Denbury Inc.

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

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

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

There are numerous factors that could cause actual events 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 this presentation, our most recent SEC filings and today's news release, all of which are posted to our website at denbury.com.

Also, please note that during the course of today's call, we will reference certain non-GAAP measures. Reconciliation and disclosure relative to these measures are provided in today's news release as well as on our website.

With that, I will turn the call over to Phil.

Thank you, John. Good morning, everyone.

Welcome to our first quarter earnings call. Even though oil prices have improved somewhat, we are not letting ourselves be deterred from our 2016 goals by assuming all that's good and that there is no longer any risk of lower prices.

We acknowledge we don't know where oil prices are going and, therefore, we remain focused on our mission. That mission and our core goals for 2016 are to reduce costs, optimize our business, reduce debt, and to do all that while maintaining our liquidity.

I'm very pleased to report that we are making significant process on all these goals and definitely headed in the right direction. On the cost side, our normalized per-BOE LOE came down for the ninth consecutive quarter to $16.23 per BOE, a 16% decrease sequentially and a six-year low in our LOE per barrel.

This substantial decrease from the prior quarter is well below analyst estimates and couldn't have come at a better time as our average unhedged oil price this quarter was just over $30 a barrel. These savings are largely due to continued cost reduction efforts across almost all categories for LOE, coupled with cost savings attributable to shutting in or postponing repairs to uneconomic wells.

I know you're wondering if we can maintain the LOE at that level, and I admit it will be difficult as a significant portion of the reduced costs relate to lower workover expenses. We do anticipate more repair and workover activity later this year with the higher oil prices, and we also anticipate gradual decline in our production throughout the year, both of which make it unlikely we can maintain that $16.23 per BOE rate.

However, we are confident we can keep it lower than originally anticipated, and we are continuing our ongoing focus at reducing cost. When you couple our reduced costs with the industry-leading percentage of 95% crude oil production, and that's compared to natural gas or liquids, our field-level cash flow per barrel becomes very competitive with our peers, creating a picture that is quite different than the high-cost label we are sometimes painted with.

Chris will give you more details on operating costs in a few minutes, but our lower LOE cost is definitely one of the highlights this quarter. To further reduce costs, this quarter we reduced our workforce by about 20%.

This is not apparent when you look at the quarterly G&A numbers, as this quarter includes over $9 million of severance-related cost associated with this reduction and a reduction occurred in late February, which means you really only have about one month of savings. However, you should see lower G&A expense next quarter.

Our efforts are also ongoing with regard to business optimization, as we continue our field-by-field development planning seeking optimization opportunities as well as continuing our improvements in day-to-day operations. While some of this work may not be evident until we begin to spend more development capital dollars, you can see the progress we are making in maintaining production, lowering CO2 usage, lowering cost and so forth.

Denbury's operations are being transformed, and optimization is a key focus for our business this year. As we stated on the fourth quarter call, we do want to reduce debt, as we do not expect oil prices to return to the same levels we enjoyed a couple of years ago.

Therefore, it's encumbered on us to adjust our business as needed in order to remain competitive. One way to accomplish this is to take advantage of the market discount on our subordinated debt, although we also realize that we must do so without sacrificing our liquidity, as that is our lifeline in case oil prices were to remain low.

In February, we amended our bank credit facility modifying our bank covenants, which should allow us to meet the revised covenants at current commodity prices. In order to provide additional assurance that we can do so and protect our liquidity, we recently entered into more hedges and are now at least 50% hedged through the second quarter of 2017.

These hedges aren't at blockbuster oil prices, but they are above our cash breakeven and, therefore, help minimize the use of our bank credit line for day-to-day operations if oil prices were to decline. Mark will give you more details on those in a few minutes.

We've also taken steps to reduce our debt in two different ways. First, we borrowed about $56 million on our bank credit facility to repurchase over 152 million of our outstanding senior subordinated notes in the open market.

