Denbury Inc

NYSE:DEN

Earnings Call Transcript 2018-Q2

[Operator]

Ladies and gentlemen, thank you for patiently standing by, and welcome to the Denbury Onshore Second Quarter of 2018 Results Conference Call. [Operator Instructions] Just a brief reminder, today's conference call is being recorded.

And I'd now like to turn the conference over, from Denbury's Investor Relations group, John Mayer.

[John Mayer, executive]

Thank you, Justin. 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; Mark Allen, our Executive Vice President and Chief Financial Officer; Matt Dahan, our Senior Vice President of Business Development and Technology; and David Sheppard, our Senior Vice President of Operations. Before we begin, I want to point out that we have slides which will accompany today's discussion. Should you encounter any issues on the webcast portion of the presentation, please refresh your browser. 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.

[Christian Kendall, executive]

Thanks, John. I appreciate all of you who joined us today.

Looking at our second quarter, the sustained and rapid improvement in our financial results is remarkable. We continue to generate significant free cash flow and we've reduced debt by nearly $200 million, with our total debt now down over $1 billion or 30% since the end of 2014. We continue to reduce costs with net G&A now below $20 million for the first time at Denbury in the last 10 years. Realized prices were very strong, up $4 to just over $68 per BOE excluding hedges. And overall oil differential to WTI was positive for the third consecutive quarter. Aided by turning 2 new wells online at Mission Canyon at the start of the quarter, production was up 3% to 62,000 BOE per day. LOE was down, nearly $0.50 per BOE. We maintained strong capital discipline with our capital spend for the first half of the year well within our full year guidance. Importantly, we also continue to build the foundation for Denbury's long-term future with the sanctioning of our EOR project at Cedar Creek Anticline, a development that we believe could ultimately recover more than 400 million barrels of oil. Even with all those successes, the most important highlight of the quarter for me was in our key safety and spill metrics where we reached multiyear record levels. I fully believe that the best business performance comes from companies that make it a top priority to keep people safe and take care of the environment, and our operating teams are doing an exceptional job at both. Aside from our focus on cost reductions, a key driver behind the rapid improvement in our financial results is that crude oil accounts for substantially all of our production. A great way to look at the impact of this is through our operating margin. Slide 5 shows how powerfully this has shifted over the past year. The $20 per BOE improvement in revenues since last year's second quarter from $46 to $66.50 over that period leads to a nearly identical $19 improvement in operating margin. The net result is that our operating margin per BOE has almost doubled to nearly $40 per BOE. I often hear comments about higher operating costs involved in the EOR business. But to me, the greater objective is to maximize cash flow margins and the nearly 100% oil weighting that our company delivers leads to operating margins that are competitive with anyone in the industry. We continue to be excited about Mission Canyon and are eager to resume drilling in this area following the stipulated March through mid-July activity pause for sage grouse nesting season. We now have 7 wells planned for the remainder of 2018 and are currently constructing a pad for the next pair of wells to be drilled in Coral Creek. We're particularly excited about these as they will be located on the highest part of the structure in the Pennel-Coral Creek accumulation. We should be spudding the first well in about 4 weeks. We're considering a plan to accelerate this development, including potentially adding a second rig later in the year. If we do choose to further accelerate drilling, we still expect to remain within our previously guided capital budget range and the production impact of a second rig would be felt mainly in 2019 as any additional wells will be brought online relatively late in the fourth quarter. While still early, Mission Canyon well performance has remained in line with our previous thinking with a fairly high initial decline followed by an extended low decline tail, which is evident in the Pennel Field production chart shown at the bottom of Slide 6. I mentioned in our last earnings call that there's a BLM and state