Denbury Inc.

Jack T. Collins - Executive Director of Investor Relations Phil Rykhoek - Chief Executive Officer, President and Director Mark C.

Allen - Chief Financial Officer, Senior Vice President, Treasurer and Assistant Secretary K. Craig Mcpherson - Chief Operating Officer and Senior Vice President

Arun Jayaram - Crédit Suisse AG, Research Division Scott Hanold - RBC Capital Markets, LLC, Research Division Timothy Rezvan - Sterne Agee & Leach Inc., Research Division Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division Hsulin Peng - Robert W. Baird & Co.

Incorporated, Research Division Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division Michael S.

Scialla - Stifel, Nicolaus & Co., Inc., Research Division Jason A. Wangler - Wunderlich Securities Inc., Research Division Pearce W.

Hammond - Simmons & Company International, Research Division Andrew Coleman - Raymond James & Associates, Inc., Research Division Robert Bellinski - Morningstar Inc., Research Division Noel A. Parks - Ladenburg Thalmann & Co.

Inc., Research Division

Thank you, Marla, and good morning, everyone, and thank you for joining us on today's call. With me today on the call 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 we begin the call, 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-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. Happy to report that we continued our positive start in 2013 as Q2's production, earnings, cash flow again exceeded consensus estimates, excluding the earnings charge we took for Delhi, and I'll talk a little bit about Delhi here in just a minute.

From a total production standpoint, things are now back to normal after all the M&A activity of last year. This quarter being the first one that included all the assets we acquired in that series of property trades over the last 12 months.

As you can see, we've now more than replaced production related to the Bakken and the other assets we've sold, which, coupled with our higher percentage of oil and attractive oil pricing, resulted in record high quarterly revenues. The exchange of assets that were uses of cash, like the Bakken, for assets that generate free cash flow, like the CCA properties we acquired from ConocoPhillips, enabled us to fully counter our growth CapEx in the first half of 2013 with operating cash flow.

We remain on track to fully fund our 2013 capital budget with cash from operations, and if oil prices remain near the current levels, we should have a little bit of cash left over. In addition to the record revenue and strong cash flow, we have some other positive things to report.

First, Bell Creek. We started Bell Creek Field in Montana [indiscernible] tertiary oil production slightly ahead of schedule.

This is a big milestone for us as it represents our first tertiary oil production in our second core area, the Rocky Mountain region, and if you recall, that's the property we obtained in the 2010 Encore acquisition. Tertiary production from Bell Creek is relatively low today, but it is expected to gradually increase particularly when we complete the full commissioning of its facilities later this quarter.

We also had some positive developments in the Gulf Coast CO2. As you know, we continually work to develop new sources of CO2 in order to perpetuate our growth plan.

We told you last quarter we thought we had drilled a good well at Jackson Dome, our primary CO2 source for the Gulf Coast region. And we're pleased to announce we added 350 billion cubic feet of proved CO2 at Jackson Dome in Q2 for this well.

Also, in the CO2 supply front, during the second quarter, we began receiving CO2 from a second man-made source into our Green Pipeline system. These projects illustrate our unique ability to use and store captured CO2 that might otherwise be released.

With the long and successful history of CO2 enhanced recovery in the U.S., we believe we offer one of the most economic and proven ways to store carbon dioxide underground. We have now injected over 5 trillion cubic feet or nearly 300 million tons of CO2 into our operated fields.

While almost all of that to date come from a natural source at Jackson Dome, today, we're using between 50 million and 70 million cubic feet of man-made or anthropogenic CO2. And we expect this amount to gradually increase over time, making us more and more eco-friendly.

Let me talk a little bit about one other event in the quarter that wasn't quite so positive. Craig will give you a more thorough update on this release -- on the release we experienced at Delhi in June, but I'd like to make just a few comments on it.

Let me start by saying that the safety and welfare of the communities in which we operate, their residents and the environment are Denbury's absolute top priorities. We continue to take the situation very seriously, and our team's response has been swift, focused and comprehensive.

We are fully committed to remediating the situation of allocating considerable resources to the efforts, demonstrated in part by the $70 million charge of remediation expenses we recorded this quarter. One of the actions we've taken at Delhi is to temporarily halt CO2 injections into the impacted area of the field in order to reduce this operating pressure.

As a result of this and other actions taken, Delhi's oil production started to decline in late June and has decreased to a production rate that is currently fluctuating between 4,000 and 4,500 barrels per day. This is down from the second quarter average daily rate of about 5,500 barrels per day.

Based on what we know today, we anticipate we will be in a position to resume CO2 injections into the impacted area in Q4. After which, we expect the field's oil production to gradually rebound.

Given Delhi's lower production and the estimated remediation costs, we estimate the payout at Delhi that was previously anticipated late third quarter will now be pushed into 2014. That means the anticipated drop in our share of Delhi's production will be deferred until 2014, making the net impact of the Delhi incident on our 2013 production relatively insignificant.

As such and with solid performance from our other assets, we still expect our 2013 total and tertiary production to be in the upper half of our previously issued guidance. Further, at today's prices, we anticipate that we can more than fully fund our 2013 capital program with cash flow from operations in spite of the $70 million of costs we expect to incur to remediate Delhi.

