PLANO, Texas, Feb. 25, 2020 (GLOBE NEWSWIRE) -- Denbury Resources Inc. (NYSE: DNR) (“Denbury” or the “Company”) 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”)
________________
| (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 |
|
________________
| (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.
The following table details changes in the Company’s estimated quantities of proved reserves:
|
|
Oil
(MMBbl) |
|
Gas
(Bcf) |
|
MMBOE |
|
PV-10 Value(1) |
| Balance at December 31, 2018 |
|
255 |
|
|
43 |
|
|
262 |
|
|
$ |
4.0 |
billion |
| Revisions of previous estimates |
|
(7 |
) |
|
(16 |
) |
|
(10 |
) |
|
|
| Improved recovery |
|
1 |
|
|
— |
|
|
1 |
|
|
|
| 2019 production |
|
(21 |
) |
|
(3 |
) |
|
(21 |
) |
|
|
| Sales of minerals in place |
|
(2 |
) |
|
— |
|
|
(2 |
) |
|
|
| Balance at December 31, 2019 |
|
226 |
|
|
24 |
|
|
230 |
|
|
$ |
2.6 |
billion |
| (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. |
Year-end 2019 estimated proved reserves and the discounted net present value of Denbury’s proved reserves, using a 10% per annum discount rate (“PV-10 Value”)(1) (a non-GAAP measure), were computed using first-day-of-the-month 12-month average prices of $55.69 per Bbl for oil (based on NYMEX prices) and $2.58 per million British thermal unit (“MMBtu”) for natural gas (based on Henry Hub cash prices), adjusted for prices received at the field. Comparative prices for 2018 were $65.56 per Bbl of oil and $3.10 per MMBtu for natural gas, adjusted for prices received at the field. The PV-10 Value(1) of Denbury’s proved reserves was $2.6 billion at December 31, 2019, compared to $4.0 billion at December 31, 2018. The standardized measure of discounted estimated future net cash flows after income taxes of Denbury’s proved reserves at December 31, 2019 (“Standardized Measure”) was $2.3 billion compared to $3.4 billion at December 31, 2018. See the accompanying schedules for an explanation of the difference between PV-10 Value(1) and the Standardized Measure and the uses of this information.
Denbury’s estimated proved CO2 reserves at Jackson Dome at year-end 2019, on a gross or 8/8th’s basis for operated fields, together with its overriding royalty interest in LaBarge Field in Wyoming, totaled 5.9 trillion cubic feet (“Tcf”), slightly lower than CO2 reserves of 6.1 Tcf as of December 31, 2018 due to 2019 production. Of these total CO2 reserves, 4.8 Tcf are located in the Gulf Coast region and 1.1 Tcf in the Rocky Mountain region.
2020 CAPITAL BUDGET AND ESTIMATED PRODUCTION
Denbury’s base 2020 capital budget, excluding acquisitions and capitalized interest, is between $175 million and $185 million, with an additional $140 million to $150 million of capital for the CCA CO2 tertiary flood development conditioned upon ongoing review and assessment of oil price movements, the Company’s capital financial resources and liquidity, and Board approval. The Company expects to make a final decision on its 2020 capital spending level in the second quarter of 2020. The 2020 base capital budget provides for approximate spending as follows:
- $75 million for tertiary oil field expenditures;
- $55 million for other areas, primarily non-tertiary oil field expenditures including exploitation;
- $10 million for CO2 sources and pipelines; and
- $40 million for other capital items such as capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.
An additional $140 million to $150 million of CCA CO2 tertiary flood development capital is subject to Board approval. The aggregate planned 2020 CCA tertiary-related development capital consists of approximately $105 million for the 105-mile extension of the Greencore Pipeline to CCA, with the remainder dedicated to facilities, well work and field development. In addition, capitalized interest for 2020 is estimated between $40 million and $45 million. At this spending level and after adjusting for the Pending Gulf Coast Working Interests Sale, the Company currently anticipates 2020 production of between 53,000 and 56,000 BOE/d. The anticipated 2020 production level compares to our 2019 average continuing production rate of approximately 56,900 BOE/d after adjusting 2019 production for 2019 property divestitures and the Pending Gulf Coast Working Interests Sale.
The Company expects to generate upwards of $100 million of free cash flow in 2020 if only the base development budget is executed, and would expect capital spending to be approximately neutral with cash flow and other cash resources (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.
FOURTH QUARTER AND FULL-YEAR 2019 RESULTS CONFERENCE CALL INFORMATION
Denbury management will host a conference call to review and discuss fourth quarter and full-year 2019 financial and operating results, together with its financial and operating outlook for 2020, today, Tuesday, February 25, at 10:00 A.M. (Central). Additionally, Denbury will post presentation materials on its website which will be referenced during the conference call. Individuals who would like to participate should dial 877.705.6003 or 201.493.6725 ten minutes before the scheduled start time. To access a live webcast of the conference call and accompanying slide presentation, please visit the investor relations section of the Company’s website at www.denbury.com. The webcast will be archived on the website, and a telephonic replay will be accessible for approximately one month after the call by dialing 844.512.2921 or 412.317.6671 and entering confirmation number 13696091.
Denbury is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions. The Company’s goal is to increase the value of its properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO2 enhanced oil recovery operations. For more information about Denbury, please visit www.denbury.com.
This press release, other than historical financial information, contains forward-looking statements that involve risks and uncertainties including estimated ranges for 2020 production, capital expenditures and free cash flow, and other risks and uncertainties detailed in the Company’s filings with the Securities and Exchange Commission, including Denbury’s most recent report on Form 10-K. These risks and uncertainties are incorporated by this reference as though fully set forth herein. These statements are based on engineering, geological, financial and operating assumptions that management believes are reasonable based on currently available information; however, management’s assumptions and the Company’s future performance are both subject to a wide range of business risks, and there is no assurance that these goals and projections can or will be met. Actual results may vary materially. In addition, any forward-looking statements represent the Company’s estimates only as of today and should not be relied upon as representing its estimates as of any future date. Denbury assumes no obligation to update its forward-looking statements.
FINANCIAL AND STATISTICAL DATA TABLES AND RECONCILIATION SCHEDULES
Following are unaudited financial highlights for the comparative three month and annual periods ended December 31, 2019 and 2018 and the three month period ended September 30, 2019. All production volumes and dollars are expressed on a net revenue interest basis with gas volumes converted to equivalent barrels at 6:1.
DENBURY RESOURCES INC.
