Denbury Inc.

Okay. Thank you, Mary, and good morning, everyone.

We're glad to have you join us for today's call. With me on the call today from Denbury are Phil Rykhoek, our President and Chief Executive Officer; Mark Allen, our Senior Vice President and Chief Financial Officer; and Craig Mcpherson, our Senior Vice President and Chief Operating Officer.

Before the call begins, let me 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 our corporate presentation, our latest 10-Q and 10-K and today's news release, all of which have been posted to our website at denbury.com. Also, over the course of today's call, we will reference certain non-GAAP measures.

Reconciliations of and disclosures on these measures are provided in today's news release. With that, I'll turn the call over to Phil.

Thanks, Jack. This morning, we reported a sequential improvement in our quarterly financial results.

Adjusted net income, adjusted cash flow both increased, primarily as a result of higher oil price and that more than offset the impact of the modest sequential decline in production that we had expected this quarter, largely due to our remediation efforts at Delhi. We generated over $300 million of cash flow from operations in the third quarter, over $1 billion year-to-date, meaning that the operating cash flow should more than cover our 2013 capital budget and will allow it to pay a significant portion of the roughly $200 million of common share repurchases we've made so far this year.

Craig will give you a more detailed report on Delhi, but I'd like to highlight that our remediation efforts are nearing completion. We have resumed CO2 injections into the areas surrounding the relatively small part of the field, directly impacted by the release.

Our team has worked tirelessly to remediate the field. And I can assure you that the lessons we've learned are being applied across the organization.

We expect gradual improvement in Delhi's production in the fourth quarter, which when you combine it with anticipated tertiary production growth at Hastings, Heidelberg, Bell Creek and Oyster Bayou, that should result in a resumption of company-wide sequential quarterly production growth. As a result of this delay in the completion of Riley Ridge, now expected to be completed in the first quarter of 2014, and some weather related downtime in the Rocky Mountain region in September and October, we do see 2013 average production coming in a bit lower than we had perhaps projected last quarter, although we still expect it to be slightly above the midpoint of our 2013 production targets.

As noted on last quarter's call, we commenced tertiary oil production in Bell Creek Field in Montana in the third quarter. This is a significant milestone for us, as it represents our first tertiary oil production in the Rocky Mountain region.

We anticipate that Bell Creek will be a key driver of our tertiary production growth for many years to come. With our Analyst Day less than a week away, we will not be discussing on this call the outcome of our corporate review process for our 2014 production and capital expenditure guidance numbers.

We'll also try to keep today's operational comments down to a minimum, as we will present a complete review on each of our fields at the analyst presentation next Monday. So with that, let's have Mark and Craig give you more details on this quarter.

Mark?

Thanks, Phil. In my comments, I'll provide you additional color around our Q3 results.

I'll primarily focus on the sequential change, the results from Q2. I'll also provide some guidance for Q4 to help you update your financial models.

Our adjusted net income in non-GAAP measure for Q3 was $165 million or $0.45 per diluted share. Adjusted net income improved from $0.21 per diluted share in Q2, primarily due to higher oil price realizations, partially offset by slight decrease in production volumes.

Adjusted cash flow from operations, a non-GAAP measure, which excludes working capital changes, was $352 million for Q3 or $0.95 per diluted share, but it would have been over $0.10 higher if the results were adjusted for the impact of the Delhi remediation charge and higher current income taxes that resulted from an expected delay in the completion of Riley Ridge. Total production for the quarter came in at just over 71,500 BOE per day, down about 3% from Q2, mostly due to decreases at Delhi and Cedar Creek Anticline.

Craig will provide more details on our Q3 production, on our Q4 production drivers in his comments. Our average realized oil price, excluding derivative settlements, was $106 per barrel for the quarter, which is up from $99 per barrel in the second quarter.

We sold our oil at an average price that, as expected, was just about in line with NYMEX in Q3, down from the $5 premium we realized in Q2. The average premium to NYMEX for our tertiary production in the third quarter was about $4 per barrel, down from $11 per barrel in Q2, as the difference between LLS and NYMEX pricing continued to narrow during the third quarter.

