Denbury Inc.

Thank you, Christina, and good morning, everyone and thank you for joining us today. With me on the call from Denbury today are Phil Rykhoek, our President and Chief Executive Officer; Mark Allen, our Senior Vice President and Chief Financial Officer; and Brad Kerr, our Senior Vice President, Development, Technical and Innovation.

Before we begin, let me remind you that today's call will include forward-looking statements that are based on our 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 are posted on the 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.

Thank you, Ross. Welcome, everybody, to our second quarter call.

These are obviously interesting times with the recent pullback in oil prices. But in spite of this drop, Denbury is actually doing quite well.

We're improving operationally everyday and contrary to the opinions of some pundits, we're actually in solid financial condition. Our production generally remains on track to produce near the midpoint of our range for 2015, if you exclude the shortfall this quarter and next quarter related to the flooding at Thompson Field.

Our operating costs per barrel, excluding nonrecurring items, have dropped for the sixth consecutive quarter and are down approximately 25% from levels in late 2015. Due to a recently completed workforce reduction, we expect to see lower admin costs in the second half of the year as that reduction takes effect.

We expect to generate over $100 million of free cash flow at current prices this year. That means that we're bringing in more cash from operations than we are spending in capital expenditures and dividends.

Our bank debt was reduced by $115 million between Q1 and Q2, largely as a result of free cash flow generated by our cost-saving initiatives. And with the financial covenant relief we put in place last quarter, we don't anticipate any issues with our bank debt in the foreseeable future.

As a matter of note, our next scheduled borrowing base redetermination is not until May of 2016. Further, we have significant liquidity on our bank line, which Mark will cover in more detail later.

So while it is a tough macro environment, we are doing quite well and becoming a stronger company each day as a result of our ongoing initiatives. As you know, we've been particularly focused on reducing our costs and improving operational efficiency the last couple of quarters.

Much of this was conducted with the help of innovation and improvement teams or IITs. These are teams that report to senior management and were established to review internal processes, reservoir surveillance, flood design, operational software and many other aspects of our operations.

Many of the ideas generated from these IITs have already borne fruit such as the continued reduction in the use of CO2, which is down 25% from the beginning of the year in the Gulf Coast. Many other ideas will create value over the next couple of years as we diligently continue our pursuit of reducing costs and improving operational efficiencies and we move from an idea generation phase to an idea implementation phase.

We are taking these ideas, evaluating them, and preparing new field development plans for each of our primary fields. These plans are scheduled to be completed over the next year and once completed will be incorporated into our long range plans.

While almost oilfield plans are still preliminary, we're seeing positive results as we're finding ways to convert plans for future floods that were not economic in this price environment to ones with reasonable rates of return in spite of low oil prices. These improved flood economics are primarily related to a few different things which Brad will cover in his discussion.

The long term implications and results of this ongoing process should have a very significant and positive impact on the company. So with that introduction, let's talk a little bit more about the quarter.

Total company production was in line with expectations and we reaffirmed our guidance of 72,500 BOE to 75,500 BOE for the year. Tertiary production averaged just over 42,500 barrels a day, an increase of 2% sequentially and up 4% year-over-year.

The strongest growth area on a sequential basis was at Hastings with many fields relatively flat during the quarter including production from our mature fields. Overall production was down 640 barrels a day, primarily due to the downtime at Thompson as a result of extensive flooding in that area.

At Hastings, sequential production increased over 650 barrels a day to 5,350 with positive response from our series of floods that we've talked about before. At Oyster Bayou production was over 5,900 barrels day, up slightly from the Q1 rate.

The A-2 sand continue to respond favorably although we do believe that Oyster Bayou may have plateaued and will likely remain relatively flat or slightly decrease during the remainder of the year. Heidelberg was just under 5,900 barrels a day, down slightly as most expansion work was curtailed at this field pending a more detailed review of our development plan to ensure that our capital dollars are spent appropriately and effectively.

Tinsley production was 8,740 barrels a day, around 200 barrels a day below Q1. As we have guided on prior calls, Tinsley may have peaked although a portion of the decrease is also due to the summer heat, which lowers CO2 efficiency and highlights facility capacity limitations.

For our mature area tertiary properties, production increased over 3% sequentially to 11,170 barrels a day, reversing a prior 10% to 15% per annum decline. The main contributor was favorable variant – to the favorable variance was Eucutta, which had response from increased injections and Lockhart which had increased response from a new pattern.

Production at Thompson Field was down over 500 barrels a day from Q1 due to the previously mentioned flooding in the Houston area. The field had to be shut in for all of June and is only recently back to its normal production levels.

This flooding will cause Q3 production to be about 200 barrels a day below forecast. And we will also have some incremental LOE at this field to repair roads and equipment damaged by the flooding and this could potentially be a few million dollars.

