Denbury Inc.

Thank you, Kevin. 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 Executive Vice President and 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.

Thanks John. Good morning and thank you all for joining us today.

On our call last quarter, I outlined two high level priorities, realigning for profitability and sustainability in a long-term $50 oil price world and eliminating aspect of the Company’s unique value that are not fully recognized by the market. We made great progress on both priorities in the third quarter.

I will start by updating on that progress and then I will go into our third quarter results and our thoughts around the rest of the year and entering 2018. I'm sure you’re all aware of oils recent move higher with WTI crossing over $57 in the last few days.

Differentials added a substantial boost beginning in the third quarter in both the Golf Coast and the Rocky and Mark will share details on that later. Even with this positive news and while no company in our peer group has more exposure to higher oil prices in Denbury, I still believe we must plan our business around $50 oil.

And our aim to realign Denbury for $50 oil, we placed our focus on three areas; reducing our cost structure, maximizing the value of our assets and improving our balance sheet. This past quarter we took strong steps to reduce our cost structure.

Most significantly, we made the difficult decision to further reduce our headcount by 15% mainly in our Plano headquarters. Through our efforts over the past few years to fully understand our assets, combined with the recent realignment of our organization, we've been able to streamline our headquarters such as our staff level is now less than half the level of just a few years ago.

Combined with multiple other measures, we’ve identified over 50 million in cost reductions, many of which we're starting to see the benefits of now and other that will be realized in 2018. And we continue to believe we have additional opportunity to reduce costs.

Highlighting a direct result of this work, our third quarter net G&A was just over 27 million. Excluding one-time severance cost of around 7 million, net G&A for the third quarter would have been about $3.70 per BOE, well below our recent G&A spend levels.

We expect to see continued incremental reductions in the coming months, as more cost savings opportunities are implemented. The second focus area is maximizing the value of our assets.

A key here is ensuring that our investments generate strong returns at $50 oil. On that note, I've been pleased with the disciplined of our capital allocation process that resulted in both the broad portfolio of high value projects we executed in 2017 as well as those planned for 2018.

Our key development projects far exceeds our investment hurdle, such as the Hastings redevelopment with expected returns above a 100% and our Bell Creek and Mission Canyon projects with expected returns above 50%. Third, the balance sheet remains a primary focus and has in with our focus on sustainability in a $50 oil price world.

Even though we have no near-term issues with our debt run way, with the first of our bonds coming due in 2021 and no covenant issues, we're working to find ways to improve our balance sheet and debt metrics. This improvement can come in many forms and we anticipate there are progress will become more evident in 2018 through cost savings, execution of high return projects and an improved hedging portfolio.

We also work on the debt itself as an example last year we reduced our debt through both repurchase and exchange debt, and we remain focused on improving our balance sheet in thoughtful ways that benefit all stake holders. Finally, I'm pleased that our bank group reaffirmed our borrowing base last month entering a strong liquidity accretion entering 2018.

So that’s a brief summary on our progress towards making Denbury profitable and sustainable at $50 oil, we’re reducing our cost, maximizing the value of our assets and working through improve our balance sheet. Our other priority has been to illuminate Denbury's significant value that stands apart from our developed fields, specifically four important potential sources of value.

These sources are our surplus, Golf Coast CO2 and pipeline capacity, EOR development of our CCA assets, additional resource exploitation across our broad asset base and the sale of high value parcels of our surface land in the Houston area. Through our work in the past few years to improve CO2 efficiency, we now have surplus CO2 capacity on the Golf Coast.

I see several possibilities for value creation with this surplus, especially when combined with the ability of our pipeline infrastructure to deliver high volumes throughout Mississippi and on into Louisiana and Texas. We’re working on plans to convert our extensive Cedar Creek Anticline assets in Montana and North Dakota from water flood to EOR.

Utilizing EOR, recoverable hydrocarbon resources in this field are potentially greater than all of Denbury's current proved reserves. Technical work along with the permitting needed to bring EOR development at CCA to an investment decision is coming to ahead, and I expect that will be in position to make the investment decision in the coming months.

Our expectations for initial field investments continue to trend lower as we lean on the learnings from our many past EOR projects to design a bit for propose initial development in this great field. Our exploitation effort is now ramping up across our $600,000 net acre leasehold position, first with the Mission Canyon well and CCA this month, and then with several other opportunities on deck for 2018 will begin to unlock additional potential in our fields, potential beyond our currently producing reservoirs.

