Attached files
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| 8-K - DIAMONDBACK 8-K - Diamondback Energy, Inc. | diamondback8-kx2x13x18.htm |
Exhibit 99.1
DIAMONDBACK ENERGY, INC. ANNOUNCES FOURTH QUARTER 2017 FINANCIAL AND OPERATING RESULTS; INITIATING DIVIDEND
Midland, TX (February 13, 2018) - Diamondback Energy, Inc. (NASDAQ: FANG) (“Diamondback” or the “Company”) today announced financial and operating results for the fourth quarter ended December 31, 2017.
HIGHLIGHTS
• | Q4 2017 net income of $115 million, or $1.16 per diluted share; adjusted net income (as defined and reconciled below) of $153 million, or $1.56 per diluted share |
• | Q4 2017 production of 92.9 Mboe/d (74% oil), up 9% over Q3 2017 and 79% year over year; full year 2017 production of 79.2 Mboe/d (74% oil), up 84% year over year within operating cash flow |
• | Proved reserves as of December 31, 2017 of 335.4 MMboe (62% PDP, 70% oil), up 63% year over year; 2017 proved developed finding and development ("PD F&D") costs of $9.09/boe |
• | Full year 2018 production guidance of 108.0 – 116.0 Mboe/d, up over 40% at the midpoint from full year 2017 average daily production |
• | Full year 2018 CAPEX guidance of $1,300 - $1,500 million, including drill, complete and equip ("D,C&E") of $1,175 - $1,325 million and infrastructure of $125 - $175 million |
• | Expect to turn 170 to 190 gross operated horizontal wells to production in 2018 with an average lateral length of approximately 9,300 feet |
• | Initiating annual cash dividend of $0.50 per common share to be payable quarterly beginning with Q1 2018 |
“In a year where investor focus shifted from resource capture to resource execution and capital discipline in the Permian Basin, Diamondback delivered on its promises by achieving 84% year over year production growth within cash flow. After successfully integrating multiple large acquisitions and doubling our asset base, we decreased cash costs by over 10% year over year and increased proved reserves by over 60% while maintaining peer-leading capital efficiency. Capital discipline and growth within cash flow are not new concepts to Diamondback, with our 2018 plan calling for over 40% growth within cash flow at current commodity prices," stated Travis Stice, Chief Executive Officer of Diamondback.
Mr. Stice continued, "Diamondback continues to increase its focus on return on and return of capital, with our return on average capital employed nearly doubling in 2017 and expected to continue to rise given current commodity prices and our continued development of undeveloped acreage. We are also taking our first step toward rewarding shareholders for their support of our growth these last five years by initiating a $0.50 annual cash dividend to be payable quarterly beginning with the first quarter of 2018. Diamondback is now in a position to generate industry-leading organic growth as well as return capital to shareholders while continuing to reduce leverage. Our commitment to robust production growth at the highest margins and efficiencies of our peer group has not changed, and we will continue to be opportunistic through multiple avenues to maximize shareholder returns.”
OPERATIONAL HIGHLIGHTS
Diamondback’s Q4 2017 production was 92.9 Mboe/d (74% oil), up 79% year over year from 51.9 Mboe/d in Q4 2016, and up 9% quarter over quarter from 85.0 Mboe/d in Q3 2017. Average daily production for the full year 2017 was 79.2 Mboe/d (74% oil), up 84% year over year from 43.0 Mboe/d (73% oil) in 2016.
During the fourth quarter of 2017, Diamondback drilled 46 gross horizontal wells and turned 38 operated horizontal wells to production. The average completed lateral length for fourth quarter wells was 10,091 feet, up from 9,603 feet in the third quarter. Operated completions during the fourth quarter consisted of 19 Lower Spraberry wells, 15 Wolfcamp A wells and four Wolfcamp B wells. The Company operated 10 rigs and four dedicated frac spreads during the quarter.
For the full year 2017, Diamondback drilled 150 gross horizontal wells, with 123 gross operated horizontal wells turned to production over the same period. The Company is currently operating 10 horizontal rigs and plans to operate between 10 and 12 horizontal rigs throughout 2018. As a result, Diamondback expects to turn between 170 and 190 gross operated horizontal wells to production for the full year 2018.