Moving to the Rockies, at CCA, we recently completed our first multi-lateral well in Q2 at a 30% lower cost than drilling two lateral wells, and this well tested at 560 barrels a day. We're currently completing our second one, drilling a third, and have plans to drill and complete a total of five by year end.

These wells could be sufficient to offset most, if not all of the declines of CCA. Efforts to reduce failure rates have continued.

We're seeing the results of lower workover cost of CCA. There have also been new initiatives implemented to optimize chemical usage and lower cost, all of which are significant, as this field is our single largest producer.

Bell Creek production was down slightly Q1 to Q2 as we initiated a way to optimize the oldest part of the flood in terms of 1 and 2. We're also balancing the patterns in order to improve performance and expect a gradual production increase for the remainder of the year.

The horizontal wells we drilled last year performed well, although production is currently on a gradual decline as evidenced by the slight decline this quarter in our other Rockies non-tertiary properties. Looking at expenses, our lease operating expenses excluding non-recurring items have decreased for the sixth consecutive quarter.

This quarter, our LOE averaged 19.70 per BOE, nearly 25% lower than the rate in late 2013. These decreases are related to a decrease in workover cost, lower CO2 expense resulting from a decrease in volumes and lower cost per Mcf and lower third-party contractor and vendor expenses.

Each dollar we save per BOE and LOE results in $27 million of additional cash flow which means that most if not all of our free cash flow this year has come from reduced operating cost. While we would like to reduce these costs even further in the future, it is becoming increasingly difficult to do so and we have increased our workover activity level at many of our fields which will further – make further decreases difficult.

As noted, a significant portion of our reduced LOE cost is due to lower usage of CO2. In the Gulf Coast region, we produced about 680 million cubic feet a day from Jacksonville in this quarter, a sequential quarterly reduction of 23%.

This reduction in Jacksonville in CO2 volumes is not only significant to current quarter operating costs, but also has significant implications for our long-term future. We believe that most of this reduction is sustainable, and longer term, we may use even less CO2 as we anticipate that we will start the WAG process, which is water-alternating gas, sooner in the life cycle of our flows than we have historically.

And that process also further reduces the use of CO2. The reduced CO2 requirements also reduce the number of wells that would be required to drill out Jackson Dome and also reduce previously estimated future capital cost to expand CO2 pipeline capacity.

This has a significant implication for our future. Our anthropogenic sources in the Gulf Coast remained relatively constant.

They produced at approximately 70 million cubic feet a day, and our Rocky Mountain supplies were also relatively constant at just over 100 million cubic feet a day. Bottom line, we're encouraged by the results today, but we are not done yet.

With our continued focus on operational efficiency, we should continue to improve our business every day. And with that, I'll turn it over to Mark to give you financial details.

Thanks, Phil. My comments today will summarize some of the notable financial items in our news release, primarily focusing on sequential changes from the first quarter.

I'll also provide some forward-looking guidance to help you in updating your financial models to reflect our current outlook. We are pleased with our financial results for the quarter and particularly our cost reduction efforts in lease operating expenses and G&A.

Our adjusted net income for the second quarter was $47 million or $0.13 per diluted share. This was ahead of analysts' estimates and more than double our adjusted net income in the first quarter.

On a GAAP basis, we had a net loss of $1.1 billion, which reflects the full cost ceiling pool test write-down of $1.1 billion net of tax, a fair value loss on our commodity derivatives and a tax valuation allowance for our financial deferred tax assets related to Louisiana net operating loss carryforwards. Our adjusted cash flow from operations, which excludes working capital changes, was $252 million up from $195 million in Q1 on higher prices and lower costs.

For the first six months of 2015, our adjusted cash flow has exceeded our incurred 2015 capital expenditures by $230 million, positioning us well to generate significant free cash flow after capital expenditures and dividends in 2015. Our Q2 realized oil price excluding hedges came in at just under $57 per barrel, up 24% from Q1.

Including the $124 million of cash received on settlements from our hedges this quarter, our per barrel realized price was a little over $76 compared to $69 in Q1. Our realized oil price averaged $0.89 below NYMEX this quarter which was almost $2 better than our NYMEX differential in Q1.

This improvement was driven by strong LLS price differentials this quarter with our Gulf Coast tertiary price differential improving by $2.26 per barrel from last quarter. In the Rocky Mountain region, our Cedar Creek Anticline oil differential improved primarily above (13:01) selling at around $6.50 per barrel below NYMEX in Q2.

We currently expect our overall oil differential to be in the range of $2 to $4 per barrel below NYMEX in the third quarter of 2015 as prices – as LLS prices relative to WTI have weakened a bit, thus far, in Q3. However, our Rockies differential has improved a bit as of recent.

On the expense side, we are continuing to show improvement on our cost structure. Our LOE per BOE was $19.70 per barrel this quarter down from $21 in Q1 due primarily to lower CO2 utilization, lower power costs, and workovers.

