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Ladies and gentlemen, thank you for standing by. Welcome to the Denbury Resources First Quarter 2018 Results Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. I'd now like to turn the conference over to John Mayer, Director of Investor Relations. Please go ahead.
Thank you, Linda. 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 joining us today. Our first quarter results continued to highlight the advantages of Denbury's unique business, building on the multiple successes we achieved in the fourth quarter. Oil prices and differentials were strong. Excluding hedges, we realized an average price of over $64, our highest since 2014, and our Rockies differential was the best we've seen since we began operations there in 2010. We again generated significant free cash flow and further lowered our already decade low G&A. $85 million of convertible notes converted into shares in April, and we reduced our bank loan balance by $25 million during the quarter, further reducing debt and improving our debt metrics. We expect to continue rapidly down the path to significantly improve debt metrics over the coming quarters. In April, our bank group reaffirmed our borrowing base at $1.05 billion, underscoring their confidence in our assets. Exploitation continues to be an exciting new dimension for Denbury. In April, we completed 2 successful Mission Canyon wells. While they've been on production just a short time, their performance has been better than we expected, especially given the location of these wells in the narrowest part of the structure, as you can see in the map on the lower right-hand side of Slide 6. This speaks to both the quality of this play and the great job our drilling team does in placing the wellbore exactly where we want it. With the nature of the reservoir and the production history we have from historical vertical producers, we expect Mission Canyon horizontal well to have a fairly high initial decline, followed by an extended low decline period. We'll continue to update you as we learn more and optimize production and value from these wells. Right now, our total gross Mission Canyon production is between 2,500 and 3,000 barrels per day. Based on these strong results, we've added a seventh Mission Canyon well to the 2018 capital budget, with 5 remaining to be drilled. After a short pause for a stipulated sage-grouse nesting season, we'll resume drilling in July and continue through year-end. I'm excited to see the results from these new wells since they will be placed in a larger part of the accumulation in Coral Creek, as you can see in the map on the lower right-hand side of Slide 6. We'll also be testing Mission Canyon further to the south in our Little Beaver field. I expect that our Mission Canyon development will be aggressive in 2019. We believe we have around 2 dozen total locations, and that number could expand as we learn more about the reservoir. We've also kicked off exploitation work in the Gulf Coast where we've recently drilled our first Perry well at Tinsley. Initial drilling indications look promising, and completion operations are in progress. Success with this initial well will kick off an estimated 18-well program to fully develop the Perry Sand across the Tinsley Field. We plan to test the unconventional Powder River Basin potential under our Hartzog Draw unit during the second half of 2018 as well as a test of additional potential under the Tinsley Field. In total, we continue to expect that we'll spend between $30 million and $40 million on exploitation projects in 2018. That wraps up the exploitation summary, and I couldn't be more pleased with the successes we've had so far. I see significant running room to grow value, production, and reserves in the coming years as we mature this program. Now I'd like to give you an update on the status of our asset sales processes. You'll recall that we have 2 separate processes working, 1 covering circus -- surface acreage near our Conroe and Webster Fields, and the other covering a set of mature-producing assets in the Gulf Coast region. Each process is well underway. Based on our present position in each process, I can't provide more deal now -- more detail now other than to say we're encouraged by the level of interest. We've seen nothing that changes our view on either process, and we'll provide more information as soon as we reach an appropriate point. Turning to specifics from our first quarter. Operationally, we continue to hit on all cylinders. Our focus on outstanding execution is showing results in many ways, including continued improvement in safety, the lowest spill rate we've had this decade and increased facility uptime. Project execution and delivery is strong, including on-time, on-budget completion of our Oyster Bayou facility expansion in January, and our new EOR project at the Grieve Field in Wyoming, completed in April under budget and ahead of schedule. Other key projects are all on track, including our Delhi Tuscaloosa infill project, which should be complete in the second half of 2018; and our Bell Creek Phase 6 development, which is scheduled for completion in the first quarter of 2019. We are approaching our midyear target for the investment decision on developing a CO2 EOR project at CCA. Based on the work I've seen so far, I'm highly optimistic that we will proceed with this project, which will further unleash the tremendous value potential of this great field. First quarter production came in as expected, essentially