With current LLS premiums only modestly above NYMEX pricing and the recent widening in Rocky Mountain region differentials, at this time, we expect our realized oil price differential to range from $3 to $5 below NYMEX in Q4. Moving to our hedging activity.

With higher NYMEX oil prices during the quarter, we paid out a small amount of hedge settlements in the quarter, and we also recognized an $80 million pre-tax non-cash loss on a mark-to-market change in our derivative positions. NYMEX oil prices have declined thus far in Q4, and if they remained near their current levels, we would not expect any cash hedge settlements in Q4 and would anticipate a noncash mark-to-market gain on our old derivative positions in Q4.

The objective of our hedging strategy remains the same, to protect our exposure to a sharp drop in oil prices, while retaining some upside exposure. We have historically done this with costless collars and during Q3, and we added a combination of NYMEX and LLS-based collars for the third quarter of 2015.

The details of our hedges can be found on our website, included in our corporate presentation. Moving to our operating costs.

We reported additional pre-tax charge of $28 million related to our remediation efforts at Delhi Field in Q3. This charge increased our current estimate of known cost to remediate the impact of the area of Delhi to $98 million.

These charges do not reflect any potential insurance recoveries for these expenses, which we will not report in our financial statements until we determine that receipt is virtually certain. Excluding the Delhi remediation costs, our overall lease operating expense per BOE averaged in the mid-$23 range, which is slightly better than our guidance for the quarter.

Looking forward to Q4, we expect LOE per BOE to again be in the mid-20s range, but slightly higher than what we saw in Q3. Again, excluding any potential nonrecurring items.

These LOE rates do not include amounts for taxes other than income, marketing and CO2 operating costs, which you will need to consider separately for your modeling purposes. G&A expense was roughly $36 million in Q3, which was in line with our expectations but up slightly from Q2.

Of our third quarter G&A expense, about $7.5 million was stock-based compensation. For Q4, we expect G&A expense to be between $35 million and $40 million, with approximately $7 million to $10 million of that in stock-based compensation.

Our overall DD&A per BOE was little change from Q2 at about $19. Looking to Q4, we estimate that our DD&A rate may translate higher to the low $20 per BOE range, depending on several factors.

Our effective income tax rate for Q3 was approximately 36%, slightly below our estimated statutory rate, and about 28% of our income taxes were reported as current. The impact of differences between our 2012 tax provision and filed tax returns and the impact of revising our estimated completion date of the Riley Ridge to Q1 of 2014 from the fourth quarter of 2013 caused our rates to be lower-than-expected and our cash taxes to be higher-than-expected.

Looking to Q4, we anticipate our effective tax rate to be between 38% and 39%, with current taxes representing 10% to 15% of total taxes. Moving to our capital structure.

Total debt at September 30 was approximately $3.3 billion, up slightly from the end of Q2. We had $310 million drawn on our bank line at the end of Q3, up from $260 million at the end of last quarter.

Based on our current assumptions for cash flows and capital expenditures for the remainder of 2013, we anticipate ending the year with between $200 million and $300 million borrowed on our bank line, excluding the impact of any incremental share repurchases in the quarter. Interest expense.

Net of capitalized interest was $35 million compared to $31 million reported in Q2, mostly due to lower capitalized interest. Looking to Q4, we expect capitalized interest to decline further to between $10 million and $13 million from about $20 million in Q3.

Our capitalization metrics remained solid, and our debt-to-capital ratio was approximately 38% at quarter end, and our debt to Q3 annualized EBITDA was just about 2x and would've been a bit lower if the Delhi remediation expense were excluded. Our 2013 capital budget remains at $1.06 billion, plus an estimated $160 million for various items including capitalized internal cost, capitalized interest and preproduction start-up costs associated with new tertiary floods.

We have spent about 70% of our full year capital budget through the first 9 months of 2013. And in the third quarter, we were active in our share repurchase program and we spent about $110 million on share repurchases during the quarter, bringing our cumulative purchases under the plan since we initiated a little over 2 years ago to about $660 million.