G&A expense was $38 million in Q2 in line with our expectations and down from $46 million in Q1. As Phil mentioned, we have recently had some workforce reductions which has contributed to our overall employee base decreasing roughly 10% to date.

In this current environment, Denbury, like many other companies, is having to address the reality of lower oil prices. The impact of this reduction on G&A will be seen more in the second half of 2015.

For the second quarter, $7 million of net G&A was related to stock-based compensation. For the – we expect the third quarter G&A to be slightly down from Q2, with approximately $7 million to $9 million of that being stock-based compensation.

We recorded a full-cost full-ceiling test write-down of $1.7 billion in Q2. As discussed on our last quarter call, we expected a significant write-down this quarter, as the full cost ceiling test calculation utilizes average prices over the last 12 months, which has continued to decrease as the prior periods roll off.

Based on recent oil future prices, we expect that we will continue to record material write-downs for the next two quarters, as current prices would indicate that the average price for the last 12 months will continue to average down. The impact of the Q2 write-down will likely reduce our ongoing DD&A expense for Q3 by approximately $3 to $4 on a per BOE basis.

Interest expense, net of amounts capitalized, was down slightly from Q1, due primarily to slightly higher capitalized interest. We currently expect capitalized interest to be approximately $5 million to $10 million per quarter for the remainder of 2015, depending on our qualifying activities.

Our effective income tax rate for Q2 was less than 36%, slightly below our estimated statutory rate of 38%, primarily due to the recognition of a valuation allowance of $30 million on our Louisiana net operating loss carryforwards. For the remainder of 2015, we anticipate our effective tax rate will be around our statutory rate of 38%, with current taxes being relatively minor.

Moving to our capital structure, total long-term debt at June 30 was approximately $3.5 billion, which was down $125 million from Q1. We had $350 million drawn on our bank facility at June 30, and based on current prices and projections, we anticipate ending the year with bank debt of between $250 million to $350 million, which is down from $395 million at the end of 2014.

We will also plan to reduce our capital lease obligations by roughly $30 million. We have over $1.2 billion available on our facility, and we have $1 billion of cushion between the $1.6 billion we have asked the banks to commit and our $2.6 billion borrowing base.

Also, as previously mentioned, a few months ago, we completed an amendment that restructures certain covenants under our credit facility in order to provide us more financial flexibility over the next several years, and allow us to better manage the credit extended us by our banks. And now, I'll turn it over to Brad.

Thank you, Mark. We are pleased to report that we have now completed field reviews on all of our fields using the improvement and innovation team process.

As you recall, this is a process where we use an integrated team of technical professionals to take a deep dive into each of our fields to challenge the existing assumptions, look at the latest data, and come up with ideas of how we can improve the value of that field. This process has generated over 250 opportunities to improve the value and increase the profitability, especially at low oil prices.

We have also reorganized our operations personnel in a manner that will improve efficiency, accelerate the growth of technical excellence, and focus our efforts on implementing these IIT opportunities. We have created, developed and designed an organization that is accountable to deliver optimized field development plans for both our existing and future CO2 floods.

We also have created a reservoir management organization that is reviewing reservoir performance and making improvements to flood parameters in existing fields to optimize profit growth. Examples of flood parameters are CO2 injection, distribution by pattern, and profile modifications.

These organizations are very busy right now implementing all these IIT opportunities. The positive impact of deploying the IIT opportunities are showing up in reducing our LOE per barrel in 2015, while maintaining production, as Phil already discussed.

All these (18:31) opportunities will be contributing to improved business performance as early as 2016. The improvements in future CO2 floods will contribute when these floods come on line.

As Phil and Mark talked about, as a result of these field reviews, we have reduced gross CO2 purchases by over 20% since last year, while keeping production relatively flat. We see further opportunities to reduce CO2 purchases, especially through the use of – expanded use of WAG injection process.

WAG is water alternating gas. The expanded use of WAG could not only reduce CO2 purchases, but also could reduce the size of compression facilities required and reduce field operating costs.

We have already piloted WAG in several of our fields and had positive response. Earlier this year, we converted the Hastings Field fault blocks B and C in one pattern to fault block A, to a series flood.

We have mentioned this in previous calls and we are pleased to announce the initial results of this conversion. The results have been positive so far.

Production response occurred after three months, which was earlier than expected, and production has increased from approximately net 130 barrels per day to 900 barrels per day in the areas under a series flood. These are early results, and we will continue to monitor for long term performance.

We're in the process of evaluating improving profitability through the use of a series flood in other fields including the future flood at Webster Field, the rest of Hastings Field, Conroe, and Heidelberg. We are already using the series flood approach at Oyster Bayou which is one of the reasons that reservoir performance has been above expectations.

Besides WAG and a series approach, there are several other types of opportunities from the IITs. We will be explaining these as we implement them.

In the meantime, I'd like to give you a flavor of the types of ideas we are pursuing to enable us to flood our fields at significantly lower costs. We see opportunities to modify pattern spacing going to larger spacing given the good quality of the reservoirs in our portfolio.