And finally, our Houston area surface land sale process is going well and we're seeing strong interest. Hurricane Harvey had no impact on the land or this process and I expect that the sales process will conclude in 2018, giving us cash with no loss of reserves or production.

Now let's move onto the third quarter. Hurricane Harvey was a pivotal event in the quarter.

I would like to make a side note here apart from the business update that I was both proud and inspired to see the supportive response of our employees in helping Denbury's multiple flood effected families. This is a tangible representation of the current team that we’re.

On the work front, teams from across the Company assisted in the operation of response, helping us rebound quickly from this significant event. We had downtime across our South East Texas field due to Harvey, shutting in about 16,000 BOE per day for a little more than a week.

Except for flooding in the Thompson field none other field sustained material damage. With the flooding, Thompson took a bit longer to comeback on but now essentially all the shut-in production is back online with only some minor work at Thompson remaining.

Overall, third quarter results were strong in spite of Hurricane Harvey. Production was up from the second quarter even with the Harvey related down time.

Our capital projects advanced on budget and on schedule. Salt Creek provided a full quarters worth of production and we continue to move forward with new EOR floods in West Yellow Creek where we still expect first production after year end and Grieve on schedule for its mid of 2018 startup.

We continue to see an up lift in production from our Hastings redevelopment project and Bell Creek Phase 5 is coming on as expected. Our first well at Mission Canyon should start in a couple of weeks and I look forward to providing you with updates as that project progresses.

Taking a look at Slide 8, total production was up for the quarter. A milestone inflection point after a series of decline that began in 2015, we expect further improvement in the fourth quarter, which set us up nicely going into 2018.

The notable event in the quarter was Hurricane Harvey, which impacted our quarter production by about 2,000 BOE per day. However, the uplift from Salt Creek combined with the response from our recent projects more than offset the Hurricane Harvey impact.

We have strong third quarter production multiple fields. Our recently completed projects at Hastings raised production over 10% from the prior quarter despite being shut-in by Harvey for 10 days.

Heidelberg was flat in comparison to both the second quarter and the year-ago quarter a result of great work by our teams and continuing to optimize that field. Oyster Bayou was down about 7% for the quarter, but up 2% when normalized to remove the effect of the hurricane shut-in.

Tinsley was up quarter-on-quarter with the benefit of improved field performance after some recent facilities work. And Bell Creek reached a record EOR level of just over 3,400 net barrels per day with response from Phase 4, and we expect to see additional production around year end from the recently completed Phase 5.

Prior to Hurricane Harvey, we were on track to meet the midpoint of our 60,000 to 62,000 BOE per day full year production guidance range. We still anticipate the previously disclosed 500 to 700 BOE per day full year impact of Harvey, so full year production should follow in the lower half of the guidance range.

Normalized LOE for the third quarter was nearly even with the second quarter at 2,074 per BOE. Absolute LOE for the third quarter was 118 million including about 3 million of clean up and recurred cost associated with Hurricane Harvey as well as a full quarter of cost associated with our newly acquired interest in Salt Creek.

CO2 expense was higher during the period primarily due to higher operating cost associated with the CO2 well work over, which totaled around 3 million during the quarter. Work overs on our Jackson Dome CO2 wells are in frequent, our last one was in the fourth quarter 2015, so they tend to swing cost noticeably in the quarter they occur.

Offsetting these increases were lower expenses across multiple categories. Looking forward, we project unit LOE will increase slightly in the fourth quarter mainly due to an estimated 4 million in cleanup and repair costs associated with Hurricane Harvey as well as additional CO2 demand in the Rocky Mountain region.

However normalized full year LOE is still expected to be between 20 and 21 per BOE. Now, I'll seek a deeper look at our CO2 utilization.

Total injected CO2 volume in the third quarter decreased to 487 million cubic feet per day over 120 million cubic feet per day below the second quarter. This was partially associated with the production shut in for Hurricane Harvey as well as lower volumes at Grieve with the field reaching its target operating pressure during the quarter.

We anticipate CO2 usage will rise somewhat in the first quarter as we continue to support growth in some of our existing tertiary fields. CO2 cost average $0.46 per MCF during the third quarter compared to $0.38 during the second.