So while this event is clearly unacceptable, it is not expected to have a meaningful impact on our 2013 operating results. I'm sure you want to know what steps we're taking so a release like this doesn't happen again, and I can assure you it is a top priority within Denbury.

It's difficult to answer that question precisely today as we are still working to determine the exact origin of the release. But once determined, we will review the situation, see if there's anything we should have done or could have known that might have prevented this, including a review and assessment of our policies and execution thereof.

And we'll take whatever corrective actions are necessary to mitigate this risk going forward. Lastly, on Delhi, although still preliminary and we've not come to agreement with our insurance carriers based on our interpretation of our policies, we currently estimate 1/3 to 2/3 of the remediation charge could be recoverable.

Let me close my prepared remarks by covering a topic that's recently garnered significant interest by investors and one that clearly illustrates the significant financial advantages of our unique and highly profitable strategy. We've said for some time we expect to generate significant and growing levels of free cash flow in 2017 and thereafter, following substantial completion of our CO2 infrastructure.

For the last few months, we've been conducting internal analysis of our options for distributing that free cash flow to shareholders, including consideration of possibly forming an MLP. In addition to review and analysis of the various organizational structures, we've also been evaluating whether we could potentially accelerate the cash distributions.

Both of these are still being analyzed, and I think one of the most significant benefits of these discussions is they highlight our planned transition to an income and growth company made possible by the unique characteristics of our business model and strategy. In our interactions, many of you have expressed your opinions, and these have been and will continue to be helpful for us.

However, there's still an extensive amount of work to be done, and so, we will not be able to provide you with further guidance on this subject on today's call. Instead, we plan to present our conclusions and plan to you at our annual Analyst Meeting on November 11 in Houston, which is also when we plan to provide you our initial estimates for 2014 production, capital expenditures and obviously, many other operational updates.

So with that, let's have Mark and Craig give you more details on the quarter. Mark?

Thanks, Phil. In my comments, I'll provide further analysis of our second quarter results, primarily focusing on the sequential change in results from the first quarter.

I will also provide some forward-looking guidance to help you update your financial models. Our adjusted net income, a non-GAAP measure, for the second quarter was $151 million or $0.41 per diluted share.

GAAP net income for Q2 was $130 million or $0.35 per diluted share, with the primary differences between the two being a $43 million after-tax charge related to the remediation of Delhi Field, offset in part by after-tax income of $28 million related to the change in the fair value of our commodity derivative contracts. Our results improved from adjusted net income of $0.33 per diluted share in Q1 due primarily to the acquisition of Cedar Creek Anticline properties at the end of the first quarter, which you will hear us refer to as CCA.

Our adjusted cash flow from operations, a non-GAAP measure, which excludes working capital changes, was $309 million for Q2 or $0.83 per diluted share, which was little changed from Q1. You should note, however, that this adjusted cash flow number has not been adjusted for the Delhi Field charge or other unusual or nonrecurring charges in the quarter.

So if we exclude the impact of those items on our Q2 adjusted cash flow, it would have been approximately $385 million or approximately $1.04 per diluted share. Total production for the quarter came in at over 74,000 barrels of oil equivalent per day compared to just under 64,000 BOE per day in the first quarter, with most of that increase due to the CCA acquisition.

Craig will provide more details on our Q2 production and our production drivers going forward in his comments. Our average realized oil price, excluding derivative settlements, was almost $99 per barrel for the quarter, which is down from $106 per barrel in the first quarter.

We sold our oil at an average price of roughly $5 per barrel above NYMEX in Q2, which was about half of the $11 per barrel premium we realized in Q1. The average premium to NYMEX for our tertiary production in the second quarter was about $11 per barrel, down from almost $16 per barrel in Q1, as the difference between LLS and NYMEX pricing narrowed during the second quarter.

Based on the continued decline in LLS premium in Q3 and the trend in our Rocky Mountain region differentials, we expect our realized oil price differential to trend lower in Q3 and be roughly flat with NYMEX prices. Moving on to our hedging activity.

We continue to execute our strategy of protecting our oil price downside while retaining upside through costless collars. As we stated on our last quarter earnings call, in addition to the NYMEX contracts we have traditionally used, we have started adding LLS-based collars to our hedging mix in 2015.

Full details of our hedging positions are shown in the updated Investor Presentation that we posted to our website this morning. Moving on to our operating costs.

As mentioned previously, we recorded a pretax charge of $70 million to lease operating expense in Q2 related to the Delhi Field incident. This charge reflects our current minimum estimate of the cost to stop the release, repair wells and remediate the impacted area, and will be adjusted as necessary for changes in our estimate as additional information becomes available.

This charge does not reflect any potential insurance recoveries for these expenses. Under the accounting rules, we will recognize insurance recoveries in our financial statements either during the period received or at the time we determine receipt as virtually certain.

Excluding the Delhi charge, our overall and tertiary lease operating expense came in better than what we expected and improved sequentially on a per BOE basis from Q1. This is due primarily to the lower cost per barrel of our CCA-acquired assets and our -- and lower tertiary op costs.