With these purchases, we have repurchased about 43 million shares or 11% of our total shares outstanding as of October 2011 at an average price of just under $15.50 per share. We had $109 million still authorized under this program at the end of Q3 and going forward, we intend to remain opportunistic with our share repurchase program.

And now I'll turn it over to Craig for an operational review.

Thank you, Mark. Our tertiary operations performed in line with our estimates in the third quarter.

Oil production averaging just about 37,500 barrels per day. Our tertiary oil production declined in the quarter due to the previously discussed issues at Delhi and facility downtime at Hastings, partially offset by increased production in Oyster Bayou and Heidelberg Fields.

I will discuss the 2 key fields that have material impacts to our tertiary production in the third quarter and they're likely to have the most significant impact over the remainder of 2013. So let's start with Delhi.

As you recall, we halted CO2 injections into the southwesternmost area of Delhi Field beginning late in Q2, as we remediated portions of that area from a release of well fluids. Our team has made good progress on our remediation efforts during Q3, allowing us to resume CO2 injections into the parts of the field surrounding the area directly impacted by the release, leading only a small portion of Delhi, into which we are not injecting CO2.

We are doing additional diagnostic work in this small area to ensure the condition of several oil wells is adequate and have isolated it from other CO2 injection wells using water injection wells. The net result is that we expect a modest increase in Delhi's production in Q4.

Based on actual remediation costs incurred to date, we've increased our current estimate for those cost by $28 million to a total of $98 million. With the primary phase of the remediation nearly complete, this represents our current best estimate of nonremediation cost as opposed to last quarter's estimate, which reflected our minimum estimate remediation cost.

Let's go to Hastings. In Hastings, production declined somewhat from that second quarter, primarily due to facility downtime for repairs and maintenance.

With the expansion of our flood and recycle capacity at Hastings, we expect production to increase in the fourth quarter. Oyster Bayou remains a bright spot for us as the field continues to show steady growth as it responds to our CO2 flood.

The field's production increased 28% from Q2 levels, and we anticipate continued production throughout Oyster Bayou in Q4, as the field continues to respond to CO2 injection. Our Heidelberg CO2 flood was also a bright spot for the quarter, with the field's tertiary production increasing 10% from Q2 levels.

We saw continued response from the new areas we're flooding in East Heidelberg and that development continues. We expect the CO2 response from East Heidelberg to be an important driver of our expected tertiary growth in the fourth quarter.

For our mature area properties, production declined by 6% sequentially and was 8% lower than the year ago quarter. We had held production from these property relatively flat in the first half of the year, so the decline reflects a return to their normal decline rate.

For the 9 months ended September 30, mature area property production was 10% lower than the prior year level. Let's go now to our Rocky Mountain region.

Bell Creek's tertiary production increased gradually during the third quarter as the field responded to the CO2 injections we started earlier this year. After some limited deliverabilities earlier this year, CO2 delivery to Bell Creek has recently been holding near their contracted level of 50 million cubic feet per day, which should drive continued production growth in the fourth quarter.

At Grieve Field, we continue to inject CO2 and water to build operating pressure and anticipate first oil production late in 2015. Production from our nontertiary assets decreased to 34,018 barrels of oil equivalent per day from 35,300 in the second quarter, primarily due to production declines at Cedar Creek Anticline.

Our Cedar Creek Anticline production, including both legacy and newly acquired fields, was 18,872 barrels of oil equivalent in the third quarter, and that's compared to 19,935 in Q2. The decline in CCA was primarily attributable to above normal levels of weather and repair-related downtime, as well as a higher net profit interest of a third party in the third quarter.

We continue to look for opportunities to increase and/or maintain production on our nontertiary, assets in advance to our planned CO2 floods. Looking at production on a total company basis.

Based on results thus far in the fourth quarter of 2013, we expect both tertiary and total production to be slightly above the midpoint of our estimated ranges for 2013. I look forward to providing you a more compressive overview of all the tertiary and nontertiary fields at our Analyst Day next Monday.