Again in the lower part of the slide, you will see the cost impact of the work over. Turning to our 2017 capital program on Slide 11, we spent 56 million in development capital during the quarter bringing our year-to-date development expenditures to just over 180 million right on track with our planned capital spending level of 250 million.

Our project teams delivered another project on-time and on-budget this quarter, Bell Creek Phase 5, and we began both water and CO2 injection in mid-September. As we look to wrap up 2017 and move into 2018, I'm excited about what lies ahead for Denbury.

We will continue to see the impact of our recently completed projects at Hastings and Tinsley. We will start to see a production and response of Bell Creek Phase 5 as well as at West Yellow Creek.

We should complete the Oyster Bayou recycle facility expansion in early 2018, stepping up production in that great field. We will drill our first exploitation well up at CCA with plans for a higher level of exploitation activity next year.

And of course, we will continue to drive towards the investment decision on our initial CCA EOR project, a project that should ultimately tap a resource larger than Denbury's entire current proved reserved base. Now, I would like to turn it over to Mark to update you on the financial side of the business and after Mark speaks, we will 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 second 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 13, on GAAP basis, our net income was essentially breakeven for the third quarter.

On an adjusted basis after adding back $25 million of expense for non-cash fair value commodity derivative changers $7 million for severance payments associated with reduction in force this quarter and $9 million for enhanced oil recovery tax credits, we realized non-cash adjusted net income of $14 million in the third quarter up from $1 million in the second quarter. The change in sequential operating results was due primarily the higher revenues and reduced payoff for commodity derivative cash settlements this quarter offset in part by higher operating expenses.

Turning to Slide 14, our non-GAAP adjusted cash flow from operations which excludes working capital changes, improved by $3 million from the second quarter to $68 million. That was due primarily to the same drivers for the change in our operating results.

Our third quarter average realized oil price before hedges was $48 per barrel, a 1% increase from the realized prices in the second quarter. When you include the impact of our hedges, our per barrel realized oil price increased 6% from the second quarter as our combined revenues and commodity derivative settlements increased by 21 million to 266 million in the third quarter.

Slide 15 provides a summary of our realized oil price differentials relative to NYMEX oil prices. Our overall realized oil price differential improved by roughly $0.80 per barrel from the second quarter to $0.34 below NYMEX prices for this quarter.

This is the best differential realized since the third quarter of 2013. We have recently seen LOS premium expand to approximately $6 WTI prices, which is considerably higher than the $1 to $2 premium we have experienced over the last couple of years.

Roughly two thirds of our production has an LOS index component including in its price formula, primarily a large portion of our Golf Coast oil production. We have also continued to our Rockies price differential improve to the best level we have had.

We currently expect that our overall oil differential for the fourth quarter of 2017 will remain close to our third quarter average or potentially improve slightly primarily demanding the continued strength in the LOS premium. On the right side of this slide, you can see the moment in the LOS premium over the last couple of years and the recent improvement I'm referring to.

I will get into our hedging positions on our next slide, but with the recent increase in the LOS premium, we've taken opportunity to lock-in LOS basis swaps to the first half of 2018 to help capture a portion of this premium improvement. Slide 16 provides a current summary of our oil price hedges.

Since our last quarter conference call, we have added to our hedge positions for the remainder of 2017 and 2018 with additional fixed price swaps around $50 per barrel. For 2018, these hedges represent roughly half of our third quarter 2017 production levels.

You can also see here the additional LOS to WTI basis swaps I just mentioned beginning in December 2017 to the first half of 2018. Depending on market conditions, we may continue to add to our existing 2018 hedges and we may start to layer in some hedges for 2019.

Moving to the next slide, I'd like to review some of our expense line items starting with G&A. Our G&A expense was $26 million for Q2 slightly higher than the $26 million last quarter.

This slight increase was attributable to severance payments associated with our third quarter workforce reduction offset in part by an overall reduction in compensation related cost to lower headcount as well as a prior quarter including compensation associated with retirement of our previous CEO. For Q3, net G&A related to stock based compensation was approximately $3 million.

As a result to lower headcount and other cost reduction measures, we currently expect our G&A will be in the lower $20 million range for the fourth quarter at 2017 with stock based compensation range in between $4 million to $6 million. Net interest expense was $25 million this quarter, consisting with last quarter and you can the components of our interest expense in the table on the bottom of this slide.

