Print Denbury Resources today announced its fourth quarter and full-year 2019 financial and operating results, along with its 2020 capital budget and currently estimated 2020 production.
2019 FOURTH QUARTER AND FULL-YEAR HIGHLIGHTS
Financial
- Delivered net income of $23 million for 4Q 2019 and $217 million for full-year 2019
Adjusted net income(1) (a non-GAAP measure) of $47 million for 4Q 2019 and $192 million for 2019
Adjusted EBITDAX(1) (a non-GAAP measure) of $155 million for 4Q 2019 and $607 million for 2019
Generated $165 million of free cash flow(1) (a non-GAAP measure) in 2019 - Invested $237 million of development capital in 2019, below the low end of $240 million to $260 million capital budget range
- Reduced debt principal by $250 million in 2019 and ended the year with no outstanding borrowings on the Company's bank credit facility
- Improved leverage ratio to 3.7x at year-end 2019, compared to 4.2x at year-end 2018
Operational and Other
- 4Q 2019 production volumes of 57,511 BOE per day ("BOE/d"), up 2% from 3Q 2019
- Produced 58,213 BOE/d for full-year 2019, in the top half of original production guidance even with sale of Citronelle Field in mid-2019
- Realized strong production response from Bell Creek Phase Five CO2 flood expansion
- Entered into a definitive agreement in 4Q 2019 to sell half of the Company's nearly 100% working interests in four conventional southeast Texas oil fields for $50 million cash and a carried interest in 10 wells to be drilled by the purchaser, anticipated to close in March 2020 (the "Pending Gulf Coast Working Interests Sale")
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| (1) | A non-GAAP measure. See accompanying schedules that reconcile GAAP to non-GAAP measures along with a statement indicating why the Company believes the non-GAAP measures provide useful information for investors. |
2020 BUDGET HIGHLIGHTS
- 2020 base development capital budget of between $175 million and $185 million (excluding capitalized interest of between $40 million and $45 million), with an additional $140 million to $150 million of capital related to Cedar Creek Anticline ("CCA") enhanced oil recovery development conditioned upon Board approval, with a final decision on 2020 CCA capital spend expected in the second quarter of 2020
- Expect to generate upwards of $100 million of free cash flow(4) in 2020 (assuming a $50 per barrel ("Bbl") NYMEX oil price) if only the base development budget is executed, and would expect capital spending to be relatively equal with cash flow (after including approximately $40 million of net cash proceeds from the Pending Gulf Coast Working Interests Sale) if the additional capital is approved for the CCA enhanced oil recovery development
- 2020 production expected to average 53,000 to 56,000 BOE/d after adjusting for the Pending Gulf Coast Working Interests Sale; comparative 2019 continuing production excluding production from the Pending Gulf Coast Working Interests Sale would have been approximately 56,900 BOE/d
2019 FOURTH QUARTER RESULTS
Sequential and year-over-year comparisons of selected quarterly information are shown in the following table:
| Quarter Ended | ||||||||||||
| (in millions, except per share and unit data) | Dec. 31, 2019 | Sept. 30, 2019 | Dec. 31, 2018 | |||||||||
| Net income | $ | 23 | $ | 73 | $ | 174 | ||||||
| Adjusted net income(1) (non-GAAP measure) | 47 | 41 | 46 | |||||||||
| Adjusted EBITDAX(1) (non-GAAP measure) | 155 | 145 | 141 | |||||||||
| Net income per diluted share | 0.05 | 0.14 | 0.38 | |||||||||
| Adjusted net income per diluted share(1)(2) (non-GAAP measure) | 0.09 | 0.08 | 0.10 | |||||||||
| Cash flows from operations | 151 | 131 | 136 | |||||||||
| Adjusted cash flows from operations less special items(1) (non-GAAP measure) | 134 | 126 | 133 | |||||||||
| Development capital expenditures | 47 | 51 | 107 | |||||||||
| Oil, natural gas, and related product sales | $ | 294 | $ | 293 | $ | 327 | ||||||
| CO2 sales, purchased oil sales and other | 17 | 22 | 11 | |||||||||
| Total revenues and other income | $ | 311 | $ | 315 | $ | 338 | ||||||
| Receipt (payment) on settlements of commodity derivatives | $ | 9 | $ | 8 | $ | (26 | ) | |||||
| Average realized oil price per barrel (excluding derivative settlements) | $ | 56.58 | $ | 57.64 | $ | 60.50 | ||||||
| Average realized oil price per barrel (including derivative settlements) | 58.30 | 59.23 | 55.75 | |||||||||
| Total production (BOE/d) | 57,511 | 56,441 | 59,867 | |||||||||
| Total continuing production (BOE/d)(3) | 57,511 | 56,441 | 59,416 | |||||||||
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| (1) | A non-GAAP measure. See accompanying schedules that reconcile GAAP to non-GAAP measures along with a statement indicating why the Company believes the non-GAAP measures provide useful information for investors. |
| (2) | Calculated using average diluted shares outstanding of 571.0 million, 547.2 million, and 456.7 million for the three months ended December 31, 2019, September 30, 2019 and December 31, 2018, respectively, and 510.3 million and 456.2 million for the years ended December 31, 2019 and 2018, respectively. |