We can reduce the size of compressors used to recycle the CO2 produced, optimizing the internal rate of return on these investments. We can reduce the pressure at which we operate these fields producing the power requirements for injection and the volumes that need to be injected to maintain the pressure.

We can design our injection distribution flow lines more efficiently thereby reducing back pressure and the power requirements on the compressors as well as the chemical cost to operate these flow lines. We've also identified opportunities where we can locate the water curtain wells to be more efficient in maintaining pressures in the CO2 flooded areas.

We've also identified additional zones above and below the zones that are currently being flooded. And we will expand the flood into these other zones, leveraging the infrastructure that is already in place.

An example of reservoir management is in our Oyster Bayou where we've identified areas where we can optimize the flow of the CO2 through the reservoir, which should increase sweep efficiency. For example, in Oyster Bayou , we recently shut in two water injection wells and increased CO2 injection in one area of the field, thereby causing the CO2 to flow differently in the reservoir and increasing production.

So far what we see is by implementing the opportunities that came from the IITs and with the new organizational structure, we are confident we can be profitable in a low oil price environment with our existing fields and with the new projects we have planned. So, with that, I'll turn it back over to Ross.

Thank you, Brad. That concludes management's prepared remarks.

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

Hi. Thanks.

Good morning.

Good morning, Ryan.

Quick housekeeping one for me to start off with Mark. I think I may have missed your LOE guidance.

Can you restate that for me, please?

Well, we actually didn't give a number. Phil discussed it in more detail in his comments, and we're very pleased with where we are.

We potentially could see workovers being a little bit higher in Q3 based on some of the work we're doing right now. But our goal here is to hold it flat or try to improve but we're not giving out specific targets right at this point.

So if you have any more comments on that, Phil.

We're very pleased with where it is and happy to come down a buck over the prior quarter. I think it's interesting too, I don't know if we really highlighted in the call, the CO2 costs were actually down 30-some cents quarter-over-quarter and the cost per Mcf was actually up.

So it's not just an oil price thing or it's not just related to savings tied to the oil price. It's really due to internal efforts and the hard work of our staff to really optimize the CO2.

So that being said, it's harder to find continued cuts but we're still working it. So as Mark said, we do see workover activity going up a little bit, so that potentially could cause expenses to go up a little but we'll keep working on the others and hopefully we can hold it flat.

Got you. Got you, so something kind of in the low 20s as opposed to kind of the mid-20s is maybe appropriate number to think about moving forward?

For sure. Yeah.

Okay. That's helpful.

Obviously, CO2 usage was down significantly, that did drive a big portion of the beat here. I'm wondering if you can speak to, I guess, first the Jackson Dome production, down quarter-over-quarter.

How those wells decline over time, obviously that's you guys managing for what the Tertiary business needs, so I was wondering if you could kind of speak to maintenance capital spending there, that asset and then the ability to sort of increase production there from Jackson Dome should you need to?

We have actually a lot of excess capacity at Jackson Dome. So I don't want anybody to think production is down because the wells have depleted.

That's not true at all. We probably have capacity of somewhere in the mid-9s (25:48) probably.

So, probably, 250 million a day (25:54) of extra capacity there. The big plus, as you pointed out, is we don't have to drill additional wells to continue to develop capacity at Jackson Dome.

So we're not drilling any of the rest of this year, and probably don't plan to drill any next year, and we'll see after that. And then if you go to our slide show, we showed in – our needs (26:27) being close to 1 Bcf a day or 900 to 1 Bcf a day, obviously, we just produced 680 (26:26) this quarter.

So it's a dramatic cut. And it will save us a lot money long term.

I was kind of trying to make that point in the prepared remarks, but this isn't just a short-term benefit. This really has a significant long-term benefit because it reduces cost at Jackson Dome and also capacity on the pipelines.

And potentially lets us go faster.

That's helpful. And I guess that's kind of the last question that I'm trying to kind of understand here is, looking out to 2016, you guys have mentioned the potential for production to be similar to this year's levels.

I was wondering if you can kind of speak to the capital that you see required there, both in terms of capital spending, and operating expenses in the form of CO2?

Yeah. Well, we haven't done our 2016 budget yet.

We do see things getting better. In fact, just to refresh a little bit, at the Analyst Meeting, I think we said, well, to hold production flat, we'd probably spend a little bit more in 2016 versus 2015.

And then kind of, I think last quarter, we said, well, maybe we can spend about the same and keep it flat. So, to be honest, I don't know that we have a precise number, because we haven't done a specific budget for 2016.

But, in this price environment, it probably will be difficult to spend the same amount of money. I think we would probably want to spend within cash flow, which means in 2016, we'll have to cut it back a little bit, because we won't have as much benefit from our hedges.

So it will be a tough challenge to hold production flat. It could slip a little bit.