So let's move on to lease operating expenses. Our lease operating expense per barrel of equivalent production, excluding the Delhi Field charge, increased by 4% from the second quarter to $23.24 per BOE in the third quarter.

Operating cost for our tertiary properties, excluding the Delhi charge, had reached $25.08 per barrel during the third quarter, and that's an increase from $23.52 on the prior quarter. The increase was attributable to the expansion of our CO2 floods, primarily Bell Creek, and increases in the cost of CO2 related to both higher realized oil prices and additional anthropogenic supply.

Let's move now to our CO2 supply and transportation operations, which in general, is performing quite well. In the Gulf Coast region, we produced just under 900 million cubic feet per day of CO2 from Jackson Dome during the quarter.

After our first well at Jackson Dome this year was highly successful, which added 350 Bcf of reserves, our second oil was determined to be uneconomic and the drilling of our third and final well planned for this year is underway. We continue to expect this year's drilling [indiscernible] Jackson Dome will allow us to fulfill the growing needs of our Gulf Coast CO2 floods.

Moving to our anthropogenic or man-made CO2 sources. We continue to make progress in increasing our supply.

Today we're currently injecting about 70 million cubic feet per day of CO2 and capture from both Air Products and PotashCorp into Denbury's operated Gulf Coast fields. Additionally, Mississippi Power's power plant, currently under construction, should be completed in 2014.

And once operational, should provide more than 150 million cubic feet per day of CO2 to our Mississippi tertiary operations. In addition to these sources, we're in various stages of discussions with other project sponsors that could further increase our Gulf Coast CO2 sources likely this decade.

In the Rocky Mountain region, we now expect natural gas and helium production from Riley Ridge to commence in the first quarter of 2014, which is slightly delayed from our previous estimate of the fourth quarter of this year. The plant is very near mechanical completion and our team is focused on ensuring a successful start up of this plant, which will ultimately become the anchor source of our Rocky Mountain CO2 supply.

CO2 deliveries from ExxonMobil's Shute Creek facility has been steady, and we expect to complete the interconnect of our Rocky Mountain CO2 pipeline to the third-party pipeline that transports CO2 from Shute Creek in the fourth quarter. This interconnect is important as it will allow us to deliver CO2 from Shute Creek to the operated Bell Creek Field, allowing us to supplement and diversify our CO2 supply to the field.

And with that, I'll turn the call back over to Jack.

Okay. Thank you, Craig.

Mary, that concludes the management's prepared remarks. Can you please open the call up for questions?

Can you all talk about the level of production response you're going to need to see this year at Bell Creek to book reserves? And then, kind of give us a tally of where you might be today.

Well, we're optimistic that we'll be able to book them this year, although we're still not certain about that. So we're waiting to see how the fourth quarter does.

I think as Craig mentioned, in the third quarter, we were a little short on CO2. And so therefore, it kind of delayed our response a little bit.

That was just the supply was a little less -- there were some turnarounds in work at the Conoco plant. So conceptually, production has to be above what it was when it was producing conventionally to be able to book approved reserves.

We're starting to have some discussions with the independent engineers on that. Like I said, we're optimistic, but it's not a certainty.

Okay. And then just a couple of field level questions.

At Hastings, can you kind of give us a little bit more information on the trajectory you're expecting after the third quarter issues?

We're expecting the production to grow in the fourth quarter as we continue to develop Hastings. We had some downtime associated with the turnaround, as well as some compressor repairs, so that's behind us.

And so that plus just the continued response in the pattern that we expect production to grow at Hastings in Q4 and into the next year.

Okay. I mean, could we model above second quarter or is it going to be somewhere between third quarter and second quarter?

We would expect it to be above second quarter.

Okay, that's helpful. And then one more.

Can you quantify the impact of the weather and downtime at CCA this quarter?

Mark?

I can tell you the cause of it. We were down for about 8 days due to the weather.

We had a freak snowstorm in the Rockies. The snowstorm lasted about 2 days.