flat with the fourth quarter. As I mentioned in the fourth quarter call, significant winter weather on the Gulf Coast impacted production in January, but this impact was factored into our full year guidance, and we remain confident in that guidance. I expect production to be higher for the remainder of the year with the weather-impacted Gulf Coast fields back at full strength, and further increases through the year coming mainly from the Delhi infill project, new production from Bell Creek Phase 5 and the new floods at West Yellow Creek and Grieve, both ramping up, as well as our exploitation projects. Operating costs also came in as expected at $118 million for the quarter and are on pace with our expectations for the full year. As I mentioned in the fourth quarter call, we've seen some upward pressure on power, mainly due to increased utility rates in a few markets. But the combined spend on all other LOE categories was about $2 million lower than in the first quarter of last year. The operations team continues to do a great job, driving LOE ownership across the organization and down to the field level, and I'm confident that we have the right level of focus on this piece of the business. Now I'll speak to the specific impact of oil price on Denbury. Slide 10 highlights how oil -- higher oil prices flow to Denbury's bottom line. In past reports, we've shown how our high oil weighting translates into a top quartile operating margin. What I'd like to highlight on this slide is the comparison between the first quarters of 2017 and 2018. Our realized price increased by $13 per BOE year-on-year, and our operating margin increased by $12 per BOE. So 90% of the price increase flows to the bottom line. But more importantly, it's the absolute magnitude of the first quarter 2018 operating margin at $34.45 per BOE, highlighting the profitability of our business in this oil price environment. Lastly, before I hand comments over to Mark, I'll highlight some financial numbers that underscore the improvements we made during the downturn and the benefit we are now starting to see with higher oil prices. Since 2014, we reduced our total debt by nearly $1 billion. Our cost reduction work turned back the clock, taking our G&A back to the levels of a decade ago. Our total debt-to-EBITDA reduced by a full turn in just the past quarter, and even that significant improvement is moderated by our current oil hedges, which roll off at year-end. At current strip prices, we expect to see further debt-to-EBITDA improvement, potentially nearing 3.5x by midyear 2019. Our financial strength is rapidly improving, and I'm thrilled to see how the hard work and dedication of our employees through some tough times has driven steady and meaningful improvements in Denbury's business. Now I'll pass it over to Mark for a financial update.
Thank you, Chris. My comments today will highlight some of the financial items in our release, primarily 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. Starting on Slide 12. On an adjusted basis, net income was $54 million for the first quarter, up slightly from $48 million in the fourth quarter. On a GAAP basis, we reported net income of $40 million, with the primary difference from adjusted net income being $15 million of expense for noncash, fair value commodity derivative changes. On the bottom portion of this slide, we have included our basic and diluted share count information to highlight the impact of the convertible debt on our diluted share numbers. In April, we converted all of our 3.5% convertible debt into 38.5 million shares of common stock. So those shares will be included in our second quarter basic shares as of the conversion date. And our diluted shares as of March 31 were reflective the full potential conversion impact as if all of our convertible notes were converted. Turning to Slide 13. Our non-GAAP adjusted cash flow from operations, which excludes working capital changes, was $125 million for the first quarter, a slight decrease of $9 million from the fourth quarter, with the primary difference being the $7 million CO2 price adjustment last quarter. Our first quarter average realized oil price before hedges was $64 per barrel, a 12% increase from our realized price in the prior quarter. Our hedge settlements were $33 million this quarter, which made our average per barrel realized price, including hedges, approximately $58 per barrel, up 4% from last quarter. Slide 14 provides a summary of our oil price differentials, excluding any impact from hedges. For the second consecutive quarter, our realized oil price was higher than NYMEX prices, averaging almost $1.30 above NYMEX prices. As expected, our Gulf Coast positive differential came down with a somewhat weaker LLS price premium this quarter, but our price realizations in our Rockies region and in CCA continue to improve relative to NYMEX prices to the best levels we have realized. We currently expect that our overall oil differential for the second quarter of 2018 will decrease from our Q1 average and will range from approximately even with NYMEX prices to $0.50 positive to NYMEX prices, with the fluctuation due primarily to the LLS price premium and other pricing adjustments. Slide 15 provides a current summary of our oil price hedges. Since our last quarter's conference call, we have added additional volumes to our 2019 hedge positions, such that we now have 15,000 barrels of oil hedge for the full year, representing roughly 1/4 of our total first quarter 2018 production levels. The majority of