That resulted in a net debt reduction of just under $100 million. These repurchases were aggregated over all three of our senior notes and allowed us to take out the debt at an average price of about $0.36 on the dollar.

Those are obviously very accretive transactions, but not a program that we could substantially expand, as we simply don't have sufficient bank liquidity to do it in a more meaningful way and also have a limit on the bank covenants. So it required us to look at other options.

This week we entered into private transactions with a small group of debt holders, swapping a new second lien note plus equity for their sub debt. Mark will give you the details, but the net result of these swaps, plus the cash purchases of debt referred to earlier, is a total debt reduction of almost $500 million or 15% of our total debt as of last year end, and also will provide a net reduction in annual cash interest expense of approximately $6 million.

This is a significant positive series of transactions that improves our balance sheet and also provides incremental value to our shareholders. Most importantly, we did this without sacrificing our liquidity.

Based on our recent borrowing base redetermination, we still have almost $700 million of liquidity, and we also have just under $500 million of junior lien capacity available under our bank agreement for potential future use depending on market conditions. Since we expect to hold our spending at or near anticipated cash flow levels for the foreseeable future, this bank liquidity should be more than sufficient to meet our needs.

So I trust that you can see our business is continuing to improve. We are driving our costs down.

We are optimizing both current and future EOR floods. We've reduced our debt by almost $500 million this year, coupled with the reduction in debt last year, and we still have close to $700 million of liquidity.

Further, due to the nature of our assets, we are not facing double-digit decline rates as we reduce our spending. We've cut our spending over 80% from 2014 levels and still anticipate a very modest 4% to 8% production decline this year excluding any wells that may be shut in due to economics.

I'll reiterate a point I made on our last conference call. This is not a distressed company, but rather a company that is improving, working tirelessly to improve our business and demonstrating that we can compete effectively in our lower oil price environment.

So with that, I will turn it over to Mark to provide you additional financial details.

Thanks, Phil. My comments today will summarize some of the notable financial items in our release, where I'll primarily be focusing on the sequential changes from the fourth quarter.

I will also provide some forward-looking guidance to help you in updating your financial models to reflect our current outlook. Starting on slide nine, our non-GAAP adjusted net loss for the first quarter was $9 million or $0.03 per diluted share.

As you can see from our GAAP reconciliation, in Q1 we had a $256 million ceiling test impairment as the trailing 12-month oil price continued its downward trend. This quarter's write-down was significantly less than the $1.3 billion we recorded in the prior quarter.

Based on recent oil price levels, we expect that we could record an additional write-down next quarter, possibly in excess of $400 million, as we anticipate this year's second quarter prices will be lower than those in the second quarter of 2015, which would bring down the average price for the last 12 months. Also during the first quarter, we repurchased 152 million of our senior subordinated notes in the open market for approximately $56 million, which resulted in a $95 million pre-tax gain on debt extinguishment.

This gain was offset by a $95 million pre-tax non-cash mark-to-market adjustment on our derivative contracts, primarily related to contracts that settled during the quarter. On a GAAP basis, we had a net loss of $185 million for the quarter.

Turning to slide 10, our non-GAAP adjusted cash flow from operations, which excludes working capital changes, was $57 million for Q1, down $72 million from the fourth quarter, which was primarily due to a $10 per barrel lower oil price realization this quarter. I want to point out that this number is not adjusted for special items during the quarter, so you should add back the $9 million in severance cost to get to a normalized number of around $66 million.

We have working capital outflows this quarter of $55 million primarily associated with normal first quarter ad valorem tax payments, bond interest payments and scheduled vesting and payout of accrued compensation amounts in the first quarter. Our first quarter average realized oil price, excluding hedges, declined to slightly less than $31 per barrel, down 24% from Q4.

