Denbury Inc.

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

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

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

There are numerous factors that could cause actual results to differ materially from what is discussed on today's call. You can read our full disclosure on forward-looking statements and the risk factors associated with our business in the slides accompanying today's presentation, our most recent SEC filings, and today's news release, all of which are posted on our website at denbury.com.

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

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

Thanks, John. I appreciate all of you for joining us today.

Denbury's fourth quarter was a great demonstration of the potential of this unique company, and it feels like we're just getting started. We generated significant free cash flow and lowered our costs, reaching a nine-year low on G&A.

We underspent on capital compared to budget, grew production for the second consecutive quarter, grew reserves, had a successful well with our first significant exploitation investment and improved our balance sheet. And 97% crude oil in our production mix, continued strengthening in the oil market drove our realized price above $55 per BOE.

And crude differentials turned positive, up by about $2 from the third quarter. We are on a path to a significant improvement in our debt metrics with our Q4 annualized EBITDA resulting in a debt to EBITDA ratio of around 4.5 times significantly lower than where we were earlier last year, and we see a path to even further improvement over the next two years in a $60 oil price environment.

Slide 5 highlights our accomplishments in 2017 and our 2018 priorities. You'll note that our high level priorities are the same.

We will continue to build our foundation of execution, seeking to always improve the blocking and tackling of how we do our business. Part of what makes Denbury special is the diverse opportunities that exist in our asset base, and we'll continue to pursue ways to turn that opportunity into tangible value.

Building on the Mission Canyon success, we plan to ramp up our exploitation activities. We also plan to drive incremental value from our surplus CO2 and pipeline capacity in the Gulf Coast, and continue EOR development with the primary focus on reaching an investment decision for the initial flood at Cedar Creek Anticline in the first half of this year.

And we'll continue to drive greater value from our existing fields, something our teams have done very well over the past years. We'll continue to build our financial strength.

We plan to extend our bank credit facility this year and Mark will share more on that later. Our Houston land sale is in progress and we expect to begin to see results as early as the second quarter.

And we'll continue to maintain capital discipline, spending within cash flow, maintaining a high bar on project economics. And before moving off this slide, I'd like to touch on significant compensation changes we're implementing this year.

Many of the changes are both at the executive and full employee base and reflect both my belief in a strong alignment between pay and performance, as well as shareholder feedback that we gathered over the last year. We feel that they better align compensation with company performance and growing shareholder value.

Key elements include a greater focus on project level returns, strengthening of the balance sheet and improving debt metrics, as well as a new long-term incentive award focused on debt adjusted reserve growth per share. We based our 2018 plan on a $55 oil price.

As you see on slide 7, this allows a capital budget of $300 million to $325 million, which will keep us spending within cash flow. The highlighted activities in this budget are continued development at Bell Creek, developing Phase 6 and the best part of that field, a seven-well Tuscaloosa infill project at Delhi, continued EOR development at West Yellow Creek, and a stepped-up exploitation program, where we expect to increase spending to the $30 million to $40 million range.

We're planning to build off our 2017 accomplishments to continue production growth in 2018 as you see on slide 8. 4Q was up about 1% from 3Q 2017, and we expect full year 2018 to be about 3% above 2017 at the midpoint of our guidance.

Looking at the table on the left side of the slide, quarter-on-quarter production increased at Delhi, Hastings and Bell Creek. In 2018, we expect production to increase in most major fields, including: Bell Creek, where we expect a response from the recently completed Phase 5; CCA, where we'll continue Mission Canyon development throughout the year; Delhi, with the Tuscaloosa infill development; and Oyster Bayou from our just completed recycle facility expansion.

Hastings volumes should also increase with a full year benefit of our 2017 redevelopment project. We expect first EOR production from West Yellow Creek early in the year and from Grieve around midyear.

Completing the picture, we'll also have the benefit of a full year's ownership in Salt Creek. The extreme cold weather in the Deep South caused some power outages and impacted our January production, so we started out the year a bit slower than we would've liked.

We anticipate that this downtime, combined with scheduled maintenance at Delhi and Heidelberg, could cause our first quarter production to be slightly lower than our fourth quarter level. But this does not affect our guidance for the full year, which was finalized taking all of this into account.

Operating costs, shown on slide 9, were in line with guidance, coming in in an adjusted $20.53 per barrel for the full year. We benefited from a $7 million CO2 price adjustment in the fourth quarter that reduced our actual full year LOE to $20.35 per barrel.

