Denbury Inc.

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

With me on the call from Denbury are Phil Rykhoek, our Chief Executive Officer; Mark Allen, our Chief Financial Officer; and Chris Kendall, our President and Chief Operating Officer. Before we begin, I want to point out that we have slides which will accompany today's discussion.

For those of you that are not accessing the call via the webcast, these slides may be found on our homepage at denbury.com, by clicking on the Quarterly Earnings Center link under Resources. I would also like to remind you that today's call will include forward-looking statements that are based on the best and most reasonable information we have today.

There are numerous factors that could cause actual 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 Phil.

Thank you, John. Good morning, everyone.

Thank you for joining us on our third quarter call. I'd like to begin by congratulating Chris on his well-deserved promotion to President and COO of Denbury.

As we previously noted in our press release, about a month ago, Chris has assumed my role as President as part of ongoing succession planning and in recognition of his significant accomplishments since joining the company. Chris has made a positive impact on the organization during the last year and I'm certain he will continue to create value for the shareholders in the future.

As you know, for 2016, we have focused on a few core goals, reducing costs, optimizing our business, reducing our debt and preserving our cash and liquidity. We have performed well with regard to all these goals and I would like to cover the highlights for you today.

On cost, we've reduced normalized LOE over 28% since late 2013 generating savings in nearly every aspect of our operations with probably the most significant lasting impact relating to our 50%-plus reduction in CO2 usage since early 2015, and a 35% reduction in CO2 usage year-to-date. Administrative costs have also been significantly reduced with the most impactful reduction related to cost associated with our 30% reduction in total personnel since early 2015.

These reductions have resulted in overall reduction in our total cash cost per barrel, down nearly $10 a barrel from our 2014 levels. This quarter, our LOE per barrel increased slightly, although that increase is primarily attributable to the lower production rate and incremental cost for repairs at Thompson Field following the two floods there earlier this year.

Our total operating costs, excluding the non-recurring items were nearly flat with Q2 indicating that we were able to keep these costs at reduced levels, which is true with respect to our CO2 usage, which is almost exactly the same as last quarter. With regard to optimizing our business, we continue to see efficiencies in our capital spending program, and I'll talk more about that in a minute as we look at 2017.

Our debt principal has been reduced by $562 million this year, and with our recently reaffirmed bank borrowing base we have over $700 million of immediately available liquidity plus $385 million of availability on our second lien basket. This quarter, we reduced our bank debt by $60 million primarily with the proceeds from the sale of our Williston Basin assets coupled with a company generally spending within or less than cash flow from per day-to-day operations.

While it's not a pressing issue due to our long-dated maturities and low interest rates, we would like to reduce our debt even more. However, with the recent increase in bond trading levels, it's become more difficult to complete an accretive transaction, and therefore less likely that we'll make significant progress on additional debt reductions in the near term, unless the market conditions change.

On a macroeconomic level, we've been encouraged by the upward movement in crude prices over the last month, although we probably need to exclude this last week which hasn't been quite so positive. But nonetheless, the industry focus seems to be shifting from survival to growth, and we're making that same shift here at Denbury.

We have several years of projects in our portfolio that are economic at current oil prices, and we're in the process of prioritizing these projects for 2017 and beyond in conjunction with our field-by-field reviews that are nearing completion. Most of these 2017 projects will likely be expansions of existing floods and other conventional development, all of which have strong rates of return at the current strip.

The economics of our new floods vary but generally they have breakevens which would probably be defined by many as a minimum 10% rate of return in the upper 40s. So while they are not on the drawing board for 2017, they will be valuable projects in the future.

In addition, we have added an exploitation team to locate and evaluate additional exploitation projects in and around our acreage and while that team is just getting started their preliminary feedback looks positive. Just to be clear, exploitation has always been a part of our business.

It's just in the last year or two, we've probably largely focused on optimizing our CO2 floods. However, we believe the company has many additional potential opportunities to further maximize our assets and we intend to fully evaluate and opportunistically pursue those.

We have not yet set our 2017 capital budget as we are still evaluating various scenarios, but I can provide you with a little color for next year although it may not be as conclusive as you would prefer. Let me preface this by saying we would like to invest enough dollars to arrest and reverse our production decline even though it's minimal, but we are simply not quite ready to commit to a specific budget today.

