Denbury Inc.

Thank you, Laurie, and good morning, everyone, and thank you for joining us today. With me on the call today I have 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 let you know that we have a few slides which will be accompanying today's discussion. For those that are not accessing the call via the webcast, these slides may be found at www.denbury.com's homepage.

Please click on the Quarterly Earnings Center link underneath resources. I would also like to remind you that today's call will include cautionary 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 cautionary statements and the risk factors associated with our business in this presentation, our latest 10-Q, and today's news release, all of which are posted to our website at www.denbury.com.

Also, please note that during the course of today's call, we will be referencing certain non-GAAP measures. Reconciliation of and disclosures relative to these measures are provided on today's news release as well as on our website.

With that, I'll turn the call over to Phil.

Thank you, Ross. First off I'd like to welcome to Chris to today's call.

It's great to have him on Board. He is studying up to speed, having been here less than two months, but he's hit the ground running, and I am receiving a great deal positive feedback and know he is already making a difference at Denbury.

Chris will be covering our operational review today, following my overview and Mark's review of our finances. While the macro environment is still challenging, I'm very encouraged with the progress we're making here at Denbury.

Late last year, we prioritized and committed to initiatives to optimize our business and lower our cost, and we have made significant progress in doing so. We initiated this pursuit by utilizing innovation and improvement teams comprised of selected individuals to review in detail various aspects of our business and to identify ideas and options to lower our cost, optimize our business and create value.

We completed this initial review several months ago, and we are now evaluating the ideas and options generated in preparing updated and optimized to our development plans. While this systematic field by field review will take another year or so to complete we believe this downturn in oil prices and corresponding slowdown in our activity makes this a perfect time to perform such a review.

As this process has progressed, you have seen incremental improvements in the form of continual reduction in cost, including reductions in the use of CO2 and you should expect to see the longer-term benefits in the future of increased rates of return, less capital per barrel, and improved value creation. I would note that this process may not necessarily result in higher productions rates particularly with regard to an individual field as our focus is on value creation not production.

Consistent with that theme, Chris will show you an illustration where production decreased slightly at one field, but operating cash flow went up; a trade we will make every time. I'm not sure you will see that trade on a regular basis throughout our industry.

Incidentally, the illustrated decrease in production that he will show you is not part of the 1,100 BOEs a day estimate of uneconomic production. Before moving on to a little detail, you might want to look at the high-level interim progress.

Including with respect to cost reductions because it's very apparent when looking at the big picture. As an example, our adjusted cash flow from operations only decreased $9 million this quarter as compared to last quarter even though the combined revenues and commodity settlements decreased by $37 million.

The difference, of course, is due to cost savings. If you move to slide five, you will see that we have reduced LOE cost per barrel 20% year-over-year, resulting in a recurring LOE of $19.43 in the most recent quarter.

This is the seventh consecutive quarterly drop in recurring LOE. Further, you can see that G&A per BOE has also been reduced by 16% year-over-year with most of these savings occurring this quarter with a sequential decline of 11% on a per BOE basis from Q2, largely related to a reduction in personnel cost.

Although it is difficult to measure refining and development costs in this environment with the significant price reductions causing reserve adjustments, I am very confident we've made significant progress in this area also as partially evidenced by our underspend in capital this year. If you move to slide six, you will see that we have reduced our 2015 development capital estimate that we did reduce by $50 million a couple of months ago.

And that was partially offset by a $20 million increase in estimated capitalized interest, but that resulted in a revised all in total of $520 million. Today, we lowered it an additional $45 million to a reduced 2015 capital forecast to $475 million, and that equates to a 20% reduction overall in our development spend.

In spite of the $95 million reduction in development capital expenditures, our 2015 production is remaining relatively flat if you adjust for the barrels we have shut in due to economics or weather-related downturn. We still expect to end the year in the lower part of our initial guidance range for 2015 as we anticipate that our Q4 production will be higher than Q3.

If you move on to slide seven, our cost savings in both capital and expenses have allowed us to generated $321 million of free cash flow in the first nine months of 2015. Quite an accomplishment considering that oil prices have generally slipped and remain low.

When I say free cash flow, I'm comparing our 2015 incurred capital expenditures and our dividends with our year-to-date cash flow from operations. When you make that calculation, you have $321 million left over.