Along with our focus on improving execution, our operating teams have done a great job of driving ownership of LOE to the field level, and we're seeing the results in terms of high predictability as well as visibility to make LOE-impacting decisions based on economics as market conditions evolve. Looking at 2018, we expect most LOE categories to remain flat with 2017.

Being in different basins for most of the industry and with our core business focused on different activities insulates us from much of the cost inflation we see across the industry. We do see upward cost pressure in two primary categories, the first being power, where utility providers in some of our operating areas have increased their electricity rates; and the second is CO2, where higher oil prices will have a CO2 price impact, but we see that as a good thing as it means our overall business is that much better.

Considering these two elements, we expect per barrel LOE to increase by around $0.50 per barrel from 2017. A key takeaway on LOE is that our improved control and visibility into LOE helps us make conscious economic choices that generate the most value for the company.

Exploitation will be a greater focus in 2018, and slide 10 is an overview of the portfolio. What I'd like you to take away from this slide is the breadth of the portfolio, underscored by the number of opportunities shown as blue circles on the chart on the right.

The scale of the portfolio is significant at 120 million BOE on an unrisked basis and $50 million BOE on a risked basis. And we're adding to that portfolio every day as our teams continue to identify new opportunities across our 600,000 net acre leasehold.

The next three slides will take you through specific near-term exploitation targets. I won't go into deep detail, but I'd like to give you a flavor for the types of opportunities we're currently working.

I mentioned our Mission Canyon success earlier, and I couldn't be more pleased with our first exploitation well here. It was well executed, maintained in a tight horizontal target window, and the production results were strong with an initial 30-day average rate of 1,050 barrels of oil per day.

It was completed open-hole with no stimulation for a total drill and complete cost of $3.6 million. We have running room with this horizon at CCA and currently think that we have around 24 additional locations.

We have a rig drilling the first well on a two-well pad right now and have a total of six Mission Canyon wells planned for 2018. On the Gulf Coast at Tinsley, we plan to drill a well in the Perry Sand starting around the end of the first quarter.

This well targets an unswept, lower perm area of Tinsley with individual well costs between $3 million and $4 million and good running room for additional development. Back up in the Powder River Basin, unconventional development of the Turner, Parkman, Niobrara and Mowry has steadily moved closer to our Hartzog Draw Unit, where we hold deep rights to around 13,000 net acres.

We're planning to drill a well here in the second half of the year to test the prospectivity on our acreage, which is held by Hartzog Draw Unit production and has significant existing infrastructure. One of our key focus areas for the year is improving our financial strengths, and we are taking a deep look at how each of our asset fits in the portfolio.

Last year, we disclosed our intent to sell some Houston area acreage, and this process is progressing well. We expect to begin to see bid results in the second quarter with parcel sales expected to continue throughout 2018.

Separately, we've been taking a hard look at our asset base and a potential for portfolio management opportunities in 2018. I believe it's important to continually evaluate our assets along their lifecycles to determine where best to deploy capital and when to divest certain assets to upgrade the asset base.

With this in mind, we've identified several of our mature oil fields in the Gulf Coast region that we plan to market for sale in the near future. The fields being marketed are those listed in the mature area on slide 8 in the presentation.

And before I hand it over to Mark, I want to emphasize how pleased I am with the performance of our employees. Their grit, creativity and hard work drove our successes in 2017 and will take us to the next level in 2018.

Thank you, Chris, and good morning. My comments today will highlight some of the financial items in our release primarily focusing on the sequential changes from the third quarter.

And I will also provide some forward-looking guidance to help you in updating your financial models. Starting on slide 15, we are extremely pleased with our financial results this quarter, as our continued efforts on cost reductions, efficiency and execution are starting to shine through.

On an adjusted basis, net income was $48 million for the fourth quarter, up from $14 million in the third quarter, with the increase mostly driven by higher revenues. On a GAAP basis, we reported net income of $127 million with the primary differences being a $78 million adjustment for non-cash mark-to-market commodity derivative changes and a one-time deferred tax benefit of $132 million, reflecting the remeasurement of deferred tax assets and liabilities, resulting from the reduction of the corporate federal income tax rate from 35% to 21%.