stipulation limiting our drilling activities in the Mission Canyon area in the March through mid-July time frame for the sage grouse nesting season. This causes drilling to be concentrated in the August to February period, which will result in a bit more lumpiness in our production. I'll touch on that when I go into production in a few minutes. Exploitation efforts in the Gulf Coast this quarter focused on the completion and start-up of the first Perry well in Tinsley. This horizontal had a 3,500-foot lateral in the Perry Sand, about 400 feet below the main Tinsley producing interval. The well completion included a fracture stimulation and has been online since early June. We're pleased with the well results in terms of good pressure support and high fluid deliverability, but we believe that we may have placed the heel of this well a bit too close to historical waterflood, resulting in a higher water cut than is typical of vertical Perry wells. The result is a well that's delivered more fluid than we expected, upwards of 1,000 barrels per day, but our 30-day oil rate was just about 150 barrels per day as water from the heel limits oil production from the lateral. We're trying to take this learning into account in the next well that we drill in the fourth quarter and we're now confident that Perry will be an economic development. The economic threshold for these wells is quite low given the relatively low cost and the infrastructure advantages we have within the Tinsley unit. As an example, our expectation is that an IP-30 of 220 barrels per day, which we think is very achievable in future wells, would generate an IRR above 20% at $50 oil and above 40% at current strip prices. Like the Mission Canyon wells, Perry wells have the added value of becoming very nice EOR targets later in their life. Rounding out exploitation, we continue to identify and mature additional exciting, impactful opportunities across our portfolio, and we're preparing for the rest of our 2018 program, including the deep test at Hartzog Draw in the Powder River Basin and the Cotton Valley test at Tinsley, both of which should spud in the fourth quarter. Production for the quarter was at the upper end of our expectations at 62,000 BOE per day. Production was either up or stable across the board with just Tinsley down a bit from the first quarter. The second quarter also benefited from high initial production from the start-up of 2 new Mission Canyon wells that we completed just before the stipulated activity pause. Looking ahead to the rest of the year, we expect third quarter production to be below the second quarter, mainly due to the second quarter pause in new Mission Canyon drilling, unplanned downtime at CCA and Oyster Bayou and the seasonal effect of summer temperatures on a few of our Gulf Coast floods. We expect production to rebound in the fourth quarter with several new Mission Canyon wells coming online, continued response from our EOR development capital projects and cooler Gulf Coast temperatures. Our operations team has held unit operating expense relatively flat over the past year, which is particularly impressive given the significant increase in oil price during that time. On a total dollar basis, nearly all of the $9 million increase over the past year is associated with our Salt Creek acquisition, which occurred at the end of the second quarter of 2017. Looking at the key power and fuel and labor unit LOE components, you get a sense of the year-on-year consistency with the current quarter just $0.20 -- $0.21 above the year-ago quarter and $0.40 below the first quarter. We're highly focused on avoiding cost escalation in an improving oil market and these results show that those efforts continue to be successful, a tribute to the hard work and creativity of our operations teams. Capital spend through the first half of the year was about $130 million. Our 2018 capital program is weighted toward the second half of the year, and we remain on track to spend within our $300 million to $325 million guidance. We're frequently asked about our plans for excess cash flow as our capital budget was based on generating positive free cash flow at $55 oil, but we're pleased with what our current capital plan does for us and do not plan to make any changes at this time. Key projects underway outside of the exploitation projects that I mentioned earlier includes Bell Creek Phase 6, which builds off of what is turning out to be a very successful Phase 5 in the heart of the field; the Delhi Tuscaloosa infill project; continued development at West Yellow Creek; and the recently sanctioned Cedar Creek Anticline EOR project.

