Denbury Resources (DNR) Q4 2016 Results - Earnings Call Transcript

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Denbury Resources, Inc. (NYSE:DNR) Q4 2016 Earnings Call February 23, 2017 11:00 AM ET

Executives

John Mayer - Denbury Resources, Inc.

Philip M. Rykhoek - Denbury Resources, Inc.

Mark C. Allen - Denbury Resources, Inc.

Christian S. Kendall - Denbury Resources, Inc.

Analysts

Timothy A. Rezvan - Mizuho Securities USA, Inc.

Tarek Hamid - JPMorgan Securities LLC

Richard Merlin Tullis - Capital One Securities, Inc.

Maryana Romanivna Kushnir - Nomura Corporate Research & Asset Management, Inc.

Jeffrey Robertson - Barclays Capital, Inc.

Jacob Gomolinski-Ekel - Morgan Stanley

Operator

Ladies and gentlemen, thank you for standing by. Welcome to the Denbury Resources Fourth Quarter 2016 Results Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Instructions will be given at that time. As a reminder, this conference is being recorded.

I'd now like to turn the conference over to John Mayer with Denbury's Investor Relations Group. Please go ahead.

John Mayer - Denbury Resources, Inc.

Thank you, Linda. 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 President and Chief Operating 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 Phil.

Philip M. Rykhoek - Denbury Resources, Inc.

Thank you, John. Good morning, everyone, and welcome to our fourth quarter and year-end call. Since our last call, oil prices have risen and shown some stability in the $50 to $55 per barrel range. Prices at these levels, obviously, allow for more development opportunities than in the past year; and it appears the overall industry is doing just that as the rig count continues to increase.

It will be interesting to see what happens to the industry service cost in this better environment, although, since we are in a unique part of the industry, we don't anticipate much of an impact on us. Just as we didn't benefit as much from vendor discounts as the rest of the industry, as prices decreased, we believe our inflationary pressures will be less severe than most if overall industry costs increase.

Before we move into 2017, I'd like to briefly focus on our 2016 results where we demonstrated outstanding execution on our core goals. The downturn in prices, in which oil prices fell to as low as $26 per barrel last February, was one of the longest we've seen, but it also enabled us to take an in-depth look at our properties, improve our processes and procedures, and find ways to make Denbury a stronger and more efficient company.

As we discussed last year, our 2016 focus was on a few core goals, including reducing costs, optimizing our business, reducing our debt and preserving cash and liquidity. Starting with costs, we reduced our full-year cash cost by over $2 a barrel or about 7% from last year and about $9 a barrel or 21% since 2014. To put this in the absolute dollar terms, we saved almost $135 million in lease operating expenses and G&A in 2016 as compared to 2015, a significant reduction and outstanding accomplishment.

Moving forward, we feel many of these cost reductions can be sustained, giving us ability to develop our high-quality assets without the added burden of significant cost inflation as oil prices improve. Although perhaps a little more difficult to see on a day-to-day basis, our capital costs have also been optimized.

For example, the next phase of Bell Creek, which is scheduled for 2017, was expected to cost almost twice as much in our prior forecast. As another example, we believe we can hold production relatively flat with our Q4 exit rate spending about $300 million per year, a significant reduction from the $450 million to $500 million just a couple years ago.

These capital cost optimizations will take more time to show up in the financial statements, but I believe they will become evident as we begin to spend more capital dollars. We were also able to create additional value in 2016 by reducing and optimizing our CO2 usage. We divested certain non-core assets that didn't fit into our core asset profile. Took advantage of joint venture opportunities to accelerate development with our corresponding capital requirements, I'm referring to Grieve Field. And we constructed a new NGL plant which enhances our EOR flood at Delhi. Our continued progress in these areas have put us in a favorable position for the future.

Reducing our debt, while at the same time preserving liquidity, has also been a top priority. Through year-end, our total debt balance was reduced by over $0.5 billion compared to year-end 2015, while still maintaining nearly $675 million of liquidity on our bank line. And we also have the potential to issue another roughly $385 million on our junior lien debt. These reductions were accomplished by taking advantage of otherwise unfavorable market conditions and seizing opportunities during periods of excess market volatility.

As we've previously discussed, we would like to further reduce our debt, although we don't see it as a pressing matter due to our long-dated maturities and low interest rates. Since our bonds have continued to hold at substantially higher trading levels than when we completed our debt reduction transactions, it has made further debt reductions more difficult to be accretive (6:00). However, we will continue to monitor and evaluate market conditions and seek to improve our leverage when it makes business sense to do so.

