Denbury Inc.

Thank you, CeCe, 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 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 the call today.

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 the news release today, all of which are posted on 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 on today's news release. With that, I will turn the call over to Phil.

Thank you, Ross. Good morning.

In spite of low oil prices, we have some positive things happening here at Denbury. Our per barrel tertiary operating costs were down for the fifth consecutive quarter, down 6% sequentially.

Our production and other results are on track as expected and we continue to find ways to improve our business with ideas emerging from the innovation and improvement teams. Further, we have solidified our financial strength by amending our bank agreement such that we do not expect to have any covenant issues during the term of the bank loan which expires in 2019.

Mark will give you more details on that in a little bit. Also with our cost-cutting measures and other efforts, we now expect to generate in excess of $150 million of free cash flow this year, that being cash flow from operations, less projected capital expenditures in our current dividend level.

These funds will likely be used for debt reduction, but could be used for other things as well such as acquisitions or capital expenditures. Bottom line, I think it's great to be able to generate that level of free cash, keep production flat and pay dividend on this current price environment.

Of course, in order to generate that much cash flow, that requires help from our hedges. As you know, we are well hedged in 2015, but previously had very few hedges back to the first quarter of 2016.

With the recent improvement in oil prices, we have started to layer in a few hedge contracts in Q2 and Q3 of 2016. The details are available on our website and I think Mark may touch on it, too.

But we generally entered into swaps in the low $60s and collars with roughly a $55 floor price and a $70-plus ceiling price. So our strategy continues and we want to make our future cash flow more predictable and we will continue to look at opportunities to add to our hedge position, doing a little bit at a time and layering on the hedges.

Although we haven't seen many M&A deals, we have entered into an agreement to purchase one small bolt-on acquisition, a field located just a few miles from Hastings in the Houston area. This is small.

It's a $20 million deal and has very minor production, but we do expect that it can add somewhere in the range of 10 million barrels net to Denbury with an EOR flood in the future. We continue to look for these types of transactions where we can pick up the field for basically the crude producing value in this low price environment.

As we stated on the fourth quarter call, we have started IIT reviews all of our assets and now reviewed over 50%. The plan is to have these reviews completed by mid-year.

Brad will talk more about a few of these items in the call. The benefits are the quarterly drop or one of the benefits is the quarterly drop in LOE per BOE.

First quarter op costs averaged $21.08 per BOE, 7% and 18% lower than the fourth quarter of 2014 and first quarter of 2014 respectively. I think it's important to highlight that we have been able to move about $5 a barrel or about 20% out of our op cost.

Another way to say that is for every $1 reduction in cost adds about $25 million in cash flow. These types of improvements are partly correlated to the price of oil as well as our efficient use of our CO2 supply.

These were the types of ideas and initiatives that allow us to thrive even if oil prices don't return to previous levels. Let me touch a little bit more on operating results and field results.

Total company production for the quarter was in line with our guided range of 72,500 BOEs per day to 75,500 BOEs per day. Our tertiary oil production averaged just over 41,800 Bbls/d, consistent with the previous quarter even after absorbing the lower production related to the reversionary interest in Delhi in the fourth quarter.

The strong growth areas in EOR were Oyster Bayou, Bell Creek and Tinsley. At Hastings, sequential production decreased about 100 barrels per day as we converted and initiated a series flood and completing the plugging and abandonment work.

We let the new area pressure up for an additional month in order to be closer to visibility pressure. So we are running 30 days to 45 days behind schedule, but are starting to see a positive response to the B and C fault blocks.

Oyster Bayou continues to show solid reservoir response, increasing over 200 barrels a day sequentially in Q1. This increase is due to continued response in the new patterns in the A-2 zone.

Development of Oyster Bayou's A-2 zone was completed at year end, and we expect to see additional production growth in the first half of 2015 as additional patterns (6:12) respond, though we do expect production to peak this year. At Heidelberg, our tertiary production decreased slightly, 137 barrels per day from Q4.

We expect continued relatively flat production at Heidelberg for 2015 as we work through a few conformance issues. We have completed our initial IIT evaluation of Heidelberg and concluded that due to the complexity of the field and its multiple producing horizon (6:37) that has sizable value and upside that this opportunity deserves further review in order to optimize its remaining EOR potential.

