Diamondback Energy, Inc. Announces Fourth Quarter 2015 Financial and Operating Results and Updated Guidance for 2016
HIGHLIGHTS
- The Company has completed its first three-well pad in
Glasscock County targeting the Lower Spraberry, Wolfcamp A and Wolfcamp B with an average lateral length of 7,400 feet. The wells are in various stages of flowback and artificial lift but produced an average in excess of 3,600 boe/d (81% oil) on a combined basis over seven days. - Proved reserves as of
December 31, 2015 increased 39% year over year to 156.9 MMboe (67% oil, 16% natural gas, 17% natural gas liquids), with a PV-10 value of approximately$1.4 billion as calculated and reconciled below. Additions replaced 465% (422% organically) of 2015 production with a drill bit finding cost ("F&D") of$5.51 /boe as calculated below. - Costs to drill, complete and equip are currently trending between
$5.0 and$5.5 million for a 7,500 foot lateral and between$6.5 and$7.0 million for a 10,000 foot lateral. - Lease operating expenses ("LOE") declined 12% from
$7.79 /boe in 2014 to$6.84 /boe in 2015. 2015 LOE was below the$7.00 to$8.00 /boe guidance range. The Company anticipates LOE of$6.00 to$7.00 /boe in 2016. - Diamondback's Q4 2015 production was 37.6 Mboe/d (76% oil), up 10% from 34.1 Mboe/d (73% oil) in Q3 2015.
- Due to ongoing commodity price volatility, the Company has widened its 2016 production guidance to a
range of 32.0 to 38.0 Mboe/d. Diamondback anticipates completing between 30 and 70 gross horizontal wells during 2016, and capital expenditures for 2016 are expected to be between
$250 million to$375 million .
"2016 began with oil prices testing recent lows. We believe Diamondback is well-positioned in this environment and continues to demonstrate that it is a low cost operator with superior execution abilities. After our equity raise last month, Diamondback had over
HORIZONTAL DRILLING UPDATE
Diamondback has drilled its first three-well pad in
14 operated horizontal wells were completed in the fourth quarter of 2015, bringing the full year 2015 total to 65 wells. Wells completed during the fourth quarter of 2015 consisted of 11 Lower Spraberry wells and three Wolfcamp B wells. In total during 2015, Diamondback competed 37 Lower Spraberry, 25 Wolfcamp B, two Wolfcamp A and one Middle Spraberry well. The Company also participated in seven gross (three net) non-operated completions in 2015.
Next month, the Company intends to release one of its three horizontal rigs that are currently operating. Diamondback will continue to monitor the commodity price environment and retains the capital flexibility to adjust its drilling and completion plans in response to market conditions. Diamondback has the option to release an additional rig in the second quarter of 2016.
FINANCIAL HIGHLIGHTS
During the fourth quarter of 2015, the Company incurred an impairment charge of
The Company's fourth quarter 2015 adjusted net income after taxes and net income attributable to a non-controlling interest (a non-GAAP financial measure as defined and reconciled below) was
Fourth quarter 2015 Adjusted EBITDA (as defined and reconciled below) was
As of
During the fourth quarter of 2015, capital spent for drilling and completion was
In
RESERVES
Proved reserves at year-end 2015 of 156.9 MMboe represent a 39% increase over year-end 2014 reserves.
Proved developed reserves increased by 39% to 92.1 MMboe (59% of total proved reserves) as of
Net proved reserve additions of 56.1MMboe resulted in a reserve replacement ratio of 465% (defined as the sum of extensions, discoveries, revisions and purchases, divided by annual production). The organic reserve replacement ratio was 422% (defined as the sum of extensions, discoveries and revisions, divided by annual production).