Our 2 asset sales continue to progress. In the second quarter, we closed the sale of the first minor track in Conroe and Webster, totaling just around $3 million. We expect closings to accelerate through the remainder of 2018 and into 2019 with multiple parcels currently either under contract or fast approaching that point. Our expectation for total value is unchanged, although that we now expect a greater portion of these sales to close in 2019. Our focus continues to be finding the greatest value to the company, even if doing so takes a bit longer than we originally expected. We are pleased with the progress on the mature property sale. As I mentioned in our last call, I can't provide more detail now other than to say we're encouraged by the level of interest we've seen. There's nothing that we've seen that changes our outlook on the process and we'll provide more information as soon as we reach an appropriate point. Earlier this quarter, we announced the sanctioning of what I believe will be a cornerstone of Denbury's future, the EOR development of Cedar Creek Anticline. Our technical teams have done a great job preparing a development plan that is low risk, incorporating the many learnings from our vast experience base. This development is attractive at $50 oil and will generate significant free cash flow for decades. We believe the overall EOR potential is greater than 400 million barrels, 1.5x greater than the company's total current proved reserves. We will develop CCA in phases. In the first phase, we'll lay a 110-mile CO2 pipeline from Bell Creek to CCA, terminating in the East Lookout Butte field. From there, we'll begin Phase 1 development in the East Lookout Butte and Cedar Hills South fields. This phase targets about 30 million barrels in the Red River formation. We see the Red River as low risk as it's only about 9 feet thick, giving us great CO2 flood control and sweep efficiency. Phase 1 is set up to carry the full economic burden of the $150 million pipeline investment, even though that pipeline will support all additional development at CCA. We've ordered steel and are progressing plans to lay pipe in the 2019 season, which puts us on track to begin injecting CO2 in 2020 with first production in late 2021 or early 2022. Phase 1 should ramp up to 10,000 barrels per day, plus or minus 25%, within 2 years of first production. Phase 2 will move to Cabin Creek, where we plan to develop the Red River, in addition to the Stoney Mountain and Interlake formations. We estimate recoverable oil from this phase to be around 100 million barrels. With our currently contracted CO2 supply, we expect that Phases 1 and 2 will maintain that 10,000 barrel per day range for many years with OpEx ranging from $10 to $15 per barrel. The upside opportunity at CCA is targeting the remainder of the structure, everything beyond Phases 1 and 2. We believe this area holds over 300 million barrels of recoverable oil. To accelerate this production, we'll need to source additional CO2. We've already identified multiple options on this front and I'm optimistic that we'll be able to accelerate the development of the enormous upside in CCA. The capital profile of the development will generally be in the $50 million annual range with most of the $150 million cost of the CO2 pipeline concentrated in 2019. Based on our current expectations for cash flow, we plan to self-fund the pipeline although we'll also consider outside funding sources. Now before I turn it over to Mark to provide additional information on our numbers and financial condition, I want to highlight the tremendous improvement we have made and are continuing to make in our leverage metrics. Our trailing 12-month debt-to-EBITDA ratio, which reduced by a full turn in the first quarter, is down by yet another full turn in the second quarter, and we believe it is on a path to be below 3.5x in the second quarter of 2019 at current strip prices. This quarter's annualized ratio is 3x ex hedges, representing the run rate leverage of our business at current prices, a stark contrast to where we were 1 year ago or even just a couple of quarters ago. Finally, our $39 per BOE operating margin spotlights the cash flow generation power of Denbury's 97% oil production, an advantage that places us near the top of the industry in terms of cash flow generation per BOE.

