, it's not real conducive to doing a large transaction.

But we'll continue to evaluate all the potential opportunities that we have.

Yeah. Thanks.

I guess second question. This is a pretty significant reduction in CapEx.

And you said you're still getting oil growth in 2018. I mean how does this CapEx reduction impact the longer term growth trajectory?

Well, not too much, Jason. And really the CapEx that we're deferring here – and I'm really thinking of it as a deferral – is we are pushing some of that CapEx at least in my mind right into the first quarter of 2018.

So really it's just a two quarter shift in some of the capital we were going to spend. So honestly I don't really see that as being a big impact.

And I still – as I mentioned earlier, still see us moving into positive territory in 2018.

Okay. So if you wanted to go bare bones and just keep CapEx – I mean keep production flat, what's that CapEx number now?

I think that it's – if you just look at what we're doing with – what'll be the $250 million for this year, I think that's probably a pretty good range to be in if you look at just where production is and where it's headed on that number. And I really think that's a testament to the teams here that have taken that number that we at one point thought was a couple hundred million annually more than that and as recently as a quarter or so ago, we felt that it was north of or around $300 million.

Now to be in that $250 million range.

Okay. Great.

And then I guess last one if I may do a third. I think last – on the 1Q call you updated us on your secured and current capacity.

Where does that stand now? Has that changed at all?

Yeah. So we – under the second lien that we have allotted, permitted under our bank line today at its $1 billion, so $385 million of capacity that's available there.

Great. Thanks.

I'll turn it back.

Thanks.

Okay, thanks, good morning. Congratulations on a nice quarter, Chris and Mark.

Thanks, Richard.

Most of my questions have been asked already. Just one final one.

Chris, as you look out to 2018, what level of operating expense reduction per barrel is achievable? Where would you like to be as far as OpEx goes as you get into 2018?

Great question, Richard. And I am actually thinking about that in terms of our overall cash costs.

Not even just operating, but just every dollar that stacks up against a barrel of oil that we sell. And not ready to share what I think that needs to be.

But I will tell you that the cost reduction effort that we've started on here is meaningful and is intended to make us profitable in that $50 world. So it's something that I intend will be a meaningful number that we end up with that makes us look different at that price.

Thank you. And that's all for me.

I appreciate it.

Bye.

Thanks, Richard.

Hi and good morning.

Morning, Eric.

Quick question on how we should be thinking about third quarter production versus fourth quarter production?

What I'd say just really I see, if you think of the first half of the year just shy of 60,000 [BOE per day] and where we're guiding the full year. I think that you'd probably look at third and fourth quarter more or less similar and north of a number that meets that midpoint of the guidance, something north of 62,000 [BOE per day].

Okay. Great.

And then as a follow-up. If prices continue to linger around this $45 to $50 a barrel, does that change your view for 2018 in the growth strategy?

It could. I'll talk a bit and let Mark finish.

But generally what we really like to do is to continue to keep ourselves within our cash flow. And so if we do get into that sub-$50 world, then we'll make the appropriate adjustments.

And I think we'll see some impact there. I would mention, one thing that's nice about 2018 right now is that we're heading into the finish of the year with a new project at Oyster Bayou that's going to enhance production.

Another new development with West Yellow Creek and of course Grieve coming on line around mid-year. So I think there's some good things happening in 2018 even if we do dial a bit more out at 2020 – a bit more out of our capital.

Great. Thanks.

Thank you.

Hey, guys. Thanks for taking the questions.

At strip pricing I was just curious what the IRR you had modeled for the Salt Creek and other acquisitions you've made since end of Q1?

Yeah. This is Mark.

We normally don't get into the IRRs on acquisitions. But I think for this particular one, we find it to be competitive with kind of where we would expect our thresholds to be for any capital investment and does have growth potential.

And so we've found it to be in our view a good investment at this point in time for what it can provide us. So we find the returns I think compelling in the current price environment with where we would find our investment thresholds with upside.

And what I'd add to that, Jacob, is just that we were in this environment when we made that acquisition, so it was no surprise.

Right. No.