Obviously this wouldn't have been possible without our hedges, but this number would have been a lot less without our significant cost reductions. We have used most of the free cash flow to reduce our obligations, including a $215 million reduction in total debt and most of the rest went to settle accrued capital expenditures that existed at year end 2014.

Our bank debt at the end of September was only $210 million, down from $395 million at year end 2014. This considerably improves our financial flexibility and ability to weather this downturn and further provides additional liquidity as our bank line currently has a total commitment of $1.6 billion, and an even larger $2.6 billion borrowing base.

I think it's important to note that we have reduced the risk related to our balance sheet and have done so in a tough macro environment. We have also periodically repurchased shares during the last two months buying another 1% or so of our outstanding shares.

We view these repurchases as highly accretive and impactful to us long-term as it doesn't take a lot of money to acquire a significant percentage of the company. We may continue to buy from time to time depending of course on the stock price, oil price and our available cash.

We want to fund any such repurchases with cash flow from operations or perhaps said another way we do not want our bank debt to increase above its prior year end 2014 level. Of course, we are also subject to the overall stock repurchase limit that has been authorized by the board.

We are very conscious and focused on adding value in everything that we do and that of course also includes stock repurchases. While we continue to look for additional assets to acquire, we also continue to be frugal with our cash and generally are looking for fields that can be purchased with limited funds but fields that could be flooded with CO2 in the future.

We announced the Martinville (9:01) acquisition earlier this year and we have a couple of other similar type deals that we are evaluating. These fields would likely not be impactful near-term, but would expand our inventory and provide positive returns in the future.

Again, everything we're doing is geared to make us a stronger and better company that will be ready and poised to deliver consistent and improved results as oil prices recover. Since Chris is here, I'm not going to go into the current operational items, however, let me touch briefly on 2016.

We are still working on our capital budget and therefore do not have specific guidance for you at this time, but I can give you a little color. We expect to spend at or near our operating cash flow and I think that's the part of the key point of this message, which based on today's strip pricing is expected to be between $300 million or $350 million.

As such our total 2016 capital budget is likely to be reduced from our adjusted 2015 estimate of $475 million. As we continue to be more efficient on our capital spend, I think we can do a lot with these limited funds, but it is doubtful that we could hold production flat.

As a comparison it appears that our exit rate in 2015 will be about 2% less adjusting for the uneconomic shut-ins than it was in 2014 with an estimated capital expenditure of $475 million. As such I'm confident that a reduced spend of $350 million will result in overall declines that are in the single digit percentage range.

But until we get our capital funds allocated and our forecast updated, I won't be able to give you a more precise production estimate. But the reductions in capital for this year and next year without a material fall off in production should illustrate the strength of our production profile strategy.

We likely won't announce our maybe more precise 2016 guidance until after the first of the year perhaps as late as our year-end earnings call released in February. And please note of course that these numbers could change somewhat as we adjust to a constantly evolving and moving macro environment.

A quick note on the personnel front, in addition to adding Chris, we've also enhanced our technical staff by adding a Chief Scientist a few months ago and we've also added several other highly experienced technical people that were available at least in part due to the macro environment. So, in summary, a lot of positive things happening at Denbury.

Our business is improving and our future is looking good. And with that, I'll turn the call over to Mark to give you financial details.

Mark?

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 second quarter.

I will also provide some forward-looking guidance to help you in updating your financial models to reflect our current outlook. As shown on slide nine, our non-GAAP adjusted net income for the third quarter was $63 million or $0.18 per diluted share.

This is better than analyst estimates and largely due to our continued cost reduction efforts and lower DD&A expense this quarter. As you can see in our GAAP reconciliation, we have a couple of significant write-downs this quarter.

First, we recorded a $1.8 billion pre-tax ceiling test impairment as the trailing 12-month oil price continued to trend down during the quarter. As you may or may not know companies such as Denbury that follow full cost accounting for oil and gas properties have a different impairment test than successful efforts companies.

Full cost companies are required to use the average first day of the month price for the trailing 12-months when comparing the PV-10 Value of the reserves against the book basis of the oil and gas properties. We have also noted that many of the full cost companies have taken similar or much more significant write-offs in this quarter.