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
The following information is based on GAAP reported earnings, with additional required disclosures included in the Company’s Form 10-K:
|
|
Quarter Ended |
|
Year Ended |
|
|
December 31, |
|
Sept. 30, |
|
December 31, |
| In thousands, except per-share data |
|
2019 |
|
2018 |
|
2019 |
|
2019 |
|
2018 |
| Revenues and other income |
|
|
|
|
|
|
|
|
|
|
| Oil sales |
|
$ |
292,447 |
|
|
$ |
324,337 |
|
|
$ |
292,100 |
|
|
$ |
1,205,083 |
|
|
$ |
1,412,358 |
|
| Natural gas sales |
|
1,383 |
|
|
3,038 |
|
|
1,092 |
|
|
6,937 |
|
|
10,231 |
|
| CO2 sales and transportation fees |
|
8,610 |
|
|
8,729 |
|
|
8,976 |
|
|
34,142 |
|
|
31,145 |
|
| Purchased oil sales |
|
5,924 |
|
|
253 |
|
|
5,468 |
|
|
14,198 |
|
|
1,921 |
|
| Other income |
|
2,249 |
|
|
1,998 |
|
|
7,817 |
|
|
14,523 |
|
|
17,970 |
|
| Total revenues and other income |
|
310,613 |
|
|
338,355 |
|
|
315,453 |
|
|
1,274,883 |
|
|
1,473,625 |
|
| Expenses |
|
|
|
|
|
|
|
|
|
|
| Lease operating expenses |
|
116,015 |
|
|
128,453 |
|
|
117,850 |
|
|
477,220 |
|
|
489,720 |
|
| Transportation and marketing expenses |
|
9,734 |
|
|
12,271 |
|
|
10,067 |
|
|
41,810 |
|
|
43,942 |
|
| CO2 discovery and operating expenses |
|
906 |
|
|
1,146 |
|
|
879 |
|
|
2,922 |
|
|
2,816 |
|
| Taxes other than income |
|
22,440 |
|
|
22,773 |
|
|
22,010 |
|
|
93,752 |
|
|
104,670 |
|
| Purchased oil expenses |
|
5,911 |
|
|
250 |
|
|
5,436 |
|
|
14,124 |
|
|
1,676 |
|
| General and administrative expenses |
|
28,332 |
|
|
10,272 |
|
|
18,266 |
|
|
83,029 |
|
|
71,495 |
|
| Interest, net of amounts capitalized of $9,126, $10,262, $8,773, $36,671 and $37,079, respectively |
|
20,960 |
|
|
17,714 |
|
|
22,858 |
|
|
81,632 |
|
|
69,688 |
|
| Depletion, depreciation, and amortization |
|
63,191 |
|
|
59,738 |
|
|
55,064 |
|
|
233,816 |
|
|
216,449 |
|
| Commodity derivatives expense (income) |
|
54,616 |
|
|
(210,688 |
) |
|
(43,155 |
) |
|
70,078 |
|
|
(21,087 |
) |
| Gain on debt extinguishment |
|
(49,778 |
) |
|
— |
|
|
(5,874 |
) |
|
(155,998 |
) |
|
— |
|
| Other expenses |
|
2,523 |
|
|
73,781 |
|
|
2,140 |
|
|
11,187 |
|
|
84,325 |
|
| Total expenses |
|
274,850 |
|
|
115,710 |
|
|
205,541 |
|
|
953,572 |
|
|
1,063,694 |
|
| Income before income taxes |
|
35,763 |
|
|
222,645 |
|
|
109,912 |
|
|
321,311 |
|
|
409,931 |
|
| Income tax provision (benefit) |
|
|
|
|
|
|
|
|
|
|
| Current income taxes |
|
2,667 |
|
|
(12,327 |
) |
|
(859 |
) |
|
3,881 |
|
|
(16,001 |
) |
| Deferred income taxes |
|
10,017 |
|
|
60,493 |
|
|
37,909 |
|
|
100,471 |
|
|
103,234 |
|
| Net income |
|
$ |
23,079 |
|
|
$ |
174,479 |
|
|
$ |
72,862 |
|
|
$ |
216,959 |
|
|
$ |
322,698 |
|
|
|
|
|
|
|
|
|
|
|
|
| Net income per common share |
|
|
|
|
|
|
|
|
|
|
| Basic |
|
$ |
0.05 |
|
|
$ |
0.39 |
|
|
$ |
0.16 |
|
|
$ |
0.47 |
|
|
$ |
0.75 |
|
| Diluted |
|
$ |
0.05 |
|
|
$ |
0.38 |
|
|
$ |
0.14 |
|
|
$ |
0.45 |
|
|
$ |
0.71 |
|
|
|
|
|
|
|
|
|
|
|
|
| Weighted average common shares outstanding |
|
|
|
|
|
|
|
|
|
|
| Basic |
|
478,030 |
|
|
451,613 |
|
|
455,487 |
|
|
459,524 |
|
|
432,483 |
|
| Diluted |
|
571,000 |
|
|
456,665 |
|
|
547,205 |
|
|
510,341 |
|
|
456,169 |
|
DENBURY RESOURCES INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
Year Ended |
|
|
December 31, |
| In thousands |
|
2019 |
|
2018 |
| Cash flows from operating activities |
|
|
|
|
| Net income |
|
$ |
216,959 |
|
|
$ |
322,698 |
|
| Adjustments to reconcile net income to cash flows from operating activities |
|
|
|
|
| Depletion, depreciation, and amortization |
|
233,816 |
|
|
216,449 |
|
| Deferred income taxes |
|
100,471 |
|
|
103,234 |
|
| Stock-based compensation |
|
12,470 |
|
|
11,951 |
|
| Commodity derivatives expense (income) |
|
70,078 |
|
|
(21,087 |
) |
| Receipt (payment) on settlements of commodity derivatives |
|
23,606 |
|
|
(175,248 |
) |
| Gain on debt extinguishment |
|
(155,998 |
) |
|
— |
|
| Debt issuance costs and discounts |
|
12,303 |
|
|
6,246 |
|
| Other, net |
|
(8,596 |
) |
|
(4,725 |
) |
| Changes in assets and liabilities, net of effects from acquisitions |
|
|
|
|
| Accrued production receivable |
|
(13,619 |
) |
|
20,547 |
|
| Trade and other receivables |
|
9,379 |
|
|
16,094 |
|
| Other current and long-term assets |
|
7,629 |
|
|
(6,827 |
) |
| Accounts payable and accrued liabilities |
|
(3,275 |
) |
|
13,008 |
|
| Oil and natural gas production payable |
|
2,170 |
|
|
(15,300 |
) |
| Other liabilities |
|
(13,250 |
) |
|
42,645 |
|
| Net cash provided by operating activities |
|
494,143 |
|
|
529,685 |
|
|
|
|
|
|
| Cash flows from investing activities |
|
|
|
|
| Oil and natural gas capital expenditures |
|
(262,005 |
) |
|
(316,647 |
) |
| Acquisitions of oil and natural gas properties |
|
(79 |
) |
|
(541 |
) |
| CO2 capital expenditures |
|
(3,154 |
) |
|
(5,878 |
) |
| Pipelines and plants capital expenditures |
|
(27,319 |
) |
|
(23,108 |
) |
| Net proceeds from sales of oil and natural gas properties and equipment |
|
10,196 |
|
|
7,762 |
|
| Other |
|
12,669 |
|
|
5,136 |
|
| Net cash used in investing activities |
|
(269,692 |
) |
|
(333,276 |
) |
|
|
|
|
|
| Cash flows from financing activities |
|
|
|
|
| Bank repayments |
|
(925,791 |
) |
|
(1,982,653 |
) |
| Bank borrowings |
|
925,791 |
|
|
1,507,653 |
|
| Interest payments treated as a reduction of debt |
|
(85,303 |
) |
|
(79,606 |
) |
| Proceeds from issuance of senior secured notes |
|
— |
|
|
450,000 |
|
| Cash paid in conjunction with debt exchange |
|
(136,427 |
) |
|
— |
|
| Costs of debt financing |
|
(11,065 |
) |
|
(16,060 |
) |
| Pipeline financing and capital lease debt repayments |
|
(13,908 |
) |
|
(23,300 |
) |
| Other |
|
348 |
|
|
(13,486 |
) |
| Net cash provided by (used in) financing activities |
|
(246,355 |
) |
|
(157,452 |
) |
| Net increase (decrease) in cash, cash equivalents, and restricted cash |
|
(21,904 |
) |
|
38,957 |
|
| Cash, cash equivalents, and restricted cash at beginning of year |
|
54,949 |
|
|
15,992 |
|
| Cash, cash equivalents, and restricted cash at end of year |
|
$ |
33,045 |
|
|
$ |
54,949 |
|
DENBURY RESOURCES INC.
SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (UNAUDITED)
Reconciliation of net income (GAAP measure) to adjusted net income (non-GAAP measure)
Adjusted net income is a non-GAAP measure provided as a supplement to present an alternative net income measure which excludes expense and income items (and their related tax effects) not directly related to the Company’s ongoing operations. Management believes that adjusted net income may be helpful to investors by eliminating the impact of noncash and/or special items not indicative of the Company’s performance from period to period, and is widely used by the investment community, while also being used by management, in evaluating the comparability of the Company’s ongoing operational results and trends. Adjusted net income should not be considered in isolation, as a substitute for, or more meaningful than, net income or any other measure reported in accordance with GAAP, but rather to provide additional information useful in evaluating the Company’s operational trends and performance.
|
|
Quarter Ended |
|
|
December 31, |
|
September 30, |
|
|
2019 |
|
2018 |
|
2019 |
| In thousands |
|
Amount |
|
Per Diluted Share |
|
Amount |
|
Per Diluted Share |
|
Amount |
|
Per Diluted Share |
| Net income (GAAP measure)(1) |
|
$ |
23,079 |
|
|
$ |
0.05 |
|
|
$ |
174,479 |
|
|
$ |
0.38 |
|
|
$ |
72,862 |
|
|
$ |
0.14 |
|
| Noncash fair value losses (gains) on commodity derivatives(2) |
|
63,508 |
|
|
0.11 |
|
|
(236,198 |
) |
|
(0.52 |
) |
|
(35,098 |
) |
|
(0.06 |
) |
| Gain on debt extinguishment(3) |
|
(49,778 |
) |
|
(0.09 |
) |
|
— |
|
|
— |
|
|
(5,874 |
) |
|
(0.01 |
) |
| Accrued expense related to litigation over a helium supply contract (included in other expenses)(4) |
|
— |
|
|
— |
|
|
49,373 |
|
|
0.11 |
|
|
— |
|
|
— |
|
| Impairment of loan receivable and related assets (included in other expenses)(5) |
|
— |
|
|
— |
|
|
17,805 |
|
|
0.04 |
|
|
— |
|
|
— |
|
| Acquisition transaction costs related to Penn Virginia transaction (included in other expenses) |
|
— |
|
|
— |
|
|
4,373 |
|
|
0.01 |
|
|
— |
|
|
— |
|
| Severance-related expense included in general and administrative expenses(6) |
|
18,627 |
|
|
0.03 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
| Other(7) |
|
(803 |
) |
|
0.00 |
|
|
1,300 |
|
|
0.00 |
|
|
(5,247 |
) |
|
(0.01 |
) |
| Estimated income taxes on above adjustments to net income and other discrete tax items(8) |
|
(7,846 |
) |
|
(0.01 |
) |
|
35,282 |
|
|
0.08 |
|
|
14,499 |
|
|
0.02 |
|
| Adjusted net income (non-GAAP measure) |
|
$ |
46,787 |
|
|
$ |
0.09 |
|
|
$ |
46,414 |
|
|
$ |
0.10 |
|
|
$ |
41,142 |
|
|
$ |
0.08 |
|
|
|
Year Ended |
|
|
December 31, |
|
|
2019 |
|
2018 |
| In thousands |
|
Amount |
|
Per Diluted Share |
|
Amount |
|
Per Diluted Share |
| Net income (GAAP measure)(1) |
|
$ |
216,959 |
|
|
$ |
0.45 |
|
|
$ |
322,698 |
|
|
$ |
0.71 |
|
| Noncash fair value losses (gains) on commodity derivatives(2) |
|
93,684 |
|
|
0.18 |
|
|
(196,335 |
) |
|
(0.43 |
) |
| Gain on debt extinguishment(3) |
|
(155,998 |
) |
|
(0.31 |
) |
|
— |
|
|
— |
|
| Accrued expense related to litigation over a helium supply contract (included in other expenses)(4) |
|
— |
|
|
— |
|
|
49,373 |
|
|
0.11 |
|
| Impairment of loan receivable and related assets (included in other expenses)(5) |
|
— |
|
|
— |
|
|
17,805 |
|
|
0.04 |
|
| Acquisition transaction costs related to Penn Virginia transaction (included in other expenses) |
|
— |
|
|
— |
|
|
4,373 |
|
|
0.01 |
|
| Severance-related expense included in general and administrative expenses(6) |
|
18,627 |
|
|
0.04 |
|
|
— |
|
|
— |
|
| Other(7) |
|
(1,596 |
) |
|
0.00 |
|
|
4,846 |
|
|
0.01 |
|
| Estimated income taxes on above adjustments to net income and other discrete tax items(8) |
|
20,637 |
|
|
0.04 |
|
|
17,602 |
|
|
0.03 |
|
| Adjusted net income (non-GAAP measure) |
|
$ |
192,313 |
|
|
$ |
0.40 |
|
|
$ |
220,362 |
|
|
$ |
0.48 |
|
| (1) |
Diluted net income per common share includes the impact of potentially dilutive securities including nonvested restricted stock, nonvested performance-based equity awards, and shares into which the Company’s convertible senior notes are convertible. The basic and diluted earnings per share calculations are included on page 13. |
| (2) |
The net change between periods of the fair market values of open commodity derivative positions, excluding the impact of settlements on commodity derivatives during the period. |
| (3) |
Gain on debt extinguishment related to the Company’s 2019 debt exchanges and open market repurchases. |
| (4) |
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. The accrual represents the aggregate cap of contractual liquidated damages the Company would be required to pay of $46 million, plus other costs associated with the settlement of approximately $3 million through December 31, 2018. |
| (5) |
Impairment of an outstanding loan receivable and related assets related to the development of a proposed plant in the Gulf Coast that would potentially supply CO2 to Denbury, due to uncertainties of the project achieving financial close. |
| (6) |
Severance-related expense associated with the Company’s voluntary separation program. |
| (7) |