There was power outage throughout a large number of our fields across Cedar Creek Anticline [indiscernible] and that lasted into about 8 or 9 days. And we've also had a bit of weather in October as well that we'll factor in.

As you're making progress at Delhi, how should we think about the Delhi reversionary interest?

Well, obviously, we spent a bit of money there. So it depends on those dollars plus, of course, what prices are in 2014.

But I think, we're a little hesitant to kind of give a date at this point yet, because we're -- we haven't sort of settled how we handle the insurance proceeds. Are they done on a cash basis, or are they estimated and accrued in a payup calculation?

So that could swing it several months, as you can imagine, because we estimate 1/3 or 2/3 of those dollars we recovered with insurance.

That's helpful. And then, thus far, the total cost for remediation, $98 million at Delhi.

Just want to clarify, when you were going through your prepared commentary earlier, were you saying that $98 million was the max that you expected? Or that's -- there still could be a higher level than that?

No. I mean, the way we kind of accrued is always kind of the minimum.

It's just that we're feeling much better about the total cost at this point. I mean, we're -- the remediation is nearly done, the well that we were working on that was the primary culprit, we plugged it, that work's done.

We are still working on another well. There's some -- there's still some open items, but we think that we're getting very close to the end.

And so it could be higher. In fairness, it's not going to be less, but at least, we're nearing the end of the work.

Great. And then on Cedar Creek Anticline, as you think about that asset before you move to CO2 flooding, do you see that as an asset that you can meaningfully grow its production before flooding?

Or just kind of keep it flattish?

I think it'd be difficult to grow CCA, but I think if we can mitigate or diminish the decline rate, I think we'd call that a success. So we do kind of plan to spend some money there, but I don't think it's going to increase it.

But it's about making not many -- very slight decline or maybe close to flat.

So I was wondering if you can talk about the current production rate at Delhi. And -- because I want to kind of get a bit of understanding for how much of the 1,500 BOE per day of oil production that was sort of lost previous quarter.

How much do you think you can regain in your fourth quarter? And how long will it take you to regain that for 1,500 going forward?

Well, I mean, current production is, I guess, slightly higher than the average in Q3. As Craig mentioned, we expect modest incline in production in Q4.

When you look at quarter-over-quarter numbers, it's a little interesting because you don't see the impact month by month. And one of our lower months, I think, was probably September.

So we do expect the quarter-over-quarter rate to be slightly or modestly higher in Q4 versus Q3. But the good news is, we believe we've hit the bottom and it's now growing.

Okay. And then, second question regarding the -- with respect to CCA.

So I know you said fourth quarter, that number -- production should also come back. But I -- can you give more color as to how -- because I think, in 3Q, it was down about 5%.

How -- I guess, how fast should we think about that coming -- that growing -- that number to grow in fourth quarter?

To manage expectations, we probably don't expect it to be significantly different than Q4 from Q3, maybe up just a little bit. Craig mentioned weather in September.

We also had a bit of weather in October. So the winter season is starting out a little bit tough.

And we were affected by both of those. Some of this does relate to oil price, the net profit interest.

We had very strong oil prices in Q3, but that takes away volumes. So that was a bit of a factor.

And some of the work we did right after we purchased the ConocoPhillips assets, and we got some flush productions, but it maybe declined fairly quickly. It was just kind of quick fixes.

So we do expect it to maybe be a bit better in Q4, but I wouldn't expect it going back to Q2 levels. I don't think that's possible.

Okay. And then, last question, I may have missed it.

Can you discuss the reason for the delay for Riley Ridge to 1Q '14? I probably just missed it.

Yes. So the plant modifications we had to make were a bit more significant than originally planned.

Primary cause has been the shortage of contract workers available to us and that slowed the pace of the work. As I did mention, the plant is now essentially mechanically complete and we are at the cusp of starting to commission it.

So we believe early next year, that plant will be turned on.

Sorry if I missed this, was there any discussion for the coming quarter about what the capitalized interest is going to look like?