As such, we have temporarily reduced our capital expenditures at Heidelberg to the absolute minimum, in order to focus on maximizing its value in the future. Tinsley's production increased modestly, adding over 150 barrels per day from Q4, the result of modified injections to improve performance in the East Fault Block.

This field continues to perform strongly, although it too is expected to be at or near its peak production. For the mature area tertiary properties, production decreased just under 300 barrels a day due to normal declines.

This is on the low-end of the expected decline range, as normally we would expect declines in the mature fields to be between 10% and 15% per year. We are continuing to review the rest of these fields and are optimistic we can continue to mitigate some of these declines with our IIT work and increased focus on reservoir management and surveillance.

In the Rockies, our Cedar Creek Anticline production stayed relatively flat sequentially. This is a result of continued optimization and higher production attributable to our net process interest which has yielded a production benefit in this lower price environment.

We have also just recently started one of our dual horizontal wells in that field and hope to have results on that in the second quarter. Bell Creek tertiary production was up sequentially, due to production from the new area of Phase 3.

We have started a WAG process in Phase 1 of Bell Creek and expect it to assist in future production growth. Hartzog Draw production was up sequentially, related to lower-than-expected declines from our previous horizontal well development, as well as focus on reducing failure rates.

On CO2 supply, we produced about 880 million cubic feet per day from Jackson Dome during the quarter. And we also used about 75 million cubic feet per day from an industrial source CO2.

Our man-made supply is expected to get a boost from the gasification and carbon capture system at Mississippi Power, Kemper County plant, probably in about the next year. In the Rocky Mountains, we received over 100 million cubic feet of CO2 per day from our combined sources at LaBarge and Lost Cabin.

We've been receiving excess CO2 from LaBarge, so we're working on a utilization plan for that CO2. And with that, I'll turn the call over to Mark to give you financial details.

[002H1R-E Mark Allen] Thanks, Phil. My comments today will summarize some of the notable financial items in our release.

I'll be primarily focusing on the sequential changes from the fourth quarter to the first quarter. I'll also provide some forward-looking guidance to help you in updating your financial models to reflect our current outlook, and I'll update you on our recent bank redetermination and amendment.

In the first quarter, our non-GAAP adjusted net income was $23 million or $0.07 per diluted share. This was in line with analyst estimates but down $70 million from the fourth quarter, as the drop in oil prices caused a significant drop in our revenues this quarter.

Our revenues were down $127 million after considering the impacts of our hedges. On a GAAP basis, we had a net loss of $108 million for the quarter due to $146 million pre-tax write-down of oil and natural gas properties and a pre-tax loss of $65 million on fair value adjustments related to our commodity hedge positions.

Turning to cash flow, our non-GAAP adjusted cash flow from operations which excludes working capital changes was $195 million for Q1, also in line with analyst estimates. That was down from $350 million in the fourth quarter due primarily to the drop in our revenues.

Plus, we had a $45 swing in current taxes, which was a benefit to us in the fourth quarter of 2014. Our first quarter realized oil price excluding hedges declined to $46 per barrel.

That is down 35% from Q4. We recognized $148 million in cash settlements from our hedges this quarter, which made our after hedge per barrel realized price of little over $69.

And that was compared to almost $87 per barrel in Q4. Our realized oil price average $2.81 below NYMEX in Q1.

That's down slightly from $2.24 below NYMEX last quarter. This decrease was primarily driven by weakness in our LLS price differentials.

All differentials for our Gulf Coast tertiary production which primarily receives LSS pricing averaged $0.22 per barrel below NYMEX this quarter and that was down from $1.52 above NYMEX prices last quarter. In the Rocky Mountain region, our Cedar Creek Anticline oil differential improved by over $1 per barrel selling at around $8 per barrel below NYMEX in Q1.

We currently expect our overall oil differential will remain in the range of $2 to $4 per barrel below NYMEX prices in the second quarter of 2015. However, we are encouraged by the recent strengthening in the LLS price differential.

Our hedging positions for 2015 haven't changed, but as Phil mentioned, we recently began adding toward 2016 positions. For the second quarter of 2016, we went from 12,000 barrels per day hedged to 31,500 barrels per day hedged, adding a combination of swaps and costless collars to our existing contracts.

These additions make our average downside hedge price at around $71 per barrel on WTI equivalent basis and our average upside price around $75 on WTI equivalent basis. We do have sold puts on 12,000 barrels at around $67.