In summary, we have sufficient liquidity, low bank debt, long-dated maturities on our outstanding debt, making our balance sheet very manageable even though the debt-to-EBITDA multiple is a little higher than we would like.

So now let's take a look at 2017. We recently released our preliminary 2017 development capital budget of $300 million. This is nearly a 50% increase over 2016 spending with the majority of this capital directed toward continued development of our existing tertiary floods. As I mentioned on our prior call, we have an ample supply of projects in our existing portfolio with strong projected rates of return at the current strip prices. And for the 2017 projects, all of these development projects have strong rates of return at $50 oil.

In addition to the tertiary capital, a smaller portion of our planned spending will be dedicated to conventional development at our non-tertiary properties, including Cedar Creek Anticline, as well as deploying a subset of this capital to exploitation opportunities.

As we've discussed, last fall, we decided to increase our focus on exploitation opportunities around our existing fields, as we believe there were potential opportunities perhaps being overlooked. While that effort is still in its infancy, we've allocated $15 million to $20 million in our 2017 budget for this program, and we would expect funding for these projects to grow in subsequent years.

With this capital spending level and our improved efficiencies, we believe we can hold our 2017 annual production roughly flat with our 2016 exit rate of just under 60,000 barrels per day or a range of between 58,000 barrels to 62,000 barrels per day, which will put us on a trajectory to resume modest production in 2018.

We anticipate growth in 2018 for a couple of reasons. One, some of the projects, such as Bell Creek Phase 5 that we started in 2017, will not bear fruit until 2018. But secondly, we have $60 million to $70 million of negative hedges in 2017 at the current strip price, which means that we can spend that much more in 2018 even if the oil prices remain flat.

So what we're presenting to you is our base plan. And while a significant improvement over the last couple years, we, as senior management, are working diligently to improve upon this plan in order to accelerate or increase the growth plan. So you might ask what are we looking for. Well, one would be continued optimization of cost efficiencies, as even though we've shown a lot of improvement, there are probably additional efficiencies to be gained.

Second, we would love to do a properly financed acquisition as that would provide growth, additional cash flow, could potentially be de-levering depending on financing, and also would likely add to our portfolio of development projects. We're looking for conventional oil plays, preferably in one of our two core areas. But if large enough, we might consider expanding to other places.

We are encouraged to see others in the industry disposing of these assets to raise funds to develop their expensive acreage, and therefore we anticipate additional conventional assets may appear in the marketplace. As such, we are actively increasing our M&A efforts, as` this is our first priority. And while encouraged, of course, these results are nearly impossible to forecast.

Additionally, we are considering more joint ventures where we could leverage our CO2 or other assets and expertise to gain interest in otherwise unavailable oil fields. This potential opportunity is greatly enhanced because of the significant efficiencies achieved during the last two years with our usage of CO2.

Lastly, we might also consider raising additional funds, which would enable us to outspend cash flow without reducing our liquidity. Any of these could be a significant catalyst to our growth profile and a great supplement to the base plan that we've outlined for you today.

And with that, I will turn it over to Mark to go over the financial details.

Mark C. Allen - Denbury Resources, Inc.

Thanks, Phil. My comments today will summarize some of the notable financial items in our fourth quarter release, where I'll primarily be focusing on the sequential changes from the third quarter. I'll also provide some forward-looking guidance to help you in updating your financial models.

Starting on slide eight, on a GAAP basis, we recorded a net loss of $386 million for the fourth quarter. But after excluding special items, our non-GAAP adjusted net loss for the fourth quarter was $7 million. The special items impacting this quarter before tax impacts were $591 million accelerated appreciation charge and a $5 million non-cash fair value gain on our oil hedges.

I will provide more color regarding the accelerated appreciation charge in a moment, but, overall, the primary drivers for the decline in adjusted income from the third quarter were a $26 million increase in cash payments on oil hedge settlements, partially offset by a $21 million increase in oil revenue due to an increase of realized prices.

Turning to slide nine, our non-GAAP adjusted cash flow from operations, which excludes working capital changes, was $53 million for Q4, down $9 million from the third quarter due to the same factors impacting the change in our adjusted net income.

Our fourth quarter average realized oil price, excluding hedges, was $48 per barrel, an 11% increase when compared to realized prices in the third quarter. We paid out $33 million on hedge settlements this quarter, which made our average realized price including hedges around $42 per barrel, consistent with Q3.

Slide 10 provides a summary of our realized oil price differentials relative to NYMEX oil prices. Our overall realized oil price differential improved slightly from Q3, primarily due to the strengthening of our Rocky Mountain region pricing. As we have noted on previous calls, our Rockies pricing has continued to improve over the last couple of years as more transportation capacity has moved into the region. We believe the improvement in our Rockies pricing is associated to some degree with increased demand to fill new pipelines, so some of this improvement could be temporary.