Turning to slide 16. Our non-GAAP adjusted cash flow from operations, which excludes working capital changes, improved to $134 million for the fourth quarter, nearly doubling from the third quarter, again driven primarily by higher revenues.

Our fourth quarter average realized oil price before hedges was $57 per barrel, a 20% increase from our realized price in the prior quarter. When you include the impact of our hedges, the per barrel realized oil price increase 16% from the prior quarter, as our combined revenues and commodity derivative settlements increased by $46 million.

Slide 17 provides a summary of our oil price differentials, which is our average realized oil prices relative to NYMEX prices. Our old price differential improved by over $2 per barrel from last quarter, which on its own equates to an $11 million uplift in revenues.

Our overall differential of $1.70 above NYMEX prices is the best differential we have realized since the second quarter of 2013. This improvement was generally related to an expanding premium for Light Louisiana Sweet oil, which averaged over $5 per barrel above NYMEX prices in Q4, tracking similarly to the increase in Brent prices.

Approximately two-thirds of our production has an LLS index component included in its price formula. We have also seen our CCA and Rockies price differential improve to the best level since we began operations there in 2010.

On the bottom portion of this slide, you can see the movement in the LLS premium over the last few years and LLS futures basis differentials for the remainder of 2018. As you can see, the LLS premium has pulled back significantly from recent highs and is trending in the positive $2 to $2.50 range.

I will review our hedging positions on our next slide. But as I mentioned on last quarter's call, we previously took advantage of the opportunities to lock in LLS to WTI basis swaps at an average premium above $4 per barrel to the first half of 2018 to capture a portion of this strong premium.

With LLS premium trending down throughout 2018, we expect that our overall oil differential, excluding hedges, will also trend lower. Currently, we anticipate that our overall differential for the first quarter of 2018 will be in the positive $0.75 to $1 range and for the second through fourth quarters, we are currently anticipating our oil differential to be in a range of flat with NYMEX to a positive $0.50.

Slide 18 provides a summary of our old price hedges. Since our last quarter's conference call, we added 2018 hedges covering 10,000 barrels per day of NYMEX and LLS fixed price swaps.

Our hedges now represent approximately 65% to 70% of our currently anticipated 2018 production levels. For 2019, we have begun to layer in a combination of fixed price swaps and three-way collars.

Our initial hedging objectives for 2019 will protect $55 and provide upside exposure to the mid-60s with collars, and protect close to $60 with swaps. We plan to continue to add to our 2019 hedges over the course of the year, depending on market conditions.

Moving to the next slide, I'd like to review some of our expense line items. Starting with G&A, our G&A expense was $21 million for Q4, 25% lower than the third quarter and the lowest quarterly level in nine years.

In the lower right hand portion of this slide, you can see our G&A per BOE, which was $3.64 per BOE in Q4. The lowest level we have had in quite some time.

Our G&A is now beginning to reflect the significant cost reductions implemented in the third quarter. Our net G&A related to stock-based compensation was approximately $3 million this quarter and we currently expect our G&A for 2018 to remain in the lower $20 million range per quarter, with stock-based compensation representing roughly $3 million to $5 million of that amount.

Net interest expense was $23 million this quarter, a slight increase from last quarter due to the additional interest treated as debt resulting from our most recent debt exchange transactions. On the bottom portion of this the slide, you will see there is a more detailed breakout of the components of interest expense.

We currently expect our capitalized interest to be in the $7 million to $8 million range per quarter throughout 2018. Our DD&A expense this quarter was $53 million, a slight increase from the third quarter.

We expect our DD&A expense will be in the $53 million to $56 million range throughout 2018. Our income taxes this quarter were significantly impacted from the Tax Cuts and Jobs Act legislation enacted in December, which, among other things, lowered the federal income tax rate for corporations from 35% to 21%.

Since we are in a net deferred tax liability position, this reduced the company's future tax liabilities, resulting in a $132 million income tax benefit this quarter. For 2018, we expect that our effective tax rate will be close to 25% with little or no cash taxes.

Turning to our 2018 sources and uses on slide 20. As Chris mentioned, we built our 2018 budget around a $55 oil price and we plan to keep our spending within cash flow as we have historically done.

Note that at the top of our – on the top, our $300 million to $325 million of development capital, we estimate approximately $30 million for capitalized interest, which brings our total CapEx range to $330 million to $355 million. As shown on the right hand portion of the slide, we estimate that our 2018 cash flow from operations will be in the $430 million to $480 million range assuming $55 WTI prices, and also assuming $30 million of interest being capitalized.