But we're just not quite there yet, and not quite sure where we're going to spend the dollars and what it's going to be on, and what that looks like. But we are very encouraged with our capital efficiency improvements over time.

Great. That's it from me.

I'll hop back in the queue. Thanks, guys.

Thanks, Ryan.

Yes. Good morning, Phil, and to the rest of your team there.

I'm wondering if you could talk a bit more about the series flood and the WAG floods, and to what extent those have to be – to what extent those are kind of – once you figure them out in one field, a template for the next field over, or conversely, if you have to start over from square one on each one of those fields, as you tailor that new flood design.

I'd be happy to take that. There's a lot of similarities between our fields and, to a large extent, once you learn how to do it in one field, you can apply those same principles to the other filters; operational aspects to it, there's reser (29:38) performance aspects to it.

So that's why our focus right now is on the Hastings and also from Oyster Bayou ,is really learning from that. So we've done some initial work on the Webster Field to convert that to a series flood, and that looks quite promising.

But we're not going to finalize that design until we get a little more information from Hastings. And so we are – there is lessons from one flood to the next flood.

The good thing about the series flood is that the floods move quite quickly, and so it isn't that you have to wait years to get your flood responses, as you heard, that we got the production response after just three months. And so, when you do a series flood, you can process the reservoir fairly quickly, and so we'll get those learnings and cascade those learnings on to these other fields fairly quickly.

But every field you want to do it to optimize to that field, and that's the key for maximizing profitability. Every field is a little bit different, and so we can tweak the parameters about what's – do we use a 9 spot or a 5 spot, (30:51) or what the reservoir pressure is.

So the development design team will be taking lessons from the previous floods, but then optimizing it for that field. And that's the key for really making the most money from every field that we have.

Okay. Thank you.

That's helpful, and then maybe broadening the scope a bit. The impression I'm getting is that, moving forward, that the better utilization of CO2 is really the prize, as far as reducing your cost.

But I wonder if you can tell me if that's the correct impression, and maybe you could give an order of magnitude, what the cost savings from that better CO2 utilization is versus, or compared to, just the more straight-up cost savings?

Well, we would – yeah, it had an immediate impact on the LOE per barrel. So, it's probably $1.50, if you go back in time a little bit in savings per barrel.

That's the part that we expensed, and that, of course, is the immediate impact. I think there's also big savings, though, potentially going to a WAG a little bit sooner and that sort of thing.

It not only could save on LOE, but it could reduce some of the requirements for the size of our facility which, of course, saves capital dollars and so forth. So there's potential savings, not only on the LOE side, but also on the capital side.

And then, as I mentioned before, wells at Jackson Dome saves on capital. So it's trying to really maximize the use of CO2, and get the most benefit out of each molecule and focus on where it's going, and we do that with 4D seismic and other techniques, and the guys have really come up with some significant reductions.

Thank you, Phil.

Yeah, Phil. Thank you for taking my questions this morning.

Just curious if you could provide an update on the COO search.

It's ongoing. We wish it would maybe have gone a little faster.

We've hit a dead end or so. And so – but we're still working it.

So, I think earlier in the year, I said maybe it'd be third quarter, so I guess I have two more months. So, we're still working it hard.

We did add a strong technical person as part of – a by-product of the search. So, we've gotten some, I guess, side benefits, but we haven't found the senior executive we're looking for yet.

Great. And my follow-up is, you guys have done a good job on capital spending this year, tracking below your guidance, if we were to annualize your spend rate for the first half of the year for the full year.

Do you think you will essentially take those savings and if you come in underneath your guidance and apply that to the bank debt? Is that your thinking right now in this price environment?

Yeah. I mean, we – cash is cash.

Unless we come up with another pressing use, it will go to the bank debt. We've, as mentioned, reduced it $115 million quarter-to-quarter, and we still expect to have free cash the rest of the year.

So, the bank debt is always the swing. We did do a small acquisition we talked about last time, Martinville (34:50), but it showed up in the financial statements this quarter.

That was $20 million. So there could be potential for some small deals, which, of course, would use that free cash.

But barring other uses, yes, it will go to bank debt.

All right. Thanks for taking my questions.

I'll jump back in queue.

Good morning. Maybe just to piggyback on that last question, just the cadence obviously for the CapEx is running pretty low.

Is there anything that you're seeing that is going to be a bigger spend in the second half, or is it just more it's going to stay with the budget and let the year play out?

We are still staying with the $550 million budget. So we haven't changed that.

There are a couple of things that may have a little higher spend. For instance, we're building the NGL plant at Delhi.

There wasn't a lot of spend in the first half. There'll be some more significant ones in the second half.

And that is expected to be put into service actually next summer or next – probably second quarter 2016. So we are having some general savings, but we continue – we're just watching capital very close and we're kind of reallocating it as need be.