We currently expect that our overall oil differential for the first quarter of 2017 should remain in the minus $1.50 to $2 per barrel range, most likely weakening somewhat from Q4 due to the addition of NGL volumes coming from the new liquids processing plant at Delhi and anticipated weaker LLS prices in Q1.

Moving to the next slide, I'd like to review some of our expense line items. First, LOE was $106 million for Q4, consistent with the prior quarter and in line with the guidance we provided last quarter. Chris will go into more detail on our LOE, but we currently expect that it could be slightly higher in the first quarter of 2017, as we anticipate some incremental expense with bringing the new Delhi plant online and some anticipated higher repair and workover costs in Q1.

G&A expense was $29 million for Q4, consistent with our guidance and up slightly from $25 million in the third quarter due primarily to an increase in our employee bonus accrual. For Q4, net G&A related to stock compensation was approximately $5 million. We currently expect our G&A to remain consistent or slightly higher in the first quarter of 2017, with stock-based compensation of roughly $5 million to $7 million. Recall that our first quarter G&A tends to be slightly higher due to long-term incentive payouts during that quarter.

Net interest expense was $22 million for Q4, a $3 million decrease from the prior quarter. As you can see from the detail provided in the lower portion of this slide, our total cash interest amount also decreased by $3 million. However, due to the accounting for our debt exchange that occurred in the second quarter of 2016, almost all of the interest on our 9% second lien notes is recorded as debt on our balance sheet. And, therefore, only $1.3 million of the $13.8 million of actual quarterly interest on the notes is included as interest expense in our financial statements.

Capitalized interest in Q4 was just over $7 million, and we currently expect capitalized interest to decrease to approximately $20 million in 2017 or $4 million to $5 million per quarter throughout the year.

Our DD&A expense in Q4 was $647 million, which includes an accelerated depreciation charge of $591 million associated with the Riley Ridge gas processing facility and related assets. Our press release provides a good summary of the issues and current status of the Riley Ridge processing plant, but essentially we have determined that current projected costs to remedy the issues and successfully operate the gas processing facility are not commercially reasonable investments based on current information.

This resulted in a reassessment of the estimated useful life of these assets and recognition of the accelerated depreciation charge. We plan to continue engineering work and analysis to determine if there are alternative options to remediate the issues. However, the timing of completion and results of such analysis are currently uncertain.

Furthermore, while Riley Ridge is a potential source of CO2 for flooding fields in the Rocky Mountain region, we have formed alternative plans to develop our future CO2 EOR floods in the Rockies region, for which we believe the CO2 volumes could be supplied through existing CO2 sources.

Excluding the accelerated depreciation charge, our DD&A expense in Q4 was $56 million, relatively flat with the prior quarter. We currently expect that our DD&A expense will be in the $50 million to $60 million range in the first quarter of 2017.

Our effective income tax rates for Q4 and full-year 2016 were a benefit of 35% and 36% respectively, slightly below our estimated statutory rate of 38% due to stock compensation and state tax impacts. For 2017, we currently anticipate our effective tax rate will be around 38% with little or no current taxes.

Slide 12 details the current summary of our oil price hedges. Since our last quarterly call, we've added more collar structures, primarily in the third and fourth quarters of 2017 with floor prices around $40 and upside price limits around $70 per barrel. We have approximately 40% of our currently estimated oil production hedged for 2017, with two-thirds of those contracts being swaps and one-third being collars.

Based on current strip prices, our swap positions in the first and second quarters will have a negative impact on our cash flows during each of those periods, currently estimated around $30 million or so each quarter. We will likely add to our hedge positions to protect a large percentage of our anticipated future cash flows, depending on market conditions, most likely using collar structures.

Moving on to our capital structure, our total debt principal was approximately $2.8 billion at year-end, down $530 million from year-end 2015 and down nearly $800 million from year-end 2014. We had $301 million outstanding on our bank credit facility at the end of 2016, in line with our expectations and leaving us with nearly $675 million in available liquidity under the facility. In addition, we have $385 million of additional Senior Secured Second Lien Notes that we could issue under our $1 billion basket permitted by the facility.

The scheduled maturities of our second lien debt and senior subordinated debt are from 2021 through 2023, placing no immediate pressure to refinance any of this debt. The next scheduled redetermination of our bank line will be in May 2017. And since the bank's price deck seem to be holding steady or slightly improving from those used in the fall redetermination, we currently do not anticipate any change in our bank borrowing base.