Due to the accounting for our debt exchanges completed over the last couple of years, roughly $90 million of interest on our debt will be shown in our financial statements as a reduction of debt instead of interest expense. So to give you an accurate reflection of cash available to spend, we have subtracted this amount from our estimated cash flow from operations, bringing our cash flow to an adjusted range of $340 million to $390 million, and giving us excess net cash flow of $10 million to $35 million.

One other thing I'd like to point on this slide is a sensitivity of cash flow to oil prices. Excluding hedges, a $5 change in oil price would impact our cash flow by around $100 million.

Considering our 2018 hedge positions, if prices average $50 for the year, we would only expect a cash flow reduction of $50 million and if prices average $60 for the year, we would expect a gain of $30 million in cash flow. Moving to our balance sheet, pro forma for the debt exchange transaction completed in early January, we had total debt principal of approximately $2.7 billion as of December 31, 2017.

We had $475 million outstanding on our bank credit facility and over $500 million of remaining borrowing base availability. Since the oil price downturn that began in 2014, we have reduced our debt principal by $836 million.

The earliest maturity of our debt is our bank facility which matures in December 2019, and we have started initial conversations with our lead bank regarding the extension of this facility in 2018. Our main priority will be to retain ample liquidity and full access to our $1.050 billion borrowing base.

We believe that our value sustaining asset base and improving debt metrics gives Denbury a much different debt profile than what is reflected in our trailing 12-month leverage metrics. Although our trailing 12-month debt-to-EBITDA ratio is in the 6.5 times range, we see this improving meaningfully throughout 2018 and 2019 assuming oil prices remain in a $55 to $60 price range.

We also see a path for Denbury to approach 3.5 times total leverage, given the $60 oil price environment over the next couple of years and with our existing asset base. Based on our current projections, we expect our outstanding bank debt to come down throughout the year to the $300 million to $400 million range largely due to anticipated proceeds from our Houston area land sales.

And now, I'll turn it back to John for some closing comments.

Thank you, Mark. That concludes our prepared remarks.

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

Hey, good morning, folks.

Morning, Tim.

Morning, Tim.

I got a few here, I guess, I'll start – the Cedar Creek Anticline EOR decision, Chris, you've repeatedly put out first half 2018 event and then the slide deck has language saying that the company's looking to establish a path forward. Given that we're at the end of February, your first half is only four more months.

Can you give any color on kind of where you stand or what you're pursuing, how that possibly could look getting to FID there?

You bet, Tim. So the way I think about CCA, first of all, it's just such a great target that we were upwards of 300 million barrels of potential EOR resource out there, which is well in excess of our total current proved reserve base.

So it's something that you really want to chase after. And what we're doing, even through the downturn we've kept the permitting process, which is really the main time impact on the whole project, we've kept that running through the downturn.

And I think what I feel is heading towards is a confluence of getting the permitting result to a point where we can proceed, and we're feeling pretty good about that in the first part of this year. Getting the technical work and getting that piece done, and every bit of that that I've seen as we've come through the last couple quarters is starting to come to a head with, again, really with this objective of getting that landed in the first half of this year.

And then, the project work and taking into account some of the learnings that we've picked up over the last few years in reducing, optimizing the costs of our facilities and making a fit-for-purpose type of development on the facility side. That's all coming together, very focused on getting that decided the first half of this year.

And then, what I see is that would put us on a position to have the pipe, which is a major single investment, late in 2019, get injection, started in 2020, and then see first production in 2021. So that's the framework that we're seeing there, Tim.

And I think that, at least everything I've seen so far is very positive.

Okay, okay. So are there plans that you may go ahead without really looking for a partner or some kind of third-party capital infusion on the project?

One piece that I didn't mention in my description there is that we are looking at how we fund that and some different options there. Honestly, we prefer not to take the chunky capital of the pipeline in one year.

We have a lot of other very nice projects we'd like to do with that. And so, part of the process that we're working through at the same time is exactly that, is looking at different paths for bringing in some outside capital for doing that.

And as you mentioned, that is a great type of business that I think people are interested and investing in. And so, that's something that will happen along the same time and, to some degree, perhaps even beyond the first half of the year.

But I don't see any risk associated with that.

Okay. Appreciate all the color.

