Denbury Inc.

John Mayer - Denbury Resources, Inc. Philip M.

Rykhoek - Denbury Resources, Inc. Christian S.

Kendall - Denbury Resources, Inc. Mark C.

Allen - Denbury Resources, Inc.

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

With me on the call from Denbury are Phil Rykhoek, our Chief Executive Officer; Chris Kendall, our President and Chief Operating Officer; and Mark Allen, our 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 Phil.

Thank you, John. Good morning, everyone, and welcome to our first quarter call.

We previously announced our management transition plan for Denbury, whereby I will retire from my role as CEO of the company on June 30, making this my last quarterly conference call. I've been extremely fortunate to work with a great community of fellow employees during my time here, where we've seen Denbury grow from producing a few thousand barrels a day when I started in 1995, to where we are today as one of the premier EOR producers.

Denbury is operationally performing at a level of excellent. It's the best I've seen during my 22-year tenure.

And I am confident this continued high level of performance will ensure the company's future success. When Chris joined the company in 2015 as COO, we anticipated that he could potentially succeed me as CEO in a couple of years.

Chris has been an integral part of our senior management team since the day he arrived. And he has during his tenure made significant contribution to the success of Denbury.

Chris has also proven himself to be a natural leader. Based on his accomplishments and attributes and our commitment to Chris, we believe the timing is right for this transition.

I am confident Chris will successfully take Denbury to the next level. And in fact I'm counting on it, since I personally own a bunch of Denbury shares.

I look forward to continuing to work closely with Chris throughout this transition and in the subsequent months. Also you may have seen in our most recent proxy that we are proposing the addition of a new board member to our board of directors, Mr.

Lynn Peterson. Lynn is the current President, CEO, and Chairman of SRC Energy.

And he previously was Chairman, CEO, and Co-founder of Kodiak Oil & Gas before it was acquired by Whiting in 2014. We look forward to welcoming him to the team.

And I trust that his extensive experience and knowledge of the oil and gas industry will serve Denbury well. Now let's move on to the quarter.

We are off to a good start in 2017 with average quarterly production of just below 60,000 barrels a day, in line with our expectations and on pace to our projected guidance between 58,000 and 62,000 BOEs per day. We are steadily proceeding with our 2017 plans to stabilize production and resume modest production growth into 2018.

Chris will cover much more on operations during his update. I'd like to take a quick minute to address some comments made last quarter and provide a little more color.

It was mentioned that we would like to acquire properties, as we believe an appropriate transaction could be a meaningful and positive event for the company. To be clear, Denbury has always been a pursuer in acquirable properties, which is how we have successfully accumulated the robust asset inventory that we have today, including even some of our best fields, Cedar Creek Anticline.

We plan to continue with that strategy. And just as we have done during my entire tenure, we will be very conscious of assessing the impact, positive or negative, that any transaction might have on our stockholders.

When assessing any potential deal, we primarily evaluate three things: the impact on leverage, which we measure generally as debt to cash flow or EBITDA; the impact on dilution, which most often is measured as cash flow per share; and the impact on free cash flow per share. This should go without saying, but I can assure you we won't do anything that we believe doesn't put the company in a better overall position when considering these three metrics.

My prior comments were not intended to suggest that a deal was imminent, as consummating a acquisition is not a particularly easy or quick process. My comments were simply intended to alert you to the fact that the company is always looking at potential opportunities to accelerate our growth and improve our balance sheet.

But I may not have placed enough emphasis on the fact that we will do so only if it can be done in a prudent, judicious and appropriate manner that is ultimately beneficial to our shareholders. Continuing with the acquisition discussion, we recently completed one relatively small acquisition of an approximate 48% non-operating interest in West Yellow Creek Field in Eastern Mississippi for $16 million, an opportunity which presented itself due to our strategic supply of CO2.

The field currently has minimal production and proved reserves, as the operators are in the process of converting that field to a CO2 EOR flood, and has already invested significant capital in that development. As part of the transaction, we have agreed to sell CO2 to the operator.

Based on the current plans, we currently expect capital expenditures on this development to be less than $10 million in 2017 and we expect first tertiary production from the field late this year or early next year and increasing thereafter. We estimate there is tertiary potential to recover up to about 5 million barrels of oil net to Denbury, at this field.

Many of the geologic compositions of the West Yellow Creek Field are very similar to some of our existing fields, in particular, Eucutta. If you look at the map, you can see West Yellow Creek is located very close to the Eucutta Field, a field that's done very well for us.

This synergy allows us to take the knowledge we've gained over the past years and apply newly gained efficiencies to this future flood. A few years ago we would not have pursued a transaction of this type, because we did not have enough excess CO2.

Today with our improved operational efficiencies around the use of CO2, we can leverage our CO2 ownership to gain participation in additional EOR floods. And with that introduction I will turn it over to Chris to go over the first quarter operational details and guidance.

Chris?