Based on recent oil price levels, we expect that we could record a similar write-downs in Q4 as current prices would indicate that the average price for the last 12 months will continue to average down. The second significant write-down was a full impairment of our $1.3 billion of goodwill, most of which related to the merger with Encore in 2010.

The write-off occurred at this time due primarily to the significant drop in the market value of our equity and debt from June 30 to September 30 relative to the drop in oil prices. On a GAAP basis, you can see that primarily due to these write-downs, we had a net loss of $2.2 billion for the quarter.

Turning to slide 10, our non-GAAP adjusted cash flow from operations which excludes working capital changes was $243 million for Q3, down only $9 million from the second quarter, as cost savings offset a $37 million drop in our combined revenues and hedged settlements. Our Q3 average realized oil price excluding hedges declined to approximately $46 per barrel, down 20% from Q2.

We recognized $161 million in cash received on settlements from our hedges this quarter, which made our average per barrel realized price including these hedges a little over $71 per barrel compared to a little over $76 per barrel last quarter. Slide 11 provides a summary of our realized oil price differentials relative to NYMEX oil prices.

Our overall realized oil price averaged $0.96 below NYMEX in Q3, down slightly from $0.89 per barrel below NYMEX last quarter. Although the overall change in our net differential was not that significant from quarter-to-quarter, we did see some change in differentials across our production areas.

Oil differentials for our Gulf Coast Tertiary production which primarily receives a LLS pricing, averaged about $1 per barrel above NYMEX prices this quarter, down from $2 above NYMEX prices last quarter. In the Rocky Mountain region, our Cedar Creek Anticline oil differential improved by almost $2 per barrel, selling at around $4.50 per barrel below NYMEX in Q3.

Thus far in the fourth quarter, we have continued to see some strengthening in our Rocky's differential, but we have also seen some weakening in our LLS pricing. As such we currently expect our overall oil differential to be in the range of $1 to $3 per barrel below NYMEX prices in the froth quarter of 2015.

Moving to slide 12, let me review some of our expense line items. First, normalized lease operating expense came in better than we expected, averaging $19.43 per BOE in the third quarter, which is down from $19.70 per BOE in the second quarter.

The current quarter normalized amount excludes $14 million of reimbursements recognized during the quarter comprised of retroactive utility rate adjustment and an insurance reimbursement for previous well-controlled costs. Including these reimbursements, our total lease operating expense during the third quarter averaged $17.34 per BOE.

Chris will go into more details on our LOE in a few minutes but for Q4 we currently expect LOE to remain around $20 per BOE. G&A expense was roughly $33 million in Q3, this was below – this was on the lower end of our expectations as the cost has continued to come down due in part to workforce reductions and continued focus on reducing expenses.

For the third quarter, $7 million of net G&A was related to stock-based compensation. In the fourth quarter, we expect G&A expense to be slightly lower than Q3, with approximately $7 million to $9 million of this amount being stock-based compensation.

Interest expense, net of amounts capitalized was down slightly from Q2 at $39 million. Capitalized interest was roughly $8 million in both quarters.

We currently expect capitalized interest to be approximately $5 million to $10 million in Q4 depending on qualifying activities. Our DD&A expense was lower this quarter due primarily to the full cost ceiling impairments recorded in the first half of 2015.

With the additional impairment recorded this quarter, we expect that our DD&A expense will likely be $3 to $4 per BOE lower in Q4. Our effective income tax rate for Q3 was approximately 25%, well below our estimated statutory rate of 38%.

This is primarily due to the full impairment of goodwill during the quarter as a significant portion of that goodwill had no tax basis. For the fourth quarter, we anticipate our effective tax rate will be close to our statutory rate with current taxes being relatively minor.

On slide 13, we have a summary of our commodity hedges. We did not enter into any new hedges in Q3, but as you can see we have about 50% of our oil production hedged to the second quarter of next year, with our downside hedged prices trending lower in the second quarter of 2016.

Onto slide 14 – slide 14 provides a summary of our liquidity and long-term debt maturities. At September 30, our total debt was approximately $3.3 billion, which was down $215 million from year-end 2014, and we had $210 million drawn on our bank debt at quarter end, down $185 million from last year end.