Going forward, we expect our LOE per BOE to be in the mid-20s per barrel range, excluding any potential additional Delhi-related remediation expenses. This rate for LOE per BOE does not include amounts for taxes other than income, marketing and CO2 operating costs, which you'll need to consider separately for your modeling purposes.

G&A expense was roughly $33 million in Q2, down from $42 million in the first quarter. This decrease was primarily due to lower compensation-related costs, which are generally higher in Q1 due to bonus payouts and divesting of other long-term compensation; an increase in overhead recovery amounts, which are due to an increase in COPAS overhead rates and the CCA acquisition; and the recoupment of approximately $1.9 million in G&A related insurance recoveries.

Of our second quarter G&A expense, about $7 million was stock-based compensation. For the back half of 2013, we expect G&A expense to be between $35 million and $40 million each quarter, with approximately $7 million to $10 million of that in stock-based compensation.

Our overall DD&A per BOE decreased to $18.82 in the second quarter from $19.65 per BOE in the first quarter. This is primarily due to the additional production associated with the CCA acquisition.

Looking forward, we expect our DD&A rate to be in the $19 to low $20 per BOE range for the remainder of 2013, trending up in the second half of the year as we place additional assets into service. Our effective income tax rate for Q2 was approximately 38.5%, in line with our estimated statutory rate.

And we recorded a current tax benefit in Q2 as our estimate of deductible capital cost in 2013 increased this quarter, and that reduced our estimate for our cash taxes in 2013. For the remainder of 2013, we anticipate our effective tax rate will be between 38.5% and 39%, with current taxes representing roughly 5% to 10% of total taxes.

Moving to our capital structure, total debt at June 30 was approximately $3.2 billion, down from approximately $3.3 billion on March 31 due to the final redemption of our subordinated notes refinanced earlier this year. And we had $260 million drawn on our bank line at June 30, which is down slightly from $275 million at the end of last quarter, while our cash balance was up about $15 million from the last quarter.

Based on our current assumptions for cash flows and capital expenditures for the remainder of 2013, we anticipate ending the year with bank debt of between $100 million and $200 million, excluding the impact of any incremental share repurchases in 2013. Interest expense net of capitalized interest was $31 million, an improvement from $36 million in the first quarter, mostly due to a decrease in our average interest rate following the refinancing of our highest rate sub-debt earlier this year and a minor increase in capitalized interest from $22 million in Q1 to $23 million in Q2.

We anticipate capitalized interest to decline in the second half of 2013 as we place new assets into service. We currently estimate capitalized interest at approximately $15 million to $20 million in Q3 and below $10 million in Q4.

Our capitalization metrics remained solid with our debt-to-capital ratio at approximately 38% and our debt to Q2 annualized adjusted cash flow and EBITDA, excluding the Delhi charge, at about 2.1x and 2x, respectively. We are maintaining our 2013 capital budget of $1.06 billion plus an estimated $160 million for various items, including capitalized interest, G&G exploration and development costs and pre-production EOR start-up costs.

We have spent slightly under half of our full year capital budget to the first half of 2013. And with regard to our share repurchase program, since the beginning of 2013, we have repurchased roughly 5 million shares of our common stock for $85 million or about $17 per share.

With these purchases, we have repurchased about 9% of our total shares outstanding since October 2011 at an average price of $15.15 per share. We intend to remain opportunistic with our share repurchase program, and we have approximately $224 million still authorized to spend under this program.

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

Okay, thank you, Mark. I'll start with a review of production in the second quarter.

Our tertiary operations performed in line with our estimates in the second quarter, oil production averaging just below 39,000 barrels per day. Our tertiary oil production growth did moderate as expected in the second quarter, but it was further impacted by declines late in the quarter at Delhi.

I'll discuss several key fields that had material impacts to our tertiary production in the second quarter and that are likely to have the most significant impact over the remainder of the year. So let's start with Delhi.

In mid-June, we observed and reported a release of well fluids, which included carbon dioxide, saltwater, natural gas and some oil. While this is a rare occurrence within our asset portfolio, and that's a portfolio that includes 18 active CO2 floods, nearly 6,000 wellbores, of which nearly half are currently plugged and abandoned, I'm going to echo Phil's comment that any release is unacceptable to us.

This release at Delhi occurred in the southwesternmost portion of the field. That's an area that can generally be described as remote, heavily forested, with some swamp, which makes access to part of that area difficult.

We are still actively working to permanently remediate this issue. And it's premature to definitively say what caused the release of well fluids to the surface.

However, our suspicion is that CO2 entered a previously plugged and abandoned well with an inadequate cement plug. The impacted part of the field was just starting to respond to CO2 injection.

If the plug in the abandoned well was inadequate or not in place, it could allow CO2 and other well fluids to use the well as a conduit to the surface. We take the situation at Delhi seriously, and we are aggressively pursuing its resolution.

Our actions to date include building containment structures to ensure the produced fluids, which were primarily saltwater, did not get into navigable waterways. Given the heavily forested, swampy area, this has been a large task, and the vast majority of this work has been completed.

We're also recovering the release fluids, and we're remediating the area. We're pumping large volumes of sodium chloride brine into several wells into the affected area, and this displaces the underground CO2 and oil away from the potential leak sources.