OPERATIONS UPDATE
In Pecos County, Diamondback continues to see strong performance from operated completions targeting the Wolfcamp A. The Neal Lethco 34-33 Unit 2WA, Neal Lethco 34-33 Unit 3WA and State Biggs 12A-2 2WA were completed with an average lateral length of 8,901 feet and commenced with an average peak 10-day 2-stream flowing initial production ("IP") rate of 148 boe/d per 1,000 feet (91% oil).
In Reeves County, the Company also continues to see strong extended performance from prior Wolfcamp A completions. After commencing with a peak 10-day flowing IP rate of 193 boe/d per 1,000 feet (81% oil), the Warlander 501 WA went on to achieve a peak 30-day flowing IP rate of 186 boe/d per 1,000 feet (80% oil) and a peak 90-day flowing IP rate of 156 boe/d per 1,000 feet (80% oil).
Also in Reeves County, Diamondback recently completed its first two-well pad targeting the Wolfcamp A and Wolfcamp B with an average lateral length of 8,315 feet. The Ayers 24-2WA and the Ayers 24-3WB achieved respective peak 30-day flowing IP rates of 226 boe/d per 1,000 feet (82% oil) and 142 boe/d per 1,000 feet (81% oil). After 90 days, the Ayers 24-3WB well has produced over 95 Mboe.
In the Midland Basin, the Company recently completed a four-well pad in Howard County targeting the Lower Spraberry and Wolfcamp A. Four wells on the Bullfrog 47 South Unit pad were completed with an average lateral length of 10,107 feet and achieved an average peak 30-day IP rate of 164 boe/d per 1,000 feet (90% oil).
In Spanish Trail, Diamondback continues to see strong performance from recent completions targeting the Lower Spraberry and Wolfcamp A. In the fourth quarter of 2017, the Company completed five Wolfcamp A wells that achieved an average peak 30-day IP rate of 142 boe/d per 1,000 feet (90% oil), with seven Lower Spraberry wells achieving 146 boe/d per 1,000 feet (86% oil) over the same period. Also in Midland County, Diamondback completed a four-well pad targeting the Lower Spraberry, Wolfcamp A and Wolfcamp B with an average lateral length of 12,843 feet. After 120 days and over 600 Mboe of combined production, these four wells continue to produce over 5,000 boe/d.
FINANCIAL HIGHLIGHTS
Diamondback's fourth quarter 2017 net income was $115 million, or $1.16 per diluted share. Adjusted net income (a non-GAAP financial measure as defined and reconciled below) was $153 million, or $1.56 per diluted share.
Fourth quarter 2017 Adjusted EBITDA (as defined and reconciled below) was $302 million, up 30% from $232 million in Q3 2017. Adjusted EBITDA for the full year 2017 was $928 million, up 139% from $388 million in 2016. Fourth quarter 2017 revenues were $399 million, up 33% from $301 million in Q3 2017.
Fourth quarter 2017 average realized prices were $53.59 per barrel of oil, $2.40 per Mcf of natural gas and $27.43 per barrel of natural gas liquids, resulting in a total equivalent unhedged price of $45.31/boe, up 18% from $38.25/boe in Q3 2017.
Diamondback's cash operating costs for the fourth quarter 2017 were $8.28 per boe, including lease operating expenses ("LOE") of $4.50 per boe, cash general and administrative expenses of $0.59 per boe and taxes and transportation of $3.19 per boe. Cash operating costs for the full year 2017 were $8.16 per boe, down 11% year over year from $9.19 per boe in 2016.
As of December 31, 2017, Diamondback had $88 million in standalone cash and $397 million outstanding on its revolving credit facility. On January 24, 2018, Diamondback priced a $300 million tack-on to its Senior Notes due 2025, with net proceeds of $308 million used to pay down a portion of its borrowings under its revolving credit facility.
During the fourth quarter of 2017, Diamondback spent $246 million on drilling, completion and non-operated properties, and $61 million on infrastructure. For the full year 2017, Diamondback spent $737 million on drilling, completion and non-operated properties, and $124 million on infrastructure, while generating free cash flow of $28 million, excluding acquisitions.