Our work is not finished. We remain focused on reducing costs, reducing debt, improving our operations and positioning this company securely to be very successful for the long haul. But I'm extremely proud of where we are now as a company and extremely optimistic about our future. Now I'll pass it over to Mark for a financial update.

[Mark Allen, executive]

Thank you, Chris. My comments today will focus -- will highlight some of the financial items in our release, primarily focusing on the sequential changes from the first quarter. I will also provide some forward-looking guidance to help you in updating your financial models. Starting on Slide 14. On an adjusted basis, net income was $61 million for the second quarter, up from $54 million in the first quarter. On a GAAP basis, we recorded net income of $30 million with the primary differences between the second quarter numbers being $41 million of expense for noncash fair value commodity derivative changes. Turning to Slide 15. Our non-GAAP adjusted cash flow from operations, which excludes working capital changes, was $134 million for the second quarter, an increase of $9 million over the first quarter, with the increase driven by higher oil and natural gas revenues generally resulting from higher production and better realized oil pricing as shown on the lower portion of this slide. For the first 6 months of the year, we have incurred $129 million in capital spend, less than half of our estimated $300 million to $325 million 2018 capital budget and significantly less than our cash flow from operations. Our second quarter average realized oil price before hedges was $68 per barrel, a 6% increase from the prior quarter. Our hedge settlements were $55 million this quarter, which made our average per barrel realized price, including hedges, approximately $58 per barrel, up slightly from last quarter. Slide 16 provides a summary of our oil price differentials, excluding any impact from hedges. For the third consecutive quarter, our realized oil price was higher than NYMEX prices, averaging $0.39 above NYMEX and in line with our prior guidance of flat to $0.50 positive to NYMEX. As expected, our Gulf Coast and Rocky Mountain differentials were less favorable in Q2, primarily due to the lower LLS price premium this quarter. Based on LLS premium and other differentials we have seen thus far in Q3, we expect that our overall oil differential for the third quarter will be slightly better than our Q2 average. Slide 17 provides a current summary of our oil price hedges. Since our second quarter conference call, we have added additional volumes to our 2019 hedged positions, such that we should now have 26,500 barrels of oil per day hedged for 2019, representing roughly 45% of our second quarter 2018 oil production level. The majority of these hedges are 3-way collars representing -- or sorry, protecting the mid-50s to low 60s, while also providing for upside exposure to the mid- to upper 60s and even upper 70s for some of the contracts. We plan to continue to add to our 2019 hedges as we deem appropriate and depending on market conditions. Moving to the next slide. I would like to review some of our expense line items. Since Chris already addressed LOE, I will begin with G&A. Our G&A expense was $19 million for Q2, down slightly from Q1 and down $6 million or 25% from the second quarter of last year. These decrease continue to reflect the results of our significant cost savings efforts over the past year, including reduced employee costs associated with the lower headcount. Through the first half of the year, our G&A expense on an annualized basis is trending roughly $30 million below last year's level. 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 $16 million this quarter, a decrease of $1 million from the first quarter. On the bottom portion of the slide, you will see there is a more detailed breakout of the components of interest expense, which shows a slight decrease in cash interest. With the conversion of our convertible notes in April and May, we should save about $6 million per year in cash interest. Capitalized interest was consistent at $9 million for the second quarter, and we currently expect our capitalized interest to be in the $6 million to $8 million range per quarter through the remainder of 2018. Our DD&A expense this quarter was $53 million, a slight increase from the prior quarter due to an increase in depletable costs. We expect our DD&A expense will be in the $53 million to $57 million range per quarter through the remainder of 2018. With the change in federal tax rates at the end of last year, our statutory rate is around 25% and our effective income tax rate for Q2 was 24%. For the remainder of 2018, we currently anticipate our tax rate will approximate the statutory rate and we anticipate little or no current tax expense. Moving to our balance sheet. We had total debt principal of approximately $2.5 billion as of June 30, 2018, and $415 million outstanding on our bank credit facility, which was down from $450 million outstanding on our bank facility at the end of the first quarter. This represents a decrease of over $1 billion on our debt principal since December 31, 2014, with the most significant recent piece of debt reduction coming from the conversion of our convertible debt during the second quarter. In connection with the conversion of $144 million in debt, we issued approximately 55 million shares, which allowed us to realize a full $329 million reduction in debt, equating to roughly $6 per share associated with the exchange transactions we did in late 2017 and early 2018. There continues to be potential for further reduction in our debt principal in 2018 based on current levels of free cash flow and proceeds from a portion of the Houston acreage sales that we are currently anticipating to be realized in the second half of the year. Based on current assumptions, we expect that we will end 2018 with bank debt between $300 million and $400 million. Our focus in the near term remains on extending our bank line beyond 2019, and we expect to have that completed well before the end of the year with our main priority around maintaining strong liquidity levels. My last slide focuses on the continued improvement in our leverage metrics. Our trailing 12-month debt-to-adjusted EBITDAX has improved to 4.5x, nearly another full turn better than just last quarter, resulting from our cost-savings initiatives, higher production and improving oil prices. If you exclude hedging impacts, our trailing 12-month ratio would be 3.9x. On the right side of this slide, you can see that our second quarter adjusted EBITDAX was $153 million. And as you annualize that amount, our 2Q '18 debt to annualized EBITDAX would be 4.1x. Furthermore, if you remove the impact of hedge settlements from the second quarter, our debt to annualized EBITDAX would be 3x. As you can see, our leverage metrics are clearly trending in the right direction. And based on current futures prices, we expect our leverage ratio to continue to trend down to the 3.5x or lower range on a trailing 12-month basis as early as the middle of 2019.

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

[John Mayer, executive]

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

[Operator]

[Operator Instructions] And first, we have the line of Charles Meade with Johnson Rice.

[Charles Meade, analyst]

Going back to the CapEx funding picture for the Cedar Creek Anticline CO2 line, if right now -- so you have that as $150 million in -- with the bulk of that coming in 2019. If we just say, for the sake of assumption, 2/3 of that comes in '19, that would represent about a 33% increment to your '18 CapEx levels. And so can you talk about if there's -- how you're thinking about CapEx allocation going into '19 and if there's room for other -- increased spending on other projects if you have to take that big chunk of CCA following your own?

[Christian Kendall, executive]

You bet, Charles. That's a great question. And there's 2 different things that I think about that. The first, and as I mentioned in the prepared remarks, is that we're not fully committed to spending our own money to develop that piece of the CCA development. We've seen a lot of interest externally and I think that that's an option that we're going to continue to take a look at. It's just we would prefer to be in a position where we have the option of doing it ourselves or finding outside money. So you kind of keep that asterisk on it. That's how we're thinking about the funding in that aspect. Secondly, when we just think about 2018 versus 2019, if you look at just our hedged position this year and with those hedges rolling off and where prices look like they're headed for next year, we kind of equate the hedges -- the amount that's rolling off on the hedges to what we have available in 2019, about $200 million being able to fund that. So that's how we're looking at it, where that spend would come from. But definitely we're going to continue to consider other alternatives, other places to invest that capital in our assets as well.