As Phil mentioned, our debt-to-EBITDA ratio is higher than we would like, and on a trailing 12-month basis was in the mid-6 range based on an oil price average of around $45 for 2016 including hedges. For every $10 change in oil prices, our cash flow to EBITDA improves by around $200 million.

We plan to continue to pursue options to improve our balance sheet and debt metrics and proactively manage our bank line so that we maintain adequate liquidity. We believe our asset base provides us the unique advantage so that our PV-10 Value does not erode even though we have significantly curtailed spending over the last couple of years, which has also allowed us to keep the amount drawn on our bank line relatively low as compared to our borrowing base.

For 2017, we've set our capital budget at $300 million, which is very close to our anticipated cash flow at recent oil price futures. And if you adjust for the $50 million of interest payments in 2017, that will be treated as a reduction of debt instead of interest expense. For purposes of matching up cash flow with spending, we treat this interest as reducing our cash flow from operations. Then, it will be treated differently for accounting purposes.

In addition to the $300 million of development capital, we currently anticipate 2017 capitalized interest to be around $20 million, and other payments on capital leases to be around $30 million. So after considering these items, we currently expect that our bank debt to trend up slightly from the year-end 2016, although our total debt should not move much based on our projected sources and uses of cash flow from operations in 2017.

And now, I'll turn it over to Chris for an update on operations.

Christian S. Kendall - Denbury Resources, Inc.

Thank you, Mark, and good morning, everyone. I'm very pleased with the operations team's accomplishments in 2016. Over the course of just one year, we carved $116 million out of our annual operating cost structure; and I expect the majority of these reductions will be retained, even in a higher oil price environment. We completed optimized plans to develop our assets, and we will see the results of this work as we begin to implement these plans in 2017.

We maintained a sharp focus on CO2, reducing our use by 44% from early 2015 and enhancing our capability of further leverage this strategic resource. We assembled a dedicated team with the priority to identify, evaluate and test additional exploitation opportunities across our nearly 600,000 net acre leasehold position. And to close out the year, we successfully completed the construction and startup of our Delhi NGL plant.

Operating results in the fourth quarter were in line with our expectations, including LOE and continuing production, which were both flat compared to the third quarter. 2017 will be an important year as our expanded capital program should halt production declines and set us on a trajectory for production growth in late 2017 and into 2018.

Our production breakdown is shown on slide 15. Total company production for the fourth quarter averaged 60,685 BOE per day, which, as I noted previously, is in line with our expectations and flat with continuing production compared to the third quarter.

A full quarter of production from Thompson and Conroe fields, following weather downtime in the second and third quarters, as well as production increases in our Delhi, Oyster Bayou and Bell Creek fields, combine to offset natural declines in other fields and the impact of higher-than-expected winter weather downtime at Cedar Creek Anticline.

Delhi production reached a multi-year high of 4,387 barrels per day, as our reservoir management focus continued to drive strong results in that field. And Bell Creek reached its highest EOR production level yet of 3,269 barrels per day, as we continue to see a positive response from our 2015 Phase 4 development.

Total production for 2016, which includes roughly 1,000 BOE per day from divested assets, averaged just over 64,000 BOE per day. And, as Phil mentioned, we expect 2017 production to average between 58,000 and 62,000 BOE per day.

Production in the second half of 2017 should be somewhat higher than in the first half, as certain capital investments we are making early in 2017 will begin to show results later in the year and should put us on a trajectory to resume production growth as we enter 2018.

Operating costs are shown on slide 16. LOE for the fourth quarter totaled $106 million, roughly flat with the third quarter. On a per BOE basis, total normalized LOE of $18.98 per BOE was $0.75 above the third quarter. 2016 full-year normalized LOE per BOE was $17.56, more than $2 below 2015, driven by reductions across nearly all LOE categories.

We expect unit LOE to increase somewhat in 2017, mainly due to the combination of lower production volumes, stepped up workover activity in this improved oil price environment and an expected higher percentage of industrial source CO2 in our supply basket, but we still anticipate LOE remaining at or below $20 per BOE for the full year.

Through the course of the past two years, our teams have found innovative new ways to remove costs from our operating structure, and I'm confident these efforts will continue to yield results even in a higher oil price environment.

As we've previously highlighted, although we have generally higher unit operating costs than our peers due to the nature of our business, our unique 96% oil-weighted asset base delivers a highly competitive operating margin relative to our peer group that includes the larger unconventional operators; and we expect this to continue to improve as oil prices recover.