We've recognized $72 million in cash receipts on settlements from our hedges this quarter, which made our average per barrel realized price, including hedges, approximately $43 per barrel compared to approximately $53 per barrel last quarter, or a decline of about 20%. Slide 11 provides a summary of our realized oil price differentials relative to NYMEX oil prices.

Our overall realized oil price averaged $3 per barrel below NYMEX in Q1, down approximately $1.25 per barrel from our NYMEX differential in Q4. Differentials weakened for our Gulf Coast tertiary production this quarter, averaging roughly $1 per barrel below our NYMEX differential in Q4.

For Q1, we saw LLS prices trade at a lower premium to NYMEX, which was the primary reason for the weaker differential. In the Rocky Mountain region, our Cedar Creek Anticline oil differential in Q1 weakened by $1.75 per barrel compared to our Q4 differential.

Based on differentials we have seen thus far in the second quarter, we currently expect that our overall oil differentials should remain in a similar range to Q1. Moving on to the next slide, I'd like to review some of our expense line items.

First, our LOE came in down $26 million or 20% from Q4. Chris will go into more detail on this and our expectations for the rest of the year, but this is a great accomplishment for Denbury.

G&A expense was $34 million for Q1. However, after adjusting for $9 million of severance costs in Q1, G&A would be a couple million lower than the $27 million expense for Q4.

We currently expect that G&A should remain in the mid-$20 million range, meaning between $20 million and $30 million, each quarter for the remainder of the year. For the first quarter, net G&A related to stock-based compensation was less than $1 million, which is lower than historical levels, due primarily to reductions in estimated payouts for performance-based equity awards and the fact that we have moved our significant portion of the company's annual equity grants to midyear this year instead of early in the year.

We expect our stock-based compensation number to increase to between $4 million to $6 million in Q2 and in subsequent quarters. Interest expense, net of amounts capitalized, was $42 million, up slightly from Q4 due to lower capitalized interest and a write-off of deferred financing costs of approximately $1 million.

Capitalized interest in Q1 was just under $6 million, and we currently expect capitalized interest to average approximately $6 million to $7 million per quarter for the remainder of the year. Our DD&A expense was significantly lower this quarter, due primarily to the full cost ceiling impairments recorded in 2015.

With the additional impairment this quarter, we expect our DD&A expense will be in the $70 million to $75 million range in the second quarter of 2016, and potentially lower in future quarters based on an anticipated full cost ceiling write-down in Q2. Our effective income tax rate for the first quarter was below our estimated statutory tax rate of 38%, due primarily to the true up for stock-based compensation awards that vested in the first quarter for which the actual deduction for those awards upon vesting was less than the financial reporting expense recognized over time.

This item is new this quarter and is related to a new accounting standard that we adopted in Q1. The impact of this new standard means that we will likely have more volatility in our tax rate going forward, as these differences between financial reporting and tax reporting now impact our tax expense instead of equity, where they were recognized previously.

For 2016, we expect our effective tax rate will be around 38% with less than $10 million of current tax. On slide 13, we have our current summary of oil price hedges.

We are around 50% hedged or more on our oil production for the remainder of 2016 and first half of 2017. We may continue to add to these positions over time.

Please note that some of our contracts for the second quarter of 2016 have sold puts, which caps the benefit we can achieve under those contracts. Moving on to the next slide, let me move on to our capital structure and the movements from 12/31.

In the first quarter, you can see the impact of our 152 million of open market sub debt repurchases with $56 million in cash. The next column reflects other activity in Q1, including an additional increase to the bank credit facility balance of $79 million, which I will cover in more detail in a minute.

The last adjustment column reflects the recent private exchange transactions we have entered into and plan to close next week. In these transactions, we have holders exchange an approximately $923 million of existing sub debt for approximately $531 million of new 9% second lien notes and 36.9 million shares of Denbury common stock.

As a result of this transaction, we expect to reduce our debt by $391 million. And when you combine that with the cash purchases in the first quarter, our total debt reduction totals approximately $488 million.