RESERVES
Ryder Scott Company, L.P. prepared estimates of Diamondback’s proved reserves as of December 31, 2017. Reference prices of $51.34 per barrel of oil, $2.98 per MMbtu of natural gas and $31.82 per barrel of natural gas liquids were used in accordance with applicable rules of the Securities and Exchange Commission. Realized prices with applicable differentials were $48.03 per barrel of oil, $2.06 per Mcf of natural gas and $20.79 per barrel of natural gas liquids.
Proved reserves at year-end 2017 of 335.4 MMboe represent a 63% increase over year-end 2016 reserves. Proved developed reserves increased by 75% to 208.4 MMboe (62% of total proved reserves) as of December 31, 2017, reflecting the continued development of the Company’s horizontal well inventory. Proved undeveloped reserves increased to 127 MMboe, a 47% increase over year-end 2016, and are comprised of 168 locations, 35 of which are in the Delaware Basin. Crude oil represents 70% of Diamondback’s total proved reserves.
Net proved reserve additions of 158.8 MMboe resulted in a reserve replacement ratio of 549% (defined as the sum of extensions, discoveries, revisions and purchases, divided by annual production). The organic reserve replacement ratio was 443% (defined as the sum of extensions, discoveries and revisions, divided by annual production).
Extensions totaling 139.0 MMboe of reserves were the primary contributor to the increase in reserves, followed by purchases of reserves of 30.7 MMboe, with downward revisions of 10.9 MMboe. Proved developed producing extensions accounted for 49% of the total. PDP extensions were the result of 102 wells in which the Company has a working interest, and proved undeveloped extensions resulted from 87 new locations in which the Company has a working interest. Diamondback's Delaware Basin properties accounted for 29% of the total extensions. Net purchases of reserves of 30.7 MMboe were the result of acquisitions of 32.7 MMboe and divestitures of 2.0 MMboe. Acquisitions in the Delaware Basin contributed 92% of the total acquisitions with small bolt-on working interests and Midland Basin royalty interests accounting for the remainder. Downward revisions of 10.9 MMboe were the result of technical revisions, and PUD re-classes to probable as a result of development timing.
Oil (MBbls) | Liquids (MBbls) | Gas (MMcf) | MBOE | |
Proved Reserves As of December 31, 2016 | 139,174 | 37,134 | 174,896 | 205,457 |
Extensions and discoveries | 99,980 | 20,825 | 109,032 | 138,977 |
Revisions of previous estimates | (7,715) | (1,466) | (10,065) | (10,859) |
Purchase of reserves in place | 24,322 | 2,633 | 34,640 | 32,728 |
Divestitures | (1,163) | (461) | (2,474) | (2,036) |
Production | (21,417) | (4,056) | (20,660) | (28,916) |
Proved Reserves As of December 31, 2017 | 233,181 | 54,609 | 285,369 | 335,351 |
Diamondback’s exploration and development costs in 2017 were $925.1 million. PD F&D costs were $9.09/boe. PD F&D costs are defined as exploration and development costs divided by the sum of reserves associated with transfers from proved undeveloped reserves at year end 2016 including any associated revisions in 2017 and extensions and discoveries placed on production during 2017. Drill bit F&D costs were $7.22/boe including the effects of all revisions including pricing revisions. Drill bit F&D costs are defined as the exploration and development costs divided by the sum of extensions, discoveries and revisions.
(in thousands) | Year Ended December 31, | ||||||||||
2017 | 2016 | 2015 | |||||||||
Acquisition costs | |||||||||||
Proved properties | $ | 452,661 | $ | 72,044 | $ | 64,340 | |||||
Unproved properties | 2,692,000 | 752,117 | 448,638 | ||||||||
Development costs | 145,362 | 47,575 | 42,749 | ||||||||
Exploration costs | 779,728 | 329,122 | 319,102 | ||||||||
Capitalized asset retirement costs | 2,682 | 4,030 | 3,458 | ||||||||
Total | $ | 4,072,433 | $ | 1,204,888 | $ | 878,287 | |||||
FULL YEAR 2018 GUIDANCE
Below is Diamondback's guidance for the full year 2018. The Company expects full year production to be between 108.0 and 116.0 Mboe/d with an estimated capital spend for drilling, completion, infrastructure and non-operated properties of $1,300 to $1,500 million. During 2018, Diamondback expects to complete between 170 and 190 gross operated horizontal wells from a 10 to 12 rig program.