And then, perhaps this is a related topic. You talk about marketing some of your mature assets.

It looks like production a little over 7,000 BOE a day on that, was that a separate decision from possible funding, CCA, or are those kind of – do you see those as integrated decisions?

I see them as separate decisions, Tim, that really, looking at our portfolio, something that we should be doing every quarter, every year and making sure that our portfolio makes the most sense for our priorities and where we want to deploy our capital and, honestly, just our focus. So, they are separate but I do see that at the end of the day there's going to be a question of proceeds from that sale.

What are you going to do with those, and we're very open with where that'd be deployed, whether it's into reducing debt into the assets, and something like CCA or doing something else with it. But that is a possibility, but they were arrived at separately, really just makes sense for us to look at these assets and get our portfolio as optimized as we can.

Okay, okay. If I could switch, this may be a better question for Mark.

4Q 2017, the unit expense profile was very strong. But I can understand that from the prepared comments, you expect LOE to go up about $0.50.

Should we think about that as $0.50 from the full year 2017 average, which gets us closer to kind of a $21 level or is that from the 4Q 2017 kind of level?

I think of it, Tim – this is Chris again – from the full year average. If we see it landing around there, obviously, there's a lot to be gained from continued focus at the field level on what we can do to improve that, and we're continuing to work other paths to improving it.

Honestly, optimizing our portfolio will do that to some degree; growing our production, will do it to another. But to frame that, I think you're right looking at the full year.

Okay, okay. And then, I guess just one final one.

It sounds like the Houston real estate sale, it may not be one package, but it could be multiple packages. So is that something that we should maybe just will get like in little pieces throughout 2018, is that how we should think about that?

So, the way we think about the real estate sale in Houston, Tim, is two distinct parts. First, the area in Conroe there that's – or near The Woodlands, south of the town of Conroe, and that is one main parcel – or one main piece of real estate that's broken up into seven parcels.

And all of those parcels are going out for an RFP on March 1 of this year, so just a couple weeks from now, and we expect to have bids in that by the end of March and see some notional – we expect to get some purchase and sale agreements executed in the second quarter. So, that's something that I think that you'd see something from us in the second quarter.

Then as we move south to Webster, that is multiple different parcels. Just the nature of the real estate there along the frontage road on I-45 going down to Galveston, there are many different nice things we can do with that property, and that will be something that I think that you'll see starting to come in over the course of 2018 and might even be beyond that.

But there's a lot of interest, a lot of good things happening there. Kind of two different things, a big piece in Conroe that we'll see some numbers on in the second quarter, and then the rest of it in Webster that will happen throughout the year here.

Okay, okay. I'll hop back in the queue.

Thank you.

Thanks, Tim.

Hi, good morning. This is actually Kevin Kwan calling in for Tarek.

Thanks for taking my question.

Sure.

Just on Mission Canyon, I understand it's slightly on early stages but just wanted to gauge expectations and sort of any change in geology for your two additional wells kind of to the north and south of your initial pilot well there. Any other detail would be helpful?

So, Kevin, we'd say about Mission Canyon. First of all, it's early days.

So we have one well that's been producing for really less than two months now. Certainly we're pleased with what we've seen.

We want to get more time with the well that we've drilled. We want to get more wells drilled and get some production history behind there.

If you look at the math that we provided for the Mission Canyon area that we're drilling right now, as I mentioned, we've already spudded the second well on that same structure. And we really don't see anything different that we expect in the next two wells in terms of where we are geologically and what we're looking for, it's more of just testing the same concept and the same accumulation and establishing some production history.

As we move outside of the Pennel/Coral Creek area, which is where these first wells will be, then there are some different ideas that we're going to be testing. But again, all of it's just generally the same concept with this fairly narrow interval of Mission Canyon that's very productive and we have some good running room across the CCA area with it.

Okay. That's quite helpful.

And I assume that a lot of the other – the remaining – the 24 locations that you have, that's for the remaining sort of Cabin Creek area and Little Beaver is kind of in the other regions or are they...

Exactly. Kevin, if you look across the inset map we have there, we have the initial wells in the Pennel/Coral area, and then we have those red ovals highlighting some other opportunities that we see in our leasehold that are outside of those fields.

Okay. Got it.

And on slide 7, too, you kind of – I'm just hoping back to your capital plan. I just want to see the cadence of your capital projects throughout the year.