We currently expect our capitalized interest to be in the $7 million to $10 million range for the fourth quarter of 2017 with our last two quarters. Our DD&A expense this quarter was $52 million also relatively unchanged from the second quarter.

We expect our DD&A expense will increase to around the $55 million or slightly higher for the fourth of 2017. During the current quarter, we recognized a 0.6 million in enhanced all recovery income tax credits which significantly secured our effective tax rate due to the near breakeven pretax amount.

For the fourth quarter of 2017, we currently anticipate our income tax rate will be slightly lower than our statutory rate of 38%, consistent with our effective rate for the nine month period and we anticipate little to no current tax expense. Moving to our balance sheet, we had total debt principal of approximately $3 billion as of September 30, 2017, with $495 million outstanding on our bank credit facility and nearly $500 million of remaining borrowing base availability.

As expected, we recently reaffirmed our volume pace and lender commitments for our bank credit facility at 1.05 billion in connection with our fall annual borrowing base redetermination. On the bottom portion of the slide, you can see that our cash flow from operations before working capital changes exceeded our development capital expenditure for first nine months of this year therefore the 194 million increase in bank debt from year-end 2016 was due primarily to the $89 million for the Salt Creek and West Yellow Creek acquisitions, $52 million for working capital outflows, and $46 million due to other debt reductions with a largest debt reduction item being interest on the second lien debt that is treated as a debt on our balance sheet.

Our 2017 capital budget including acquisitions and capitalized interest remains unchanged from the previous estimated amount of approximately $250 million. Assuming all prices remain in the mid 50s per barrel for remainder of 2017 based on our current projections, we would expect to end the year with bank debt between 450 million to 475 million, leaving over 500 million of liquidity on drawn bank credit facility.

The next regulatory scheduled borrowing base redetermination is set to occur in early May of 2018. And now, I'll turn it back to John for some closing comments.

Thank you, Mark. That concludes our prepared remarks.

Kevin, can you please open the call up for questions.

I guess the strategy question to start. I mean you guys have done a great job of as you said planning for $50 oil through the cost savings and the reduced CapEx.

But also as you point two-thirds of your production is now tied to $63 oil or LOS also you said you have added some hedges, you're about 50% looks like overall hedge. But as you go into '18, what -- how is that strategy come together?

I mean, is the priority go into bank line? Is it that you have done three acquisitions now in three quarters, so we continue see bolt-ons what's the plan?

Paul, this is Chris. The way I think about that to a few different aspects.

First, the improvement in prices is fairly recent and we definitely noticed it along with everyone else, not something that we are going to continue to watch very carefully, as we go through the next weeks and months and set our plans for 2018. I think that we're going to continue to look at multiple options for what we can do with incremental cash flow that comes from higher prices and other efforts that we’re taking part in here to open new opportunities for 2018.

Obviously, we would like to drive growth in the Company and so that an aspect of it. But then, we will also look at all other opportunities that we have out there to do with the additional cash flow.

I know Mark to add anything that you might have you to, your thoughts on that.

I think working toward 2018 now and we will continue to over the next couple of months here, I think continuing with our past practice and time deliver within cash flow, and like this year we internally had some of a variable budgets that we could either ramp up for maybe slowdown depending on what happens with prices. So, the good thing I think about our business is we have flexibility to do that in many ways as we demonstrated.

So I think that’s how we think about it right now.

And then maybe a follow-up here. In your presentation from some of your fall conference, you had a bullet point that one of your goals was to maintain significant liquidity under the bank line and work to extend the maturity beyond 2019.

I know you've just gone through your redetermination and the next one is May, but just to see how you feel about that with what you've just gone through?

Yes, obviously before the end of 2018, we want to work on that extension. And so, I think we will continue to work toward that here as we see timing as appropriate, and so that’s we could be focused on for early '18 and see how that comes together.

Maybe just to put a little but more a parameters around sort of the project at Cedar Creek Anticline sort of how do you think about sort of special timeline to decision, sort of roughly what it would look like in terms of potential production et cetera. Just kind you give us some numbers to help to think about it?

So, I will tell you how we’re thinking about it right now and I will caveat that with the work is in progress and coming to ahead, but I don’t have the final answers right now. But generally, the way that we're looking at it, first you just have to look at the potential of EOR development and CCA where you have upwards of 290 million barrels of potential EOR recoverable reserve.