Other adjustments include (a) $2 million gain on land sales, <$1 million of expense related to an impairment of assets, and <$1 million of costs associated with the helium supply contract ruling, (b) $1 million of costs related to the Company’s land sales during the three months ended December 31, 2018, and (c) $6 million gain on land sales, <$1 million of transaction costs related to the Company’s privately negotiated debt exchanges, and <$1 million of costs associated with the helium supply contract ruling during the three months ended September 30, 2019. The year-ended December 31, 2019 was further impacted by $1 million of transaction costs related to the Company’s privately negotiated debt exchanges, $1 million of expense related to an impairment of assets, and $1 million of costs associated with the helium supply contract ruling. The year-ended December 31, 2018 was further impacted by a $4 million gain on land sales, offset by a similar amount of other expense accrued for litigation matters, $2 million of transaction costs related to the Company’s privately negotiated debt exchanges, and $2 million write-off of debt issuance costs associated with the Company’s 2018 reduction and extension of the senior secured bank credit facility, |
| (8) |
The estimated income tax impacts on adjustments to net income are generally computed based upon a statutory rate of 25% with the exception of (1) the periodic tax impacts of a shortfall (benefit) on the stock-based compensation deduction which totaled $0.1 million, ($0.1) million and $2 million during the three months ended December 31, 2019, December 30, 2018 and September 30, 2019, respectively, and $2 million and ($2) million for the years ended December 31, 2019 and 2018, respectively, and (2) tax benefits for enhanced oil recovery income tax credits of $5 million and $11 million for the three and twelve months ended December 31, 2018, respectively. In addition to these items, the Company recorded $9 million of valuation allowances established against a portion of the Company’s business interest expense deduction during the year ended December 31, 2019. |
BASIC AND DILUTED NET INCOME PER COMMON SHARE
|
|
Quarter Ended |
|
|
December 31, |
|
September 30, |
|
|
2019 |
|
2018 |
|
2019 |
| In thousands, except per-share data |
|
Amount |
|
Per Share |
|
Amount |
|
Per Share |
|
Amount |
|
Per Share |
| Numerator |
|
|
|
|
|
|
|
|
|
|
|
|
| Net income – basic |
|
$ |
23,079 |
|
|
$ |
0.05 |
|
|
$ |
174,479 |
|
|
$ |
0.39 |
|
|
$ |
72,862 |
|
|
$ |
0.16 |
|
| Effect of potentially dilutive securities |
|
|
|
|
|
|
|
|
|
|
|
|
| Interest on convertible senior notes, net of tax |
|
6,685 |
|
|
|
|
— |
|
|
|
|
5,101 |
|
|
|
| Net income – diluted |
|
$ |
29,764 |
|
|
$ |
0.05 |
|
|
$ |
174,479 |
|
|
$ |
0.38 |
|
|
$ |
77,963 |
|
|
$ |
0.14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Denominator |
|
|
|
|
|
|
|
|
|
|
|
|
| Weighted average common shares outstanding – basic |
|
478,030 |
|
|
|
|
451,613 |
|
|
|
|
455,487 |
|
|
|
| Effect of potentially dilutive securities |
|
|
|
|
|
|
|
|
|
|
|
|
| Restricted stock and performance-based equity awards |
|
2,117 |
|
|
|
|
5,052 |
|
|
|
|
865 |
|
|
|
| Convertible senior notes |
|
90,853 |
|
|
|
|
— |
|
|
|
|
90,853 |
|
|
|
| Weighted average common shares outstanding – diluted |
|
571,000 |
|
|
|
|
456,665 |
|
|
|
|
547,205 |
|
|
|
|
|
Year Ended |
|
|
December 31, |
|
|
2019 |
|
2018 |
| In thousands, except per-share data |
|
Amount |
|
Per Share |
|
Amount |
|
Per Share |
| Numerator |
|
|
|
|
|
|
|
|
| Net income – basic |
|
$ |
216,959 |
|
|
$ |
0.47 |
|
|
$ |
322,698 |
|
|
$ |
0.75 |
|
| Effect of potentially dilutive securities |
|
|
|
|
|
|
|
|
| Interest on convertible senior notes, net of tax |
|
14,134 |
|
|
|
|
539 |
|
|
|
| Net income – diluted |
|
$ |
231,093 |
|
|
$ |
0.45 |
|
|
$ |
323,237 |
|
|
$ |
0.71 |
|
|
|
|
|
|
|
|
|
|
| Denominator |
|
|
|
|
|
|
|
|
| Weighted average common shares outstanding – basic |
|
459,524 |
|
|
|
|
432,483 |
|
|
|
| Effect of potentially dilutive securities |
|
|
|
|
|
|
|
|
| Restricted stock and performance-based equity awards |
|
2,396 |
|
|
|
|
6,500 |
|
|
|
| Convertible senior notes |
|
48,421 |
|
|
|
|
17,186 |
|
|
|
| Weighted average common shares outstanding – diluted |
|
510,341 |
|
|
|
|
456,169 |
|
|
|
DENBURY RESOURCES INC.
SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (UNAUDITED)
Reconciliation of cash flows from operations (GAAP measure) to adjusted cash flows from operations (non-GAAP measure) to adjusted cash flows from operation less special items (non-GAAP measure) and free cash flow (deficit) (non-GAAP measure)
Adjusted cash flows from operations is a non-GAAP measure that represents cash flows provided by operations before changes in assets and liabilities, as summarized from the Company’s Consolidated Statements of Cash Flows. Adjusted cash flows from operations measures the cash flows earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables. Adjusted cash flows from operations less special items is an additional non-GAAP measure that removes other special items. Free cash flow is a non-GAAP measure that represents adjusted cash flows from operations less special items and interest treated as debt reduction, development capital expenditures and capitalized interest, but before acquisitions. Management believes that it is important to consider these additional measures, along with cash flows from operations, as it believes the non-GAAP measures can often be a better way to discuss changes in operating trends in its business caused by changes in production, prices, operating costs and related factors, without regard to whether the earned or incurred item was collected or paid during that period.