Based on current prices and projections, we anticipate ending the year with bank debt of approximately $150 million to $200 million. We currently have around $1.4 billion available on our bank facility and as you can see we have additional cushion between what we have asked the banks to commit to and our current borrowing base of $2.6 billion.

At current 2016 strip prices of around $50 per barrel and based on our best projections at this time, we expect that we should be in compliance with our bank covenants through 2016. Recall that earlier this year we modified our debt covenants beginning in 2016 with a primary change being the replacement of a total debt-to-EBITDAX covenant with a secured debt to EBITDAX covenant going out through 2017.

The next redetermination of our credit facility is expected to be next May, as we are on an annual cycle. And now, I'll turn it over to Chris for an update on operations.

Thank you, Mark. I feel fortunate to have joined Denbury at this very challenging time in the industry, yet at a time it makes Denbury's unique business model standout.

Having spent the past two months with the operations teams, my observation is that we have strong technical and operational capabilities, high quality, long lived assets and a strong strategy that will lead to long-term success. Regarding our overall results for the quarter, I am very pleased by our sustained improvement in CO2 usage and lease operating expense both of which we reached multiyear lows for the quarter.

In addition, we fully restored production at Thompson, after the flooding that we mentioned in the second quarter call. And we reached record quarterly tertiary production levels at Bell Creek.

Starting with production on slide 16. Overall company production was 71,410 BOE per day for the third quarter, 3% lower than our production on those on both a sequential quarter basis as well as the third quarter of 2014.

And as Bill mentioned, we had about 1,100 BOE per day shut-in for economics. Looking in more detail at our tertiary fields, production during the third quarter was 40,834 barrels per day, a decrease of 4% or 750 barrels per day on a sequential quarter basis, and 2% or just under 800 barrels per day from third quarter 2014.

Aside from the production shut-in for economics, the main drivers in sequential changes were a reduction at Hastings that I'll discuss later, and a temporary reduction in production at Tinsley to correct facility processing constraints partially offset by record tertiary production at our Bell Creek field. The facility processing constraints at Tinsley have since been corrected, and production there is now recovering to expected levels.

At Bell Creek, we reached 2,225 barrels per day, an increase of nearly 350 barrels per day or 18% over the second quarter as we continue ramping up Phase III of the flood, and implementing a WAG in the first phase and second phases. Beyond that, we're continuing the development of Bell Creek with Phase IV expected to begin injection later this quarter.

Non-tertiary oil equivalent production was down 2% or about 550 barrels per day on a sequential quarter basis and 5% or just over 1,600 barrels per day from third quarter 2014 levels. The production shut-in for economics and natural production declines drove the main reductions both comparative to the second quarter of 2015 and to the third quarter of 2014, while the restored production after the flooding at Thompson added about 300 barrels per day compared to the second quarter.

Adding some color to the production shut in due to economics, these are wells that at today's prices are either uneconomic to operate or that require repairs that are not economic. Phil mentioned that we have about 1,100 BOE per day shut-in for economics and this is split between about 200 BOE of tertiary production and 900 BOE of non-tertiary production.

Our current assumption is that this continues until oil prices improve. Of course we continually evaluate the economic thresholds on all of our wells and can put production back on line if justified.

And just to clarify, I say suspended because when prices eventually return to needed levels, it will require minimal time to bring that production back on line. As Phil made clear earlier, we are focused on making value based operation decisions rather than just driving production growth.

A good example of this is our Hastings Field that I mentioned earlier. As shown on slide 17, we determined that we can significantly reduce daily CO2 purchases in Fault Block A by optimizing injection rates and using water instead of CO2 in certain cases.

As a result, we were able to cut CO purchase volumes in half, resulting in a small production impact of about 250 barrels per day, but the overall change resulted in an expected $10 million increase in cash flow in 2015. LOE continued to trend down for the seventh consecutive quarter.

Absolute LOE for the third quarter was $128 million after adjusting for $14 million in non-recurring utility and insurance credit. This is a 3% decrease from the prior quarter and an 18% decrease from the third quarter of 2014.

On a per barrel basis adjusted LOE was $19.43 per barrel, 1% below the prior quarter and 20% below the third quarter of 2014. The biggest drivers of this decrease are reduced workover expense and lower CO2 costs, which I'll discuss in more detail in a moment.