these hedges are 3-way collars, protecting at or above $55 per barrel while also allowing for upside exposure to the mid-60s to low $70 per barrel. In our most recent contracts, we have stepped the per barrel price floors up to $58 with caps above $70. We plan to continue adding 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. Since Chris already addressed LOE, I will start with G&A. Our G&A expense was $20 million for Q1, down slightly from Q4 and down $8 million or almost 30% from the first quarter of last year. The impacts of our cost-saving efforts over the past year and employee reductions to further rightsize our business for a low oil price environment are the primary drivers for this reduction, which equates to an approximate $1.50 per BOE reduction in our cost structure. Our net G&A related to stock-based compensation was approximately $3 million this quarter, and we currently expect our G&A for the remainder of 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 $17 million this quarter, a decrease of $6 million from the fourth quarter due to additional interests treated as debt resulting from the debt exchange transactions completed in late 2017 and early 2018. On the bottom portion of the slide, you will see there is a more detailed breakout of the components of interest expense, which shows that actual cash interest was relatively unchanged from last quarter. Capitalized interest was $9 million for the first quarter, and we currently expect that our capitalized interest will be in the $5 million to $7 million range per quarter through the remainder of 2018. Our DD&A expense this quarter was $52 million, relatively flat with the prior quarter. We expect our DD&A expense will be in the $54 million to $58 million range per quarter throughout the remainder of this year. With the change in the federal tax rates at the end of last year, our statutory rate is around 25%, and our effective income tax rate for Q1 was 26%. For the remainder of 2018, we currently anticipate our tax rate will be somewhat higher than our statutory rate, most likely similar to what we have in the first quarter. And we still anticipate little to no current tax expense. Moving to our balance sheet. Pro forma for the April conversion of our 3.5% convertible senior notes into shares of common stock, we had total debt principal of approximately $2.6 billion as of March 31, 2018, with $450 million outstanding on our bank credit facility and roughly $540 million of remaining availability. Including the recent debt conversion, this represents a decrease of almost $1 billion in our debt principal since December 31, 2014, with potential for further reductions in 2018 based on current levels of excess cash flow, the expectation for a portion of our Houston area acreage sales to be realized in the back half of 2018 and the potential for the conversion of our 5% convertible notes. We currently expect that we will end 2018 with bank debt between $300 million and $400 million. As expected, in April, our banks reaffirmed our borrowing base for a bank credit facility of $1.05 billion, in connection with our spring semiannual review. The next item we will be working on is the extension of this facility beyond 2019. As we have previously stated, our main priority will be to retain ample liquidity and full access to our $1.05 billion borrowing base. My last slide focuses on our improving leverage metrics. As we have said before, our value-sustaining asset base and improving debt metrics provide Denbury a much different debt profile than some may think. Our cost-saving initiatives and higher oil prices, combined with our 97% oil weighted, are resulting in significant changes to our leverage metrics. As shown on this slide, our trailing 12-month debt-to-EBITDA ratio was at 5.4x, which is down a full term from last quarter. And if you exclude hedge impacts, our trailing 12-month ratio would be 4.8x. On the right side of the slide, you can see our first quarter EBITDA was $142 million. And if you annualize that amount, our first quarter debt annualized EBITDA -- our debt-to-EBITDA would be 4.6x. And if you remove the impact of hedge settlements from the first quarter, our debt to annualized EBITDA would be around 3.7x. Based on current strip prices, we see a path to getting our leverage down to 3.5x or lower during 2019, which is a threshold the banks are looking for based on regulatory parameters. Improving the balance sheet remains a tough priority, but I wanted to highlight the progress we have made and where we are heading. And now I'll turn it back to John for some closing comments.
Thank you, Mark. That concludes our prepared remarks. Linda, can you please open the call up for questions?
[Operator Instructions] We have a question from Charles Meade with Johnson Rice.
Chris, you spent a lot of time talking about the Mission Canyon at the Cedar Creek Anticline. But I'm wondering if we can just spend a little bit more time on that. So the 3 wells you have now and the 2 you have planned are all in this Coral Creek area, but you mentioned that you're looking forward to pushing that to the Southeast as you go to that -- the Little Beaver area. Is there -- can you give us a narrative? Is there a reason why you started in this Coral Creek area that it looked better? Or maybe you had a pad ready? Is it -- did it look better there than down at Beaver Creek? Or perhaps, is it the other way around, you've tried it in a kind of lower-impact area first as a proof of concept and you've got better things in front of you?