Purchases of reserves came from the acquisition of acreage primarily in
| Oil (Bbls) | Liquids (Bbls) | Gas (Mcf) | BOE | |||||||||
| Proved Reserves As of | 75,689,589 | 18,541,932 | 111,605,260 | 112,832,398 | ||||||||
| Extensions and discoveries | 48,725,132 | 12,055,631 | 53,452,948 | 69,689,588 | ||||||||
| Revisions of previous estimates | (12,130,474 | ) | (4,080,886 | ) | (14,726,160 | ) | (18,665,720 | ) | ||||
| Purchase of reserves in place | 2,775,599 | 1,165,090 | 7,101,933 | 5,124,345 | ||||||||
| Production | (9,081,135 | ) | (1,677,623 | ) | (7,931,237 | ) | (12,080,631 | ) | ||||
| Proved Reserves As of | 105,978,711 | 26,004,144 | 149,502,744 | 156,899,980 | ||||||||
Diamondback's exploration and development costs in 2015 were
| (in thousands) | Year Ended | |||||||
| 2015 | 2014 | 2013 | ||||||
| Acquisition costs | ||||||||
| Proved properties | 64,340 | 302,234 | 339,130 | |||||
| Unproved properties | 448,638 | 601,188 | 279,402 | |||||
| Development costs | 42,749 | 86,097 | 88,460 | |||||
| Exploration costs | 319,102 | 475,756 | 242,929 | |||||
| Capitalized asset retirement costs | 3,458 | 4,962 | 697 | |||||
| Total | 878,287 | 1,470,237 | 950,618 | |||||
FULL YEAR 2016 GUIDANCE
Diamondback forecasts 2016 production of 32.0 to 38.0 Mboe/d, including 6.0 to 6.5 Mboe/d attributable to its subsidiary
Diamondback expects a 2016 total capital spend of
Diamondback now expects to complete 30 to 70 gross horizontal wells in 2016. The Company anticipates costs for a 7,500 foot lateral horizontal well to range from
As shown in the table below, 2016 LOE is expected to be in the range of
| 2016 Guidance | ||||||||||
| Total Net Production - MBoe/d | 32.0 - 38.0 | 6.0 - 6.5 | ||||||||
| Unit costs ($/boe) | ||||||||||
| Lease operating expenses, including workovers | n/a | |||||||||
| Gathering & Transportation | ||||||||||
| G&A | ||||||||||
| Cash G&A | ||||||||||
| Non-cash equity-based compensation | ||||||||||
| DD&A |
| |||||||||
| Interest expense (net of interest income) | ||||||||||
| Production and ad valorem taxes (% of revenue)(a) | 8.0 | % | 8.0 | % | ||||||
| ($ - million) | ||||||||||
| Gross horizontal well costs(b) | n/a | |||||||||
| Horizontal wells completed (net) | 30 - 70 (25 - 58) | |||||||||
| Capital Budget ($ - million) | ||||||||||
| Horizontal drilling and completion | n/a | |||||||||
| Infrastructure | n/a | |||||||||
| Non-op and other | n/a | |||||||||
| 2016 Capital Spend | n/a | |||||||||
(a) Includes production taxes of 4.6% for crude oil and 7.5% for natural gas and NGLs and ad valorem taxes.
(b) Assumes a 7,500' average lateral length.
CONFERENCE CALL
Diamondback and Viper will host a joint conference call and webcast for investors and analysts to discuss their results for the fourth quarter of 2015 and 2016 guidance on
About
Diamondback is an independent oil and natural gas Company headquartered in
Forward Looking Statements
This news release contains forward-looking statements within the meaning of the federal securities laws. 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, including specifically the statements regarding the acquisitions announced above. 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
| Consolidated Statements of Operations | |||||||||||||||
| (unaudited, in thousands, except share amounts and per share data) | |||||||||||||||
| Three Months Ended | Twelve Months Ended | ||||||||||||||
| 2015 | 2014 | 2015 | 2014 | ||||||||||||
| Revenues | |||||||||||||||
| Oil, natural gas liquids and natural gas | 114,323 | 131,583 | 446,733 | 495,718 | |||||||||||
| Operating Expenses | |||||||||||||||
| Lease operating expense | 17,508 | 23,168 | 82,625 | 55,384 | |||||||||||
| Production and ad valorem taxes | 7,954 | 9,288 | 32,990 | 32,638 | |||||||||||
| Gathering and transportation expense | 1,748 | 1,143 | 6,091 | 3,288 | |||||||||||
| Depreciation, depletion and amortization | 48,549 | 53,641 | 217,697 | 170,005 | |||||||||||
| Impairment of oil and natural gas properties | 217,610 | — | 814,798 | — | |||||||||||
| General and administrative | 8,522 | 6,280 | 31,968 | 21,266 | |||||||||||
| Asset retirement obligation accretion expense | 245 | 164 | 833 | 467 | |||||||||||