I'd also like to point out that the small uptick in power and fuel from the second quarter was driven by a non-recurring credit that we received in the second quarter. And for the fourth quarter, we expect LOE to remain around $20 per BOE.

I mentioned that we've driven sustained improvement in our CO2 efficiency. This year we've reduced our total company injection volumes from 979 million cubic feet per day in the first quarter to 678 million cubic feet per day in the third quarter, representing a 31% reduction from the first quarter.

I will get into that in a bit more detail on the next slide, but this is an impressive accomplishment especially as production has been held relatively flat or in the Hastings case, we've traded some temporary production shortfalls for improved overall cash flow. The graph on the right breaks down the composition of our CO2 costs.

I want to show it to highlight the cost impact of managing CO2 volumes. We've seen some benefit from lower direct pricing of CO2, but the lion's share of the savings since the first quarter, nearly $0.77 per BOE has been accomplished by reducing volumes.

Beyond costs increasing our efficiency with Gulf Coast CO2 extends the life of our strategic low cost Jackson Dome asset. The chart on this slide looks at our prior projection of long-term CO2 supply and demand in the Gulf Coast, which as you see in yellow has now been reduced to less than 600 million cubic feet per day versus our prior expectation shown in red of nearly 1 billion cubic feet per day.

This improvement has multiple implications, not just reducing the cost of producing oil, but also reducing the capital required to manage Jackson Dome, as well as opening up additional CO2 flood opportunities. Our development design teams are incorporating the learnings that have reduced our use of CO2 into their field development plans and I expect that we will be revising our projections for CO2 demand as those plans come together.

We intend to continue to use both natural and industrial sources of CO2. Our industrial sources have remained relatively constant during the third quarter of 2015, delivering about $60 million a day in the Gulf Coast, and just under $40 million a day in the Rocky Mountain region.

Looking forward, our teams continue to focus on taking advantage of the current business environment as an opportunity to improve every aspect of our operations from working through field development plans for each of our fields to optimizing our current fields and operations to improving our underlying operations and project management processes. All of this will position Denbury to not only succeed in the current environment, but in the future as well.

And now, I'll turn it back over to Ross.

Thank you, Chris. That concludes our prepared remarks.

Laurie, can you please open it up for questions.

Hi. Good morning, guys.

Thanks for taking my questions. Phil, if oil prices recover in the second half of 2016, how quickly can your capital program and your production respond to these higher prices?

And then also, what oil price is necessary to bring that suspended or curtailed production back online?

Well we, I mean, I think we can adjust our spending relatively quickly, probably not instantly, but maybe if you give us a few months lead time. But it depends on what the expenditure is, what the production response will be.

Obviously if it's initiating a new part of a flood or starting a new flood, there's going to be a delay in that production response. If it's drilling a well or repairing some of these uneconomic wells, that response will be very quick, almost instant.

So, I think it depends on what we do and where we'd allocate the money. As to the uneconomic wells, I'd say most of them probably need to be at least in the mid-$60s per barrel, but again that does vary, some may require $70s per barrel and that probably varies a little bit depending on what the situation is.

Thank you for that and then in your prepared remarks you mentioned the possibility of some acquisitions. Why would you feel the need to do further acquisitions?

It seems like you have plenty of inventory to flood with CO2, right now, especially with the flooding schedules on some of these projects pushed out and to the right with these lower oil prices and lower cash flows?

Well again, I believe as I mentioned we're looking for ones that don't require a lot of capital to buy them, so it's not like we have a big carrying cost, I guess. And they provide additional flexibility for us in the future and we are optimistic of course, that oil prices will recover and that we can resume our growth.

And so, having more inventory that we can pick up at these distressed prices, it seems like a good thing to us, particularly when you're not tying up a lot of capital with purchasing.

Good. And then – the one last one from me, what's the latest from Riley Ridge?

Not a lot new at Riley Ridge. We've been working on a solution to solve the software deposition.

They believe they fixed the issues that were related to the plant. So we're – we had two or three options on that.

We're still kind of fine tuning the cost and so forth. The hard part today is as you probably noticed, gas prices have gone down, went to the low $2s.