You bet, Charles. If you take a look back at the slide in the presentation on Mission Canyon, it helps clarify that. So first, the wells that we've initially drilled have been in the Pennel Field, which is adjacent into the north of the Coral Creek field. The colored image on the lower right-hand side of that slide has a bit of kind of a pie shape to it. And so we're essentially in the middle of the pie with the Pennel wells, and that's where just -- in general, we see the largest accumulation. Later in the year, we're going to move down to Coral, and so that's the -- to the south there and the larger size of that pie shape. Now if you think in the big picture across CCA, Charles, if you look at the graphic in the upper right, you'll see that, that combination of Pennel and Coral Creek is the biggest overall accumulation that we've seen. And so that's really why we started there. We've also highlighted in red ovals other fields, including Little Beaver that I mentioned to the south there, that we'll also be testing later in the year.
Okay. But if I understand you right, Chris, you started in the spot, it looked best.
It looked the biggest. But again, it's the -- that's going to translate into how many wells we can drill in each area. And based on what I've seen so far, the horizon is very prolific. Our drilling teams have been able to steer the wellbore exactly where we want, and so I expect good results wherever we go across here. It's really just going to be number of wells that we're able to drill.
Got it. And then, if I could transition over to some of the -- Mark's comments at the end about your leverage and what the outlook for your leverage is. Can you give us an update on your thinking in your goals as we're living in kind of a WTI $65 to $70 world? What's your balance between debt paydown versus additional CapEx if oil prices stay high? And is there a target, perhaps, of getting your revolver balanced down to some figure or perhaps down to 0 that you're shooting for like an 18-month time frame?
Yes. I guess, getting our revolver maybe down to 0, I guess, is -- we hadn't necessarily stated that as a goal. We do think being minimally drawn on that is a good place to be. And obviously, we're continuing to make improvements there. So I think the bigger focus for us really is just around debt-to-EBITDA levels, and that really ties back to when you're dealing with the banks and the regulatory requirements that they're living under and shooting for, the 3.5x becomes a significant mark close there, too. And so we find, as we move closer to that, our ability to do certain things and definitely improves and obviously, helps the line of sight to removing concerns around the balance sheet. And obviously, we want to continue to do better than that over time, but I would say that's kind of the initial driver and where we would like to get to in the near term.
Mark, do I understand you right in your comments if -- that you're working both the numerator and the denominator on that debt-to-EBITDA metric, and that's the way you're going about it?
Definitely. I mean, I think we keep every -- everything in front of us and the various options that we can pursue and some relates to just pure debt reduction, and we've looked at -- done some of those. And we've done some other things that improve the EBITDA side. So we're definitely working all parts of the equation will help make our balance sheet stronger.
And our next question is from Tarek Hamid with JPMorgan.
This is actually Kevin Kwan, calling in for Tarek. Just wanted to see if I can get a quick update on some of your Houston asset sales or maybe some of the mature asset sales.
You bet, Tarek (sic) [ Kevin ]. The -- as I mentioned in the remarks, we have both of those processes underway. And where we stand now, essentially, they're in line with where we expect it to be heading. We're not at a point where we are prepared to give more details on exact timing or any other expectations other than they're on track with what our initial expectations were. And that's -- as soon as we get to a point where we're able to talk more about those, we'll be happy to do that. I don't think it will be too long.
Okay. Sounds good. And just stepping to another topic. I just want to see on your ABL what kind of strategy or timeline we might be looking at for potential restructuring of that?
Sure. I mean, so obviously, we've wanted to get the redetermination out of the way, and we did that early April. Wanted to get first quarter behind us here. And with each passing period here, our metrics will be improving, and so that's very helpful. We've been in discussions with our lead banks and really working towards we think some good solutions. And so we'll continue to work that here over the next several weeks and maybe months just looking for the right time to maybe move forward and get all that locked in as we roll -- look to roll it out past '19, so.
All right. That's helpful. And finally, my last one is just on operating costs. I know a lot of your increases in LOE as of late have been more focused on the power side. Just wanted to see what -- how that looks for the remainder of the year. Should we still see that continue to rise a little bit as production ramps up? Or should that become flat as the year goes on?
So first, I'd say that the production cost and the electricity cost associated with that was something that we knew going into the year. So similarly to how we guided our production for the year, we've guided OpEx knowing that. I don't see big changes as we move through the year with our electricity. And I guess, just the other thing I'd add on the OpEx side is that the first quarter tends to run a little high with seasonal weather impacts, like snow removal and some comp timing, but we're very confident in our original guidance of $21 million for the full year.