For example, compared to the third quarter of 2016, our operating margin per BOE in Q4 increased by $4.40 to nearly $23, almost identical to the increase in our realized price per BOE, excluding hedging settlements.

Key CO2 trends are shown on slide 17. CO2 use during the fourth quarter of 2016 was in line with our expectations, above the lows achieved during the second and third quarters, but still well below levels from prior years. Our full-year 2016 CO2 use was over 250 million cubic feet per day below full-year 2015, accounting for about $20 million of our year-on-year LOE savings. In 2017, we expect our CO2 use to be somewhat higher, mainly due to incremental demand associated with new development projects in some of our existing floods that I'll review shortly.

While we've not yet begun taking CO2 from Mississippi Power's Kemper County power plant, we expect deliveries to begin in the first half of 2017, as the commissioning of plant's carbon capture facilities is completed. Once fully operational, we expect the Kemper County facility to provide a reliable supply of CO2 to our Mississippi and other Gulf Coast EOR operations. And we anticipate that it will ultimately deliver around 160 million cubic feet per day within the next several years.

Moving to our 2017 capital program on slide 18, you'll see that our development capital budget has increased to $300 million from actual spending of $209 million in 2016. And we've assembled a strong lineup of projects that should put our production on an upward trajectory in late 2017, enabling us to return to production growth in 2018. Most of these projects are enhancements or expansions of existing floods, and all have high returns with an average IRR above 50% at current futures prices.

In the Hastings Field, we're redeveloping Fault Block B/C into a dedicated injector to producer configuration, which will improve CO2 sweep efficiency and accelerate production. This work is already well underway with completion expected around midyear and production impact expected in the second half of 2017.

We've also kicked off Phase 5 expansion at Bell Creek. As an example of how we're optimizing our developments, Phase 5's design is different than previous phases, targeting only the highest quality reservoir on a larger pattern spacing than phases 1 through 4. With this new design, we expect improved capital efficiency and value compared to previous phases. Work here will be completed in 2017, with the bulk of the production impact expected in 2018.

In Wyoming, we'll continue to progress our Grieve joint venture, injecting pre-production CO2, designing and constructing facilities, and completing well work with the first EOR production expected in mid-2018.

Along the Gulf Coast, at Heidelberg, we plan to continue development and reconfigure several portions of the Christmas interval. At Delhi, we have an infill development planned for several Tuscaloosa sand intervals that should improve oil recovery by improving our CO2 sweep efficiency. We should see a production impact from these projects in 2018 as well.

Finally, during 2017, we plan to test some of our significant identified exploitation opportunities in both the Gulf Coast and Rocky Mountain regions. These opportunities include testing new portions of existing and producing reservoirs, as well as exploring deeper targets on our existing acreage.

That completes the operations update, and I'll turn it back over to John.

John Mayer - Denbury Resources, Inc.

Thank you, Chris. That concludes our prepared remarks. Linda, can you please open the call up for questions?

Question-and-Answer Session

Operator

All right. We do have a question from the line of Tim Rezvan with Mizuho. Please go ahead.

Timothy A. Rezvan - Mizuho Securities USA, Inc.

Hi. Good morning, folks. Thanks for taking my question. Phil, I was hoping you could kind of expand a bit – I know you probably won't – but on some of the M&A discussion you gave. Because you've been in public forums recently talking about the interest for some type of, I guess, growth catalyst or your conventional oil play. Has there been stable oil prices that's kind of driven that opportunity, or are you starting to knock on doors more? I guess, can you add any color to the status of your search?

Philip M. Rykhoek - Denbury Resources, Inc.

Well, probably a little bit of both. I mean, oil prices have kind of stabilized. That helps, because it helps with forecasting value and things. But also we've kind of stepped up our M&A activities in our group. We're seeing a few more properties come on the market. But we see that as a great way to potentially really, really transform the company and really accelerate our growth. And so, we're pushing it pretty hard.

Timothy A. Rezvan - Mizuho Securities USA, Inc.

Okay, okay. I appreciate that. And then, one other question. You don't have this in today's slide deck, but in the past you've shown the Rockies footprint with proposed pipelines that you'd like to build. And in the most recent iteration, the cost of some of these pipelines have come down; and I know it's due to kind of reconfiguration within the last couple of years. But should we read anything into that, that that would make you kind of incrementally more excited to kind of initiate these projects? Or is that just you just trying to reflect current costs?

Christian S. Kendall - Denbury Resources, Inc.