Thanks, Phil, and good morning. I'd first like to recognize Phil for his many accomplishments during his 22 years at Denbury, initially as CFO and most recently as CEO.

And his significant contribution to making Denbury the special company that it is. I'd also like to express my appreciation to our board of directors and their confidence and support for my transition into the CEO role during the next couple of months.

I'm honored to have been given the opportunity to lead this great company. And I'm confident that the dedication and talent of our outstanding employees, combined with our unique business model and strong asset base will lead to long-term growth and success for all our stakeholders.

Moving on to operations, beginning on slide 8. We produced just under 60,000 BOE per day for the quarter, flat with our 2016 year-end exit rate and in line with our expectations.

We project full year production to average between 58,000 and 62,000 BOE per day with the second quarter essentially flat with the first. Production in the second half of the year is expected to be higher than the first half, as we begin to see the benefits of our recent development work.

That work should put us on track to resume production growth as we exit 2017. The key production highlight from the first quarter was at Delhi with increased oil production and added liquid sales from the first operations of the new NGL plant, driving total Delhi net liquids production to a multi-year high of nearly 5,000 barrels per day.

We expect both NGL production as well as the operational benefits of the plant to the EOR flood to continue to grow as the plant ramps up to full capacity over the coming months. Additional production gains in the second half of 2017 should come from Hastings, where we expect to complete the flood reconfiguration of Fault Blocks B and C this quarter.

We also expect to see increasing Bell Creek production throughout the remainder of 2017 with continued response from Phase 4. And on the non-tertiary side, we should see higher volumes through the course of the year at Conroe and Webster as we work to improve fluid handling in those fields.

Looking at operating costs on slide 9, LOE in the first quarter was $114 million, or $21 per BOE, up about $2 from Q4. With the crude price significantly higher than it was at this time last year, we stepped up workover and repair activities, which we expect will further enhance production throughout 2017.

These increased activities accounted for an incremental $4 million in costs in the first quarter, which should decrease as we continue through the year. It's important to note that nearly all of this incremental cost is due to our increased activity level.

And that we have not experienced any significant service cost escalation across our operations. As expected, CO2 expense increased by about $3 million compared to the fourth quarter.

I'll touch on total CO2 utilization in a moment, but CO2 costs in the first quarter were generally impacted by a higher proportion of industrial-sourced CO2 and somewhat higher overall utilization. Looking forward, we project LOE will remain relatively flat in the second quarter, then decrease on a per barrel basis during the second half of 2017.

With the full year expected to be in line with our prior guidance, around or below $20 per BOE. Digging deeper into CO2 utilization on slide 10.

Our total injected CO2 volumes in the first quarter increased as planned to 576 million cubic feet per day, about 30 million cubic feet per day above the fourth quarter. We anticipate CO2 usage will rise as we inject additional volumes to support growth in some of our existing tertiary fields, particularly at Hastings with the redevelopment of Fault Blocks B and C, as well as at Bell Creek with the Phase 5 expansion and in certain other fields where we continue to identify and execute conformance projects.

At $0.41 per MCF, CO2 costs in the quarter were up about $0.02 from the fourth quarter due mainly to our utilization of a higher proportion of industrial-sourced CO2, as one of our industrial sources came back online after fourth quarter maintenance activities. We also began receiving small volumes from Mississippi Power's Kemper County Plant.

We expect volumes from Kemper to increase throughout the year and when the plant reaches full capacity in the coming years, we should receive up to 160 million cubic feet of CO2 per day, more than doubling our current industrial CO2 supplier. And as we've said before, although industrial-sourced CO2 comes at a somewhat higher cost than our naturally occurring CO2, it's a renewable source and it allows us to defer investments and extend the life of our low cost Jackson Dome asset.

Touching briefly on our 2017 capital program on slide 11, we spent $53 million in development capital during the quarter, making significant progress on our Fault Blocks B/C expansion at Hastings, which is on budget and ahead of schedule. We're also progressing Phase 5 development at Bell Creek, with initial production expected around year-end and have multiple conformance projects in our existing tertiary floods during the quarter.

We're moving forward on our Green project in Wyoming and we expect to start production there by mid-2018. All of these projects have strong rates of return at current strip prices and we're continuing to high-grade our project inventory, as well as to evaluate exploitation opportunities across our portfolio.

We'll continue to keep an eye on crude prices and are keeping flexibility in our plans to lower our capital spend if needed. That completes the operations update and I'll now turn it over to Mark to go over first quarter financial details and guidance.

Thank you, Chris. First, let me update you on our bank facility redetermination amendments and then I'll provide some additional color around certain financial items and our forward-looking projections.

Starting on slide 13, we are pleased to report that our bank group recently reaffirmed our $1.05 billion borrowing base as part of their semiannual redetermination. In conjunction with this review, we also amended certain covenants to the remaining term at the facility to provide flexibility in managing the credit extended by the banks.