We've stopped injection of CO2 into the impacted area. Note that we are still injecting CO2 into the non-impacted parts of the field.

We're reentering the old P&A wells to ensure they're properly plugged. We're also drilling 2 wells to intercept 2 old P&A wells that are suspect.

We may decide to drill more of those after the first 2 are finished. We're also looking for a potential ghost well that may have been drilled and abandoned but never reported early in the life of Delhi, which was discovered in the 1940s.

Local and state authorities have been and continue to be on site, and we're working very closely with them every day to coordinate that response. Our remediation work that is currently underway should shed additional light on the root cause.

Also, we're conducting an internal review of our processes for assessment of P&A wells, both at Delhi and all our EOR fields, to help ensure the processes are appropriate and solid, and we use what we learn from this event to improve. As Phil mentioned, production at Delhi started to decline late in the second quarter as we undertook steps to remediate the situation.

We expect production from this area of the field to continue to slowly decline until CO2 injections return to their prior rates, and we anticipate that to occur in the fourth quarter. Once injections are fully resumed, we expect the field's production to gradually rebound.

With that, we'll move to Oyster Bayou. Oyster bayou continues to show a strong response and steady growth, increasing 12% from prior levels -- prior-quarter levels.

We anticipate continued growth at Oyster Bayou in 2013, as the field dewaters and more wells respond to CO2 injection. At Heidelberg, our CO2 flood is another bright spot for the quarter, with the field's tertiary production increasing 5% from prior quarter levels to 4,149 barrels of oil equivalent per day.

We saw continued response from the new zones we're flooding in the western part of Heidelberg. And also, our new development in East Heidelberg remains on track.

And we forecast CO2 response from these new areas to be a key driver of our expected tertiary growth in the fourth quarter. Moving on to Hastings.

Hastings tertiary production increased slightly on a sequential basis and is expected to remain relatively flat in the third quarter before the expected contribution from our expansion of the flood drives meaningful growth in the fourth quarter. As we noted on last quarter's call, one area of increased operational focus has been managing and optimizing our more mature EOR floods.

These optimizations efforts continue to bear fruit, as evidenced by the fact that the mature areas' first half 2013 tertiary production is only about 2.5% lower than the areas' fourth quarter 2012 production level. This decline has [indiscernible] forecasted.

With the recent startup of our tertiary oil production at Bell Creek Field in Montana, we look forward to reporting our first Rockies tertiary production in the third quarter. Bell Creek tertiary production flipped a few weeks ago and is currently averaging less than 100 barrels per day.

We expect to have our production facilities at Bell Creek fully commissioned later this quarter, at which time, the field's tertiary production should begin to gradually increase. To give you an idea of our expectation for Bell Creek's production profile, we believe the field's reservoir characteristics are similar to our Tinsley Field in that the field's CO2 flood should respond in a somewhat similar manner.

As a reminder, we've also started CO2 injections in the Grieve field in Wyoming. We anticipate first oil production in 2015 when that field reaches the appropriate operating pressure.

Production from our non-tertiary assets increased to 35,300 barrels of oil equivalent per day from the 24,766 barrels of oil per day the prior quarter, primarily due to the production contributions from the CCA assets we acquired near the end of the first quarter. The recently acquired properties from ConocoPhillips are performing quite well.

Our Cedar Creek Anticline production, including both legacy and newly acquired fields, was 19,935 barrels of oil equivalent per day in the second quarter. We continue to look for opportunities to increase production by optimizing our waterfloods at CCA, and this is in advance of our planned CO2 flood of that field later this decade.

Looking at production on a total company basis, with the strong first half and despite the expected reduction of Delhi, we continue to look for both tertiary and total company production to be in the upper half of our originally estimated ranges for 2013. We do anticipate modest sequential declines of both our EOR and total production in the third quarter, as we expect the modest production contributions from Bell Creek to be more than offset by the temporary decline at Delhi.

With the expected growth from Bell Creek and several Gulf Coast fields in the fourth quarter, we expect total and tertiary production to resume their sequential quarter growth in the fourth quarter. So with that, let's move to lease operating expenses.

Our lease operating expense per barrel of equivalent production, excluding the Delhi Field charge, declined by 9% from the first quarter to $22.34 per BOE in the second quarter. This over $2 per BOE reduction was primarily due to lower unit operating cost for the recently acquired Cedar Creek Anticline properties and a reduction in tertiary operating costs.

Operating costs for our tertiary property, excluding the Delhi charge, averaged $23.52 per barrel during the second quarter, down over $1 per barrel from the prior quarter. We will continue to look for ways to improve the efficiency of our operations.

Let me now give you a brief recap of our CO2 supply and transportation operations. At a high-level, our CO2 supply and transportation operations are performing well and are on track to fulfill the growing demand for tertiary oil production operations.

In the Gulf Coast region, we produced about 1 billion cubic feet per day of CO2 from Jackson Dome during the quarter. Additionally, we booked 350 billion cubic feet of proved CO2 reserves at Jackson Dome during the quarter related to the first well we drilled in the area this year.

There is some potential that this proved reserve number could increase once we have more production history from the well. Given the success of this well, we now plan to drill only a total of 3 CO2 wells at Jackson Dome this year to meet our supply requirement, down from our originally budgeted 5.