And so I think we'll still spend the $550 million, but it may not be the same as the original $550 million. We're fine to put it on projects that make sure we get positive rates of return and making money on everything we do.

Thanks. And then just a lot of guys on the group have looked at their dividend or cut it or reduced it at least and obviously you guys have kept it at that level.

Could you just maybe comment on where your plans are there? It's obviously yielding a great number now, which is good and bad.

But just going forward as you look even in I guess 2016 just the plans with the dividend.

Yeah. That's a tough one to answer, too.

It's something we look at. Every quarter, it's a discussion we have with the board and so we'll just evaluate it I guess as we get closer, which we just declared in the third quarter, so we're keeping that intact.

I mean, philosophically, that base dividend is important to us and we're going to try to protect it, but as we've said, if we – the financial security and well-being of the company is more important so that would be a reason that we would potentially reduce it or cut it. So I guess I really can't answer.

We're evaluating it every quarter and seeing what oil prices do and so forth. And we'll just make that decision on time.

All right. I appreciate it.

Good morning.

Good morning.

Sort of putting together some of the things that have been discussed before, just maybe just talk about as you think about your business on sort of a half-cycle basis, you kind of put some numbers around the cost savings you realized both on the OpEx side as well as sort of some of the capital projects you touched on in your prepared remarks. Are we talking about sort of $10 better, $15 better per barrel?

What's the order of magnitude we should be thinking about, in your minds?

Well, our – okay. So LOE has come down over $6 just in the last year or 18 months.

I think our goal is to get $15 or $20 a barrel out of our costs in total. So that means a lot of the rest of it has to come out of finding and development cost, maybe a little bit of G&A and some of the other categories.

F&D is a little bit harder for us to demonstrate because it's not quite the same industry where we drill wells and we can point to immediate results. But we are seeing better use of our capital, and I think as we start some new floods, hopefully maybe next year we'll be able to give better numbers.

But I believe we can easily take $5 to $10 a barrel out of F&D from where it was in the last three years.

All right. And then on the capital allocation front, you paid down a decent amount of revolver during the quarter.

Any thought about sort of bond buybacks as an alternative for revolver pay-down?

Well, it's something we always consider, and I guess it's always depending on where the stock price is, as you know, on bond buybacks. I thought you said stock buybacks.

I apologize. Mark corrected me.

I'll answer a question you didn't ask. How about that?

Bond buybacks, I think that's just hard to make a big dent in that. And so I don't think we'd probably be too inclined to do that.

We kind of like having low bank debt because it's very secure and it's nice not to have to repay the bonds so in the first principle isn't due until 2021. So, that gives us very solid financial condition.

I don't think it'd be too likely, although they are trading down. But I think that probably won't be a likely scenario.

Okay. Great.

And just one last one for me. If you're looking to accelerate your capital spend in the next couple of years, would you think about issuing structurally senior debt?

You have obviously some relatively loose indentures that will allow that, or are you comfortable with kind of the borrowing base as it stands and your bonds as your capital structure?

Right now, I think we're pretty well set. I mean, in this price environment, obviously we're watching our debt very closely.

So, as we work forward over the next few years, we'll evaluate that relative to prices in our development plans, but no plans at this point.

Thank you very much.

Hi. Good morning, folks.

Thank you for taking my questions. I wanted to ask Phil relating to his prepared comments.

Is there any – did you give a tilt kind of to the low end of your production guidance range based on the Thompson issues, I know you kept it. Is that incorporated, I guess, in the range you gave for the year for production?

Well, yes. Thompson wasn't big enough to throw us out of the range.

I guess what I was basically trying to say is we should still be near the midpoint if you adjust for the Thompson effect. That was basically what the summary was.

So Thompson was probably 500 barrels a day, actually a little bit more than that in Q2 and we said it's probably going to be a couple of hundred barrels a day to the impact of Q3. So, if you're looking to be at the midpoint, you need to adjust for the impact of Thompson.

Okay. That's helpful.

And then, back to the discussion on the WAG floods, it's kind of the most color you've given on the topic in quite some time. How pervasive is this kind of switch going to be?

Is this just kind of like you're testing this and series floods at the same time and just thinking of maybe a new way to sort of develop the fields or is it going to be like a field-specific kind of – are there certain fields that wouldn't work or, like, how much of a game changer, I guess, is this additional usage?

I think WAG is actually going to be a game changer for us. When you look across the industry, most fields are WAG-ed.

We have, over the last two years, been piloting WAGs in several of our fields like Mallalieu and the West Heidelberg. And we had such low cost CO2 that WAG wasn't as high a priority.

Now in this lower oil price environment, we, discrete analysis we've done, we see WAG being a key way that we can be reducing our CO2 requirements and also reducing our operating cost. It cost a lot less money to inject water than CO2.

We see WAG flexibility in several of our fields and we're doing studies right now to rescreen all those fields. And as we update the field development plans for every one of our fields, that's one of the opportunities we're going to look at for every field.