I know you list quite a few tertiary and non-tertiary ones there. I am just trying to see how lumpy it might be towards the end of the year, et cetera.

Just off the top of my head, I don't think that there's any particular jump or drop in capital as we go through the course of the year. The exploitation piece is working now and will continue.

The Bell Creek Phase 6 piece is working now and will continue throughout the year. So, I see it being fairly flat as we move across the year.

Okay. That's fair.

And then, along those same lines, the mature area field that you mentioned that you're looking at marketing, just want to get any detail on those particular assets in the sense of what interest has looked like, I know again, it's probably early days as well, but just trying to get a gauge on how soon that might happen.

So, that's something that – we don't want to share too much of our thinking around that. We can share why we're making this move, but our expectations and so on, we want to let the process work.

But it is something that we expect to kick off fairly soon here and we'll see that out in the public within the next few days actually, looking to close it by the end of second quarter.

Okay, that's helpful. Now last one too is just quickly on the revolver, just wanted to see what your expectations on potential refinancing might be, given your improvement in the reserve base.

Yeah. This is this Mark, yeah, as I mentioned, we're starting to work with our lead bank, JPMorgan, and the bank group, in terms of extending that out.

We think there is numerous possibilities. And I think the one thing that really – and I said it before – that differentiates us is just our assets and our sustaining value.

Yes, our leverage metrics have been higher than we would like and we're starting to see those move here in the right direction, with cost reductions in prices, which is I think one very positive sign. And I think over the last few years, our bank group has continued to work with us quite well, and we're confident in how we're going to move forward here.

Okay, appreciate the comments.

Yes, good morning, Chris, to you and your whole team there.

Hey, Charles.

Good morning.

I apologize for asking again about this Mission Canyon well. But I guess when you make 1,000 barrel a day well for whatever, $3.6 million, people want to know more about it.

I'm curious if you can talk about what kind of decline profile you're seeing, and you expect to see in this well. When I just look at your current EUR and the rate, the way those two fit together make it seem like it's a pretty high decline well.

But I wanted to just test that because we've gotten to the point where we've answered the question about – or maybe addressed the question of how repeatable it is, but also how good is this. So, can you talk about what you're seeing in two months of decline on this?

You bet. So what I say, Charles, is that, first of all, that the EUR that you have seen – that we've disclosed publicly was a pre-drill expectation, so there's going to be some adjustment to that as we go.

I still would say its early days on how this behaves. But if you think about just the nature of putting a long lateral in a pretty thin reservoir, we'd expect it to behave, honestly, more like an unconventional well where you have some fairly high initial decline rates.

We're going to keep watching that. We're not at a point where we have enough of a track record out here with it to really talk in too much detail.

But what I would say, look at it to be along the lines of what you'd expect more in the unconventional side with the benefit of these wells being that we are completing them open-hole without a frac and the cost associated with that.

Got it. That's helpful.

That's helpful insight, Chris. Thank you.

And then, if I could ask also about – if you could talk a bit more about the exploitation you're doing at Tinsley in this Perry Sand. Did I hear you right that this was one of the traditional field pays that's maybe under CO2 flood in different parts of the field, and are you guys planning on going at this with a big frac or what's your plan of attack?

Yeah. And so, what's interesting about that and it even applies back to the Mission Canyon, Charles, is that certain of these reservoirs, when we produce them on primary, when that's complete, they set themselves up very nicely for CO2.

And that's the case with Mission Canyon, and that'll be the same for Perry. With the Perry, it's an area of the Tinsley Field that we don't have perm for traditional vertical wells to really do a great job of sweeping with EOR, so we have a lot of residual oil left in that horizon.

And that's why we're going to attack this one with horizontals again. We are going to have to put a bit of a frac into these, we think, to get the rates that we want.

So it will be a little different, although just if you kind of balance the whole nature of that field and the depth of the reservoirs, our well costs are going to be in the same ballpark as what you saw with Mission Canyon.

Got it. Thank you, Chris.

Thanks, Charles.

Thanks. Good morning.

Good morning, Richard.

Just a couple of questions to you, Chris. Going back to the potential sale of the mature properties, it sounds like if you're expecting possibly to have some news in the second quarter.

Things, I guess, are moving along. Is this more of a package to one party or would you expect to break it up?

Have you received inbound interest on this that kind of started things off?