Yes. We see it decreasing to roughly $10 million to $13 million in Q4 versus roughly $20 million in Q3.

Okay. And similar trends heading into 2014 as best as you know at this point?

Yes. I think you'll continue to see it trend down slightly and I'll discuss more about that next week.

Okay, great. And -- again, sorry if I missed this, I was juggling a couple of different calls.

At Tinsley, can you just refresh my memory on sort of where operations stand there in terms of the different subphases of the field? I saw production was down sequentially for the quarter a bit.

Well, the development for Tinsley is unchanged. We're developing the North Fault Block, that's gone well.

It was down a little bit. We had a little bit of delay in our development plan there.

We were plugging -- in fact, we were plugging some wells in advance of the development, so that just slowed the pace of it. But essentially, we're on track to develop Tinsley.

We'll give you more color on that next week for what the plan is for '14, but the takeaway, the plan is unchanged at Tinsley. We're happy with how Tinsley's responding.

A bit of delay last quarter, just due to some slight schedules -- schedules slow up.

Tinsley's been relatively flat, really, if you look at it for the last year or 2 years. And so it's really -- I mean, getting a little vacillation from quarter to quarter to quarter but it's -- but for the most part, we expected it to have peaked.

We're just finishing up the areas of the field that we're flooding. And so, it's great.

We don't expect any, really, growth from Tinsley.

Right, right. Actually, along the same line, lifecycle of the floods to the various fields.

I was just sort of struck in the release where you listed the -- that you expected the growth in fourth quarter was going to come from Hastings, Heidelberg, Bell Creek and Oyster Bayou. And just thinking about how now you've got 4 fields on the incline and realize, I guess, this is sort of a mark of things to come.

Isn't that safe to say, where instead of having one field that's really going to dictate the growth trajectory that you're going to have, the field sort of heading online and then as others mature?

I would agree. I mean, it's great to have multiple fields growing.

I was hoping to just ask about Oyster Bayou, if you could give some color there, I guess, as it relates to your previously expected peak production, sort of in the ballpark of where we are now, assuming that we're maybe at 3,600 barrels equivalent a day at the end of the quarter, so you've had like a pretty attractive ramp there. Has it changed any of your assumptions about sort of the recoverable oil in place there?

Or estimates on peak production? And is this more of a result of sort of barrels that were kind of left behind by prior operators?

I don't think we're far enough along to change our recovery rates at this point. It's something -- usually, it takes a little longer before we start adjusting the proved reserves.

I'm going to do first some of this, because we're going to talk about our future plans next week. Anyway, if we can, if we could push that off, I'd appreciate it.

Just have a question on the stock buyback program. It looks like you guys ramped up pretty significantly compared to the prior quarters.

I just was wondering the thought process behind that.

Well, we've always kind of try to be opportunistic. So just to reiterate, it depends on the stock price, oil price and available capital.

And we thought the stock was a little weak in the third quarter, so we picked up a little bit. And we just -- it's not a real formula, but we tend to be just kind of opportunistic depending on those factors.

Okay. Thanks, Mary.

Thank you all for joining us today. Before you go, let me cover a few housekeeping items for you all.

As a quick reminder, we'll be hosting our annual Analyst Day next Monday, down in Houston. Management's presentation at the Analyst Day is scheduled to begin at 1 p.m.

Central time. A live audio webcast of that presentation will be available on our website.

Also, the slides for that presentation and a news release summarizing the key strategic themes of it will be published to our website the afternoon of Sunday, November 10. Phil and Craig will be giving a recap of Analyst Day presentation in New York on Tuesday, November 12.

Please contact me or anyone in our investor relations group if you would like to attend either event. Management will also be presenting at various conferences in the fourth quarter, a full schedule of which is available on our website.

The webcast and slides for these presentations will be accessible through the Investor Relations section of our website on the day of the presentation. Lastly, for your calendars, we plan to report our fourth quarter 2013 results on Thursday, February 20, 2014, and hold the conference call that day at our usual time of 10 a.m.

Central. Thank you again for joining us and we hope to see you all soon.