And our next question is from Jason Wangler with Imperial Capital.
I wanted to ask, Chris, I think you may have kind of at least hinted at it on the prepared remarks. But as the year goes on, if oil prices kind of stay higher than kind of the budget, if you will, would you be looking to redeploy some of those funds into some of these Mission Canyon and other opportunities as the year goes on? Or would you just simply just kind of throw it back on the paying down the debt?
You bet, Jason. I couldn't quite catch the full question, but I think I got enough of it. And really, as we look at the full year, our budget, as we've disclosed before, was based on $55 oil. And certainly, we're seeing higher than that as we've gone through the first few months of the year. We haven't officially changed our budget at this point. We -- you will note that we did add a Mission Canyon exploitation well for the year, so that's a piece of what we're doing. What I say is as we come a little bit further through the year, we're continuing to bring very high-quality opportunities forward, and we'll be looking for opportunities to take excess cash that we generate, and deploy it back into the assets. Haven't made a final decision on a change yet there.
Okay. And maybe on -- with CCA, the decision kind of coming in the next few months, if you did move forward with that, would there be an ability to kind of maybe spend some of this cash flow this year? Or would that really be a future event that you'd be looking at?
I think that's a fair question and where the -- with CCA and where that capital will come from. Right now our planning is being built around self funding that. And some of that would be this year, not a great quantity but advanced steel purchases for the pipeline, right of ways for the pipeline and so on. More of that expense would come into '19. And I do expect at least based on the way we see it now is that there's a good chance that we'd want to look at funding that internally.
And we have a question from Kyle Bickel with Stifel.
I was just wondering if you could provide a little more color or specific rates on these second 2 wells at Mission Canyon? Or at least just kind of how they compare to that first 1,050, whether any of these second or third are looking stronger or weaker than that first one or just kind of all performing in line?
Sure thing, Kyle. So looking at Mission Canyon, first thing I'd say is everything we've seen so far is better than we expected. Are 3 Mission Canyon wells are our 3 top producers in the company. And when we look at them in aggregate, we've already produced over 100,000 gross barrels. So very pleased with how they have performed. The second 2 wells, I think we took some learnings from our first well, and geo steered even to a greater degree than we had in the first well. And so in many ways, we see the performance on a per foot basis stronger than what we saw on the first well. So we're excited about that. Looking at the performance of the first well, we've increased that EOR to over 500,000 barrels. And again, we're still early days, but we see enough to move that up. Pretty confident in these wells. One thing I'd point out is they're different from unconventional wells. We have very strong aquifer support here and a very high-quality reservoir. And so we're using ESPs to produce them. And the rates that we're achieving are based on what we choose to set the ESPs at to optimize the life and value of these wells. That's something we're going to be continuing to work in these early days. And I see as we get a bit further down the road here, we're going to develop a representative-type curve for Mission Canyon wells. I think we're a few months away from that, but that's something, as we get a good history built in here, we're going to share that with you.
Okay. And then you mentioned the geo steering in the ESP. Are you guys doing anything -- toggling anything on the completion front? Or is that something that you feel pretty comfortable with here?
Yes. We're very comfortable with these completions. Then just as a reminder, they're open hole completions. We have very high-quality competent rock in these horizontals, and so the ESP is able to work with an open hole in the lateral.
Okay. And then real quick. I think you guys had put a number up there. You're kind of targeting $50 million in cost reductions throughout 2018. I guess, just a little more color on kind of where you expect that to come from and kind of where you're targeting those savings.
Yes. This -- a large part of that is reflected in G&A. And so I think just as you -- I referred back to our first quarter '17 number, we're roughly $8 million lower on a run rate basis. So obviously, a big part of it is there and some other savings across the board that we targeted in LOE and other areas. But G&A will be the biggest area of impact there.
And there are no further questions on the phone line.
Thank you, Linda. Before you go, let me cover a few housekeeping items. On the conference front, we will be attending the RBC Global Energy and Power Executive Conference on June 5, followed by the Bank of America Merrill Lynch 2018 Energy Credit Conference on June 6 in New York City. The details for these conferences and webcast for the related presentations 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 second quarter 2018 results on Tuesday, August 7, and hold our conference call that day at 10:00 a.m. Central. Thanks again for joining us on today's call.
Ladies and gentlemen, that does conclude your conference for today. Thank you for your participation and for using AT&T Executive TeleConference. You may now disconnect.