Hey, Tim. This is Chris. I'll answer that question. Certainly, we've been working on the development of CCA, and you did pick up on some of the changes that we've made in that particular slide where we've looked hard at how we develop it. And even in line with some of our discussion around Riley Ridge and some potential alternate sources of CO2, our existing sources of CO2, we found a way to develop that field with lower volumes than we've got before with our existing sources.

And then, along with that, we've looked at all kinds of ways to optimize that development. And you picked up on the reduced pipeline link from Bell Creek up to CCA, which is saving capital there. And we've also looked at a smaller diameter pipe, still more than adequate for the CO2 we need to get up there, but again something that represents cost savings. So I'd say we are incrementally more excited. We're going to continue to push ahead with plans and permitting to develop that field.

Timothy A. Rezvan - Mizuho Securities USA, Inc.

Okay. And then, I guess, lastly, I noticed the cost didn't change in the Gulf. Is that something you just don't see that – the same opportunities?

Christian S. Kendall - Denbury Resources, Inc.

What I'd say, Tim, is we're working through all of the different costs and deals. And so, what's more likely is that we just haven't dialed in that cost for that piece of new pipe.

Timothy A. Rezvan - Mizuho Securities USA, Inc.

Okay. Appreciate the color. Thank you.

Philip M. Rykhoek - Denbury Resources, Inc.

Thanks, Tim.

Operator

All right. Thank you. And next from Tarek Hamid, JPMorgan. Please go ahead.

Tarek Hamid - JPMorgan Securities LLC

Good morning. It's Tarek. On the 2017 production guidance, can you just sort of let us know kind of what assumptions you're making on sort of shut-ins and reversals of shut-ins, and that number? Just sort of any context will be helpful.

Christian S. Kendall - Denbury Resources, Inc.

Good morning, Tarek. And, right now, what I'd say is we're looking at the prices that we've entered the year at which are still in this low-50s, which really doesn't put us into a position where we'd be putting any of that shut-in production back on. We're close, but not quite there. So the assumption is in the budget is that we don't have any of that coming back on.

Tarek Hamid - JPMorgan Securities LLC

Got it. And then, just sort of you touched on a little bit, but maybe just any sort of more color to help us think about the cadence of production through the first half and into the second half would be helpful?

Christian S. Kendall - Denbury Resources, Inc.

What I'd say, and I mentioned it a bit in my prepared comments, Tarek, we expect production to be increasing through the course of the year. So I would expect that we should see the highest production in the third and fourth quarters as we bring some of these developments on.

Tarek Hamid - JPMorgan Securities LLC

And then, just last one from me. Given just the move off of SEC pricing, many of your competitors have been providing an updated PV-10 at strip. Do you guys have sort of a similar number prepared that you're willing to share?

Philip M. Rykhoek - Denbury Resources, Inc.

Well, we haven't done that. What we have said that, in really rough numbers at least within small movements, is about a $1 billion add for every $10 change in oil price. Obviously, the more you change it, the less relevant that becomes.

Tarek Hamid - JPMorgan Securities LLC

But at least, initially, that's a good way to think about it?

Philip M. Rykhoek - Denbury Resources, Inc.

That's a good way to think about it, yeah.

Tarek Hamid - JPMorgan Securities LLC

Got it. Thank you very much. I'll get back in the queue.

Operator

Thank you. And next from the line of Richard Tullis, Capital One Securities. Please go ahead.

Richard Merlin Tullis - Capital One Securities, Inc.

A couple of quick questions. Chris, if we could go back to the planned 2017 non-tertiary spending and dive into that a little bit more. Just looking for a little bit more detail around timing of wells, how many would you expect to drill, and the targets that you would be going after with the exploitation opportunities that you see there?

Christian S. Kendall - Denbury Resources, Inc.

You bet, Richard. And so, what I'd say first just to specifically address the exploitation side, that we're not yet ready to talk about any specific targets that we'd go after. There's some work that we need to do and then need to keep that under wraps for a bit. But we'll share that as soon as we can. And really a lot of the remaining work that we'll do on the non-tertiary side and over the course of the year, a lot of that is facilities-related and including some – getting back into some of our existing wells. But the exploitation piece, we're going to need to hold off on that until later in the year.

Richard Merlin Tullis - Capital One Securities, Inc.

Okay. That's fair. And then, Phil, just following up a little bit more on the prior comments. In general, what geographic areas would be your preferred areas of expansion if you were to proceed with some sort of acquisition?

Philip M. Rykhoek - Denbury Resources, Inc.