|
|
Quarter Ended |
|
Year Ended |
| In thousands |
|
December 31, |
|
Sept. 30, |
|
December 31, |
|
2019 |
|
2018 |
|
2019 |
|
2019 |
|
2018 |
| Net income (GAAP measure) |
|
$ |
23,079 |
|
|
$ |
174,479 |
|
|
$ |
72,862 |
|
|
$ |
216,959 |
|
|
$ |
322,698 |
|
| Adjustments to reconcile to adjusted cash flows from operations |
|
|
|
|
|
|
|
|
|
|
| Depletion, depreciation, and amortization |
|
63,191 |
|
|
59,738 |
|
|
55,064 |
|
|
233,816 |
|
|
216,449 |
|
| Deferred income taxes |
|
10,017 |
|
|
60,493 |
|
|
37,909 |
|
|
100,471 |
|
|
103,234 |
|
| Stock-based compensation |
|
2,604 |
|
|
3,240 |
|
|
3,001 |
|
|
12,470 |
|
|
11,951 |
|
| Noncash fair value losses (gains) on commodity derivatives |
|
63,508 |
|
|
(236,198 |
) |
|
(35,098 |
) |
|
93,684 |
|
|
(196,335 |
) |
| Gain on debt extinguishment |
|
(49,778 |
) |
|
— |
|
|
(5,874 |
) |
|
(155,998 |
) |
|
— |
|
| Other |
|
2,962 |
|
|
3,607 |
|
|
(2,099 |
) |
|
3,707 |
|
|
1,521 |
|
| Adjusted cash flows from operations (non-GAAP measure) |
|
115,583 |
|
|
65,359 |
|
|
125,765 |
|
|
505,109 |
|
|
459,518 |
|
| Net change in assets and liabilities relating to operations |
|
34,982 |
|
|
70,796 |
|
|
4,813 |
|
|
(10,966 |
) |
|
70,167 |
|
| Cash flows from operations (GAAP measure) |
|
$ |
150,565 |
|
|
$ |
136,155 |
|
|
$ |
130,578 |
|
|
$ |
494,143 |
|
|
$ |
529,685 |
|
|
|
|
|
|
|
|
|
|
|
|
| Adjusted cash flows from operations (non-GAAP measure) |
|
$ |
115,583 |
|
|
$ |
65,359 |
|
|
$ |
125,765 |
|
|
$ |
505,109 |
|
|
$ |
459,518 |
|
| Accrued expense related to litigation over a helium supply contract |
|
— |
|
|
49,373 |
|
|
— |
|
|
— |
|
|
49,373 |
|
| Impairment of loan receivable and related assets |
|
— |
|
|
17,805 |
|
|
— |
|
|
— |
|
|
17,805 |
|
| Severance-related expense |
|
18,627 |
|
|
— |
|
|
— |
|
|
18,627 |
|
|
— |
|
| Adjusted cash flows from operations less special items (non-GAAP measure) |
|
$ |
134,210 |
|
|
$ |
132,537 |
|
|
$ |
125,765 |
|
|
$ |
523,736 |
|
|
$ |
526,696 |
|
| Interest on notes treated as debt reduction |
|
(21,448 |
) |
|
(21,262 |
) |
|
(21,372 |
) |
|
(85,454 |
) |
|
(86,111 |
) |
| Development capital expenditures |
|
(47,482 |
) |
|
(107,451 |
) |
|
(51,420 |
) |
|
(236,921 |
) |
|
(322,670 |
) |
| Capitalized interest |
|
(9,126 |
) |
|
(10,262 |
) |
|
(8,773 |
) |
|
(36,671 |
) |
|
(37,079 |
) |
| Free cash flow (deficit) (non-GAAP measure) |
|
$ |
56,154 |
|
|
$ |
(6,438 |
) |
|
$ |
44,200 |
|
|
$ |
164,690 |
|
|
$ |
80,836 |
|
DENBURY RESOURCES INC.
SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (UNAUDITED)
Reconciliation of commodity derivatives income (expense) (GAAP measure) to noncash fair value gains (losses) on commodity derivatives (non-GAAP measure)
Noncash fair value adjustments on commodity derivatives is a non-GAAP measure and is different from “Commodity derivatives expense (income)” in the Consolidated Statements of Operations in that the noncash fair value gains (losses) on commodity derivatives represents only the net change between periods of the fair market values of open commodity derivative positions, and excludes the impact of settlements on commodity derivatives during the period. Management believes that noncash fair value gains (losses) on commodity derivatives is a useful supplemental disclosure to “Commodity derivatives expense (income)” because the GAAP measure also includes settlements on commodity derivatives during the period; the non-GAAP measure is widely used within the industry and by securities analysts, banks and credit rating agencies in calculating EBITDA and in adjusting net income to present those measures on a comparative basis across companies, as well as to assess compliance with certain debt covenants.
|
|
Quarter Ended |
|
Year Ended |
|
|
December 31, |
|
Sept. 30, |
|
December 31, |
| In thousands |
|
2019 |
|
2018 |
|
2019 |
|
2019 |
|
2018 |
| Receipt (payment) on settlements of commodity derivatives |
|
$ |
8,892 |
|
|
$ |
(25,510 |
) |
|
$ |
8,057 |
|
|
$ |
23,606 |
|
|
$ |
(175,248 |
) |
| Noncash fair value gains (losses) on commodity derivatives (non-GAAP measure) |
|
(63,508 |
) |
|
236,198 |
|
|
35,098 |
|
|
(93,684 |
) |
|
196,335 |
|
| Commodity derivatives income (expense) (GAAP measure) |
|
$ |
(54,616 |
) |
|
$ |
210,688 |
|
|
$ |
43,155 |
|
|
$ |
(70,078 |
) |
|
$ |
21,087 |
|
DENBURY RESOURCES INC.
SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (UNAUDITED)
Reconciliation of net income (GAAP measure) to Adjusted EBITDAX (non-GAAP measure)
Adjusted EBITDAX is a non-GAAP financial measure which management uses and is calculated based upon (but not identical to) a financial covenant related to “Consolidated EBITDAX” in the Company’s senior secured bank credit facility, which excludes certain items that are included in net income, the most directly comparable GAAP financial measure. Items excluded include interest, income taxes, depletion, depreciation, and amortization, and items that the Company believes affect the comparability of operating results such as items whose timing and/or amount cannot be reasonably estimated or are non-recurring. Management believes Adjusted EBITDAX may be helpful to investors in order to assess the Company’s operating performance as compared to that of other companies in our industry, without regard to financing methods, capital structure or historical costs basis. It is also commonly used by third parties to assess the leverage and the Company’s ability to incur and service debt and fund capital expenditures. Adjusted EBITDAX should not be considered in isolation, as a substitute for, or more meaningful than, net income, cash flows from operations, or any other measure reported in accordance with GAAP. The Company’s Adjusted EBITDAX may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDAX, EBITDAX, or EBITDA in the same manner. The following table presents a reconciliation of our net income to Adjusted EBITDAX.
|
|
Quarter Ended |
|
Year Ended |
| In thousands |
|
December 31, |
|
Sept. 30, |
|
December 31, |
|
2019 |
|
2018 |
|
2019 |
|
2019 |
|
2018 |
| Net income (GAAP measure) |
|
$ |
23,079 |
|
|
$ |
174,479 |
|
|
$ |
72,862 |
|
|
$ |
216,959 |
|
|
$ |
322,698 |
|
| Adjustments to reconcile to Adjusted EBITDAX |
|
|
|
|
|
|
|
|
|
|
| Interest expense |
|
20,960 |
|
|
17,714 |
|
|
22,858 |
|
|
81,632 |
|
|
69,688 |
|
| Income tax expense |
|
12,684 |
|
|
48,166 |
|
|
37,050 |
|
|
104,352 |
|
|
87,233 |
|
| Depletion, depreciation, and amortization |
|
63,191 |
|
|
59,738 |
|
|
55,064 |
|
|
233,816 |
|
|
216,449 |
|
| Noncash fair value losses (gains) on commodity derivatives |
|
63,508 |
|
|
(236,198 |
) |
|
(35,098 |
) |
|
93,684 |
|
|
(196,335 |
) |
| Stock-based compensation |
|
2,604 |
|
|
3,240 |
|
|
3,001 |
|
|
12,470 |
|
|
11,951 |
|
| Gain on debt extinguishment |
|
(49,778 |
) |
|
— |
|
|
(5,874 |
) |
|
(155,998 |
) |
|
— |
|
| Severance-related expense |
|
18,627 |
|
|
— |
|
|
— |
|
|
18,627 |
|
|
— |
|
| Accrued expense related to litigation over a helium supply contract |
|
— |
|
|
49,373 |
|
|
— |
|
|
— |
|
|
49,373 |
|
| Impairment of loan receivable and related assets |
|
— |
|
|
17,805 |
|
|
— |
|
|
— |
|
|
17,805 |
|
| Noncash, non-recurring and other |
|
130 |
|
|
6,643 |
|
|
(4,744 |
) |
|
1,589 |
|
|
5,504 |
|
| Adjusted EBITDAX (non-GAAP measure) |
|
$ |
155,005 |
|
|
$ |
140,960 |
|
|
$ |
145,119 |
|
|
$ |
607,131 |
|
|
$ |
584,366 |
|
DENBURY RESOURCES INC.