For Q3, we have added 5,000 barrels per day with costless collars and floors with average – or sorry with costless collars that have floors and caps, averaging roughly $55 and $71 on WTI equivalent basis. All this information is summarized and included in our latest slideshow presentation on our website.

On the expense side, LOE per barrel came in better than we expected at $21 per barrel. On a sequential quarter basis, this is $1.56 lower than our base LOE in Q4, primarily due to lower CO2 costs and utilization.

This is our lowest LOE per barrel in over two years. G&A expenses were roughly $46 million in Q1.

This is on a high end of our expectation. And as you recall, our G&A in the first quarter is always higher as we have incremental payroll burdens from bonus and long-term incentive payouts in the first quarter.

Also, due to reduced capital spending levels, we have less overhead than anticipated being capitalized, which put us at the higher end of our range. For the first quarter, $7 million of our net G&A was related to stock-based compensation.

In the second quarter of 2015, we expect G&A expense to be between $36 million and $41 million with approximately $7 million to $10 million of that amount being stock-based comp. As I mentioned on the fourth quarter call, we expect our G&A in 2015 to be flat or slightly lower than 2014 levels.

This reduction would be more except for some of the impacts that lower capital spending has had on our allocation of costs. We've recognized the full cost, full ceiling test write-down of $146 million in Q1.

As you may or may not know, companies that follow full-cost accounting for oil and gas properties have a different impairment test than successful efforts companies. Full cost companies are required to use the average trailing 12-month price when comparing the value of its reserves against the book value of its oil and gas properties.

As such, when prices fall dramatically from levels at which costs have been accumulated, including acquisitions at significantly higher price values, it would force us to take a write-down of our property balance. We have also noted that many of the full-cost companies have taken similar or more significant write-downs this quarter than us.

Based on recent oil price levels, we expect that we could record a significantly larger write-down next quarter or subsequent quarters as current prices would indicate that the average price for the last 12 months will continue to average down. On the interest expense, net of amounts capitalized, this was down slightly from Q4, mostly due to higher capitalized interest levels.

We currently expect that our capitalized interest will be approximately $5 million to $8 million per quarter for the remainder of 2015, depending on qualifying activities. Our effective income tax rate for Q1 was slightly below our estimated statutory rate of 38%.

For the remainder of 2015, we anticipate our effective rate to be between 38% and 39% with current taxes being relatively minor at this point. Moving on to our capital structure, long-term debt at March 31 was approximately $3.6 billion, which was up about $60 million from Q4.

We had $465 million drawn on our bank facility at March 31, and that was up $70 million from Q4. The increase in bank debt was to cover Q1 working capital items such as accrued capital and compensation paid out in Q1.

Based on our current projection and prices, we anticipate ending the year with bank debt of approximately $200 million to $300 million. We recently completed our borrowing base redetermination with our lenders, under our bank facility.

And as we anticipated, due to the lower oil prices used by our banks and their evaluation, our borrowing base was reduced from $3 billion to $2.6 billion. However, as we've only asked our lenders for $1.16 billion of commitments, this reduction has no impact on our liquidity.

Also, as previously mentioned in our fourth quarter call, we have completed an amendment that restructure certain covenants under our credit facility in order to provide us more financial flexibility over the next several years and to allow us to better manage the credit extended by our banks. I won't go into all the details as they are included in our press release, but the primary adjustment was to our debt-to-EBITDAX coverage test which moved it to a secured coverage test for 2016 and 2017.

Our borrowing base redetermination is on an annual basis. So, our next scheduled redetermination will not be until May 2016.

Although we currently have no issues meeting our covenants, we believe this is a prudent move in the current environment, as we wanted to alleviate concerns around our bank credit facility. And now, let's turn it over to Brad.

Thank you, Mark. As Phil said, we now have completed the improvement and innovation reviews on over 50% of our fields and the pace of completion is accelerating as we gain experience with the innovation process.

These reviews have already generated over 120 ideas that could help improve cost, value and returns. We have preliminary estimates of what these ideas might be worth and we are enthused about what they might mean for our future.

Additional technical studies are being done to mature and implement these opportunities, some of which could take several months or even years to implement, particularly the improvements to the development plans of the fields. We will release more details hence these improvements are delivered and show up in our quarterly business results.

One theme I like to talk about today and has occurred in several fields and is already having an immediate benefit is the more efficient utilization of our CO2 purchase volumes. We have found ways to do more with less.