Sure. Well, I'll try to put a little more color, although obviously, as Tim suggested, it's a little hard to answer some of these questions. So Utopia, I guess, would be an oil field along our CO2 pipeline that we could flood with the CO2 someday, and one that still has a little bit of cash flow. Obviously, there aren't many of those. So I think the next priority would probably be these conventional oil assets in one of our two regions. And as I mentioned in the prepared remarks, we'd consider going to another region if we thought it was sizable and made sense to expand.

Those oil assets don't have to be future EOR floods. It's great if they are. That's still, obviously, our core business. But we also feel like we're pretty good at just exploitation and waterfloods, et cetera, on conventional oil assets. Like I said, that'd kind of be the priority. We'd love to have some cash flow with it. We'd like to have some development opportunities with it. And I think as far as financing, the goal would be that it would not hurt our leverage and hopefully improve our leverage with the way we finance it and the mix of debt and equity. Does that help?

Richard Merlin Tullis - Capital One Securities, Inc.

Yeah. It does, Phil. Thank you. And that's all from me. I appreciate it.

Operator

Thank you. And next from the line of Maryana Kushnir, Nomura Asset Management. Please go ahead.

Maryana Romanivna Kushnir - Nomura Corporate Research & Asset Management, Inc.

Hi. I just wanted to clarify a few things that you mentioned. I guess, you mentioned that CapEx would be aligned with cash flow, so suggesting cash flow neutrality. But also you mentioned that revolver borrowings might be going up by the end of 2017. So could you clarify that?

Mark C. Allen - Denbury Resources, Inc.

This is Mark. When you look at $300 million spent, and we look at our – what we anticipate to be in our cash flow, they're pretty neutral based on recent prices here. Now, the nuance that I was talking about with regard to the $15 million of interest, when that flows through our accounting cash flow next year, it won't flow through as interest; it'll flow through as debt repayments. And, in fact, cash flow from operations is that much higher.

But when we look at the neutrality of the cash flow from operations versus what we're spending on CapEx, we back that out as – we back interest payment out as though it were interest expense. And then, on top of the $300 million, the things that we count for a little bit different or we have to take into consideration would be about $20 million of capitalized interest. And then, there's about $30 million of financing lease or capital lease payments that are cash outflows. So when you consider that, overall, our net debt doesn't move much, but you could see a little bit of increase in our revolver borrowings. So does that help explain that? It's really the $50 million kind of nuance with the interest...

Maryana Romanivna Kushnir - Nomura Corporate Research & Asset Management, Inc.

Capitalized lease and capitalized interest, right?

Mark C. Allen - Denbury Resources, Inc.

Right, yeah.

Maryana Romanivna Kushnir - Nomura Corporate Research & Asset Management, Inc.

Okay. All right. Okay. I think I understand that. And then, also in your prepared remarks you mentioned that you might also raise additional funds if you see that you can accelerate growth, accelerate spending. And if you see that opportunity, what would be the form of those funds? Would that be debt, or equity, or a combination?

Philip M. Rykhoek - Denbury Resources, Inc.

Well, I think we're very conscious about increasing our debt, and so we'd be very careful with doing that. I think if you're talking minor amounts of money, we might consider it because we have quite a bit of liquidity on our bank line and also the Second Lien capacity. And I guess it's hard to define what's significant, but if it would be significant I think it had to be some sort of equity.

Maryana Romanivna Kushnir - Nomura Corporate Research & Asset Management, Inc.

Okay. Thank you.

Operator

We do have a question from the line of Jeff Robertson with Barclays. Please go ahead.

Jeffrey Robertson - Barclays Capital, Inc.

Thanks. Good morning. Phil or Chris, it sounds like part of the strategic idea of looking at other opportunities is made possible by the re-engineering you all have done at some of your existing floods over the last couple years where you reduced CO2 requirements without having a what seems like a decremental impact to production. Is that transferrable to other EOR areas, like the Permian, do you think, based on things you've looked at in the past?

Philip M. Rykhoek - Denbury Resources, Inc.

Well, the reason it works for us in Gulf Coast or the Rockies, particularly Gulf Coast, we're long CO2 and we reduced the usage so much. Just to give color, historically, we were a little hesitant to enter into JVs because our CO2 was somewhat limited or at least in capacity in pipelines and so forth. And, today, with the nearly 50% reduction, we're pretty long on CO2. So we see that as a potential tool to let us buy into or get into fields that maybe we couldn't have gotten into before and maybe the current operator weren't (41:35) sell us the field, but they'll do a JV; we provide CO2. So that's the color on that.

If you try to translate that to the Permian, the issue is, of course, we don't have any CO2 in the Permian. So it'd be hard to leverage that. I guess if someone had the right opportunity and so forth, we could always look at it. But the advantage in the Gulf Coast and the Rockies is we have a significant source of CO2 in both places.