So huge target, like I said bigger than the total proved reserve base that Denbury has right now. Now having said that that also expands over a 120 miles, so it's quite extensive, and so what we're looking at doing is getting into that field with the limited, with its limited of front capital as we can, kind of learning from some of our developments that we've implemented in the past and minimize our upfront capital, learn more about the field and expand as we go.

We're going to be pulling that together as we get through the next few months here. Of course, we have the pipeline investment that would come in front of that.

On the earlier side, what we like to be seeing is having that pipeline investment, the pipeline actually installation taking place as early as 2019, putting us in position to have first production from CCA in 2020, 2021 following that. That’s the frame work of what we're thinking.

But like I said Tarek, the work is still ongoing, and we should be at a decision point on that in the coming months here.

Is this sort of intense here to farmout some of that capital? Or is the thought process -- can me just how creative is the value to fund that was all of throughout CapEx?

Great question and we are going to look at that from both sides. I'll say my initial thinking on it, one of the chunkier pieces of capital that we need to spend initially is on the pipeline.

We think it's about 150 million to get the pipeline out from Bell Creek there on the Montana-Wyoming border up to the CCA, about a $150 million investment and that’s one we might look outside. I think there is some different options that we can use there that would help preserve our capital to some do some other value generating investments with.

And we are going to look at that as we push this forward.

Then some hedge position looks like you guys are about 50%-ish plus or minus on 2018 at this point a little over 50. I guess just talk about appetite to layer next additional hedges just given kind of what we're looking at over the next few months in terms of credit?

Sure, we are obviously looking at it. I think we want to leave some optionality in our positions here, and we have seen it move up nicely so we will definitely consider putting a few more things in place here just to add more certainty to cash flow, but do like we have a little bit of optionality as well.

Fair enough. Last one and Paul also touched on it, but as we think about options to de-lever the balance sheet.

Just maybe talk a little bit about how you view this using secondly basket at this point? Just sort of any thought process around that will be helpful.

Sure, we obviously look at a lot different things. More recently here, the prices have been moving on all our securities and so it makes it potentially a little bit more difficult to do some things.

But we will say, we are always focused on things that might be beneficial to improving the balance sheet and positions for all of our stakeholders. So, it's probably about as much as I can go into, but we are always focused on it for sure.

First question is on the acquisition front. Would you guys be willing to buy for just conventional development?

Or would the opportunity have to include some sort of tertiary oil potential?

Eric, I think that we look at both aspects. I think our investors generally like the oil rating that we have, the low decline type of assets that we have.

Certainly, we can add the dimension of EOR to a water flood in its future, but I can see potential in acquisitions to have both conventional and EOR.

Great. And then with the success of the Hastings redevelopment, have you guys identified other opportunities like the Hastings redevelopment?

And then if so, how much that would add to production in 2018 and beyond?

So great success with Hastings project and that certainly one of the, first thing we took away from that is where else can we apply this kind of thinking. What I see is that we have, every one of these producing assets has opportunities to gain more value from, some of those opportunities are like we did in Hastings flood block BC where we reconfigure the flood, and we will continue to look at other opportunities like that.

Other are on surface facilities, I mentioned some work we did at Tinsley and I mentioned this Oyster Bayou recycle facility expansion that we’re working towards in the early part of next year. We're going to continue looking across everything that we have for those types of opportunities.

Now are some that we see in the period, I can't go in any more detail on that right now, but that’s a high focus for us.

Couple of things. First, there have been a few EOR sales recently you got the resolute in [indiscernible] sales.

What do you think the read across from the sales should be? And then, is there a deep bid out there for EOR assets?

Yes, I think obviously the EOR and the things that we looked that I think we even used to own [indiscernible]. And so, we're very familiar I would say in terms of things that we’re focused on.

It's generally areas that we're operating in and things that we feel where there is more opportunity that directly suits us. It's hard for us to probably get into much detail about competitiveness and what went on those things, but I guess for us that’s kind how we look at it.

Okay, I may follow up offline. Also the Houston area real estate, can you give us an update on sort of that process?

And what do you think valuations there might be?

Sure, Jason, the process is continued slight pause with the flooding, but actually no real impact on what we see on the timeline of the process itself. It is something that when we first embarked on the process, we saw that it was going to take a few quarters to really do it right.