I guess I was more just asking in terms of balancing that against the, call it, 20-plus percent returns on the sub notes at current levels and how you sort of think about balancing those two opportunities.

Yeah. And that's – as we think about any investment, we found it compelling and attractive considering where other levels are that we could use opportunistically for sure.

Okay. And then I guess similar in terms of asset sales and purchases.

Just can you talk about the similarities and differences between your assets and the package sold by Hess to OXY?

Probably the biggest difference I've seen in that package, first of all, just generally, it's the location being in West Texas is that that package included interest in a field that OXY was already operating in. And so it was building interest in an area where they operated.

And then it included some actual CO2 assets as far as I understand. Besides that I don't have a lot of the detail on that.

But again included CO2 assets. And it was stepping up in an area where that company was already present.

Got it. And then I guess last question from me.

I don't want to – is just besides the property in Houston and the Houston area that you're marketing, do you have any other non-EBITDA generating assets that you might be taking a look at? And then sort of given you mentioned you had an appraisal done, I know you said it would be enough to cover the Salt Creek acquisition, but did you have a ballpark range in terms of asset sale proceeds you might be expecting?

In terms of the acreage sales, I guess no. We're a little I guess preliminary in terms of what we would expect.

Obviously it's a – it'll be a competitive process. And we don't want to get into too much detail around it.

But definitely based on what we believe to be the market today, it's well north of what we paid for Salt Creek. So...

Okay. And then no other non-EBITDA generating assets that you're looking at?

In terms of other assets I think that's pretty much it in terms of non-EBITDA generating assets that we've identified to date. So...

Okay. That's all.

Really helpful. Thanks very much, guys.

Sure.

Thanks, Jacob.

Morning and thank you for taking my question. Regarding the Kemper Power Plant, are there any potential breakage fees associated with that agreement?

And how does this change CO2 cost assumptions going forward?

Good morning, James. Can't really talk about any of the specifics of the agreement with Mississippi Power as far as your question on breakage fees.

And looking at our costs going forward, what I would say, just as we've generally said in the past, is that when we look on straight-up CO2 costs, our – generally our naturally provided CO2 is at a lower cost than the man-made CO2. So I would expect, if that does not come into play, that we'd be more leaning towards that lower weighting than we would have otherwise.

Great. Appreciate it.

That's it for me.

All right. Thanks, James.

Hey, guys. Excuse me.

Hey, Gregg.

All the debt questions have been asked. So I will ask something on the operational side.

What I'm starting – when you look at the Hastings redevelopment project, it was very impressive. I'm trying to get a sense of two things.

One, how much of that did you anticipate? And was it in line with what you expected?

Did you -book any of the reserves in sort of proved developed, non-producing, or PUDs? And then beyond that how many more opportunities like that that have that type of investment potential and have those types of returns?

You bet. So what I'd say first is kind of even continuing on a previous question on how many other opportunities we might see.

First thing I'd point out, so I mentioned Oyster Bayou as another Frio flood that has a similar configuration. Another thing I'd point out is the rest of Hastings.

We're talking about a single fault block here at Hastings, B/C, and Hastings is comprised of multiple fault blocks. So we see quite a bit more there.

And in terms of reserves, generally the reserves associated with this are in PNP. And we'd expect them to be converted to PUDs by year-end.

And hopefully that answers your question.

That does. Were those – was that in line with what you were expecting or were you – did you pluck those?

It was in line with what we were expecting. One of the things that I think is really nice that the company has done over the last couple years, and I've talked about our development planning group and the modeling capability that we have.

And so when we first modeled this conversion and saw some of the results, it did indicate that we should see numbers along the lines of what we're seeing. So even though the numbers are large and very significant for that field's production, they were in line with what we'd modeled.

So then the remaining PNPs that are in your reserves from sort of last year, does that include – does that anticipate the rest of Hastings and some of those multiple fault blocks you mentioned? Or you just think there's incremental beyond that based on what you've seen from Hastings?

Okay. There are some additional PUDs that are at a lower elevation that we're not tackling with this particular project.

So that's another one that we could develop in the future here.