Where we were once using 1,000 million cubic feet of new CO2 from Jackson Dome to supply our CO2 Gulf Coast fields, we are now doing it with less than 800 million cubic feet a day. This reduces our two largest areas of LOE, CO2 purchase volumes and the power supply to run the compressors to inject it.

Secondly, in fields where CO2 injection is limited by compressor capacity, we are shifting CO2 injection from patterns with high producing gas oil ratios to patterns with low producing gas oil ratios. This optimized the oil production that we get per Mcf of CO2 injected.

Lastly, we wanted to give you an update on the implementation of the new series flood approach in Hastings, Fault Block B and C. We discussed this during the fourth quarter call.

CO2 injection began in January 2015. And as Phil said, we reached higher reservoir pressures that's closer to miscibility in the early April time period.

We have recently started to open up to producers and the initial production response that we are seeing is promising. We look forward to giving you more detailed overview of the flood response at the end of the second quarter.

So, with that, I'll now turn you back to Ross.

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

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

Hey, good morning, guys.

Hey.

The acquisition you mentioned at Hastings or nearby Hastings, just curious with the timing and plans there. Obviously, I assume it's pretty close so you could have something built out, but are you looking at when that's going to maybe have some CO2 to it?

I don't think we're that far along yet. We haven't closed yet.

We have an agreement. Closing, I believe, is in a week or two but we just haven't really put it in the schedule yet.

Okay. And so it will happen here in the second quarter.

Are you seeing more deals kind of crop up, whether it's the smaller ones like that or anything nearby your property, because it seems like a lot of those small ones probably are around and, if so, would be pretty good opportunity especially given the cash flow generation you're seeing?

Well, we've seen an occasional deal. I mean, we're quite specialized in just looking for old oilfields that we can utilize in our EOR business.

So we don't chase every deal that's out there, but we have one or two others we're looking at. So we'll see.

But we're – these little add-ons are very accretive to pick them up basically for crude producing in a low price environment.

Great. Thank you.

I'll turn it back.

Good morning, guys. Thanks for taking my questions.

Hi, Pearce.

Phil, congrats on the cost reductions on the LOE. It's really good.

If you were to allocate by sort of percentage, how much of that improvement do you think is related to CO2, and how much is related to lower oil, and then how much is just from being more efficient?

I was looking at Mark; I was just trying to get the numbers. Obviously, CO2 drop is what – we've had significant drops, as said – identified in the press release, drops in workover costs, power, and CO2 and to some degree, third-party.

Actually, workover is probably actually the biggest, and that one is really from focusing on the issues: how do we reduce, what's the root cause analysis and really trying to manage that and manage the checkbook. And so those have come down quite a bit, particularly from a year ago.

CO2 has also come down. As you know, we get a lot of help from oil price because a lot of our CO2 fluctuates with the price of oil.

So I'd have to say the majority of our drop in CO2 is really commodity price driven. However, we are very focused on using less.

And I believe in the script we said, I think we used in the upper 800s for CO2 in the first quarter but that's actually down thus far in the second quarter. So, it's actually looking promising going forward.

So, those two are probably the biggest components of the drop. Smaller decreases and maybe other cost relating to benefits or reductions from third-party expenses and so forth.

Excellent. And then, if you look out to next year to 2016, if you were to keep production roughly flat, when we've discussed this in the past, I think you've mentioned on the earnings conference call, the prior one, that you might need a slight uptick in CapEx for 2016.

Is that still the case, or is it more kind of flattish CapEx equals flattish production?

Yeah. Historically, we said we might need a little more.

I am hopeful that with some of these IITs and so forth that maybe we can hold it flat with existing CapEx. In other words, i.e., being more efficient with our capital dollars.

I think that's possible. We're shooting for at least 10%, 15% improvement in our efficiency.

So, if you extrapolate that, I think you can get to the same answer. Historically, we also said we probably need something close to $70 oil to fund our existing CapEx program and dividends, with cost coming down and so forth and, of course, the strip has come up.

It's looking more promising that maybe we can fund that with the current strip price which is in the mid-$60s I believe now for 2016.

Thank you. And then last one from me.

Phil, if you look at possibly selling some matured tertiary properties and if so, is there a pretty strong market for those?

Well, one negative to selling matured EOR properties is, of course, they're not worth too much to the new owner unless you give them the CO2 supply. We've actually looked at some of our older mature fields, Little Creek, of course, being the oldest, because that was started by Shell actually in the 1980s.