2018 Guidance | ||
Diamondback Energy, Inc. | Viper Energy Partners LP | |
Total Net Production – MBoe/d | 108.0 – 116.0 | 14.5 - 16.0 |
Oil Production - % of Net Production | 73% - 76% | 71% - 75% |
Unit costs ($/boe) | ||
Lease operating expenses, including workovers | $4.25 - $5.25 | |
Gathering & Transportation | $0.25 - $0.50 | $0.10 - $0.30 |
G&A | ||
Cash G&A | Under $1.00 | $0.75 - $1.25 |
Non-cash equity-based compensation | $0.75 - $1.25 | $0.75 - $1.25 |
DD&A | $11.00 - $14.00 | $9.00 - $11.00 |
Interest expense (net of interest income) | $1.00 - $2.00 | |
Production and ad valorem taxes (% of revenue)(a) | 7.0% | 7.0% |
Corporate tax rate (% of pre-tax income) | 20% - 23% | |
Gross horizontal D,C&E/Ft. - Midland Basin | $760 - $810 | |
Gross horizontal D,C&E/Ft. - Delaware Basin | $1,125 - $1,225 | |
Horizontal wells completed (net) | 170 - 190 (146 - 163) | |
Capital Budget ($ - million) | ||
Horizontal drilling and completion | $1,175 - $1,325 | |
Infrastructure | $125 - $175 | |
2018 Capital Spend | $1,300 - $1,500 | |
(a) | Includes production taxes of 4.6% for crude oil and 7.5% for natural gas and NGLs and ad valorem taxes. |
CONFERENCE CALL
Diamondback will host a conference call and webcast for investors and analysts to discuss its results for the fourth quarter of 2017 on Wednesday, February 14, 2018 at 10:00 a.m. CT. Participants should call (877) 440-7573 (United States/Canada) or (253) 237-1144 (International) and use the confirmation code 7273289. A telephonic replay will be available from 1:00 p.m. CT on Wednesday, February 14, 2018 through Wednesday, February 21, 2018 at 1:00 p.m. CT. To access the replay, call (855) 859-2056 (United States/Canada) or (404) 537-3406 (International) and enter confirmation code 7273289. A live broadcast of the earnings conference call will also be available via the internet at www.diamondbackenergy.com under the "Investor Relations" section of the site. A replay will also be available on the website following the call.
About Diamondback Energy, Inc.
Diamondback is an independent oil and natural gas Company headquartered in Midland, Texas focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. Diamondback’s activities are primarily focused on the horizontal exploitation of multiple intervals within the Wolfcamp, Spraberry, Clearfork, Bone Spring and Cline formations.
Forward Looking Statements
This news release contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. All statements, other than historical facts, that address activities that Diamondback assumes, plans, expects, believes, intends or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward-looking statements are based on management’s current beliefs, based on currently available information, as to the outcome and timing of future events. These forward-looking statements involve certain risks and uncertainties that could cause the results to differ materially from those expected by the management of Diamondback. Information concerning these risks and other factors can be found in Diamondback’s filings with the Securities and Exchange Commission, including its Forms 10-K, 10-Q and 8-K, which can be obtained free of charge on the Securities and Exchange Commission’s web site at http://www.sec.gov. Diamondback undertakes no obligation to update or revise any forward-looking statement.