All right. I appreciate the color, guys.

Thanks.

All right. Thanks, Gregg.

Hi. Thank you for taking the questions.

Hi, Sean.

You bet, Sean

I think most were kind of asked and answered. But I guess, Chris, I appreciate you can't fully lay out the 2018 plans yet.

But when you think about it conceptually, is the plan that you're – when you look at the strip today, to try to be kind of roughly free cash flow neutral? Or is there some level of outspend that you're comfortable with?

Or how should we be thinking about that context?

Sean, I think we'd enter 2018 looking to balance cash flow. I mean that's one of the great selling points I see in Denbury, that we can operate this way without outspending.

And so I think going into the year, that's the way we will set it up. And then of course we have a lot of flexibility to be able to ramp one direction or the other, depending on outlook.

And so I think that even as we get into the year, we can really look at opportunities there and decide which way we want to go with it. But really starting from a base of keeping ourselves cash flow neutral.

Right. And so that presumably is like organically you fund it, meaning not including after sale proceeds?

Is that how we should think about it?

Yes.

Okay. That's helpful.

And then just lastly, can you just remind me – maybe for Mark. Just remind me, are there any limitations for you guys to be able to use free cash flow to buy back any of the sub notes in the open market?

I know you have the second lien capability. But just open market purchases of it, is that possible?

Yeah. Under – we do have a restriction under our bank line.

I think it's just south of $150 million of cash that we can use to repurchase sub notes at this time.

Okay, and that whole $150 million is available today?

Yes.

Okay. Great.

Thank you very much.

Thanks, Sean.

Hi. Good morning.

Morning.

Morning.

I think I missed – if you could just go into a little bit more detail about the comments regarding the Mississippi Power Kemper off-take agreement? And then to the extent that that CO2 supply was unavailable, could you talk about in magnitude, does that bring forward any CapEx accelerated?

Or can you maybe just give kind of a number of how you think about incrementally how that would add to CapEx?

Sure. So just to circle back around, Clayton, on the Mississippi Power.

So as I mentioned before, we can't really share the details of the agreement between Denbury and Mississippi Power. But we did receive notice that they were suspending their deliveries of CO2.

And this really goes back to the suspension of their operations of the lignite coal gasification portion of their project. So that suspended low, which in the first half of the year was intermittent and fairly low level.

Ultimately we'd expect delivery from a fully functioning gasification carbon capture piece of that plant well in excess of 100 million cubic feet a day. And so that's the piece that is in question right now.

What I would say going back to your question about tradeoff between CapEx at Jackson Dome and OpEx associated with the gas, is that I don't see near term CapEx acceleration at Jackson Dome. As we pull harder on it over time, I think that we'll look at the number of wells that we have and investments that we need to make there.

But as a reminder even today, we're flowing Jackson Dome at 60% of its capacity. So there's still quite a bit of running room out there for us before we really need to dig into the capital side.

Thanks a lot.

Thanks, Clayton.

Hey. How are you?

Good morning.

How much of your previously mentioned 2018 growth expectations are being contributed by these recent acquisitions?

So a decent amount, Clayton – or Cameron. I'd say the Salt Creek acquisition is going to provide in excess of 2,000 barrels a day for the year.

We don't have that dialed in just yet but somewhere in that neighborhood. And then of course on a smaller scale, West Yellow Creek will be contributing as well.

So there's a piece of that that is in our 2018 expectations. And again that's why even looking at our capital in 2018, I think a lot of what we'll see in 2018 is baked in by the investments and these couple acquisitions that we've made in 2017.

Great. Thank you.

Thank you, Cathy. Before you go let me cover a few housekeeping items.

On the conference front Chris Kendall and Mark Allen will be attending EnerCom's The Oil & Gas Conference in Denver on Tuesday, August 15, followed by the Barclays CEO Energy-Power Conference in New York City on Wednesday, September 6. The details for these conferences and webcasts for their 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 our third quarter 2017 results on Tuesday, November 7 and hold our conference call that day at 10:00 AM Central. Thanks again for joining us on today's call.