SUPPLEMENTAL NON-GAAP FINANCIAL MEASURE (UNAUDITED)
Reconciliation of the standardized measure of discounted estimated future net cash flows after income taxes (GAAP measure) to PV-10 Value (non-GAAP measure)
PV-10 Value is a non-GAAP measure and is different from the Standardized Measure in that PV-10 Value is a pre-tax number and the Standardized Measure is an after-tax number. Denbury’s 2019 and 2018 year-end estimated proved oil and natural gas reserves and proved CO2 reserves quantities were prepared by the independent reservoir engineering firm of DeGolyer and MacNaughton. The information used to calculate PV-10 Value is derived directly from data determined in accordance with FASC Topic 932. Management believes PV-10 Value is a useful supplemental disclosure to the Standardized Measure because the Standardized Measure can be impacted by a company’s unique tax situation, and it is not practical to calculate the Standardized Measure on a property-by-property basis. Because of this, PV-10 Value is a widely used measure within the industry and is commonly used by securities analysts, banks and credit rating agencies to evaluate the estimated future net cash flows from proved reserves on a comparative basis across companies or specific properties. PV-10 Value is commonly used by management and others in the industry to evaluate properties that are bought and sold, to assess the potential return on investment in the Company’s oil and natural gas properties, and to perform impairment testing of oil and natural gas properties. PV-10 Value is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for the Standardized Measure. PV-10 Value and the Standardized Measure do not purport to represent the fair value of the Company’s oil and natural gas reserves.
|
|
December 31, |
| In thousands |
|
2019 |
|
2018 |
| Standardized Measure (GAAP measure) |
|
$ |
2,261,039 |
|
|
$ |
3,351,385 |
|
| Discounted estimated future income tax |
|
354,629 |
|
|
673,754 |
|
| PV-10 Value (non-GAAP measure) |
|
$ |
2,615,668 |
|
|
$ |
4,025,139 |
|
DENBURY RESOURCES INC.
OPERATING HIGHLIGHTS (UNAUDITED)
|
|
Quarter Ended |
|
Year Ended |
|
|
December 31, |
|
Sept. 30, |
|
December 31, |
|
|
2019 |
|
2018 |
|
2019 |
|
2019 |
|
2018 |
| Production (daily – net of royalties) |
|
|
|
|
|
|
|
|
|
|
| Oil (barrels) |
|
56,185 |
|
|
58,266 |
|
|
55,085 |
|
|
56,672 |
|
|
58,532 |
|
| Gas (mcf) |
|
7,954 |
|
|
9,603 |
|
|
8,135 |
|
|
9,246 |
|
|
10,854 |
|
| BOE (6:1) |
|
57,511 |
|
|
59,867 |
|
|
56,441 |
|
|
58,213 |
|
|
60,341 |
|
| Unit sales price (excluding derivative settlements) |
|
|
|
|
|
|
|
|
|
|
| Oil (per barrel) |
|
$ |
56.58 |
|
|
$ |
60.50 |
|
|
$ |
57.64 |
|
|
$ |
58.26 |
|
|
$ |
66.11 |
|
| Gas (per mcf) |
|
1.89 |
|
|
3.44 |
|
|
1.46 |
|
|
2.06 |
|
|
2.58 |
|
| BOE (6:1) |
|
55.53 |
|
|
59.44 |
|
|
56.46 |
|
|
57.04 |
|
|
64.59 |
|
| Unit sales price (including derivative settlements) |
|
|
|
|
|
|
|
|
|
|
| Oil (per barrel) |
|
$ |
58.30 |
|
|
$ |
55.75 |
|
|
$ |
59.23 |
|
|
$ |
59.40 |
|
|
$ |
57.91 |
|
| Gas (per mcf) |
|
1.89 |
|
|
3.44 |
|
|
1.46 |
|
|
2.06 |
|
|
2.58 |
|
| BOE (6:1) |
|
57.21 |
|
|
54.81 |
|
|
58.02 |
|
|
58.15 |
|
|
56.63 |
|
| NYMEX differentials |
|
|
|
|
|
|
|
|
|
|
| Gulf Coast region |
|
|
|
|
|
|
|
|
|
|
| Oil (per barrel) |
|
$ |
0.90 |
|
|
$ |
5.34 |
|
|
$ |
3.11 |
|
|
$ |
3.30 |
|
|
$ |
2.94 |
|
| Gas (per mcf) |
|
0.01 |
|
|
0.24 |
|
|
(0.24 |
) |
|
(0.04 |
) |
|
0.09 |
|
| Rocky Mountain region |
|
|
|
|
|
|
|
|
|
|
| Oil (per barrel) |
|
$ |
(2.48 |
) |
|
$ |
(4.31 |
) |
|
$ |
(1.65 |
) |
|
$ |
(2.01 |
) |
|
$ |
(1.50 |
) |
| Gas (per mcf) |
|
(1.26 |
) |
|
(0.85 |
) |
|
(1.61 |
) |
|
(0.96 |
) |
|
(1.06 |
) |
| Total company |
|
|
|
|
|
|
|
|
|
|
| Oil (per barrel) |
|
$ |
(0.44 |
) |
|
$ |
1.69 |
|
|
$ |
1.30 |
|
|
$ |
1.23 |
|
|
$ |
1.30 |
|
| Gas (per mcf) |
|
(0.52 |
) |
|
(0.29 |
) |
|
(0.87 |
) |
|
(0.47 |
) |
|
(0.49 |
) |
DENBURY RESOURCES INC.