| Total expenses | 302,136 | 93,684 | 1,187,002 | 283,048 | |||||||||||
| Income (loss) from operations | (187,813 | ) | 37,899 | (740,269 | ) | 212,670 | |||||||||
| Other income | (520 | ) | 569 | 728 | 677 | ||||||||||
| Other expense | — | — | — | (1,416 | ) | ||||||||||
| Net interest expense | (10,106 | ) | (10,424 | ) | (41,510 | ) | (34,514 | ) | |||||||
| Non-cash gain (loss) on derivative instruments | (35,386 | ) | 111,479 | (112,918 | ) | 117,109 | |||||||||
| Gain (loss) on derivative instruments | 40,503 | 16,637 | 144,869 | 10,430 | |||||||||||
| Total other income (expense), net | (5,509 | ) | 118,261 | (8,831 | ) | 92,286 | |||||||||
| Income (loss) before income taxes | (193,322 | ) | 156,160 | (749,100 | ) | 304,956 | |||||||||
| Provision for (benefit from) income taxes | (6,487 | ) | 56,243 | (201,310 | ) | 108,985 | |||||||||
| Net income (loss) | (186,835 | ) | 99,917 | (547,790 | ) | 195,971 | |||||||||
| Less: Net income attributable to noncontrolling interest | 574 | 1,243 | 2,838 | 2,216 | |||||||||||
| Net income (loss) attributable to | (187,409 | ) | 98,674 | (550,628 | ) | 193,755 | |||||||||
| Basic earnings per common share | $ | (2.80 | ) | $ | 1.74 | $ | (8.74 | ) | $ | 3.67 | |||||
| Diluted earnings per common share | $ | (2.80 | ) | $ | 1.73 | $ | (8.74 | ) | $ | 3.64 | |||||
| Weighted average number of basic shares outstanding | 66,850 | 56,787 | 63,019 | 52,826 | |||||||||||
| Weighted average number of diluted shares outstanding | 66,850 | 57,045 | 63,019 | 53,297 | |||||||||||
| Selected Operating Data | |||||||||||||||||||
| (unaudited) | |||||||||||||||||||
| Three Months Ended | Twelve Months Ended | ||||||||||||||||||
| 2015 | 2014 | 2015 | 2014 | ||||||||||||||||
| Production Data: | |||||||||||||||||||
| Oil (MBbl) | 2,641 | 1,785 | 9,081 | 5,382 | |||||||||||||||
| Natural gas (MMcf) | 2,407 | 1,447 | 7,931 | 4,346 | |||||||||||||||
| Natural gas liquids (MBbls) | 418 | 341 | 1,678 | 1,002 | |||||||||||||||
| Oil Equivalents (1)(2) (MBOE) | 3,460 | 2,367 | 12,081 | 7,108 | |||||||||||||||
| Average daily production(2) (BOE/d) | 37,614 | 25,724 | 33,098 | 19,474 | |||||||||||||||
| % Oil | 76 | % | 75 | % | 75 | % | 76 | % | |||||||||||
| Average sales prices: | |||||||||||||||||||
| Oil, realized ($/Bbl) | $ | 39.32 | $ | 66.01 | $ | 44.68 | $ | 83.48 | |||||||||||
| Natural gas realized ($/Mcf) | $ | 2.14 | $ | 3.91 | $ | 2.47 | $ | 4.15 | |||||||||||
| Natural gas liquids ($/Bbl) | $ | 12.68 | $ | 23.86 | $ | 12.77 | $ | 28.39 | |||||||||||
| Average price realized ($/BOE) | $ | 33.04 | $ | 55.60 | $ | 36.98 | $ | 69.74 | |||||||||||
| Oil, hedged(3) ($/Bbl) | $ | 54.66 | $ | 75.33 | $ | 60.63 | $ | 85.42 | |||||||||||
| Average price, hedged(3) ($/BOE) | $ | 44.74 | $ | 62.63 | $ | 48.97 | $ | 71.21 | |||||||||||
| Average Costs per BOE: | |||||||||||||||||||
| Lease operating expense | $ | 5.06 | $ | 9.79 | $ | 6.84 | $ | 7.79 | |||||||||||
| Production and ad valorem taxes | 2.30 | 3.92 | 2.73 | 4.59 | |||||||||||||||
| Gathering and transportation expense | 0.51 | 0.48 | 0.50 | 0.46 | |||||||||||||||
| General and administrative - cash component | 1.06 | 1.02 | 1.11 | 1.61 | |||||||||||||||
| Total operating expense - cash | $ | 8.93 | $ | 15.21 | $ | 11.18 | $ | 14.45 | |||||||||||
| General and administrative - non-cash component | $ | 1.40 | $ | 1.63 | $ | 1.54 | $ | 1.38 | |||||||||||
| Depreciation, depletion, and amortization | 14.03 | 22.67 | 18.02 | 23.92 | |||||||||||||||
| Interest expense | 2.92 | 4.40 | 3.44 | 4.86 | |||||||||||||||
| Total expenses | $ | 18.35 | $ | 28.70 | $ | 23.00 | $ | 30.16 | |||||||||||
| (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 include 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, interest expense, depreciation, depletion and amortization, impairment of oil and gas properties, non-cash equity-based compensation expense, capitalized equity-based compensation expense, asset retirement obligation accretion expense and income tax (benefit) provision. Adjusted EBITDA is not a measure of net income (loss) as
determined by United States' generally accepted accounting principles, or 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 attributable to
The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income.