Diamondback Energy, Inc. | |||||||||||||||
Consolidated Statements of Operations | |||||||||||||||
(unaudited, in thousands, except share amounts and per share data) | |||||||||||||||
Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Revenues | |||||||||||||||
Oil, natural gas liquids and natural gas | $ | 387,106 | $ | 185,012 | $ | 1,186,275 | $ | 527,107 | |||||||
Lease bonus | 9,257 | — | 11,764 | — | |||||||||||
Midstream services | 2,831 | — | 7,072 | — | |||||||||||
Total revenues | 399,194 | 185,012 | 1,205,111 | 527,107 | |||||||||||
Operating expenses | |||||||||||||||
Lease operating expenses | 38,411 | 23,348 | 126,524 | 82,428 | |||||||||||
Production and ad valorem taxes | 23,530 | 9,212 | 73,505 | 34,456 | |||||||||||
Gathering and transportation | 3,724 | 3,542 | 12,834 | 11,606 | |||||||||||
Midstream services | 3,282 | — | 10,409 | — | |||||||||||
Depreciation, depletion and amortization | 105,078 | 51,329 | 326,759 | 178,015 | |||||||||||
Impairment of oil and natural gas properties | — | — | — | 245,536 | |||||||||||
General and administrative expenses(1) | 11,145 | 10,208 | 48,669 | 42,619 | |||||||||||
Asset retirement obligation accretion | 361 | 294 | 1,391 | 1,064 | |||||||||||
Total expenses | 185,531 | 97,933 | 600,091 | 595,724 | |||||||||||
Income (loss) from operations | 213,663 | 87,079 | 605,020 | (68,617 | ) | ||||||||||
Interest expense, net | (10,892 | ) | (10,418 | ) | (40,554 | ) | (40,684 | ) | |||||||
Other income, net | 763 | 1,417 | 10,235 | 3,064 | |||||||||||
Gain (loss) on derivative instruments, net | (97,888 | ) | (16,680 | ) | (77,512 | ) | (25,345 | ) | |||||||
Loss on extinguishment of debt | — | (33,134 | ) | — | (33,134 | ) | |||||||||
Total other expense, net | (108,017 | ) | (58,815 | ) | (107,831 | ) | (96,099 | ) | |||||||
Income (loss) before income taxes | 105,646 | 28,264 | 497,189 | (164,716 | ) | ||||||||||
Provision for (benefit from) income taxes | (23,961 | ) | (176 | ) | (19,568 | ) | 192 | ||||||||
Net income (loss) | 129,607 | 28,440 | 516,757 | (164,908 | ) | ||||||||||
Net income attributable to non-controlling interest | 15,048 | 2,842 | 34,496 | 126 | |||||||||||
Net income (loss) attributable to Diamondback Energy, Inc. | $ | 114,559 | $ | 25,598 | $ | 482,261 | $ | (165,034 | ) | ||||||
Earnings per common share: | |||||||||||||||
Basic | $ | 1.17 | $ | 0.32 | $ | 4.95 | $ | (2.20 | ) | ||||||
Diluted | $ | 1.16 | $ | 0.32 | $ | 4.94 | $ | (2.20 | ) | ||||||
Weighted average common shares outstanding: | |||||||||||||||
Basic | 98,169 | 80,315 | 97,458 | 75,077 | |||||||||||
Diluted | 98,368 | 80,510 | 97,688 | 75,077 | |||||||||||
(1) | Includes non-cash expense of $6,119 and $5,810 for the three months ended December 31, 2017 and 2016, respectively, and $25,537 and $26,453 for the year ended December 31, 2017 and 2016, respectively. |
Diamondback Energy, Inc. | |||||||||||||||
Selected Operating Data | |||||||||||||||
(unaudited) | |||||||||||||||
Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Production Data: | |||||||||||||||
Oil (MBbl) | 6,345 | 3,507 | 21,418 | 11,562 | |||||||||||
Natural gas (MMcf) | 6,103 | 3,172 | 20,660 | 10,728 | |||||||||||
Natural gas liquids (MBbls) | 1,182 | 742 | 4,056 | 2,399 | |||||||||||
Oil Equivalents (MBOE)(1)(2) | 8,544 | 4,778 | 28,917 | 15,749 | |||||||||||
Average daily production (BOE/d)(2) | 92,872 | 51,934 | 79,224 | 43,031 | |||||||||||
% Oil | 74 | % | 73 | % | 74 | % | 73 | % | |||||||
Average sales prices: | |||||||||||||||
Oil, realized ($/Bbl) | $ | 53.59 | $ | 46.72 | $ | 48.75 | $ | 40.70 | |||||||
Natural gas realized ($/Mcf) | 2.40 | 2.53 | 2.53 | 2.10 | |||||||||||
Natural gas liquids ($/Bbl) | 27.43 | 17.70 | 22.20 | 14.20 | |||||||||||
Average price realized ($/BOE) | 45.31 | 38.72 | 41.02 | 33.47 | |||||||||||
Oil, hedged ($/Bbl)(3) | 52.73 | 45.97 | 48.94 | 40.80 | |||||||||||
Natural gas, hedged ($ per MMbtu)(3) | 2.59 | 2.41 | 2.65 | 2.06 | |||||||||||
Average price, hedged ($/BOE)(3) | 44.81 | 38.09 | 41.26 | 33.54 | |||||||||||
Average Costs per BOE: | |||||||||||||||
Lease operating expense | $ | 4.50 | $ | 4.89 | $ | 4.38 | $ | 5.23 | |||||||
Production and ad valorem taxes | 2.75 | 1.93 | 2.54 | 2.19 | |||||||||||