| (3) | Continuing production excludes production from Citronelle Field sold on July 1, 2019. |
| (4) | Represents currently forecasted cash flow, less development capital, capitalized interest and interest treated as debt reduction. |
2019 FULL-YEAR RESULTS
Year-over-year comparisons of selected annual information are shown in the following table:
| Year Ended | ||||||||
| (in millions, except per share and unit data) | Dec. 31, 2019 | Dec. 31, 2018 | ||||||
| Net income | $ | 217 | $ | 323 | ||||
| Adjusted net income(1) (non-GAAP measure) | 192 | 220 | ||||||
| Adjusted EBITDAX(1) (non-GAAP measure) | 607 | 584 | ||||||
| Net income per diluted share | 0.45 | 0.71 | ||||||
| Adjusted net income per diluted share(1)(2) (non-GAAP measure) | 0.40 | 0.48 | ||||||
| Cash flows from operations | 494 | 530 | ||||||
| Adjusted cash flows from operations less special items(1) (non-GAAP measure) | 524 | 527 | ||||||
| Development capital expenditures | 237 | 323 | ||||||
| Oil, natural gas, and related product sales | $ | 1,212 | $ | 1,423 | ||||
| CO2 sales, purchased oil sales and other | 63 | 51 | ||||||
| Total revenues and other income | $ | 1,275 | $ | 1,474 | ||||
| Receipt (payment) on settlements of commodity derivatives | $ | 24 | $ | (175 | ) | |||
| Average realized oil price per barrel (excluding derivative settlements) | $ | 58.26 | $ | 66.11 | ||||
| Average realized oil price per barrel (including derivative settlements) | 59.40 | 57.91 | ||||||
| Total production (BOE/d) | 58,213 | 60,341 | ||||||
| Total continuing production (BOE/d)(3) | 57,999 | 59,615 | ||||||
________________
| (1) | A non-GAAP measure. See accompanying schedules that reconcile GAAP to non-GAAP measures along with a statement indicating why the Company believes the non-GAAP measures provide useful information for investors. |
| (2) | Calculated using average diluted shares outstanding of 571.0 million, 547.2 million, and 456.7 million for the three months ended December 31, 2019, September 30, 2019 and December 31, 2018, respectively, and 510.3 million and 456.2 million for the years ended December 31, 2019 and 2018, respectively. |
| (3) | Continuing production excludes production from Citronelle Field sold on July 1, 2019 and production from Lockhart Crossing Field sold in the third quarter of 2018. |
MANAGEMENT COMMENT
Chris Kendall, Denbury's President and CEO, commented, "Denbury's fourth quarter 2019 results round out an exceptional year for the Company. Through the sustained focus of our dedicated teams, we beat our targets for all key performance measures, including safety, production, and all expense categories, and we achieved our highest free cash flow level since 2015. We also took significant steps towards further reducing our debt and strengthening our balance sheet.
"As we move into 2020, we are intently focused on our highest priorities of addressing 2021 and 2022 debt maturities, spending within cash flow, further reducing debt and strengthening our balance sheet, progressing our development programs, and above all else, operating safely and as a responsible corporate citizen. Given these priorities, we have divided our 2020 capital plan into two parts: a base plan and a contingent portion. The base plan allocates $175 million to $185 million primarily to high return capital projects within our existing portfolio, with an additional contingent $140 million to $150 million allocated to Cedar Creek Anticline EOR development. While we expect to proceed with the contingent CCA investment in 2020, considering the current market uncertainty and our focus on addressing 2021 and 2022 debt maturities, and with the bulk of our CCA capital investment planned for the second half of the year, we have decided that the best path forward is to defer the investment decision on this contingent portion of our capital budget until the second quarter.
"The combination of qualities that Denbury possesses is unique in the industry. Our oil-weighted, low-decline, high-margin asset base creates the foundation of a business that has the capability to generate significant free cash flow. But what truly distinguishes and sets us apart is our ability to reduce CO2 emissions as part of our core business. I'm pleased to share that the Scope One and Scope Two emissions associated with Denbury's operations have been carbon negative for several years, as we offset those emissions by annually injecting more than three million tons of industrial CO2 into the ground as part of our enhanced oil recovery process. Importantly, we believe Denbury's business has the potential to also fully offset the Scope Three emissions generated by the refining and end use of the hydrocarbons we produce. We believe this can be accomplished through Denbury's strategy of leveraging our expertise and our strategic assets into a growing carbon capture, use, and storage industry. As this new industry evolves, we see the opportunity to fully offset our Scope One, Scope Two, and Scope Three emissions within this decade, a goal that we believe is both achievable and sustainable."