We didn't have pressure on needing to make the sales, so we want to maximize the value that we can get, and that’s exactly what we are doing, seeing a lot of interest multiple parties have expressed interest, and we are going to continue through that process into the first part of 2018 and expect as we get into 2018 we will start to see some results from that. I don't really want to talk more about what we expect for value from those sales other than that we had originally expected that it would at least offset the purchase cost of the Salt Creek acquisition.

Since then some of the numbers we have looked have been then quite a bit above that, so we expect to see some upside from that that really need to wait and see what was the numbers come in live.

Is there a list price for the fact as those are not being marketed that way?

It's not marketed in that way.

One last sort of if I may. You've talked about cost savings.

Where do you think you can drive LOE per barrel overtime? Now, we have you about $23 of BOE and times past, you were in the mid teens granted your mix might have been a bit different on the past, but where can that $23 per barrel go?

Sure, so I'm not sure I can match up with your $23. I see us in this $20 to $21 right now.

And so like to explore that a bit, but what I see is LOE is interesting without that’s obviously one of our biggest cost elements, so it's a very strong focus. We have made some changes and how we are organized I mentioned our reorganization here recently and one of the byproducts of that organization I intend to have a much more direct ownership of LOE within the organization and we are just in the beginning phases of having that.

But I would say, I think the Company has done a good job of managing LOE overtime and there is a flexibility to it, there is a -- at low price environment we have been able to dialed it all the way down into the mid teens as you saw in 2016. Then when we get into higher price environments we can look at optionality for investments that we can make this actually end up falling in the LOE categories that add value to the Company.

And those are decisions whether that’s a decision to turn the compressor on or off or to execute a work over or not. We are going to flex that with the environment that we are in.

Again not necessarily always targeted towards absolutely minimizing LOE, but targeted towards maximizing the value that we generate for the Company. So kind of mix question there depends on the environment but I see quite a bit of flexibility that we have within our LOE depending on the oil price environment.

How would CCA development potentially impact you guys as deleveraging plans? And is that one of the governing aspects of how and when you move forward there?

I don’t know that I would necessarily tie the two together. I think CCA is a little bit long-term development plan here and so obviously, it could be helpful for our future down the road and we expect it to be.

But it’s a next two to three year big change or type of it I think here.

Okay. And then with regards to Harvey.

Is the Thompson field now fully up and running or any impacts into 4Q?

We do have impacts into 4Q in Thompson there. The repairs continue to after the end of September.

So that’s where when you see us talking about a 500 to 700 barrel impact on the full year. You have a bit of that that does carry on into 4Q.

So that's included in the guidance then.

Yes.

Given this moment from, how do you think about 2018 plans? I mean assumingly roll up the curve, it looks like you could generate a fair amount of cash flow, if you’re able to keep CapEx relatively flat year-over-year.

So just curious, how you balance investment opportunities and ramping up CapEx against deleveraging through organic cash flow?

Jacob, I think I said a bit earlier that something that we're going to keep a close eye on and watch where these prices go as we and the year end and come into next year. One of the great things about Denbury is there's tremendous capital flexibility that we have.

When we saw it worked the other way in 2017, we're able to dial back from 300 to 250 and still have our production in the good place. There is potential to work that the other way and we continue with this portfolio projects that we have to find areas that we can ramp up into.

I talk some about exploitation, I think if we have an improved price environment in 2018 and we might be able to do some more on that. And of course we're always going to be making that decision of what make the best sense for the Company overall whether it is to further invest and grow production or to double back and do some work on the balance sheet.

I think we're just going to have those on a case by case basis.

And then you mentioned I think earlier in the year about $80 million of annual cost savings or about $2 barrel as a result of your cost production efforts. So I just wanted to get a sense of when you expect that $2 a barrel of savings flow through the income statement?

And also when you expect non-recurring cost severance cost to be completed?

So, I'll answer your second part first. I think we had most of those severance cost in Q3.

So we shouldn’t see may more of those. And then to go back to your first question, Jacob, I see that the nature of the cost savings just because of the variety of areas that they come from or be deterring in through the remainder of this year and on into 2018.

So it's going to be a process, I think we taken a big chunk of that already with what we seen in third quarter here and will be evident going into the fourth quarter. With some more to come in 2018, but there's a nature of them they're a bit different and how they all filter in over the next few quarters.