Gathering and transportation expense | 0.44 | 0.74 | 0.44 | 0.74 | |||||||||||
General and administrative - cash component | 0.59 | 0.92 | 0.80 | 1.03 | |||||||||||
Total operating expense - cash | $ | 8.28 | $ | 8.48 | $ | 8.16 | $ | 9.19 | |||||||
General and administrative - non-cash component | $ | 0.71 | $ | 1.22 | $ | 0.88 | $ | 1.68 | |||||||
Depreciation, depletion and amortization | 12.30 | 10.74 | 11.30 | 11.30 | |||||||||||
Interest expense | 1.27 | 2.18 | 1.40 | 2.58 | |||||||||||
(1) | Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl. |
(2) | The volumes presented are based on actual results and are not calculated using the rounded numbers in the table above. |
(3) | Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects includes realized gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting. |
NON-GAAP FINANCIAL MEASURES
Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDA as net income (loss) plus non-cash (gain) loss on derivative instruments, net, net interest expense, depreciation, depletion and amortization, impairment of oil and natural gas properties, non-cash equity-based compensation expense, capitalized equity-based compensation expense, asset retirement obligation accretion expense and income tax provision. Adjusted EBITDA is not a measure of net income (loss) as determined by United States’ generally accepted accounting principles ("GAAP"). Management believes Adjusted EBITDA is useful because it allows it to more effectively evaluate the Company’s operating performance and compare the results of its operations from period to period without regard to its financing methods or capital structure. The Company adds the items listed above to net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within its industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of the Company’s operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Adjusted net income is a non-GAAP financial measure equal to net income (loss) attributable to Diamondback Energy, Inc. plus non-cash (gain) loss on derivative instruments, net, (gain) loss on the sale of assets, net, other income, impairment of oil and gas properties and related income tax adjustments. The Company’s computations of Adjusted EBITDA and adjusted net income may not be comparable to other similarly titled measures of other companies or to such measure in our credit facility or any of our other contracts.
The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income (loss).
Diamondback Energy, Inc. | |||||||||||||||
Reconciliation of Adjusted EBITDA to Net Income | |||||||||||||||
(unaudited, in thousands) | |||||||||||||||
Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Net income (loss) | $ | 129,607 | $ | 28,440 | $ | 516,757 | $ | (164,908 | ) | ||||||
Non-cash (gain) loss on derivative instruments, net | 93,605 | 13,664 | 84,240 | 26,522 | |||||||||||
Interest expense, net | 10,892 | 10,418 | 40,554 | 40,684 | |||||||||||
Depreciation, depletion and amortization | 105,078 | 51,329 | 326,759 | 178,015 | |||||||||||
Impairment of oil and natural gas properties | — | — | — | 245,536 | |||||||||||
Non-cash equity-based compensation expense | 8,349 | 7,364 | 34,178 | 33,532 | |||||||||||
Capitalized equity-based compensation expense | (2,230 | ) | (1,554 | ) | (8,641 | ) | (7,079 | ) | |||||||
Asset retirement obligation accretion expense | 361 | 294 | 1,391 | 1,064 | |||||||||||
Loss on extinguishment of debt | — | 33,134 | — | 33,134 | |||||||||||
Income tax (benefit) provision | (23,961 | ) | (176 | ) | (19,568 | ) | 192 | ||||||||
Consolidated Adjusted EBITDA | $ | 321,701 | $ | 142,913 | $ | 975,670 | $ | 386,692 | |||||||
EBITDA attributable to noncontrolling interest | (19,815 | ) | (4,605 | ) | (47,631 | ) | 843 | ||||||||
Adjusted EBITDA attributable to Diamondback Energy, Inc. | $ | 301,886 | $ | 138,308 | $ | 928,039 | $ | 387,535 | |||||||
Adjusted net income is a performance measure used by management to evaluate performance, prior to non-cash mark to market ("MTM") loss on derivative instruments and gain on sale of assets, both net of income tax adjustments. Additionally, adjusted net income removes the income tax benefit relating to change in the statutory tax rate and the change in the tax valuation allowance.