OPERATING HIGHLIGHTS (UNAUDITED)
|
|
Quarter Ended |
|
Year Ended |
|
|
December 31, |
|
Sept. 30, |
|
December 31, |
| Average Daily Volumes (BOE/d) (6:1) |
|
2019 |
|
2018 |
|
2019 |
|
2019 |
|
2018 |
| Tertiary oil production |
|
|
|
|
|
|
|
|
|
|
| Gulf Coast region |
|
|
|
|
|
|
|
|
|
|
| Delhi |
|
4,085 |
|
|
4,526 |
|
|
4,256 |
|
|
4,324 |
|
|
4,368 |
|
| Hastings |
|
5,097 |
|
|
5,480 |
|
|
5,513 |
|
|
5,403 |
|
|
5,596 |
|
| Heidelberg |
|
4,409 |
|
|
4,269 |
|
|
4,297 |
|
|
4,195 |
|
|
4,355 |
|
| Oyster Bayou |
|
4,261 |
|
|
4,785 |
|
|
3,995 |
|
|
4,345 |
|
|
4,843 |
|
| Tinsley |
|
4,343 |
|
|
5,033 |
|
|
4,541 |
|
|
4,608 |
|
|
5,530 |
|
| West Yellow Creek |
|
807 |
|
|
375 |
|
|
728 |
|
|
640 |
|
|
205 |
|
| Mature properties(1) |
|
6,347 |
|
|
6,748 |
|
|
6,415 |
|
|
6,422 |
|
|
6,702 |
|
| Total Gulf Coast region |
|
29,349 |
|
|
31,216 |
|
|
29,745 |
|
|
29,937 |
|
|
31,599 |
|
| Rocky Mountain region |
|
|
|
|
|
|
|
|
|
|
| Bell Creek |
|
5,618 |
|
|
4,421 |
|
|
4,686 |
|
|
5,228 |
|
|
4,113 |
|
| Salt Creek |
|
2,223 |
|
|
2,107 |
|
|
2,213 |
|
|
2,143 |
|
|
2,109 |
|
| Grieve |
|
60 |
|
|
20 |
|
|
58 |
|
|
53 |
|
|
7 |
|
| Total Rocky Mountain region |
|
7,901 |
|
|
6,548 |
|
|
6,957 |
|
|
7,424 |
|
|
6,229 |
|
| Total tertiary oil production |
|
37,250 |
|
|
37,764 |
|
|
36,702 |
|
|
37,361 |
|
|
37,828 |
|
| Non-tertiary oil and gas production |
|
|
|
|
|
|
|
|
|
|
| Gulf Coast region |
|
|
|
|
|
|
|
|
|
|
| Mississippi |
|
952 |
|
|
1,023 |
|
|
873 |
|
|
970 |
|
|
960 |
|
| Texas(2) |
|
4,382 |
|
|
4,319 |
|
|
4,268 |
|
|
4,310 |
|
|
4,546 |
|
| Other |
|
5 |
|
|
6 |
|
|
6 |
|
|
6 |
|
|
13 |
|
| Total Gulf Coast region |
|
5,339 |
|
|
5,348 |
|
|
5,147 |
|
|
5,286 |
|
|
5,519 |
|
| Rocky Mountain region |
|
|
|
|
|
|
|
|
|
|
| Cedar Creek Anticline |
|
13,730 |
|
|
14,961 |
|
|
13,354 |
|
|
14,090 |
|
|
14,837 |
|
| Other |
|
1,192 |
|
|
1,343 |
|
|
1,238 |
|
|
1,262 |
|
|
1,431 |
|
| Total Rocky Mountain region |
|
14,922 |
|
|
16,304 |
|
|
14,592 |
|
|
15,352 |
|
|
16,268 |
|
| Total non-tertiary production |
|
20,261 |
|
|
21,652 |
|
|
19,739 |
|
|
20,638 |
|
|
21,787 |
|
| Total continuing production |
|
57,511 |
|
|
59,416 |
|
|
56,441 |
|
|
57,999 |
|
|
59,615 |
|
| Property sales |
|
|
|
|
|
|
|
|
|
|
| Property divestitures(3) |
|
— |
|
|
451 |
|
|
— |
|
|
214 |
|
|
726 |
|
| Total production |
|
57,511 |
|
|
59,867 |
|
|
56,441 |
|
|
58,213 |
|
|
60,341 |
|
| (1) |
Mature properties include Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb and Soso fields. |
| (2) |
Includes non-tertiary production related to the sale of 50% of our working interests in Webster, Thompson, Manvel, and East Hastings fields, which is expected to close in March 2020 and averaged 1,170 BOE/d and 1,085 BOE/d for the three and twelve months ended December 31, 2019, respectively. |
| (3) |
Includes production from Citronelle Field sold in the second quarter of 2019 and Lockhart Crossing Field sold in the third quarter of 2018. |
DENBURY RESOURCES INC.
PER-BOE DATA (UNAUDITED)
|
|
Quarter Ended |
|
Year Ended |
|
|
December 31, |
|
Sept. 30, |
|
December 31, |
|
|
2019 |
|
2018 |
|
2019 |
|
2019 |
|
2018 |
| Oil and natural gas revenues |
|
$ |
55.53 |
|
|
$ |
59.44 |
|
|
$ |
56.46 |
|
|
$ |
57.04 |
|
|
$ |
64.59 |
|
| Receipt (payment) on settlements of commodity derivatives |
|
1.68 |
|
|
(4.63 |
) |
|
1.56 |
|
|
1.11 |
|
|
(7.96 |
) |
| Lease operating expenses |
|
(21.93 |
) |
|
(23.32 |
) |
|
(22.70 |
) |
|
(22.46 |
) |
|
(22.24 |
) |
| Production and ad valorem taxes |
|
(3.98 |
) |
|
(3.78 |
) |
|
(3.89 |
) |
|
(4.09 |
) |
|
(4.39 |
) |
| Transportation and marketing expenses |
|
(1.84 |
) |
|
(2.23 |
) |
|
(1.94 |
) |
|
(1.97 |
) |
|
(2.00 |
) |
| Production netback |
|
29.46 |
|
|
25.48 |
|
|
29.49 |
|
|
29.63 |
|
|
28.00 |
|
| CO2 sales, net of operating and exploration expenses |
|
1.46 |
|
|
1.37 |
|
|
1.56 |
|
|
1.47 |
|
|
1.28 |
|
| General and administrative expenses(1) |
|
(5.35 |
) |
|
(1.87 |
) |
|
(3.52 |
) |
|
(3.91 |
) |
|
(3.25 |
) |
| Interest expense, net |
|
(3.96 |
) |
|
(3.22 |
) |
|
(4.40 |
) |
|
(3.84 |
) |
|
(3.16 |
) |
| Other |
|
0.24 |
|
|
(9.89 |
) |
|
1.09 |
|
|
0.43 |
|
|
(2.01 |
) |
| Changes in assets and liabilities relating to operations |
|
6.61 |
|
|
12.85 |
|
|
0.93 |
|
|
(0.52 |
) |
|
3.19 |
|
| Cash flows from operations |
|
28.46 |
|
|
24.72 |
|
|
25.15 |
|
|
23.26 |
|
|
24.05 |
|
| DD&A |
|
(11.94 |
) |
|
(10.85 |
) |
|
(10.60 |
) |
|
(11.00 |
) |
|
(9.83 |
) |
| Deferred income taxes |
|
(1.89 |
) |
|
(10.98 |
) |
|
(7.30 |
) |
|
(4.73 |
) |
|
(4.69 |
) |
| Gain on debt extinguishment |
|
9.41 |
|
|
— |
|
|
1.13 |
|
|
7.34 |
|
|
— |
|
| Noncash fair value gains (losses) on commodity derivatives |
|
(12.00 |
) |
|
42.88 |
|
|
6.75 |
|
|
(4.41 |
) |
|
8.92 |
|
| Other noncash items |
|
(7.68 |
) |
|
(14.09 |
) |
|
(1.10 |
) |
|
(0.25 |
) |
|
(3.80 |
) |
| Net income |
|
$ |
4.36 |
|
|
$ |
31.68 |
|
|
$ |
14.03 |
|
|
$ |
10.21 |
|
|
$ |
14.65 |
|
| (1) |
General and administrative expenses includes an accrual for severance-related costs of $18.6 million associated with the Company’s voluntary separation program for the quarter and year ended December 31, 2019, which if excluded, would have averaged $1.83 per BOE and $3.03 per BOE for the quarter and year ended December 31, 2019, respectively. |