As such, I thought I'd give an indication of what you should expect at various spending levels, which is a good story in and of itself as the capital efficiency profile of Denbury has significantly improved in the last couple years. If we spend within cash flow, at the current strip, we would probably have a similar capital budget to 2016, that being in the $200 million range.

At that spending level, this would likely result in a production decline of 5% to 10%, although likely a somewhat flatter profile than 2016. If we spend an additional $100 million for a total in the $300 million range, we believe we could keep production relatively flat with the 2016 exit rate.

And of course, if we spend more, we could increase production. I think the key thing to note is that the efficiency of our capital spending has substantially improved as just a couple years ago we required $400 million to $500 million of capital to keep production relatively flat.

Also, you should note that our low decline rates do not dramatically change from one year to the next as historically there was some concern that things would get much worse in subsequent years. If anything, I'd say they are improving.

So, while our capital budget won't be finished until probably early 2017, I trust you can see that whatever the capital program is, our results are continuing to improve as we move towards a sustainable long-term program. Our production this quarter averaged 61,533 BOEs per day, down about 5% from the prior quarter.

This sequential decrease is primarily due to asset sales, continued downtime related to weather-related events and natural declines due to our low levels of capital spending. We expect the fourth quarter production to be relatively flat with Q3 and expect to exit the year in a similar range resulting in full year production within prior guidance and single-digit declines after adjusting for the asset sales, weather-related issues and so forth.

Chris will expand more on our production in a moment, but in summary, this was another solid quarter that we can build on going into 2017. We look forward to giving you an update on our 2017 capital budget and associated production guidance on our next call.

Now, I'll turn it over to Mark for a more detailed review of our financials.

Thank you, Phil. My comments today will summarize some of the notable financial items in our third quarter 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. Starting on slide 7, for the third quarter, on a GAAP basis, we had a net loss of $25 million, but after excluding special items consisting of a $29 million non-cash fair value gain on our oil hedges, a $76 million ceiling test impairment on our oil and gas properties, and an $8 million gain on debt extinguishment, our non-GAAP adjusted net income for the third quarter was $1 million.

The decline from adjusted net income in the prior quarter was principally due to our stronger hedges rolling off in Q2. Depending on oil prices and other factors, we could potentially have another asset impairment in Q4.

Turning to slide 8, our non-GAAP adjusted cash flow from operations which excludes working capital changes was $62 million for Q3, down $31 million from the second quarter, and was primarily due to an approximate $60 million reduction in cash receipts on oil hedge settlements. Just to remind you, the prior quarter adjusted cash flow amount included $30 million paid out in legal settlements.

So excluding that amount from the prior quarter, our change between the quarters was closer to $60 million over the change in our hedging receipts. Our third quarter average realized oil price excluding hedges was $43 per barrel consistent with Q2.

We paid out $7 million on hedge settlements this quarter, which made our average per barrel realized price including hedges drop to $42 per barrel, an approximate $10 decrease from the last quarter when we received $52 million in hedge settlements. Slide 9 provides a summary of our realized oil price differentials relative to NYMEX oil prices.

Our overall realized oil price differential improved roughly $0.60 per barrel from Q2, due to strengthening of both our Gulf Coast and Rockies pricing. We are continuing to see our Rockies pricing improve over the last couple of years, as more transportation capacity has moved into the region.

We believe that the improvement of Rockies pricing is associated to some degree with increased demand to fill new pipelines, so some of this improvement could be temporary. We currently expect that our overall oil differential for Q4 should remain in a similar range to what we have seen for the first nine months of this year in the minus $2 to $3 range.

Moving to the next slide, I'd like to review some of our expense line items. First, our LOE increased slightly from Q2, mainly driven by repair work at Thompson Field, following the weather-related events of Q2.

Chris will go into more detail on our LOE, but we continue to be pleased with the strides that we have made in this area and expect it to remain in the same range for Q4. G&A expense was $25 million for Q3 in line with our expectations and up slightly from $23 million in Q2, with the primary change being stock-based and other long-term incentive compensation granted in July under our customary annual grants to all employees, which was roughly six months later than normal, as we have moved to a mid-year cycle for these grants.

For Q3, net G&A related to stock-based compensation was approximately $6 million. We currently expect that for Q4, our G&A will remain in a similar range to this quarter in the mid to upper $20 million range and stock-based compensation for Q4 should between $6 million to $8 million.