Although cash interest savings on the exchange transactions are not significant, when combined with our cash repurchases, we anticipate annualized cash interest savings of approximately $6 million. We currently expect that we will not incur significant cash taxes due to the cancellation of debt income created by these transactions, but it could create a small amount of cash taxes for us in 2016.

On slide 15, I want to walk through the increase in our bank borrowings under our credit facility since 12/31. As you can see, we ended 2015 with $175 million drawn on the facility.

And in the first quarter 2016, our incurred capital expenditures and cash flows were essentially equal. As such, the primary drivers for the increase in our bank debt relates to our sub debt repurchases, the change in working capital associated with those items I discussed earlier in my comments, and lastly cash outflows for payments on our financing leases.

Based on our current projections, we would anticipate our bank debt ending the year in a range of $275 million to $300 million. Lastly, with the amendments to our bank credit facility in the last year, I thought it might be helpful to summarize some of our more pertinent information related to our facility.

As previously announced, we recently completed our borrowing base redetermination which set our borrowing base and commitment level from our banks at $1.05 billion. In addition, we amended the facility to provide for up to $1 billion of junior lien debt capacity, which may be used for purchase, refinance or to replace the company's existing senior subordinated notes or other unsecured indebtedness with up to $300 million of the proceeds that are usable for general corporate purposes and other purposes, not otherwise prohibited under the credit agreement.

We have also included in here our financial covenants for the next several years. Our bank line is our primary source of excess liquidity.

And as of March 31, we had around $680 million of liquidity available under our bank line, with $310 million drawn and $59 million in letters of credit outstanding. And now I'll turn it over to Chris for an update on operations.

Thank you, Mark. The first quarter of 2016 was exceptional for Denbury's operations.

First, we set a new standard for safety performance in the quarter with zero OSHA recordable incidents for both Denbury employees and our contractors, the first time this has been achieved in our history. At the same time, we drove LOE down to $16.23 per BOE, a low we've not seen since early 2010.

We kept production right on track with our plan, even as we significantly reduced our LOE and capital. And finally, we continued to focus on improving the fundamentals of our business, putting the right plans and processes in place to drive Denbury's continued success.

Starting with a closer look at LOE, I could not be more pleased with the work that our teams have done to reduce costs. Costs are down in each category compared to the fourth quarter of 2015.

Overall, LOE is down $26 million from the prior quarter. On a per BOE basis, LOE was $16.23, down over $3 per BOE or 16%.

CO2 costs per BOE are down $0.73 per BOE or 27%, split between a reduction in our CO2 injected volumes and reduced workover expense. With the low oil prices in Q1, we shut in an additional 1,100 BOE per day, over half of which was related to required repairs that were not economic at Q1 oil prices.

The wells that we shut in contributed to lower workover costs and reduced our ongoing LOE by an estimated $0.25 per BOE to $0.50 per BOE. Workover costs reached their lowest levels in many years, down 44% or $0.94 per BOE, a result of our continued focus on failure reduction, combined with shutting in wells that were uneconomic to repair at Q1 prices.

We anticipate that workover activity will increase somewhat if oil prices continue to improve and we bring production back online. Most of the other reductions are the result of ongoing cost savings measures, including a 20% staff reduction in February, which will have more of an impact on next quarter's results.

Turning to slide 19, our work on CO2 efficiency continues to be a great story as we've continued to find ways to make sure we are getting the most value from our CO2. Our total CO2 injected volumes for the quarter were reduced to 634 million cubic feet per day, compared to nearly 1 billion cubic feet per day in the first quarter of 2015, and 705 million cubic feet per day in the fourth quarter of 2015.

We believe these reductions are sustainable, as we carefully monitor production response to CO2 injection rates, and adjust quickly if we see an unexpected response. The good reservoir properties we have in most of our fields allow us to quickly observe the effects of these adjustments without creating a long-term production or reservoir impact.