The following table presents a reconciliation of adjusted net income to net income:
Diamondback Energy, Inc. | |||||||
Adjusted Net Income | |||||||
(unaudited, in thousands, except share amounts and per share data) | |||||||
Three Months Ended December 31, 2017 | |||||||
After-Tax Amounts | Amounts Per Share | ||||||
Net income attributable to Diamondback Energy, Inc. | $ | 114,559 | $ | 1.16 | |||
Noncash mark-to-market "MTM" derivative losses, net ($93,605 pretax) | 60,387 | 0.62 | |||||
Gain on sale of assets, net ($69 pretax) | (45 | ) | — | ||||
Adjusted income excluding noncash MTM derivative losses and gain on sale of assets. | 174,901 | 1.78 | |||||
Income tax benefit relating to change in statutory tax rate and change in valuation allowance | (21,407 | ) | (0.22 | ) | |||
Adjusted income excluding noncash MTM derivative losses and unusual item | $ | 153,494 | $ | 1.56 | |||
PV-10
PV-10 is the Company’s estimate of the present value of the future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” The Company believes PV-10 to be an important measure for evaluating the relative significance of its oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, the Company believes the use of a pre-tax measure is valuable for evaluating the Company. The Company believes that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry.
The following table reconciles PV-10 to the Company’s standardized measure of discounted future net cash flows, the most directly comparable measure calculated and presented in accordance with GAAP. PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP.
(in thousands) | December 31, 2017 | ||
Standardized measure of discounted future net cash flows | $ | 3,757,059 | |
Add: Present value of future income tax discounted at 10% | 39,528 | ||
PV-10 | $ | 3,796,587 | |
Derivatives
As of the filing date, the Company had the following outstanding derivative contracts. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing and Crude Oil Brent and with natural gas derivative settlements based on the New York Mercantile Exchange Henry Hub pricing. When aggregating multiple contracts, the weighted average contract price is disclosed.
Crude Oil (Bbls/day), $/Bbl) | |||||||||||||||||||||||||||||||
Q1 2018 | Q2 2018 | Q3 2018 | Q4 2018 | Q1 2019 | Q2 2019 | Q3 2019 | Q4 2019 | ||||||||||||||||||||||||
Swaps - West Texas Intermediate | 27,000 | 29,000 | 27,000 | 26,000 | 4,000 | 3,000 | 3,000 | 3,000 | |||||||||||||||||||||||
$ | 51.33 | $ | 51.24 | $ | 51.27 | $ | 51.27 | $ | 52.04 | $ | 49.82 | $ | 49.82 | $ | 49.82 | ||||||||||||||||
Swaps - Crude Brent Oil | 2,000 | 6,000 | 6,000 | 6,000 | — | — | — | — | |||||||||||||||||||||||
$ | 54.00 | $ | 55.07 | $ | 54.99 | $ | 54.92 | — | — | — | — | ||||||||||||||||||||
Basis Swaps | 15,000 | 15,000 | 15,000 | 15,000 | — | — | — | — | |||||||||||||||||||||||
$ | (0.88 | ) | $ | (0.88 | ) | $ | (0.88 | ) | $ | (0.88 | ) | — | — | — | — | ||||||||||||||||
Costless Collars Floor | 6,000 | — | — | — | — | — | — | — | |||||||||||||||||||||||
$ | 47.00 | — | — | — | — | — | — | — | |||||||||||||||||||||||
Costless Collars Ceiling | 3,000 | — | — | — | — | — | — | — | |||||||||||||||||||||||
$ | 56.34 | — | — | — | — | — | — | — | |||||||||||||||||||||||
Natural Gas (Mmbtu/day, $/Mmbtu) | |||||||||||||||
Q1 2018 | Q2 2018 | Q3 2018 | Q4 2018 | ||||||||||||
Swaps | 25,000 | 20,000 | 20,000 | 20,000 | |||||||||||
$ | 3.39 | $ | 3.00 | $ | 3.02 | $ | 3.07 | ||||||||
Investor Contact:
Adam Lawlis
+1 432.221.7467
alawlis@diamondbackenergy.com