And we've found that the CO2 that's in the ground is actually quite valuable. So, I think the more likely scenario is that we will ultimately, I guess, blow it down or i.e.

recover as much CO2 as we can from the field and transport it to other fields. And we've done the economics on that and found that that's probably the most economic and the best use of that field.

Excellent. Thanks.

Thank you very much.

Good morning.

Good morning.

Couple of things. You talked about the strip for oil including a bit into 2016 and if you think of your longer-term planning, if 2015 turns out to be kind of a pivotal year, as far as whether oil prices are going to go back to where they were or going to hang out more like where they are, I guess, I'm trying to figure out have you – is it pretty much established now sort of what your tertiary peak is going to look like.

In past years, it was going to be a very fairly steep peak just as you layered fields on. Is that definitely going to be flatter when you look at the overall portfolio now?

I don't know if I can answer that, Noel. I think, near term, it's going to – we expect it to be flattish.

We have deferred expansion of some of the floods in order to maximize the capital dollars in key production plant. So that will affect our peak but I don't know that we kind of need to get a little more certainty on oil prices and maybe a little bit more work done on reviewing our fields so we can put together an updated long-range plan before I can answer that question.

Sure. And with the cost savings we see in the industry, the Conroe Pipeline, are the cost for that pretty much set or have you gotten into any contracts on sort of the materials or services tie or do you stand to benefit from oil slowdown for the cost of that?

Well, again, I'm not sure I can answer it. We haven't really tried to rebid that recently because Conroe is probably still a few years out.

I mean, I think costs have down a little bit, but I don't know that we have any good numbers to share because we really haven't chased it to be fair.

Fair enough. And you mentioned that at Heidelberg that you're delaying CapEx going forward out there.

And you mentioned some conformance study you were doing. Different deals have had conformance issues over the years.

Is this anything different from what you've seen in other fields?

I'll take that. Heidelberg is actually similar to several other fields.

It's different in that it's actually 10 different zones, so it's more zones than some other fields. Hastings is mainly four or five zones.

Tinsley is mainly one zone. So it is more complex in that there's more layers, and the good news is, you have more zones, there's more oil there.

And so, it's just going to take some more work to figure out how to most efficiently get out the oil in all those zones. So our goal would – to be effective in as many zones as possible.

And so, it's really the same concepts that we're talking about with the series floods actually. And so, we – in our redevelopment plans, we're looking at applying a lot of the learnings we've gotten from Hastings on the series flood approach in order to increase the amount to the reservoir that is swept.

Okay. That's all for me.

Thanks.

Thanks.

Hi, good morning, folks. Thank you for taking my question.

First one, I wanted to talk on the production expense side. You talked about the five quarters of sequential decline.

It sounds like you're halfway through your kind of IIT work. I mean, is there any reason to think that – or I guess, how do you see that trending throughout the rest of the year with oil still generally weak?

Do you think you can drive that down towards or below $20 at some point?

Well, we've always kind of used the goal of getting down to $20 or getting below that, I think is pretty tough. And of course now oil has actually come back up a little, which will affect, to some degree the cost of the CO2, so we're quite happy with the $21 that we just did for Q1, but I think it's going to be hard to get materially below that, particularly with oil prices coming back.

Okay. Thank you.

And then lastly, I didn't hear any updates on Riley Ridge on prepared comments, is there anything new to add on the work being done there?

No. We didn't put anything in the prepared comments because it's kind of the same as last time.

We're working on solving the sulfur deposition issues on the wells. We weren't expecting to have that study or those conclusions really until kind of mid-year 2015.

And just to remind you, no production in 2015. That work would probably be done in 2016.

So really that study is still ongoing. It's moving forward and may have a few different solutions.

So we're trying to sort out what we think the best one is. So there wasn't really too much to report on that today, I guess.

Okay. Thank you.

Yeah. This is Ken, Mike's associate.

Given what you guys have been seeing in Hastings, do you think the series style flood will become the new design for all the fields in the Gulf Coast?

I think it's very important to realize that it will be (33:10) a little bit different. And so, to say it's a design for all floods may be a bit extreme because you have to do what's economic and best for each field.

But when you look at the majority of the fields, they do share the same characteristics. And so, that series flood is working in Hastings; also Oyster Bayou we've implemented.