Net interest expense was $25 million for Q3, an $11 million decrease from Q2. As you can see from the detail provided in the lower portion of this slide, our cash interest amount was essentially the same between the two periods.

However, due to our debt exchange occurring in the middle of the second quarter, there is more interest this quarter that is related to our 2021 senior secured notes that is not being treated as interest expense for financial statement purposes. As noted in our last quarter conference call, the accounting for our debt exchange resulted in almost all of the future interest on our 9% senior secured notes being treated as debt on our balance sheet and therefore only $1.3 million out of the $13.8 million of actual quarterly interest on the notes is included as interest expense in our financial statements.

As we make the semi-annual interest payments this debt obligation will be reduced. Capitalized interest in Q3 was just under $7 million, and we currently expect the capitalized interest of approximately $7 million to $8 million for the fourth quarter of 2016.

Our debt (sic) [DD&A] expense in Q3 was $55 million, a decrease of $12 million from Q2 due primarily to the full cost ceiling impairment recorded last quarter and lower production in Q3. We currently expect our DD&A expense will be in the $55 million to $60 million range in the fourth quarter of 2016.

Our effective income tax rate this quarter was 37%, and we anticipate that our full year 2016 effective tax rate will be between 36% and 38% with limited or no current taxes. On slide 11 is a summary of our current oil price hedges.

Since our last quarterly call, we have added more collars in the second half of 2017 with floors around $40, and upside price limits between $69 and $70. We now have around 40% of our current oil production hedge for 2017, with two thirds of those contracts being swaps and one third being collars.

We may add to these positions over time depending on market conditions. Moving to our capital structure.

As previously announced, our banks have recently reaffirmed our $1.05 billion bank credit facility and there were no changes to any of the terms under the facility. At September 30, we had $715 million of available liquidity under the facility of $385 million of additional senior secured second lien notes that we could issue under the $1 billion basket permitted by the facility.

We issued $615 million of second lien debt during the second quarter in conjunction with our debt exchange transactions, and that debt which has traded up nicely since being issued, is now trading above par. The scheduled maturities of our second lien debt and senior subordinated debt are from 2021 through 2023 as shown on the slide.

Therefore, we have no immediate pressure to refinance any of this debt. The next scheduled redetermination of our bank line will be May 2017 and we currently do not anticipate any concerns with meeting our bank covenants in the near future.

On the bottom portion of this slide, you can see that we have reduced the principal amount of our debt by $562 million during 2016, primarily through privately negotiated exchange agreements and open market debt purchases. During the third quarter, we added to our open market debt repurchases, spending approximately $21 million to repurchase $30 million principal amount of our senior subordinated notes.

In total, during 2016 we have used $77 million of cash to repurchase $182 million principal amount of our senior subordinated notes and we still have $148 million remaining for permitted debt repurchases under our bank facility. Our last slide covers the change in our bank facility bonds since year-end 2015, which has increased by $85 million.

As discussed previously, we have been keenly focused on reducing debt while also preserving liquidity during this down cycle. One way we will accomplish this is by limiting our capital spending, which through Q3 is around $35 million less than our cash flow from operations before working capital changes.

Note that the amount here for capital expenditures not only includes the $146 million we have incurred for development spending but also an additional $30 million for capitalized interest and acquisitions. We have also raised around $56 million this year through non-core asset sales.

As such, the primary drivers of our higher bank debt are our note repurchases and working capital changes. The working capital changes are generally a result of the timing of interest payments and cash outflows for accrued capital, LOE and compensation as of last year end, and that have been paid out during 2016.

Based on our current projections, we anticipate that our 2016 year end bank debt balance will range between $275 million and $300 million. And now, I'll turn it over to Chris for an update on operations.

Thanks, Mark, and good morning. To begin, I'd like to thank Phil and our Board of Directors, for their confidence and support.

Having been with Denbury for just over a year now, I continue to be extremely encouraged and inspired by the strength of our asset base and our business model, as well as the capabilities of our employees and their genuine enthusiasm toward the long-term success of our company. Denbury possesses a unique capacity in our industry to generate value in mature oil basins and I believe the future holds long-term growth and success for all of our stakeholders.

Diving into third quarter operations, our solid progress continued through the quarter. A key focus was the work to repair damage caused by severe weather at our Conroe and Thompson fields and I'm proud of the teams that worked tirelessly and safely over the past months to bring those fields back online.