[Charles Meade, analyst]

Got it. And then maybe picking up on that point, Chris. You made some comments about the Perry Sand and I wonder if we just kind of go back to it and you may have given us the oil rate there, but could you remind us what the oil rate was on that first horizontal, and specifically, where it is in relation to what you think a development mode well is going to be?

[Matthew Dahan, executive]

Yes, Charles. This is Matt Dahan. I'll take that question. The 30-day IP rate on our first well was 150 barrels a day. As Chris mentioned, it is far more prolific as far as it's able to deliver fluid, just a little bit higher water cut than we anticipated. So we're looking at ways to move more fluid out of the well. So we're optimistic we can get higher rates out of this well. And as Chris mentioned, future wells, we're looking at about a 220 barrel a day IP rate.

[Charles Meade, analyst]

Got it. And then just to press a little bit more on that. Can you talk about what the suggestion is or what -- how you use this -- what the indications are that makes you suspect you completed part of that, the heel of that well in a water-bearing zone? And are -- is that zone still producing from a waterflood?

[Matthew Dahan, executive]

Historically, the Perry was waterflood in portions of Tinsley. So we did notice in drilling the well that we saw some reduced gas in the first part of it. We went ahead and stimulated it anyway to -- just really it's a test well to understand the concept. So as we drill future wells, we'll certainly take those learnings into account.

[Operator]

[Operator Instructions] Next, we have the line of Eric Engel of Stifel.

[Eric Engel, analyst]

So on Slide 6, you mentioned that there's a potential to increase the location count in the Mission Canyon. What do you need to see in order to increase the location count? And then did you have a projected EUR on the first wells there?

[Christian Kendall, executive]

So Eric, this is Chris. I'll answer that question. First, just what I say, we're not making many changes to our projected EURs from what we've last disclosed, so we're comfortable with that at that point. Actually, you're referring to increasing the well count and I think you might be referring to how many we're planning to drill this year versus next. We still see about 2 dozen total wells as the opportunity set there for Mission Canyon. And really, what we're looking at doing is pulling as much as we can into 2018, given the great success that we've had so far. With the activity pause coming out of that, getting those wells drilled might take another rig and that's why I mentioned that potential that we're looking at right now. But that's kind of the framework for how we're thinking about that.

[Eric Engel, analyst]

Okay. And then just to follow up on that. So I'm talking about the 24 locations that you guys have identified. What would you need to see to increase the location count up from that 24?

[Matthew Dahan, executive]

Eric, this is Matt Dahan again. If you look at the map on Slide 6, you can see the different areas of the Mission Canyon that we are targeting and we are beginning here in the second half of '18. We're going to start drilling some wells outside of the current accumulation that we've proven up. And then we're also going to gather some more reservoir data, additional logs to better understand the reservoir. And from that, it'll help us determine well spacing, well length, the optimal well length and et cetera.

[Eric Engel, analyst]

Got you. Okay. And then moving on to you mentioned that you're working on extending the bank line and the maturity dates in December 2019. So how come you're working on that now? It just seems a little bit early.

[Mark Allen, executive]

Yes. I know we just said we definitely want to get it done before the end of the year. And so that's our focus, just to make sure we get the extension at least 1 year out. But we do like to be proactive with it rather than just waiting for it to get to the end of the year.

[Operator]

[Operator Instructions] And at this time, we have no more questions queued by phone. I'd like to turn it back to John Mayer for any closing remarks.

[John Mayer, executive]

Thank you, Justin. Before you go, let me cover a few housekeeping items. On the conference front, we will be attending Enercom, the oil and gas conference, on August 21 in Denver, followed by Barclays CEO Energy-Power Conference on September 5 in New York City. The details for these conferences and the 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 third quarter 2018 results on Tuesday, November 6, and hold our conference call that day at 10:00 a.m. Central. Thanks again for joining us on today's call.

[Operator]

Ladies and gentlemen, that does conclude the event for this morning. Again, we thank you very much for all of your participation and for using our executive teleconference service. You may now disconnect.