And so, I think it -- looking forward we have to consider the economics and what it costs to implement these changes. We're not quite ready to go yet, but we're – I think we're zeroing in on a solution, but the natural gas market probably hasn't helped us with regard to that.

Keep in mind that with regard to Denbury, that really the CO2 that would come off of that plant really isn't needed until we published our CCA, which is probably at least five years off.

Great. Thanks so much for that, Phil.

Yes. Good morning, everyone there.

I'm wondering -- I know this is a theme that we've touched on certainly last quarter and awhile and previously, but I want to go back to the idea -- to the question of how durable these reductions in LOE are? And I think you gave part of the answer in saying that most of your shut-in volumes are actually not tertiary volumes.

But presumably if some of those are tertiary volumes, of the 200 barrels a day when you try to bring those on your LOEs are going to go back up. And I'm wondering if you could just talk about the longer term – your longer term view on how durable the savings are and if there is any unknowns that you're trying to keep track of on, maybe what the long-term effect of reduced CO2 injections on fuel productivity is?

Well. So, I'll start with the last part of the question.

We're definitely watching the impact on production and any effect that using less CO2 would have and of course as Chris showed you, a chart showing that in monitoring that we did note that the production at Hastings dropped a little bit, although again it was still a positive impact on cash flow. So that's a trade we would make.

We're looking at that we're seeing if maybe – if we increase just a little bit of injections, can we get the production back. So it's not a real precise science in some cases and we have to do a little bit of experimentation, but I think if you look at our LOE, it's really two categories.

CO2 costs have come down substantially and workover costs have come down substantially. We feel confident that we can keep the CO2 usage down, don't know if it will stay exactly where it is, but I think we are making a concerted effort to maximize every molecule of CO2 and we can continue to do that and we are seeing minimal impact on production.

So, we feel pretty confident that we can do that. Obviously as price – oil prices go back up the costs per Mcf, goes up a little bit, but as Chris pointed out in his slide most of the savings have come from lower usage not from oil prices.

Workover expense, if you do put these uneconomic wells back on and you spend a little bit more money, you will see a little bit of an uptick in workover expense. I don't think it will be – go back to the old levels.

For one, we're very focused on solving what's causing the workovers, and reducing them and looking for the root cause analysis and so forth. So we're very conscious of what we spend.

But then I think, if prices did increase, I think you probably would see workover expense pickup a little bit.

Got it. That's helpful color, Phil.

And maybe a simpler question. What's the story with the production uptick at Oyster Bayou and Bell Creek?

It sounds like that's just part of the – your typical tertiary ramp, but I thought I'd test that idea and see if there is maybe some other aspects of the quarter-over-quarter production bump for those two fields?

Well, I mean Bell Creek is just we continue to expand Bell Creek, and so it's really for the most part related to continued development. In fact as, I believe, as Chris mentioned we're continuing that, and we plan to start injecting in Phase IV any time.

Also if you look at our capital expenditures, Bell Creek is one where we've actually continued to spend money in 2015, and we really haven't reduced the budget there really at all to speak of. That one stayed pretty whole.

So, Bell Creek is, I guess if you summarize it, is really kind of related to continued development now. We're looking at Phase I and II, and we've implemented a WAG and obviously we're very focused on conformance and so forth and so on and that is helping.

But I think that's the short answer. Oyster Bayou production is up a little bit.

I think we've seen good positive results from the A-2 Sand, maybe it was a little bit better than we had originally forecasted. But to manage expectations, Oyster Bayou is largely – it is basically fully developed.

So I wouldn't expect that to continue to grow, but obviously, again we're trying to maximize our conformance. We've – just go to 40,000 feet, we've put a significant emphasis and effort on reservoir management and surveillance.

And I think you're seeing some of those results in some of the production levels staying at the current level a little bit longer and so forth. In fact, if you look at the mature properties, if you noticed we're really keeping that pretty flat in 2015 even though we normally would have a 10% decline.

So I think it's back to kind of the nitty-gritty engineering reservoir management. But I think you're seeing positive impacts.

That's great detail. Thanks, Phil.

Hi. Good morning, folks.

Thank you for taking my question. First, if it was in the release I missed it.