There's definitely some interest in it, Richard. When we look at how the package is set up, it's actually in two separate packages that are more geographically aligned.

We think there's interest, but it's something that I don't see going to nine different sellers, but we would like to keep it in those two packages. But like with all of these processes, you kind of need to see what the interest is and how that shapes out.

Not that you borrow much against your borrowing base, but what would the expected impact be to the basin and to reserves if you were to sell the whole package with the associated roughly 7,000 barrels a day?

Yeah. Richard, this is Mark.

Yeah, we'll need to work through that with the banks. It could be at a level that we'll need to get their permission, but it's kind of marginal at that point.

Okay, okay. And, Mark, I know you also talked about potentially moving the leverage ratio down into the 3.5 times level over a period of years.

What leverage do you have to pull at this point? Beyond, say, oil price-related, what's up next?

Yeah. Well, I think we've done a lot of things over the last couple years.

Obviously, we've hit on cost reductions. We've done some exchanges utilizing our capital structure and the flexibility that it has provided.

I think we still have some flexibility remaining there. We have some new instruments in the last exchanges in the form of converts, which could provide some optionality.

And we'd like to see those convert here at some point. But we still think what really drives our ability forward here is obviously we're doing a lot of great things on the operations side, we have some new projects.

But more than that, it's just really getting back to the sustaining nature of our reserves and the fact that our reserve base is very desirable; it doesn't deplete rapidly over time. And so, when people look at that from an investment standpoint, they appreciate that and it has totally different profile.

So all those things combined, I'd say, still give us a lot of flexibility and ways to think about continuing to improve our balance sheet over time, Richard.

Thanks, Mark. That's helpful.

And just lastly from me, did you provide a range of expected proceeds for Houston land sale or maybe ask another way, have you had an appraisal done on the properties – or that you could share with us?

When we rolled this out, Richard, last year, we talked about it covering off basically our Salt Creek acquisition, which is in the low $70 million range. And I would say since that point in time, we've obviously continued to expand our thinking, and, yes, we're working with the brokers who are marketing this and have some values in mind.

And so, we're very cautious to get into much beyond what we've said, but we continue to become more encouraged over time in terms of what that could be.

Okay. Thanks a bunch.

Appreciate it.

All right. Thanks, Richard.

Hi. Just a couple of quickie follow-ups from me.

Can you disclose what the P&A liabilities would be on those mature assets?

Yeah. At this point, I don't think we want to get into too much of the specifics around that.

As we go forward and we get to talk about potential sale or get bids and stuff, then we'll give more clarity around that.

Okay. It's worth a shot, I guess.

And then, a second, you've talked a lot about Bell Creek Phase 5 expansion and Phase 6 coming in this year. From a modeling point of view, how should we think about kind of at what level and kind of when we could see sort of production peaks in that field?

I mean, what assumptions you all have for 2018 baked in kind of the corporate production guidance.

So, Tim I'll take that. First thing I'd say about Bell Creek, and you might have noticed that on our production table, is that without the contribution from Phase 5, we still reached a new EOR record in the fourth quarter there.

And our teams have just done a superb job of working through the Phases 1 through 4 and optimizing our production there, did some creative nice work to continue to grow production from the initial phases. Then Phase 5, we expect to start to see the response, we actually have it completed, as I mentioned, and we're injecting and we have the initial response, which is essentially water production that's very strong.

It looks good to us, we're optimistic about how it's going to respond with oil. We expect to see that midyear, not really ready to talk about the volumes that we expect.

But I think that what you've seen in our overall guide represents probably a conservative view of what we think about that. And then then, of course, Phase 6 we're falling right beyond Phase 5, so that'll be executed through the course of this year with a response expected in 2019.

So I think, our peak on Bell Creek is still a few years aways here.

Okay. So, 2019 will be the year we could the potential step change increase?

Yeah. I think you'll see a step change that will begin in 2018 with the Phase 5 response, and that will continue on with the Phase 6 in 2019.

Thanks for the clarity.

Thanks, Tim.

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

On the conference front, we will be attending the JPMorgan High Yield Conference [Global High Yield & Leveraged Finance Conference] in Miami on Monday, February 26. The presentation for the conference will be accessible through the Investor Relations section of our website at a later date.

Finally, for your calendars, we currently plan to report our first quarter 2018 results on Tuesday, May 8, and hold our conference call that day at 10:00 AM Central. Thanks again for joining us on today's call.