The covenant changes included eliminating the consolidated total debt to EBITDAX covenant that was scheduled to go into effect in 2018 and 2019; extending the existing senior secured debt to EBITDAX covenant through the remaining term of the facility, with the ratio not to exceed 3 times through the first quarter of 2018 and 2.5 times thereafter; and extending the existing 1.25 times minimum interest coverage ratio through the remaining term of the facility, which would have otherwise expired after the fourth quarter of 2017. As part of the amendment we also agreed to increase the applicable interest rate margin for borrowings by 50 basis points.

Based on current expectations, these changes should alleviate concerns around access to our bank line, as we look out for the foreseeable future. The next regularly scheduled borrowing base redetermination is set to occur on or about November 1, 2017.

Moving to our financial results. On a GAAP basis we recorded net income of $22 million for the first quarter.

But after excluding special items we realized a non-GAAP adjusted net loss of $7 million, consistent with last quarter. The primary special item impacting this quarter was a $52 million non-cash, fair value gain on our oil hedges.

Turning to slide 15. Our non-GAAP adjusted cash flow from operations, which excludes working capital changes, was $62 million this quarter, up $9 million from the fourth quarter.

We routinely have a working capital outflow in the first quarter due to cash outflows for ad valorem taxes, compensation payouts, and investing in long-term incentive awards. This quarter was also impacted by the $14 million current tax benefit that will not be realized until future periods.

Our first quarter average realized oil price excluding hedges was $50 per barrel, a 5% increase over the realized price in the fourth quarter. We paid out $27 million on oil hedge settlements this quarter, which made our average per barrel realized price including hedges approximately $45 per barrel.

Slide 16 provides a summary of our realized oil price differentials relative to NYMEX oil prices. Our overall realized oil price differential decreased as expected by roughly $0.40 per barrel from Q4.

We currently expect that our overall oil differential for the second quarter of 2017 should remain in a similar range to the first quarter in the minus $1.50 to $2 per barrel range. Moving to the next slide, I'd like to review some of our expense line items.

Chris already covered lease operating expense, so I will start with G&A. Our G&A expense was $28 million for Q1, in line with our expectations and consistent with the $29 million in Q4.

For this quarter net G&A related stock-based compensation was approximately $4 million. For the second quarter we currently expect our G&A will be slightly higher.

And then I would expect it to decrease somewhat to between $25 million to $30 million for the third and fourth quarters with stock-based compensation averaging between $4 million to $6 million per quarter. Net interest expense was $27 million this quarter, up $5 million from last quarter due to higher cash interest and lower capitalized interest.

Additional information on our interest expense and cash interest is shown in the lower portion of this slide. Our DD&A expense this quarter was $51 million, a decrease of approximately $5 million when excluding the accelerated depreciation charge recorded last quarter.

This decrease primarily related to a reduction in net capitalized costs subject to depreciation this quarter. We expect that our DD&A expense will be in the $50 million to $55 million range for the second quarter of 2017.

Our effective income tax rate this quarter was 49%, higher than our 38% estimated statutory rate, due primarily to the true-up for stock-based compensation awards that vested in the first quarter, for which the tax deduction was less than the financial expense recognized over time. A new accounting rule adopted last year requires this difference to run through tax expense instead of equity, therefore creating more volatility in our tax rate.

With regard to current taxes, this quarter we recognized a current tax benefit of $14 million. This benefit was generated as part of our tax planning strategies, in which we expect to utilize our alternative minimum tax credits and generate a tax refund for us in 2017 and 2018.

For the remainder of 2017 we currently anticipate our tax rate will be around 38%, excluding volatility for stock compensation items, with little or no current tax expense or potentially even a slight current tax benefit. Slide 18 provides a summary of our oil price hedges.

Based on recent strip prices, we estimate that our swap positions in the second quarter will have a negative impact of around $15 million on our cash flows. We plan to add to our positions over time depending on market conditions.

On slide 19, moving to our capital structure, our total debt principal was approximate $2.8 billion as of March 31, with $355 million outstanding our bank credit facility. Our bank borrowings were up approximately $50 million from last quarter due primarily to seasonal working capital changes in the West Yellow Creek acquisition.

With our recent redetermination, this leaves us with over $600 million of current liquidity available on our bank line, plus an additional $385 million of junior lien debt that we could issue under the $1 billion basket committed by the facility. And now I'll turn it back to John for some closing comments.

Thank you, Mark. That concludes our prepared remarks.

Paul, can you please open up the call for questions.

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

On the conference front, Phil Rykhoek and Chris Kendall will be attending the Bank of America Merrill Lynch 2017 Energy Credit Conference on June 6, followed by the RBC Global Energy and Power Executive Conference on June 7, both being held in New York City. The details for these conferences and the webcast for their 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 2017 results on Tuesday, August 8 and hold our conference call that day at 10:00 AM Central. Thanks again for joining us on today's call.