But can you just repeat the repurchase numbers? You said it was 1% of shares outstanding?

I think we've done about 4.4 million incremental shares.

Great, great. And then I guess this is for Phil or Chris.

In prepared comments, I know Phil mentioned if I heard correctly it will take about another year to kind of finish your field by field review. Should we take that as kind of there is potentially more low hanging fruit that you can kind of clean up as you think about the improving efficiencies?

I think there is yes, although I think a lot of that will show up more in long-term capital and long-term improved returns, and not so much in LOE. So, we are working through the development plans on every field.

We're part way through that, but we have another year. But I think this will show up more in improved results overtime.

I don't want to mislead you and think that there is a lot of additional low hanging fruit in LOE. We are continuing to work it, but that's kind of a separate process.

Okay. That's all I had.

Thank you.

Morning Phil and Mark. Thanks for taking my questions.

Morning.

Could you guys comment at all, I understand that the share buybacks here, I guess there is, is it fair to think that this window to make share buybacks is basically within the fourth quarter here. Because as you go into 2016 you will effectively be running a free cash neutral program and you're not going to take on incremental leverage to buy back shares.

Or would you be willing to take on leverage to buy back shares?

I think it would be possible depending on the oil price, et cetera, I guess what I was trying to say, we are trying fund it with excess free cash flow, but we generated a little bit of excess free cash flow and reduced the leverage in 2015. The bank debt, I think I made the comment that we would not want the bank debt to go above year-end 2014 levels, but of course, we're going to end up the year somewhere probably north of $200 million below.

So, I guess the way we kind of look at is we probably have a little bit of free cash flow set aside that we would consider. But it has to be a really good opportunity and obviously, we are very conscious of managing our cash and being very prudent with our cash.

True. And I guess if you were to think of all else equal having free cash right now available is share buybacks more attractive to you than repurchasing your debt?

Good answer, yes. If you look at the impact that $50 million, $100 million, what it pick whatever number you want, but if you look at the impact that it can have on the long-term aspects of the company.

You can make a significant dent in the outstanding shares for a little bit of money. Yes, you can buy debt.

I think we're trading Mark I may need your help, I think 65%, 70%, is where they're kind of trading, and that's nice. But it's not going to have as much of an impact long-term is as spending the same amount of money on shares, again all depends on where the shares are and debt is and so forth.

But generally we would see that as a maybe better impact.

Got it. And could you give us any update on where you are in the thought process now of with the dividend suspension some excess capital available for operations perhaps.

Are you looking at accelerating Webster or is that still part of the 2016 budgeting process that hasn't been determined yet?

So it is somewhat a part of the 2016 budgeting process. We also have not completed our revised plans for Webster to date and actually it's not schedule to be completed till probably about second quarter of 2016.

So, I think it'd be highly unlikely we would start anything at Webster until we get that completed. We'll see where oil prices are, so the earliest I think you'd potentially see something at Webster would definitely be in the second half of 2016.

In terms of flooding but production volumes would be I guess early 2017 or?

Yes, production volumes would be in 2017.

Okay. And just the last one I had, just to recap on Tinsley.

I understand you guys had warned last call that things were kind of peaking out there, just given the warmer temperatures. I can't remember if I'm misremembering this, but was there a coolant plant that was down for the CO2 there, and has that been reconstructed?

No, I don't believe it was a coolant issue, it was – we always struggle a little bit with CO2 in the summer, because as the temperature goes up it becomes more gassy and it becomes a little bit harder to manage. So that was part of the issue, we kind of were hitting facility constraints there and I think – and so those things caused a, what we believe is a little bit of a temporary dip in production or more exaggerated, then we would have expected.

I think if you look at Tinsley, you know we've been saying for some time that the field is generally developed and don't expect production to grow anymore. I think if you kind of look at the trend over the last year or two is it's been running the low 8,000 barrels a day, 8,300 barrels a day.

So, over time we do expect that to decrease, I guess, the message we're trying to say, it was a little bit more exaggerated decrease in the third quarter because of some of these facility things and CO2 issues. And we expect part of that to come back, but if you look at the long-term picture at Tinsley we do not expect it to really grow.

It will start decreasing.

Okay. Thanks for your color, Phil.