This high CO2 efficiency does more for us than reduce LOE and improve field economics; it extends the life of our strategic low-cost CO2 assets, reducing our investment level and, ultimately, allowing us to take on more development with the same CO2 resource. Production for the quarter was in line with our expectations of 69,350 BOE per day, about 4% below the fourth quarter of 2015.

The quarter-to-quarter decrease was primarily due to natural declines in most fields based on our current investment level, plus 1,100 BOE per day shut-in due to economics, as oil prices reached new lows in the quarter. These declines were partially offset by improved production at Tinsley and Bell Creek, up a combined 591 barrels per day from the last quarter.

Production was essentially flat quarter-on-quarter at CCA, Delhi and Hastings. After adjusting for production shut-in for economics, our sequential quarter decline would be just 2% and our decline from the year-ago quarter just 3%, underscoring the unique low-decline nature of our portfolio.

Next, I'd like to go into a bit more detail about the production we have shut in for economics. In total, we have of about 2,800 barrels per day shut in consisting of 1,100 BOE per day that is uneconomic to produce and 1,700 BOE per day that is uneconomic to repair.

We have looked at threshold costs for bringing this production back on, and about one-half of the shut-in production is profitable at $50 oil, increasing to about two-thirds at $60 oil, with the remainder at prices above $60. We currently expect to start bringing this production back online later this year, assuming prices remain stable, at or above the current level.

Moving to more recent events, in mid-April, a series of strong thunderstorms in the Houston area affected two Denbury fields, causing damage to a primary tank battery in Conroe Field and flooding at Thompson Field. We currently have about 2,000 barrels per day shut in and are working to restore full production in both fields.

We expect to have most of the shut-in production back online by the end of May, and we estimate the combined production impact to be about 300 barrels per day for the full year. I'll wrap up by touching briefly on the development side, where our most significant ongoing project is the NGL plant at Delhi.

This plant serves three main purposes. First, it will strip NGLs from our gas stream, so they can be sold separately.

Second, it'll improve the effectiveness of our Delhi flood with a purer CO2 recycle stream. And third, methane recovered will be used to generate power, part of which will be used to offset the field's electricity purchases, reducing our overall power costs.

This plant is on schedule and on budget with major equipment installation ongoing in the field now and should come online by year end. That completes the operations update.

And I'll now turn it back over to John.

Thank you, Chris. That concludes our prepared remarks.

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

Good morning, folks. Thank you for taking my call.

I've got a few quick ones here. I guess, Phil, you talked about the new hedges coming in above your cash breakeven costs.

And I was curious, kind of how do you define that and kind of what's the number that you think about as cash breakeven.

Well, it's simple I guess, it's adding up all the costs other than replacement costs and looking at what it is on a cash basis. Although minor, it also excludes things like stock compensation and so forth.

Based on first quarter, we think that number is pretty close to – it's probably just over $30 a barrel would be our total cash costs.

Okay. So you have interest expense in there?

Yes.

Okay, okay. Then I guess my next question for Chris, when we talked about LOE a quarter ago or a couple quarters ago, folks were kind of – you all were hesitant to go below the $20 line, given how much you had executed in 2015.

You seem to be kind of conservative here. But what was the big change in this one quarter?

Is it just that kind of your work you were able to fully implement it? I mean it's such a big change from 4Q 2015.

I guess what made it to be so dramatic in the first quarter?

What I'd say Tim is a few things. One is I don't think that there's a single big change that made that difference.

I think that if you look at what the team is doing, focusing on every single aspect of our business and driving the cost down everywhere possible that we're just seeing greater results there. Of course, the places where we have the best bang for the buck are absolutely in CO2 use, and driving that down almost 400 million BOE a day versus a year or so ago is a big cost improvement.

And we've continued to see changes there even in this quarter. Second, there is an impact.

As Phil mentioned, there is an impact of shutting in some production. And the LOE that's associated with production that was uneconomic to produce is going to drive us down a bit.