And one real quick housekeeping question. Just want to confirm that 20 million to 45 million of revolver pay down before.

Is that just there you sort of guided to in the press release? Is that before any assume proceeds from the Houston acreage sale?

Or does it proceeds from that potential asset sale into account?

Currently, we're not anticipating any Houston acreage sales for the end of the year.

A few questions. First just a clarification on G&A value, you said that your G&A expectation in Q4 would be low 20 million and do that includes unit based comp?

Yes, yes.

And is that if your run rate for us to use going forward? Or is there any noise in the fourth quarter?

I think it's good for now. Yes, I think we feel pretty good about where we sit.

There is still as Chris mentioned in -- we are still sorting through some other potential cost saving items and but mostly impacting '18, so we are going to continue work. I think that’s good for right now.

And then with respect to product guidance the fact that you are still giving full-year range, a pretty big range of potential outcomes for Q4. It sounded in the remarks like you said you expect Q4 to be higher than Q3.

Can you discuss more color there and maybe talk about how you expect Q4 versus Q3, if we exclude the impacts of the hurricane?

We expect -- I don’t want to go into any more clarity that we already published there Eric, but we -- like I said, we do have some lingering effects of Harvey not nearly to the extent that we had in Q3. So, we do have some of that but we still see stronger than where we into that in Q3.

You still see it's stronger than Q3 or the negatively Q3, are you making distinction there?

Stronger than what where we were in overall in Q3.

I appreciate you don’t want to go that far but it's giving such a big impact from the hurricane Q3 it doesn’t give us that much color. Can you maybe talk a little bit -- you mentioned four potential tools to drive more value and the first was maybe getting more value from the CO2 infrastructure.

Can you maybe give a little more color there in terms of -- are there near tem opportunities on the horizon? And is that probably on a form of more M&A worked with the other things?

Just any more color you can provide there will be helpful.

Eric and we are I point you to initially on that as to think about what we did with Yellow Creek where we used the excess CO2 capacity that we had to enter into a field that had really we haven’t been able to get into before. So that's a joint venture type of opportunity that opened up because of that CO2 supply and distribution capacity.

I see much more of that across the Gulf Coast in particular and so more potential for deals like that. Definitely, we have multiple opportunities to continue to sell CO2 on more of a commercial basis where we have potential off takers, so just want to buy it.

And then those again -- they occur in different places, but there these opportunities that we would look at each one, look at our capacity and decide what we want to do with those. I think that there is a spectrum of options that we can hold in there that in aggregate really starts to move the needle and using that surplus capacity and accelerating value generation there.

That’s terrific. Do you think that could have a meaningful impact as soon as 2018?

I think it's possible. I mean some of them as you just kind think about them are longer term and our nice business things to implement but may not have a real bang in 2018, others could.

This is more of a theoretical question. I mean given that you guys have moderate production growth CapEx of 250 million, recognizes you cut that budget from earlier in the year.

How should we think about maintenance of CapEx, given the 2017 exit break? Just provide any context from just kind of maintenance level of CapEx, if your objective was solely just to maintain 2017 exit rate?

Jay, my thinking in the past on that, we guided more towards a 300 million range on what that maintenance capital would look like. But as our team have continue to optimize the deal, these deals in our production and have just done more with the assets that we have, on top of that we enable to execute these projects at a better and better level then we have in the past.

I actually think that we're probably more subscriber 300 may be closer to that 250 that we're looking at here in 2017.

When it comes to hedging, I think the expectation for a lot of investors is that there should be a lot of producers, they are locking in, as some of these higher pricing on the curve as it relates to you guys. Are you going to focus more on basis swaps or fixed price swaps, a combination or if you could provide some more color on how you may potentially lock in more of 2018 price?

I guess it could be little over the each, but I don’t see us necessary going above like 70% hedge or something like that. So we think we have a little bit to play with and think about in terms of how much additional certainty we want to bring into the cash flow for 2018, probably 50%, so hedge around on the base of swaps as well.

So it's -- I think that descent level to be right now and we're going to continue to launch it.

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

On the conference front, we will be attending the Capital One Securities both annual Energy Conference in ne Orland on Wednesday December 6th. The details for these conferences and webcasts 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 our fourth quarter 2017 results on Thursday, February 22nd and hold our conference call that day at 10:00 AM Central. Thanks again for joining us on today's call.