And there are some fields that it will make sense for but there are several fields where it's looking like that will be a positive economic decision is to go to WAG. So lots of space and I believe we'll get some real good results by converting some fields over to WAG.

Okay. I appreciate that detail.

And then is it safe to say that you talked about it being a positive economic decision, is that kind of regardless of the oil price scenario or at a higher oil price does that thought change?

It is regardless of the scenario. It gets more positive as you go up to higher oil prices.

It is something, when you put in the oil and (44:44) gas earlier. So we had the plan to do it later but what we're seeing is we want to implement that earlier than we had in our current plans.

That allows you to be injecting less expensive fluid to do all that. But it also allows you to not have as big gas recycle compressors and those compressors are an expensive capital item as well as an expensive item to operate and take a quite bit of power and maintenance.

And so WAG is something that's been a tried and true method, and we're just going to leverage that to apply that to our fields. But it is something that would be reducing capital cost, operating cost for our fields, and if we can reconvert them at this oil price, we can make money.

When the oil prices go up, then we just make more money.

That sounds great. Then I had one last one.

You have a very attractive hedge position through the first half of 2016. We back of the envelope valued it at well over $300 million, obviously, a little higher today with oil rolling.

How do you think about maybe capturing the value at a trough oil price, to maybe buy some security out later into 2016?

Yeah. We've looked at it.

We entered into a few more hedges after our call in the first quarter. Prices dipped shortly after that, so we've kind of pulled back.

We do look at different structures and ways to enhance our hedge position over time, and we've done some of that in the past. But we're just continuing to evaluate it in light of the current price environment, and we're not necessarily trying to call prices.

We're looking for price certainty and cash flow certainty. And so that's generally where we come back to, but we do evaluate different optionality and structures.

Okay. Thank you.

Great. Thanks for taking my question here, guys.

The two questions I had was, first, with the lower CO2 needs here, is there any chance that you guys would look at high-grading some of your fields down the road? Does that give you the flexibility to do that, if you wanted to?

Well, I'm not sure what you mean by high-grading, but the...

Perhaps sell some of them?

Sell some of them?

Yeah.

I doubt that we will sell any. The hard part of selling EUR floods is – or future EUR floods is, you've got to supply CO2, and to be honest, we'd make more money doing it ourselves.

So I think that'd be the hurdle. I think the thing it may allow us to do is potentially go a little bit faster in some of our floods, or do one or two simultaneously.

Now, we do have to get a little help from the oil price and be able to fund it and so forth. But at least CO2 should not be as much of a limitation, or a limiting factor, as perhaps it was historically.

Okay. All right.

Great. And the second question I had was just, with the WAG floods, I guess, what's the performance difference?

I thought most of these fields are already on waterflood for some time before you all picked them up. I mean, by switching it to a WAG, how does that improve the recovery?

So, just in general, what it does is it – sometimes, it does improve it a little bit. Sometimes it basically keeps it the same, at a lower operating cost.

But when you put in the gas and then you follow with a cycle of water, the gas is less dense and tends to rise; the water is more dense and tends to fall. So, basically, when you put them back to back, it tends to hold up the flood front easier and you get better performance, a better vertical sweep.

And so, for instance in one of our floods in Soso, I believe, we did a pilot and we actually saw an uptick in our recovery, because it had a better vertical sweep efficiency, because putting in the water helps keep the CO2 from rising up in the oil column, and putting the gas keeps the water up. So, it just maintains that spud (49:27) flood more even across the reservoir, and you get a more efficient sweep.

Okay. Thank you very much.

Little bit hard to explain that over the phone, but hopefully that was clear enough.

No, it is. It's been years since I've kind of looked at that sort of stuff, but that all makes sense.

So thanks again.

Excellent. Mark, thanks for taking my questions.

Sure.

Curious just to ask more questions around this idea of, since you're using CO2 more efficiently now, the flexibility in perhaps going faster. Would this be in existing fields where you have sort of new zones to bring online, are there areas that currently, that you're producing in, that you feel like you're sort of underserving the field with injections, or would these be (50:21) – because it sounds like you're not ready to do Webster until after you finished learnings from the series floods in Hastings.

So, it doesn't sound like these would be any new floods in areas that you had previously moved out. Is that correct?

Yeah. I mean, it's not probably a short-term benefit to go faster, one, because we want to look at Hastings.

We want to finish the good (50:46) development plan for Webster. So, Webster – we may start Webster next year, but there's nothing that's going to happen on that this year.

But it does – if you go back to kind of the history, one of our limiting factors in the pace that we could go in the Gulf Coast, that limited the pace we could go, was the CO2 supply and the pipeline capacity. And we had it scheduled out.

We started a field every year or two, and we kind of had it so we were maximizing the use of the infrastructure. But I guess the only point I'm making is, with using 20% or 25% less CO2, you could potentially go at a faster rate.