Hey. Good morning.

Good morning, Parks.

See, thinking about Rockies and the CO2 in the Rockies, I was wondering as far as other operators doing tertiary production up there. Do you have any sense of what the volumes being sold out of LaBarge are for the overall region, are right now especially given the pull back in oil prices we've had?

Well, I don't know that we are privvy to their precise volumes of what's being sold. I mean, we know kind of what the plant capacity is, it's in the range of between 300 million and 350 million of day, because we have a third of it.

But I don't know that we can answer exactly what's being taken at this moment.

Sorry. Probably a better way to put it would be – just are you aware of any decrease in activity in any of the other large fields along that pipeline route?

I don't know. Again, I don't know that we know specifics.

I mean if I were to speculate I would guess they are probably not taking, not increasing their volumes just in light of the oil price, but I don't think I probably can comment on that.

Sure. No problem.

And sorry if you touched on this earlier, but as far as the work on the Cedar Creek Anticline and just workover activity and so forth. I know over the years you've done a fair amount of working on optimizing those water floods out there, just any progress anything new on that front in this quarter?

I don't think there is anything really unusual or revolutionary. I mean, that they – I kind of alluded to it earlier, they've obviously been focused on root cause analysis and we've seen the failure rate come down 20%, 25%.

So that's part of what's helped us with workover cost because not only is the failure rate coming down, but also obviously vendor costs have come down. So add those two together and you get some pretty significant savings.

We continue to work that, continue to experiment a little bit and we're just trying to maximize that asset just like all of the others, but we have seen significant improvements at CCA in terms of our failure rate and that's a positive.

Great. Thanks.

That's all from me.

Hi, good morning.

Good morning.

Do you have any expectations on the borrowing base. I know it's in May, but any thoughts if strip prices held today what that would look like?

We've run some sensitivities based on what we saw for fall numbers and such. I mean, obviously reserves process is ongoing for year end and those will be the reserves we'd use.

So, everything we're working off those so there's been kind of historical roll forward for the most part. I think obviously price decks have come down for the banks, so we would expect to see probably some degradation in the $2.6 billion, but we don't feel like the $1.6 billion would be in jeopardy, based on what we know at this point at all.

So, obviously prices can change, and, but, would expect the banks will continue to approach things fairly conservatively going forward. So, that's what we're anticipating.

Okay. And then with regard to acquisitions.

What type of scale would you think about and would these be tuck-ins around your existing acreage. And then finally, how would you think about financing?

Yes. They would be tuck-ins or bolt-ons or however you want to describe them.

They'd be fields that we can access with infrastructure without significant expansions to infrastructure. We'd probably, I guess, in short we'd probably finance it just with bank debt, but again keep in mind we're being will be in – we aren't really looking at any of that would be a really large expenditure.

The one we purchased earlier this year was about $20 million a couple were looking at now are probably even less than that. So, we're not talking major outflow.

Okay. Great.

That's all I have. Thank you.

Yes. Hi.

Good morning, guys.

Good morning, Joe (48:50).

Can you just walk me through, how you guys are kind of evaluating buying back stock versus buying back the bonds in the 50s and 60s? What's kind of – are you looking at IRR there, kind of what's the exact calculation you guys are when you're evaluating in these analysis?

I think we're looking at – when you can do IRR and that sort of thing, but I think probably we're looking more – what has the biggest impact on the company long-term? And say take $100 million, for $100 million at the prices we paid would get you 10% or 11% of the company, how does that compare to what $100 million would do with buying debt and you save maybe $30 million or $40 million.

If you look at those two, we just feel like the long-term benefit to the company and to the shareholders is superior buying stock at that price, now it all depends on what the price is and so forth with all the normal caveats, but that's kind of I guess how we look at it.

Okay. Thank you.

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

On the conference front, Phil Rykhoek who will be presenting at Bank of America Merrill Lynch Global Energy Conference in Miami which will occur next week. The details are available on our website and the webcast for Phil's presentations will be accessible through the Investor Relations section.

Lastly, for your calendars, we plan to report fourth quarter 2015 results on Thursday, February 18 and hold that conference call that day at New York time of 10 AM. Thank you again for joining us on the call today.

We look forward to keeping you updated on our progress.