And then we do have reduced workover activity as we're selecting not to repair those wells that failed during the quarter. But I'd say it's a combined impact which – supplemented by that workover piece.

Okay, okay. I guess my last one I'll direct at Mark.

You exchange I guess the $531 million of the senior secured second lien in exchange. Was that a targeted amount?

Did you just kind of end up at that level? I guess I'm just curious kind of how you size this deal and how you think about kind of your remaining capacity there?

Well, we were dealing with a small group of holders, so there's certain limitations we have to work within. So that was kind of what we were dealing with.

I think once we get these closed, we'll just assess market conditions and evaluate our options going forward.

Okay. Thank you.

Good morning, guys.

Good morning.

Just curious around the shut-in production. Obviously especially, I guess, the uneconomic to repair, if we do get so lucky to get up to those type of prices, do you have a ballpark estimate of what that would cost to get that stuff up and running again?

Sure, Jason. This is Chris.

That's something, obviously, we're looking at very carefully. And as we're looking at the oil price behavior in the year, there's still quite a bit of volatility.

But as we get more confidence in where that oil price is going to be stable, we're going to be looking at bringing that production back on. And the first tranche of that is what we call the uneconomic to produce.

And if you'd recall, being down in the $30 range, we have wells that were simply shut in because they were uneconomic to produce, those can be brought on basically at nominal cost, just having somebody go out and put them back on, turn the pump back on and so on. And then the uneconomic to repair, it scales, but basically you're looking at broad repairs, different types of repairs that are fairly low cost, just expenses we chose not to incur in the low price environment.

Okay. And maybe, Mark, if I could ask again on the news this week, on the share issuances, is there going to be any lock-up on those?

Are those going to be pretty much free to trade once the deal is consummated? Just looking for color on that side of it.

No extended lock-up, I mean there are some restrictions depending on how long holders may have held their bonds and such, but otherwise no significant restrictions.

Okay. I appreciate it.

I'll turn it back.

Yeah, hi. Just another follow-up on the exchange here.

Wondering if the private holders that you did the exchange with, if there was more capacity to do additional exchanges, would that be something you'd be interested in. And did you think at all about opening up the exchange more broadly to other investors?

Well, I think as Mark mentioned, we're going to try to get this closed and then we'll reevaluate market conditions. So we'll just have to see where we go after that.

I think the issue with doing a broader deal was the market kind of keeps moving on a fairly rapid pace and is kind of volatile. So it's difficult to do something that sits out there for 20 days or 10 days just because of market volatility.

So we concluded that it was better just to enter into private negotiations with a few holders.

Okay. That's great.

Thank you. And then on the bond repurchases that you made, I think you still do have some incremental remaining capacity, although you talked about obviously being conscientious about liquidity as well.

Is that something that you're still looking at or, with the recent rally in prices, is that off the table at this point?

Well, I mean I think we're continuing to look at our options to reduce debt and that is one of them. You know that market price is a big factor on that, and we don't have a lot of availability left under our bank line, I guess I think about $170 million under that covenant.

But we're also very conscious of protecting liquidity. So we just have to – I think it's hard to answer.

We probably haven't reached our goal reduction to date, but on the other hand we just have to evaluate it day by day depending on what the market offers us.

Okay, that's helpful. Thank you.

Thanks. Chris, question on the CO2 efficiencies.

Can you talk about what, if any, impact that might have on reserves in the fields? And also, how does it make you think about this business going forward in terms of CO2 requirements and the kind of capital that's required from an infrastructure standpoint as you reevaluate the economics of new plays?

You bet, Jeff. And I think you hit on every one of the key points of what these CO2 efficiencies do for us.

Number one, because they're such a big piece of our cost structure, when we can drive that much out of the cost structure, then the economics of our fields, the life span of our fields get that much longer. So that brings more reserves into the picture.