And so, we do envision that being the first option. You'd probably have to have a good reason not do a series flood in other fields.

And there may be cases where that would be the case, but we see broad application of that concept to most of our fields, including fields like Conroe.

Okay. And then, sorry if I missed it, but can you guys speak to the well you guys drilled in the Jackson Dome and how that impacts your future drilling over the area?

Yeah. We drilled that well and unfortunately, the reservoir was smaller than we expected.

And so we don't believe at this time we want to complete it or build a pipeline to it. It doesn't really affect anything in the future, because it was a separate fault and of course, we have plenty of CO2 today with the savings and the utilization and so forth.

So, we actually, probably have bought anyway significant excess volumes based on the productivity capacity of Jackson Dome versus what we're using. But it was a little disappointing.

Do you guys still see 15 to 20 drilling locations at the field?

Yes, definitely.

Okay. Thanks, guys.

I apologize if I missed this, but I was just curious if you had an update on the COO and Senior VP of Op search?

Nothing to announce. We're working it, we've been talking to candidates and so forth.

So, historically we've said it's probably the second half of the year before that happens and I guess it's – it probably will still be the same message.

Thanks, Phil.

Good morning, everyone. Phil, you talked about the blowdown of CO2 from the older fields and then taking it and putting it into newer fields.

I was wondering on the timing of that. Is that something that will happen in the next 18 months or is that more a, I guess, three to five-year plan?

Well, that's a good question. And to be honest, some of that depends on what oil price does.

If Little Creek is still economic, to give you a specific example, we'd probably keep producing oil, but at some point production will decline. And as the economics get close to breakeven then I think you probably convert to more of a blowdown mode.

We're actually working the engineering to determine the optimum rate and so forth. So we're trying to do some of the details of how we do it.

With oil prices coming back up, it actually helps us because Little Creek was kind of that breakeven mode when oil was – a few months ago when oil was in the upper $40s, low $50s.

Okay. And then from the standpoint of cost savings of blowing down CO2 and using that CO2 versus drilling at Jackson Dome well versus man-made sources.

Is the blowdown the cheapest source or is Jackson Dome still the cheapest source?

Yeah. I'd just add some more color to that is that, the ideas and opportunities coming out of the IITs on these mature fields is just that is, we're looking at how we maximize the value of these assets in the end game.

And some of our initial estimates, it shows that the cost of blowing down that CO2, cleaning up and putting it back to system is actually lower than the costs it would take to deliver from Jackson Dome, so you get – at a lower cost plus you get more volume. So, you recycle that CO2 essentially.

But there are several issues. We see opportunities to reduce costs in these mature fields.

So to extent that we can really reduce costs and eke the last value out. We can maybe extend the life of these fields if oil prices are in a reasonable range.

And then, what's the right sequence and timing to go to things like WAG and the blowdown. So, that's a subject of a whole analysis and study.

These are some of the redevelopment plans I talked about as part of the IITs. So this applies to Little Creek and several fields.

We really want to look ahead and see what's the best way to the endgame on these reservoirs to get the most value out.

Great. Thank you so much.

Good morning.

Good morning.

I just wanted to get a feel that since you started to add hedges now that oil has valued a bit. How do you think you'll be implementing incremental new hedges going forward?

Well, it's a sure way to make oil go up is just put some hedges in place. So, it's working.

We're trying kind of do this in kind of a layered fashion. So we haven't gotten too aggressive.

But I think we'll just continue look at it and add a little bit from time to time and we'll probably average out kind of on the hedges. The most recent ones we've been doing, we did a few swaps initially.

Recently, we've been doing more collars with – as Mark indicated, floor of around $55 just to protect against any potential disaster and ceilings are now in the low $70s. But most part, those won't matter going forward unless and of course oil breaks one of those boundaries.

Right. Thanks a lot.

Before you go, let me cover a few housekeeping items. On the conference front, Mark Allen will be giving a presentation at the UBS Oil & Gas Conference in Austin, and Phil will be presenting at the Sanford Bernstein Strategic Decisions Conference in New York.

Both will occur at the end of May. The details for both are available on our website and the webcast for Phil's presentation will be accessible through the Investor Relations section.

Lastly, for your calendars, we plan to report second quarter 2015 results on Wednesday, August 5, and hold our conference call that day at our usual time of 10 AM Central. Thanks again for joining us on the call today.

We look forward to keeping you updated on our progress.