CAPITAL EXPENDITURE SUMMARY (UNAUDITED)(1)
|
|
Quarter Ended |
|
Year Ended |
|
|
December 31, |
|
Sept. 30, |
|
December 31, |
| In thousands |
|
2019 |
|
2018 |
|
2019 |
|
2019 |
|
2018 |
| Capital expenditures by project |
|
|
|
|
|
|
|
|
|
|
| Tertiary oil fields |
|
$ |
20,998 |
|
|
$ |
35,427 |
|
|
$ |
17,547 |
|
|
$ |
93,331 |
|
|
$ |
142,560 |
|
| Non-tertiary fields |
|
15,075 |
|
|
53,097 |
|
|
19,385 |
|
|
71,014 |
|
|
104,811 |
|
| Capitalized internal costs(2) |
|
10,642 |
|
|
12,572 |
|
|
11,175 |
|
|
46,031 |
|
|
46,599 |
|
| Oil and natural gas capital expenditures |
|
46,715 |
|
|
101,096 |
|
|
48,107 |
|
|
210,376 |
|
|
293,970 |
|
| CO2 pipelines, sources and other |
|
767 |
|
|
6,355 |
|
|
3,313 |
|
|
26,545 |
|
|
28,700 |
|
| Capital expenditures, before acquisitions and capitalized interest |
|
47,482 |
|
|
107,451 |
|
|
51,420 |
|
|
236,921 |
|
|
322,670 |
|
| Acquisitions of oil and natural gas properties |
|
162 |
|
|
391 |
|
|
25 |
|
|
284 |
|
|
541 |
|
| Capital expenditures, before capitalized interest |
|
47,644 |
|
|
107,842 |
|
|
51,445 |
|
|
237,205 |
|
|
323,211 |
|
| Capitalized interest |
|
9,126 |
|
|
10,262 |
|
|
8,773 |
|
|
36,671 |
|
|
37,079 |
|
| Capital expenditures, total |
|
$ |
56,770 |
|
|
$ |
118,104 |
|
|
$ |
60,218 |
|
|
$ |
273,876 |
|
|
$ |
360,290 |
|
| (1) |
Capital expenditure amounts include accrued capital. |
| (2) |
Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs. |
DENBURY RESOURCES INC.
INTEREST AND FINANCING EXPENSES (UNAUDITED)
|
|
Quarter Ended |
|
Year Ended |
|
|
December 31, |
|
Sept. 30, |
|
December 31, |
| In thousands |
|
2019 |
|
2018 |
|
2019 |
|
2019 |
|
2018 |
| Cash interest(1) |
|
$ |
46,838 |
|
|
$ |
47,972 |
|
|
$ |
48,297 |
|
|
$ |
191,454 |
|
|
$ |
186,632 |
|
| Interest not reflected as expense for financial reporting purposes (1) |
|
(21,448 |
) |
|
(21,262 |
) |
|
(21,372 |
) |
|
(85,454 |
) |
|
(86,111 |
) |
| Noncash interest expense |
|
1,037 |
|
|
1,266 |
|
|
1,060 |
|
|
4,554 |
|
|
6,246 |
|
| Amortization of debt discount(2) |
|
3,659 |
|
|
— |
|
|
3,646 |
|
|
7,749 |
|
|
— |
|
| Less: capitalized interest |
|
(9,126 |
) |
|
(10,262 |
) |
|
(8,773 |
) |
|
(36,671 |
) |
|
(37,079 |
) |
| Interest expense, net |
|
$ |
20,960 |
|
|
$ |
17,714 |
|
|
$ |
22,858 |
|
|
$ |
81,632 |
|
|
$ |
69,688 |
|
| (1) |
Cash interest includes interest which is paid semiannually on the Company’s 9% Senior Secured Second Lien Notes due 2021, 9¼% Senior Secured Second Lien Notes due 2022, and the Company’s previously outstanding 5% Convertible Senior Notes due 2023 and 3½% Convertible Senior Notes due 2024. As a result of the accounting for certain exchange transactions in previous years, most of the future interest related to these notes was recorded as debt as of the debt issuance dates, which is reduced as semiannual interest payments are made, and therefore not reflected as interest for financial reporting purposes. |
| (2) |
Represents the amortization of debt discounts related to the Company’s 7¾% Senior Secured Second Lien Notes due 2024 (“7¾% Senior Secured Notes”) and 6?% Convertible Senior Notes due 2024 (“6?% Convertible Senior Notes”) issued in June 2019. In accordance with FASC 470-50, Modifications and Extinguishments, the 7¾% Senior Secured Notes and 6?% Convertible Senior Notes were recorded on the Company’s balance sheet at a discount of $30 million and $80 million, respectively, which will be amortized as interest expense over the term of the notes. |
SELECTED BALANCE SHEET AND CASH FLOW DATA (UNAUDITED)(1)
|
|
December 31, |
| In thousands |
|
2019 |
|
2018 |
| Cash and cash equivalents |
|
$ |
516 |
|
|
$ |
38,560 |
|
| Total assets |
|
4,691,867 |
|
|
4,723,222 |
|
|
|
|
|
|
| Borrowings under senior secured bank credit facility |
|
$ |
— |
|
|
$ |
— |
|
| Borrowings under senior secured second lien notes (principal only)(1) |
|
1,623,049 |
|
|
1,520,587 |
|
| Borrowings under senior convertible notes (principal only)(1)(2) |
|
245,548 |
|
|
— |
|
| Borrowings under senior subordinated notes (principal only) |
|
245,690 |
|
|
826,185 |
|
| Financing and capital leases |
|
167,439 |
|
|
185,435 |
|
| Total debt (principal only) |
|
$ |
2,281,726 |
|
|
$ |
2,532,207 |
|
|
|
|
|
|
| Total stockholders’ equity |
|
$ |
1,412,259 |
|
|
$ |
1,141,777 |
|
| (1) |
Excludes $165 million and $250 million of future interest payable on the notes as of December 31, 2019 and December 31, 2018, respectively, accounted for as debt for financial reporting purposes and also excludes a $27 million discount to par on the 7¾% Senior Secured Second Lien Notes due 2024 as of December 31, 2019. |
| (2) |
Excludes a $75 million discount to par on the 6?% Convertible Senior Notes due 2024 as of December 31, 2019. |
|
|
Year Ended |
|
|
December 31, |
| In thousands |
|
2019 |
|
2018 |
| Cash provided by (used in) |
|
|
|
|
| Operating activities |
|
$ |
494,143 |
|
|
$ |
529,685 |
|
| Investing activities |
|
(269,692 |
) |
|
(333,276 |
) |
| Financing activities |
|
(246,355 |
) |
|
(157,452 |
) |
DENBURY CONTACTS: Mark C. Allen, Executive Vice President and Chief Financial Officer, 972.673.2000 John Mayer, Director of Investor Relations, 972.673.2383