The other 2 wells planned for this year will be delayed to future periods. Moving to anthropogenic or man-made CO2 sources, we continue to make progress in increasing our supply.

Today, we're currently injecting the CO2 being captured from both Air Products and Potash Corp. into our Gulf Coast fields.

Additionally, Mississippi Power's power plant currently under construction should be completed in 2014 and could provide more than 115 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 later this year.

In the Rocky Mountain region, we now expect natural gas and helium production from Riley Ridge to commence on the fourth quarter of this year, a few months later than our previous estimate. We are focused on ensuring a successful start of this gas processing plant, which represents the first step in making Riley Ridge an anchor source of our Rocky Mountain region CO2 supply later this decade.

We continue to expect to receive additional CO2 deliveries from ExxonMobil's Shute Creek facility in the future, and we're very close to finalizing an agreement that would connect our Rocky Mountain CO2 pipeline to the third-party pipeline to transport CO2 from Shute Creek. This interconnect would significantly reduce the cost and time to deliver CO2 from Shute Creek to our operated Bell Creek and Hartzog Draw Fields.

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

Okay, thanks, Craig. Marla, that concludes management's prepared remarks.

Could you please open the call up for questions.

I do want to follow up a little bit on Delhi. It doesn't sound like you've yet quite identified the root cause, as you mentioned.

However, it seems like you're still pretty confident that you could restore or begin reinjecting CO2 in Q4. So I was just wondering if you could maybe comment on the certainties or uncertainties around the remediation actions because I didn't get a sense of how comfortable you are that you've identified the action plan going forward.

This is Craig. We have a high degree of confidence that we're targeting the right areas.

We believe there's primarily 2 old P&A wells that we believe are -- one of the two of them is the likely source, and we're intervening on those wells. There is, I guess, a low probability that they are not the source, and if so, it's another well.

And so we are also targeting several other wells to intervene on those and have well intervention plans for those. So we have a high degree of confidence that it's one of the wells we're targeting.

We can't say with 100% certainty which well it is until we get on it and finalize that work. But our -- we've got a comprehensive approach to address all of the potential sources.

Okay. And then, you do have a rig on location drilling to re-cement those wells, is that correct, on both of those locations?

Yes, we have a rig that's drilling an intervention well now, and we're in the process of rigging up another well -- another rig to intercept the second target well.

Okay, okay. Phil, you talked about planning to talk more about the dividend strategy going forward in November, but I did just want to talk to you a little bit about the MLP market regarding some of the upstream companies.

We've seen one notable company have some issues regarding that. And does that perhaps change your thought process or the board's thought process in terms of employing an MLP as part of a potential income strategy going forward?

Well, I think we're -- I mean, we're taking that into consideration. One thing we've kind of said that we would plan to perhaps run the business a bit different than some of the MLPs in the sense that we would stay within cash flow for CapEx and distributions.

And so we think that would make it a very attractive entity, whether it's an MLP or a C corp or what that looks like. So we won't -- we'll probably try to avoid going down some of the path that maybe some of the MLPs have done where they spend more than they make.

That's helpful. And last question, just can you give as a sense of what the updated timing would be for Riley Ridge to get -- to begin production there?

Yes, mid to late October.

Just one more thing on Delhi, you spent $70 million from remediation in the second quarter. How much more do you think that's going to be as we go into the third quarter?

Is there a significant amount of money that needs to be spent there, or is it pretty much wrapping up?

Well that $70 million is actually our estimated -- no, it's the -- in fairness, as the accounting rules provide, it's the low end of the estimated total cost. We have actually not spent $70 million to date.

I believe the number to date is about $45 million. And most of that would have been in the third quarter.

But under -- and Mark could probably get into it more, if you want to, but under the accounting rules, we need to accrue the estimated total cost to remediate the situation.

Okay, I understand it. That kind of got me to the cash flow numbers you guys spoke to as well.

All right. And then the other thing, just a question on the CO2 well that you drilled, so it sounds like the plan of drilling your 5 wells is not needed at this point.

So how much CapEx was allocated to that program compared to what you're going to do now? And then, where does that difference gets spent?

Those wells are in rough numbers, about $15 million a well. And so I don't know that the $30 million went to any one specific spot, but it's just kind of being reallocated among other areas.

We expect our CapEx to still be kind of the same as what we had last quarter, just over $1.60 billion. And so, that hasn't changed.

But we'll take that money and just use it in various places.

Great. Fair enough.

And then -- and one last thing just on some of the conventional stuff, it looks like Mississippi production dropped, if I'm looking at that right, sequentially by roughly 1,000 barrels per day. What was that the result of?

And is that going to kind of recover again in the third quarter?

Are you talking about that in the mature areas?

No, no actually -- yes, the non-tertiary stuff, the conventional stuff, conventional Mississippi.

Yes, I show it going down about 700 rather than 1,000 -- or about 650, actually. But just one second, we'll give you an answer on that.

You have that handy, Mark?

Yes. We did -- it's kind of normal declines there.

We did -- we do have some fluctuations in our inventory numbers there. But I don't know if it's anything too terribly unusual.

Quickly on the performance of the mature assets. I think Craig had mentioned a shallower decline than expected.