In a broader sense, I'm pleased that we maintained our historically low level of CO2 use for a second consecutive quarter. Our project execution has been exceptional, with the Delhi NGL plant progressing on-budget and on-schedule for start-ups later this month.

In addition, our field development planning continued, enhancing the broad portfolio of development opportunities in front of us. Looking at production, beginning on slide 15, total company production for the quarter was 96% oil and averaged 61,533 BOE per day, off roughly 5% from the second quarter.

Besides natural declines at our current investment level and a seasonal reduction at some of our tertiary fields due to higher summer temperatures, production was influenced by the Thompson and Conroe downtime that we discussed in the second quarter call and a few one-off maintenance and repair events that I'll touch on briefly. Thompson production for the quarter averaged 758 BOE per day, as full field production was not restored until late in the third quarter.

The field has been producing at expected rates since early in the fourth quarter. Conroe production for the third quarter averaged 2,138 BOE per day, as works to repair the central tank battery from storm damage continued.

All but about a 150 BOE per day of production was restored by the end of the third quarter, with a small amount of remaining shut-in production to be phased in as we complete final repairs over the fourth quarter and into the first quarter of 2017. Maintenance activities and repairs during the quarter affected production more than we had planned at Tinsley, Webster and Oyster Bayou.

This was partially offset by better than expected performance at Delhi as conformance on production enhancement projects there continued to deliver solid results, increasing production in that deal by about 7% from the second quarter. We continued to evaluate production at a shut-in that's either uneconomic to produce or to repair.

Adjusting for asset sales and production brought back online during the quarter, we had just over 2,000 BOE per day shut-in at the end of the third quarter, 35% economic at $50 per barrel or below, increasing to two-thirds economic at $60 per barrel or below, with the remainder economic above $60 per barrel. Looking ahead to the fourth quarter, we expect overall production to be relatively flat to the third quarter, with the recovered production for Thompson and Conroe, reduced maintenance and repair activities and continued growth at Delhi and Bell Creek offsetting natural declines.

Across the board, our fields are performing as expected. As an example, full year average production from our tertiary fields is currently anticipated to be within a 100 barrels per day of our initial expectations for the year.

Even though we reduced our capital spending to a minimal level of approximately $200 million this year, our overall decline rate is still expected to be low at 8% to 9% and within our previously reported guidance range after adjusting for asset sales and Thompson and Conroe weather impact. Looking at operating cost on slide 16, LOE for the third quarter was $107 million up $7 million from the second quarter.

Over half of this increase was due to cost associated with re-establishing normal operations at Thompson. On a per BOE basis, total lease operating expenses increased from $17.04 per BOE in Q2 to $18.82 per BOE in Q3, mainly driven by the flood repairs and lower quarterly production volumes.

Through the first three quarters of 2016, we pulled $94 million out of our LOE cost structure compared to the same period in 2015 on an adjusted basis and our year-to-date LOE has averaged $17.32 per BOE on track with our previously guided range and about 13% lower than adjusted full year 2015 operating expenses. Our teams continue to keep a sharp focus on optimizing cost throughout our business, including this quarter's implementation of a WAG project in Eucutta, as well as our continued focus on optimizing well failure rates, electricity cost and CO2 use.

We expect LOE to remain relatively flat in the fourth quarter, as somewhat higher CO2 use and the anticipated startup of the Delhi NGL plant should generally offset the third quarter completion of the Thompson repairs. Turning to slide 17.

Third quarter CO2 volumes and costs were flat with the historic lows we reached in the second quarter with total company injected CO2 volumes again below 460 million cubic feet per day. And as a result, the CO2 component of our LOE was essentially flat with Q2.

What we expect the fourth quarter CO2 injected volumes to be higher than the mid-year numbers, I'm very pleased with this teams accomplishments in this area especially considering that we averaged nearly 800 million cubic feet per day in 2015 and over 900 million cubic feet per day in 2014. Our new third party supply for Mississippi Power's coal fired facility may begin to deliver small amounts to our Gulf Coast region in late Q4.

But at this point, we do not expect to see significant volumes until 2017. Next, I'd like to go into a bit more detail in Delhi, a focus area attracting our highest level of investment this year.

As, I mentioned earlier the field had another quarter of strong production performance and continued to respond positively to our conformance and enhancement projects. We're excited about Delhi's future as the approaching completion of the NGL plant will not only separate NGL's from our CO2 recycle stream for sale but we'll facilitate higher CO2 flood efficiency.