REVIEW OF OPERATING AND FINANCIAL RESULTS
Denbury's oil and natural gas production averaged 57,511 BOE/d during fourth quarter 2019, an increase of 2% from the third quarter of 2019 (the "prior quarter") and a decrease of 3% compared to continuing production in the prior-year fourth quarter. The sequential-quarter increase was primarily due to higher production at Bell Creek Field, where production was reduced in the prior quarter due to planned maintenance at the Company's primary CO2 source in the Rocky Mountain region. On an annual basis, Denbury's 2019 total production averaged 58,213 BOE/d, in the top half of the Company's original 2019 guidance range of 56,000 BOE/d to 60,000 BOE/d, despite the sale of Citronelle Field in mid-2019, and in-line with the mid-point of the Company's mid-year updated 2019 production guidance range. Further production information is provided on page 19 of this press release.
Denbury's fourth quarter 2019 average realized oil price, including derivative contracts, was $58.30 per Bbl, a 2% decrease from the prior quarter and a 5% increase from the prior-year fourth quarter. Denbury's NYMEX differential for the fourth quarter 2019 was $0.44 per Bbl below NYMEX WTI oil prices, compared to $1.30 per Bbl above NYMEX WTI in the prior quarter and $1.69 per Bbl above NYMEX WTI in the fourth quarter 2018. The sequential decrease was primarily attributable to a lower Gulf Coast premium in the fourth quarter of 2019, which represents approximately 60% of the Company's crude oil production.
Total lease operating expenses in fourth quarter 2019 were $116 million, a decrease of $2 million, or 2%, on a sequential-quarter basis, and a decrease of $12 million, or 10%, compared to fourth quarter 2018. The sequential-quarter decrease was primarily due to lower contract labor costs, and the year-over-year decrease was primarily due to lower workover expense and lower CO2 costs. For full-year 2019, lease operating expenses averaged $22.46 per BOE, at the lower end of the Company's original guidance range of $22-$24 per BOE.
General and administrative ("G&A") expenses, excluding $19 million of severance expense in the fourth quarter associated with a voluntary separation program ("VSP"), were $10 million for the fourth quarter of 2019 and $64 million for full-year 2019. These G&A expense amounts represent a decrease of $9 million compared to the third quarter of 2019 and $7 million, or 10%, compared to full-year 2018, with a significant portion of the decrease due to lower compensation and employee related costs. The Company expects ongoing annual savings of $21 million from the VSP, spread across G&A expense, lease operating expense and capital.
The Company recorded a $50 million noncash gain on debt extinguishment during fourth quarter 2019 as part of a series of debt exchanges, whereby the Company repurchased $101 million principal amount of previously outstanding senior subordinated notes for $11 million of cash and issuance of 38 million shares of the Company's common stock.
Interest expense, net of capitalized interest, totaled $21 million in fourth quarter 2019, a decrease of $2 million from the prior quarter and an increase of $3 million from fourth quarter 2018. The increase from the fourth quarter of 2018 was primarily due to increased noncash amortization of debt discounts resulting from the 2019 debt exchange transactions. A schedule detailing the components of interest expense is included on page 21 of this press release.
Depletion, depreciation, and amortization ("DD&A") increased to $63 million during fourth quarter 2019, compared to $55 million in the third quarter of 2019 and $60 million in fourth quarter 2018. The sequential-quarter increase was primarily due to lower depletion on CO2 assets during the prior quarter resulting from lower CO2 production in the Rocky Mountain region, and the increase compared to the prior-year fourth quarter was due primarily to an increase in depletable costs and lower reserve volumes.
Other expenses were $3 million in the fourth quarter of 2019, compared to $74 million in the fourth quarter of 2018, as the prior-year period included (1) a $49 million accrued expense associated with a trial court's unfavorable ruling related to the non-delivery of helium volumes from the Company's Riley Ridge Unit under a helium supply contract and (2) an $18 million impairment for an investment in a proposed plant in the Gulf Coast that would potentially supply CO2 to Denbury, given uncertainties of the project achieving financial close.
Denbury's effective tax rates for the fourth quarter and full-year 2019 were 35% and 32%, respectively, higher than the Company's statutory rate of 25% due primarily to a valuation allowance applied against a portion of the Company's business interest expense deduction that it estimates will be disallowed in the current year as a result of limitations enacted under the Tax Cuts and Jobs Act. The Company currently forecasts that its effective tax rate for 2020 will be approximately 32%, depending in part on taxable income.
2019 PROVED RESERVES
The Company's total estimated proved oil and natural gas reserves at December 31, 2019 were 230 million BOE, consisting of 226 million barrels of crude oil, condensate and natural gas liquids (together, "liquids"), and 24 billion cubic feet (4 million BOE) of natural gas. Reserves were 98% liquids and 90% proved developed, with 60% of total proved reserves attributable to Denbury's CO2 tertiary operations. Total proved reserves declined by a net 32 million BOE during 2019 primarily due to 21 MMBOE of production, 10 MMBOE of revisions of previous estimates primarily associated with changes in commodity prices, and 2 MMBOE of properties sold during the year.
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