Can you give some granularity on what you're doing there? And is that a trend you think can persist into 2014?

There's no syllable that's actually there. It's a focus of our operations primarily on uptime, so it's optimization of wells, optimization of compression equipment and frankly, just less down -- just the focus on less downtime.

So that's a significant part of it. It'll be a bit lumpy as we see opportunities and pursue them.

So I don't think we're ready to declare a permanent change in our production decline, but it should enhance that performance. It's just operations excellence.

I mean, it's just an overall pursuit we've got throughout the company around being more efficient with every piece of our assets and processes.

Just to follow up, when we give guidance, we usually assume that it kind of goes back to projected declines, which, in rough numbers, is probably anticipated to be about 10% per year as a group. So in our guidance, we've kind of assumed that it continues to slip a little bit.

Okay. And then on Bell Creek, obviously de minimis production now, less than 100 barrels a day.

When you talk about the tertiary production increasing after commissioning, what kind of ramp do you envision? And then, do you have a target 2013 exit rate you think this could be at?

Well, I think Craig mentioned that we expect the field to look somewhat like a Tinsley. So it should grow.

The only difference, we're not injecting quite as much into Bell Creek as we normally did at Tinsley because we just have the one supply today, which comes from ConocoPhillips plant. Probably hasn't given exit rate yet.

It's still pretty early. But it should grow pretty steadily actually for the next several years.

Most of mine have been answered, but wanted to go back to Delhi just real quick here. Can you talk about how you'll make the decision whether or not to resume CO2 injection there?

And just help us understand the potential variables that you need to see before moving forward and then reinjecting CO2 in that specific area?

Yes. So the fundamentals, we've got to be confident that we've isolated and sealed off this underground leak source.

And so, that will be determined as we do these intervention wells, and basically, it's drilling a well that's twin this old well and intercepting at the bottom and squeezing cement into the bottom. And so we'll get a response when we do that.

And assuming that it's an effective squeeze and we're confident that it's sealed off, that will give us confidence that we've isolated the leak and we'll be ready to resume.

Okay, very good. And then shifting a little bit to corporate strategy, it does look like the share repurchases have slowed significantly from the first quarter level.

Should we anticipate minimal repurchases in some of the company updates that's corporate strategy in November?

Well, I don't know that it is necessarily related to the corporate strategy. I think it's just the stock price has been a little bit better recently, and we're used to this kind of a subjective repurchase program depending where the stock price is and where the oil price is.

So we have slowed down a bit, but I think that's largely just where the stock price is. So we'll tend to still kind of be a little bit opportunistic, I guess, in that matter.

We have a little over 200 left on the authorized program. And perhaps one positive is that oil prices are staying strong, so our cash flow is pretty strong, which helps.

But we just tend to look at it still day by day, I guess.

Got you. And then one final one for me, oil futures, looks like they're in pretty steep backwardation.

2015 WTI, I was just checking, was at $90 this morning; 2015 Brent, $97. How does that impact your hedging strategy, if at all?

I mean, do you go more towards Brent than WTI? Is it too backward dated to really layer on hedges?

Just curious your thoughts on longer-dated hedging.

We'd appreciate if you fix that backwardation for us. We have been kind of still keeping about 2 years hedged in front of us.

We try to be opportunistic. It is a little tougher with backwardation.

I think we're hedging now in the third quarter of '15, and it's probably about $80 floor and, what, $95 ceiling roughly, Mark? So we're kind of trying to keep 2 years, but we tend to be opportunistic.

We really haven't changed our approach. We have hedged a little bit of LLS instead of WTI, and if you do that, you're generally about $5 higher.

So we just tend to still watch it and my guess we'd kind of hope that the backwardation kind of goes away a little bit.

So I have a quick follow-up to Delhi. I know you mentioned the CO2 injection expected to resume in fourth quarter.

Can you talk about in terms of response time, like [indiscernible] you can, you will need to get production back up to the 5,000 level? And maybe -- or if you can comment on the impact in 2014, please.

I don't know if we have a good number for '14 yet. I don't think -- we wouldn't expect to be back to the 5,000 until '14.

It won't happen in the fourth quarter. It's not going to respond that quickly.

And then the other thing that will come into play in '14, which is where we're kind of hedging our bets, the payout that's been deferred will likely happen sometime in '14. And that one's a little tough to nail down today because, one, we're not sure exactly what we spend; two, we're not sure what we're going to recover from insurance; and third, we're not sure of the timing of those insurance recoveries.

So we know it's out there sometime in the future, but we'd prefer to kind of wait maybe until the Analyst Meeting we should have better numbers and we can give you maybe a better feel for 2014 Delhi.

Okay, okay. And then second question is just on Bell Creek.

Given that you have seen a very -- I mean, fairly small spill production rate. But in terms of the performance compared to your expectations, is it still -- is the peak year still 2019 or thereabout and also the peak production's still 5,000 to 10,000 BOE per day sort of range?

Yes, it's really quite early to speculate 2019 production, I guess. But we would still anticipate it to be as previously disclosed.

Okay, and then last question. I know we'll get more information on the Analyst Day regarding your analysis of your -- of the various options for contribution -- I mean, for the free cash flow.