Jeffrey Robertson - Barclays Capital, Inc.

And just on LOE, I think you all said, or Mark you said, around $20 a barrel this year. As you looked out into 2018 and where you think production will start to grow again, do you think it still stays around $20, or do you start to see some pressure with some of those new projects coming in?

Christian S. Kendall - Denbury Resources, Inc.

Jeff, this is Chris. And what I'd say is that we would like to keep it below that level, and actually production growth I think is going to help us in that way. We're trying to kind of hedge our bet a little bit there. Because as you get into a potentially better oil price environment, then some more projects make sense and doing some more things that might edge that up a little bit make sense. But certainly, what I see, just looking at the competitive environment, we'd really like to see our LOE stay below that level.

Jeffrey Robertson - Barclays Capital, Inc.

Okay. I guess last question, Phil. Along the lines of Denbury is (43:07) always like to have control of the CO2, are there opportunities that you see in other parts of the country where you could get control of CO2 related to an EOR project?

Philip M. Rykhoek - Denbury Resources, Inc.

Well, because you said other parts of the country, I think that's difficult. I mean, the other obviously most logical place would be the Permian and that's controlled really by a couple people, for the most part. So I think that's probably difficult. And so, we kind of have two of the three kind of core areas and, as I said, have a pretty good supply and control the bulk of it. But I think it'd be a little tough to control it on the Permian unless somebody is willing to sell. So we'd probably have to kind of work through it with contracts and other things, like everybody else.

Jeffrey Robertson - Barclays Capital, Inc.

Okay. Thank you.

Operator

Next, we'll go to the line of Jacob Gomolinski with Morgan Stanley. Please go ahead.

Jacob Gomolinski-Ekel - Morgan Stanley

Hey, guys. You mentioned you'd like to reduce debt and were planning to pursue a couple options to manage the overall levels of debt and improve the leverage ratio. Just wanted to see if you might be able to provide any additional color on some of the options you're considering.

Philip M. Rykhoek - Denbury Resources, Inc.

Sure. Well, as you know, we continually watch how the debt is trading. And if that were to slip a little bit, then I think that'd provide an opportunity maybe to pick it up at a discount, which in effect is what we did with the exchanges or the open market purchases. With it trading in the 80s and some of it near 90, that makes that a little tough, because it's just hard to be accretive and make a real dent when it's trading pretty close to par.

I think we'll just continue to watch it. If there is some other exchange or some other instrument that we kind of get creative with or use a portable instrument or equity or something, I think we'd consider that. That is obviously on our list and we're watching it very closely, but we don't feel like it's a pressing issue. And so, we've tried to kind of outline that in the prepared remarks. And we'd probably actually prefer to be looking at acquisitions or something like that as a way to de-lever, rather than just trying to issue equity to buy back debt. But I think we'd look at all the different options and figure all the alternatives.

Jacob Gomolinski-Ekel - Morgan Stanley

Got it. That's very helpful. Thank you. Just on the M&A front then, you mentioned that – I guess, you talked about if you were to raise additional funds for CapEx. You gave some color there earlier in Q&A. But in terms of M&A, just want to confirm, I mean I think it sounds like it'd be equity funded of some sort, but just want to confirm what you envision financing to look like for some transaction?

Philip M. Rykhoek - Denbury Resources, Inc.

Well, I think I may have mentioned. I think the real guideline is it would – not want it to be -- make our leverage worse. In other words, we'd like it to at least be equal or better. So how far you go along that spectrum remains to be seen. But, again, we're very conscious of the leverage. So which means that if you buy something of substance, there would be some equity with it and see how it fits with our program, see how accretive it is.

We also are very conscious, of course, of making that accretive for the equity owners. And so, it's hard to answer that in a vacuum, but I think we'd definitely look at that. And any significant acquisition would probably need some equity with it because of the leverage where we're at.

Jacob Gomolinski-Ekel - Morgan Stanley

All right. That's it for me. Thank you very much.

Operator

And there are no further questions. I'll turn it back to you for any closing remarks.

John Mayer - Denbury Resources, Inc.

Thank you, Linda. Before you go, let me cover a few housekeeping items. On the conference front, Mark Allen will be attending the JPMorgan High Yield Conference in Miami on Monday, February 27. The details for this conference and the webcast for the related 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 first quarter 2017 results on Thursday, May 4th, and hold our conference call at 10:00 AM Central. Thanks, again, for joining us on today's call.

Operator

Ladies and gentlemen, that does conclude our conference for today. Thank you for your participation. You may now disconnect.

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