Like I said, we need cash flow or funding to do that, but it reduces that bottleneck, or potential bottleneck, that we had historically.

Got it. Okay.

I understand now. And then on the M&A front, you guys picked up the Mandeville (51:55) field, I guess it hit numbers second quarter.

We've seen historically a lot of dots along the Gulf Coast there. It seems like the bid-ask spread has been historically high, just given the nature of the parties that own those fields.

Are you starting to see that narrow in this downturn, and are the prices getting compelling enough where you could be buying cheap cash flows, or is that more of like a pipe dream these days?

Well, we haven't seen too many bargains yet. We feel like we've got Mandeville (52:28) at a pretty good price.

I mean, it basically was just buying the existing production, which is pretty marginal, I mean minor, which is why it wasn't a very expensive field. So we think we picked that one up at a reasonable price.

Some other ones we've looked at, we've been a little surprised at some of the prices people are paying, but I guess we'll just have to take one at a time. I mean, there's more talk, of course, that there'll be more stressed companies; this fall, the banks re-determine their borrowing bases and so forth.

So we'll see what comes out of that. Maybe there'll be some fields we can get.

Got it. And just the last one for me.

I just want to make sure on the timing with Webster. When do you feel like you would have the design – enough information out of Hastings to put together the series flood design at Webster?

Well, the internal schedule is to have the plan by second quarter of 2016.

Okay. Thanks, guys.

That's all for me.

Good morning. Sorry about that.

I think most of my questions have been asked. One final one, Phil or Mark.

What do you expect your non-EOR spending could be next year, say in a $50, $55 oil environment? I know we've talked about EOR spending.

Yeah. I mean, we haven't gotten there yet, but probably the area we're spending the most is the CCA.

We're drilling five wells and some other work. And the aggregate probably ends up to maybe $100 million of spend toward non-tertiary across the company, the bulk of that being at CCA.

There's a lot of other potential at CCA, so that number may be a similar ratio, I guess, to the total in 2016.

Okay.

Still kind of preliminary.

That's helpful. Thanks.

That's all I had. Appreciate it.

Hi, guys. Thanks.

My questions have been answered.

Good morning.

Good morning.

In your comments about the mature properties and just the overall plan to try to keep production flat going forward, I was looking into 2016, as far as sort of the most bang for the buck, is it in mature fields that you might have the best chance of getting some boost to help keep production steady or would it be in the still growing fields like looking into next year?

Probably. I mean, probably, the fields that are growing you get the best bang for the buck because you're expanding an existing flood without having to maybe make a proportional expansion of the infrastructure.

Most of the spend in mature floods is pretty minor and it really relates to conformance modifications or doing things to improve the sweep which, as Brad pointed out now, we have a group that's solely focused on reservoir management surveillance. And so, they'll be watching for that.

But that usually it doesn't turn out to be very big dollars, but it can help you get the recoveries you expected and help with your production, but they're usually minor dollars.

Okay. Great.

And I'm sorry if I missed this, but as far as the workover activity that you see going forward, do you expect that to be relatively steady or more lumpy and I'm just wondering have you evaluated maybe what the rate of return looks like on some of the workovers you're doing?

We're definitely looking at the rate of return and we've had a big effort in continuing to do root cause analysis and reduce the number of failures and so forth. And that's been a big contributor to the reduction in workover cost.

However, you can't reduce that to zero. When you do, you do have work that's required.

So we just – we're watching kind of the workover rig rate and so forth, and therefore know that there's going to be a little bit of an uptick in Q3. But we're continuing to watch failures, and if it's a marginal well and if it's not worth fixing or completing or working over, we don't do it.

So we do continue to look at rate of return and make sure it's economic.

Okay. Great.

And about the, I guess, the overall CO2 cost outlook, I heard you talking about implementing WAGs. One of the benefits is that it can help reduce the size of the facility that you need.

I just wonder. Is there any trade-off in terms of picking up neighboring fields, I mean, down the road?

I mean, are there advantages to maybe designing a little bit data with some excess as far as bolt-ons down the road?

Yeah. Well, most fields aren't close enough to share facilities.

The one we're still debating, I guess, because we just purchased it was Martinville, and could we share the Hastings facility and use that same facility for Martinville, which is only about five miles away. But in most cases, our fields aren't that close together to share facilities.

We have talked about making them a little more modular so we can move them a little easier, but of course that's way down the road, and the present value of that is probably not real high, but it does help you long term on your total capital cost.

Got it. Thanks.

That's all for me.

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

On the conference front, Phil will be giving a presentation at Enercom in Denver on August 18 and then at Barclays Conference on September 9. The webcast for both presentations will be accessible through the Investor Relations section of our website.

Lastly, for your calendars, we plan to hold our conference call to report third quarter 2015 results on Thursday, November 5 at our usually scheduled time of 10 AM Central. Thank you for joining us on today's call.

We look forward to keeping you updated on our progress.