But I was just wondering if you can comment on what are your key position criteria? And -- I mean, I would assume production growth is [indiscernible] not the highest one on there.

But I just wanted to kind of understand how you -- what your key criteria are for that decision-making process?

Well, yes, we're just looking at what's the most advantageous for the Denbury shareholders, and that's a little bit of a tough question to answer because we've got to take into account potential tax impact and so forth. So we're just trying to evaluate that, and I think it's just difficult to give much color on this call.

Just a quick question on Bell Creek. With the earlier start up of EOR production, does that make it more likely to be able to book proved reserves out there this year -- proved tertiary reserves?

It helps. I mean, we still do need a fairly strong production response probably late third or fourth quarter really in order to be able to book it.

But obviously, the sooner the better so that maybe increases the probability. I don't think it's a slamdunk, yet.

Okay, and then shifting to Jackson Dome, the 3 other wells you have planned for this year, are any of those targeting reserve add as well, are those all rigged wells?

All 3 wells. Well, one, we've already given you a number, but the other 2 also we're targeting reserve adds.

Heidelberg seems to be growing pretty nicely. Can you talk about how you're looking at that now and what you're doing both the east and west side of the field?

I know you have projected the peak in 2018 to 2020, does that still look like an accurate forecast? And wondering how much CapEx you need to spend over that time frame to get there.

Heidelberg is doing really well. [indiscernible] there would be -- it's tracking beautifully with what we forecast, and so we're very pleased with the performance of it.

It's primarily the result of the Christmas zone. And so we like what we see there, and we're encouraged that our out-year plans are appropriate and actually quite profitable.

With respect to the out-years' spending, I actually don't have that number in my head. I don't know, Phil, if you've got it or, Mark, more specifically?

If there's a lot of optionality, I guess, what I'd tell you is we don't have to spend -- we have a lot of flexibility in what we choose to spend at Heidelberg, I would say the 2013 results are encouraging, as that is a very strong investment down the road that we can scale as we choose to.

Are there still, I guess, a lots of wells to be drilled there as you develop that Christmas zone, or is this...

There's multiple patterns yet to be -- that can still be pursued. Yes.

The Christmas is just getting started, so the production you've seen today is, for the most part, from the Utah, and that's a bit older flood, if you will. Although it's actually growing very modestly, or kind of holding its own.

But the expected growth is Christmas -- so it's almost conceptually, if you just think of it as a second flood at Heidelberg or an additional flood, it might be one way to look at it, it's almost like starting a new flood.

Would looking at historical expenditures for the Utah be -- get you in the ballpark for what you need to spend to develop the Christmas, is that one way of thinking about it?

Yes, that's -- maybe not quite as big because you can share some facility costs. But we spent a lot there this year.

I think it's over $150 million.

$100 million between the two.

But probably, I don't think it will continue at that pace going forward.

Okay. At Hastings, I know you haven't -- it's taken a little bit of a pause there.

Is there any sign of any downdip response in those downdip patterns yet?

Some. And this past week, we put a compressor online, and so I would say it's on track relative to expectations.

So we're encouraged with what we see at Hastings. But yes, we'll start to see increased response in the downdip patterns into the latter part of this quarter and most certainly into the fourth quarter.

Yes, and one of the -- actually, one, I guess, kind of minor, but it's a few days of production as we had to turn around at the facility to install additional compression, so that, obviously, has a little bit of a minor impact on third quarter production, which is why we said we expect it to be kind of flattish with the second but then a little bit of increase from the fourth. That is it.

Okay. And then last one for me, any update on the permitting and right-of-way process for Hartzog Draw?

I don't think I have that on top of my head.

On track.

I think in my understanding, I think we're -- it's basically rate, waiting, everything, the process of regulatory approval, environmental assessments and so forth, and that's the long lead time there.

Just had 1. Most have been answered.

As you've obviously been moving more to the Rockies and a lot more of your oil production's coming from up there, what are you seeing as far as pricing? And then, where are your price points for that oil?

Well, as you know, most of the -- I mean, conceptually, the Gulf Coast is priced off -- a lot of it is priced off LLS, the Rocky is priced off WTI. Of course, those 2 have converged quite a bit recently, but -- so as an example, the Cedar Creek Anticline, our single biggest deal in the Rockies, this quarter was just over $6 below NYMEX.

So it tends to get a little bit of a transportation [indiscernible], but that's kind of the main delta between the 2 areas. One's kind of WTI-based, one's LLS.

Just one for me. If you can provide an update on that plant pipeline interconnect between the Greencore Pipeline and, I guess, just the Shute Creek pipeline.

We expect the agreement to be signed any day, so we should have it in place. We plan to start -- put -- doing the operations in the next 30 days.

And it should be in place mid-fourth quarter.

First one I have was just on Grieve. I know you all had said previously, it was about a year to inject in that field to get it started up.

So has there been any change to those expectations, or any progress report?

No change to our expectations. We were injecting CO2 into the Grieve.

It's starting to pressure up. Yes, we're on track.

Okay. Great.

And then kind of looking at your forecast there for all your major fields, you have Delhi in the 5 to 10 Mbd kind of bucket, with the field kind of producing close to 6 there in, I guess, prior-quarter. I guess, where do you think that might top out once everything gets back to normal?