The plant is on budget and nearing completion and we expect initial commissioning and startup later this month. Modest NGL sales could commence by the end of Q4, and will ramp up into 2017.

We expect peak NGL production at the plant to range from a net 800 barrels to 1,100 barrels per day, and we'll be able to further refine this estimate once we have the plant fully operational. Phil mentioned our new field exploitation team and I'll touch on that now.

The team is pouring through Denbury's broad leasehold position of about 600,000 net acres in some of the U.S.' s most prolific oil producing regions where the work has just started and we're not yet ready to discuss opportunities in detail.

I believe that the team is on track to identifying multiple opportunities that will add meaningful value to Denbury's asset base. I'm looking forward to sharing more on this team's results in 2017.

Finally, our 2016 capital development program is on track. Through the third quarter, we spent 73% of our capital budget, about $146 million excluding capitalized interest in acquisitions down 49% from the $287 million spent during the first three quarters of 2015.

We expect full year capital expenditures of around $200 million, in line with our plans. That completes the operations update and I'll turn it back over to John.

Thank you, Chris. That concludes our prepared remarks.

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

Hi. Good morning folks.

Thanks for taking my call and congratulations on a promotion Chris. I thought I'd dig back in, Phil, on your 2017 comments.

You mentioned kind of maybe $300 million of spend. You're kind of flat to your 2016 exit rate.

What do you anticipate that exit rate to be based on current guidance?

We expect it to be very similar to Q3. We expect our Q4 production to be relatively flat, so we'll probably be in the 61,000 range for an exit rate.

Okay. Okay.

So, that's flat ex the Williston Basin production?

Yes.

Okay. That's helpful.

And then, I guess, quickly on Delhi, it seems to be kind of the focus here near term. Assuming things proceed with the plant up and running, should we expect continued kind of growth on a BOE basis and I guess is that your first?

Where do incremental project stack up in the queue for Delhi and how do we think about that growing into 2017?

Tim, this is Chris. What I'd say, a couple things.

First we have just the plain oil and gas conformance and production enhancement projects that we're doing, that have been very successful this year and have led to better than expected results just on that side so far. I do expect those to continue into next year with some of the work that I've seen.

And then layering on top of that, we have the NGL plants that will of course add the NGL barrels, clean up the CO2 stream and we expect to see some production improvements there. The team have done a great job all around and I expect that as we go through next year, we will continue to see more of these type of conformance and improvement projects that keeps that on an upward trajectory into next year at least.

Okay. That's all that I had.

Thank you.

Hi, good morning.

Good morning.

Good morning.

Just a question on the borrowing base. I see it was reaffirmed, unchanged levels.

Any thoughts at current strip prices, what that could look like in 2017, just given current spending levels? Do you think that's a flat outcome in May as well?

Yeah. This is Mark.

I don't see that changing much. I mean if I guess contrasting to the spring, we saw the near-term pricing come up a little bit as the strip has improved.

However, I'd say the banks are still running below strip prices and then the outer years, some of the banks are capping in the $50, mid 50s, upper 50s and probably 60s, about the highest out about eight to ten years. So, with the strip kind of firming up and just our lower natural decline, we typically don't see a lot of roll off of our PV value, so I don't anticipate much change at this point.

Okay. And then just as a follow-up, you have $385 million of that junior lien basket and like you said, the second liens are trading above par.

Any thoughts on terming out some of that revolver with an add on to the 9% bonds?

We continue to evaluate all our options. I mean obviously one of our core focuses has been to reduce debt as much as possible.

We don't see our bank debt has being a critical item at this point, we're in good shape from coverage and good shape from covenants. So we'll continue to evaluate the best use of that as we go forward.

Okay. Great.

That's all I have. Thank you.

Hey, thank you, Trisha. Before you go, let me cover a few housekeeping items.

On the conference front, Phil Rykhoek will be attending Capital One Securities Energy Conference in New Orleans, the week of December 5. Further details of this conference and the webcast for the related presentations will be accessible through the Investor Relations section of our website at a later date.

Finally, for your calendars, we currently plan to report fourth quarter 2016 results on Wednesday, February 22, and hold our conference call that day at 10:00 a.m. Central.

Thanks again for joining us on today's call. We look forward to keeping you updated on our progress.