The second part of that, that you touched on, is that not using as much CO2, even though Jackson Dome, for example, is a huge reservoir, nearly 6 TCF now, it's still finite. And we will consume it with our business.

And the more efficiently we can use it, the longer that lasts, the more we can blend it in with man-made CO2 and still maintain a strategic advantage in our business and last longer. So just really every way we look at it, these CO2 efficiencies help us in our current cost and what the future looks like.

I assume almost all of this is from the Gulf Coast. Is what you are doing transferable, if you look at the Rocky Mountain business in the future?

Jeff, it's absolutely transferable. It's a way of doing business.

And just really as we look at our business and our costs and the fact that our CO2 resources is finite, I guess I'd say we've been more brave with how we look at experimenting with CO2 and making – very careful with the placement of the CO2, making sure we're getting bang for the buck where we're putting it. And that's something we can do in the Gulf Coast.

That's something we can do in Montana and North Dakota.

Okay. Thank you.

Hi. Good morning.

Morning.

Good morning, Gary.

Just a couple of questions on production and capital, and there's a lot of moving parts, it sounds like, with shut-in production and declines. Can you just give us a sense for how we should think about fourth quarter production, either average run rate or an exit?

And then I guess the second part is what level of capital would keep that production flat in 2017 and 2018?

Let me try that one. We don't usually give guidance by quarter.

We did give the range and I think the midpoint was right at 66,000. And we actually expect it to be a fairly steady change each quarter.

In other words, it's not a big quarter that jumps up or falls off. It is relatively steady, kind of, throughout the year.

Maybe very late in the year actually we'll get a little bump with the Delhi NGL plant that comes on, but that won't impact totals very much, but you may get a little bump right at year-end. So I don't know, I'd kind of just forecast it kind of on a steady line averages somewhere in that midpoint or plus or minus with the ranges.

As far as capital to hold production flat, I think we're still working on optimization and so forth. So I don't know that I have a conclusive number.

I think you can look back at last year and say we held it flat or very close to flat, if you take out kind of that uneconomic stuff spending about $400 million. We think we're continuing to improve and drive down costs as you can see.

So I think the number is something less than $400 million. I don't know if I know precisely what that number is.

Okay. That's very helpful.

And then just second question if I may. Maybe this is for Mark.

Mark, what's your expectation for the fall borrowing base redetermination given current oil prices?

Well, the redetermination we just went through was pretty severe. We just, you know, on the tail of the first quarter where prices obviously hit their lows, I would say a lot of the banks' price decks started in the low $30s per BOE, and some capped out around $50 per BOE or maybe slightly above that.

So obviously, the near-term strip has moved up a fair bit, which is helpful. So I do think the banks will continue to be pretty conservative, though, relative to strip and they're probably not going to obviously be outpacing strip.

So I think it's moved up a little bit from where valuations occurred in the first quarter. But obviously we'll just have to see what happens, because they do continue to move their price decks around pretty frequently.

Okay. And given the hedge roll-off, would you expect a neutral outcome in the fall, all else equal, given the increase in oil prices and then the roll-off in hedge value?

Yeah. I think today I wouldn't see a significant downward movement.

So I don't have any real concern about where we're at today and necessarily holding that in the current environment. Again, a lot of this is subject to where the banks are at and where they move to.

So I can't say definitively, but I feel pretty good about where we sit right now.

Okay. That's all I had.

Thank you.

Before you go, let me cover a few housekeeping items. On the conference front, Phil Rykhoek will be attending the UBS Global Oil and Gas Conference in Austin, Texas, the week of May 23rd.

Further details of the conference and the webcast for Phil's presentation will be accessible through the Investor Relations section of our website at a later date. Finally, for your calendars, we currently plan to report second quarter 2016 results on Thursday, August 4, and hold our conference call that day at 10:00 a.m.

Central. Thanks again for joining us on today's call.

We look forward to keeping you updated on our progress.