Well, net -- we're going to lose our reversionary interest again, just to reiterate that, at some point in '14, so we've got to overcome that. So we might get a -- ultimately get a little bit above where we were, but we've got to overcome the backend.

Okay. And then just how long a plateau should we think that field would then have?

It has a few years of growth.

2 years, yes.

2, 3 years left probably.

Okay. And then last question, I know there's been an uptick in capitalized interest the last few quarters, I guess, while total industry expense on a cash basis looks like it's declining sequentially, I guess.

When should we look at capitalized numbers to taper off to follow suit?

Capitalized interest will taper off here as we go throughout the year. I think we said between $15 million to $20 million in Q3 and less than $10 million in Q4 once Riley Ridge comes online.

Two things. First, how long do you expect production at Cedar Creek to stay at its current level, and how should we think about capital spend and production declines over time?

And then second, given that you're starting to hedge LLS, I was just wondering is there a catalyst that prompted you to add those hedges? And what are your general thoughts on how the LLS differential might change going forward?

Well, Cedar Creek Anticline, we expect quite modest decline. It's not keeping it relatively flat for the next couple of years.

That's the function of our waterflood work and optimization work that we think is pretty robust. So we're refining those plans, and we'll talk more detail in November about that.

But it's proven out a bit. And particularly the assets we've got from ConocoPhillips, we see some opportunities to enhance that to really keep the production relatively constant.

We had a pretty strong quarter in Q2. CCA may not be quite that strong, but we would think it would probably run between 19,000 and 20,000 barrels a day at least in the near-term.

And we think we can hold it there with a little bit of work. You want to talk about LLS?

Yes, on the hedging front, we really started looking -- we think hedging some on LLS is reasonable because it is what we sell the crude in, and so it does give us some protection there from the differentials whichever way they may go. Longer-term, we've seen a pull in here as transportation has continued to come into the area, and I think if the futures are reasonably close, that will likely continue to contract some and really just represent kind of a transportation differential in terms of moving barrels around.

So we're not exactly sure where it goes. But we felt that it was reasonable to begin to hedge some in LLS, potentially that's what we sell it in.

A general question. I was thinking about the staggering of the different CO2 flood going forward and a bit of discussion is already happening today about the Rockies versus the Gulf and resources.

And when you look at possible options for cash flow [indiscernible], I'm thinking about some of the recent shuffling, for example, last year, I think it was Conroe that got pushed out from 2015 to 2017. And if you did monetize or [indiscernible] in another part of the company, do you think you have the room to sort of move projects maybe back up a little bit sooner, or do you think of the schedule as being pretty much that given the bandwidth that you have?

Well, no. I think we've kind of stated this, it's difficult for us to really accelerate things significantly.

We -- and so that's one of the reasons also I think we turned into a real cash flow generating entity because we really can't throw more money at it and grow at twice the rate or whatever. It's just that doesn't fit our profile and it would be hurting our rates of return.

However, we do have a lot of flexibility in rearranging things. And so we look at that, we continue to look at it and see what the best return is.

And as you appropriately said, we swapped. When we purchased Webster, we swapped it around with Conroe, and that was just because Webster was closer and, to be honest, it was a little better rate of return because you don't have to build as long of a pipeline to get to Webster as you do Conroe.

So we have a lot of capability to shuffle things. We don't have a lot of capacity to accelerate things, at least not in the aggregate.

I mean, you can accelerate one, but then you're trading -- usually trading that off against slowing down some other field.

Right. And this has been touched on already, but I think what comes to mind when I hear you talk about the evaluation process you're going through is I think of the maps we've seen over the years and sort of the vast number of smaller fields along the pipeline routes on the Gulf Coast.

And I just get curious, thinking about what -- is there a way to get at those maybe simultaneously or a little bit faster? I don't know if that's a goal of what you'd be thinking of -- when I say faster, I mean, things that you might not be able to get to the first, say, 10 years coming closer into 5 years, if they were available.

Well again, I think you'd be reshuffling. I mean, today, we've kind of given you the plan and the schedule for everything we own in the Gulf Coast, at least everything that's material.

If we were to pick up some other fields, and we'd just have to consider if we want to shuffle that around. But I think there would still be somewhat of a trade off.

In other words, if you take CO2 away from Conroe, as an example, to flood some small field, there's going to be some trade-offs there.

Okay. Thank you again, everyone, for participating in today's call.

Before you go, let me cover a few housekeeping items with you on the conference front, Phil will be giving presentations at the EnerCom Conference in Denver next Tuesday and at the Barclays Conference in New York on Thursday, September 12. The webcast and slides of these presentations will be accessible through the Investor Relations section of our website.

And if you are attending either of these conferences, we hope to see you there. Also, we recently launched our redesigned corporate website at denbury.com.

Hope you'll find the new website design more informative and user friendly. And if you have any questions or feedback, don't hesitate to contact us.

And lastly, just for your calendars, we plan to report our third quarter 2013 results on Tuesday, November 5. And we'll hold our conference call that day at our usual time of 10 a.m.

Central. Thanks again for joining us, and we look forward to keeping you updated on our progress.