| Reconciliation of Adjusted EBITDA to Net Income | ||||||||||||||||
| (unaudited, in thousands) | ||||||||||||||||
| Three Months Ended | Twelve Months Ended | |||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||
| Net income (loss) | $ | (186,835 | ) | $ | 99,917 | $ | (547,790 | ) | $ | 195,971 | ||||||
| Non-cash (gain) loss on derivative instruments, net | 35,386 | (111,479 | ) | 112,918 | (117,109 | ) | ||||||||||
| Interest expense | 10,106 | 10,425 | 41,510 | 34,515 | ||||||||||||
| Depreciation, depletion and amortization | 48,549 | 53,641 | 217,697 | 170,005 | ||||||||||||
| Impairment of oil and gas properties | 217,610 | — | 814,798 | — | ||||||||||||
| Non-cash equity-based compensation expense | 5,788 | 4,108 | 24,572 | 14,253 | ||||||||||||
| Capitalized equity-based compensation expense | (918 | ) | (1,329 | ) | (6,043 | ) | (4,437 | ) | ||||||||
| Asset retirement obligation accretion expense | 245 | 164 | 833 | 467 | ||||||||||||
| Income tax (benefit) provision | (6,487 | ) | 56,243 | (201,310 | ) | 108,985 | ||||||||||
| Consolidated Adjusted EBITDA | $ | 123,444 | $ | 111,690 | $ | 457,185 | $ | 402,650 | ||||||||
| Less: EBITDA attributable to noncontrolling interest | (2,154 | ) | (2,183 | ) | (7,940 | ) | (4,316 | ) | ||||||||
| Adjusted EBITDA attributable to | $ | 121,290 | $ | 109,507 | $ | 449,245 | $ | 398,334 | ||||||||
| Adjusted Net Income | ||||||||||||||||
| (unaudited, in thousands, except share amounts and per share data) | ||||||||||||||||
| Adjusted net income is a performance measure used by management to evaluate performance, prior to non-cash (gains) losses on derivatives, (gain) loss on sale of assets, and impairment of oil and gas properties. | ||||||||||||||||
| The following table presents a reconciliation of adjusted net income to net income: | ||||||||||||||||
| Three Months Ended | Twelve Months Ended | |||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||
| Net income attributable to | $ | (187,409 | ) | $ | 98,674 | $ | (550,628 | ) | $ | 193,755 | ||||||
| Plus: | ||||||||||||||||
| Non-cash (gain) loss on derivative instruments, net | 35,386 | (111,479 | ) | 112,918 | (117,109 | ) | ||||||||||
| (Gain) loss on sale of assets, net | 759 | (9 | ) | 668 | 1,396 | |||||||||||
| Impairment of oil and gas properties | 217,610 | — | 814,798 | — | ||||||||||||
| Income tax adjustment for above items | (27,758 | ) | 40,154 | (263,878 | ) | 41,353 | ||||||||||
| Adjusted net income | $ | 38,588 | $ | 27,340 | $ | 113,878 | $ | 119,395 | ||||||||
| Adjusted net income per common share: | ||||||||||||||||
| Basic | $ | 0.58 | $ | 0.48 | $ | 1.81 | $ | 2.26 | ||||||||
| Diluted | $ | 0.58 | $ | 0.48 | $ | 1.81 | $ | 2.24 | ||||||||
| Weighted average common shares outstanding: | ||||||||||||||||
| Basic | 66,850 | 56,787 | 63,019 | 52,826 | ||||||||||||
| Diluted | 66,850 | 57,045 | 63,019 | 53,297 | ||||||||||||
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) | ||
| PV-10 | 1,431,341 | |
| Less income taxes: | ||
| Undiscounted future income taxes | (28,233 | ) |
| 10% discount factor | (15,025 | ) |
| Future discounted income taxes | (13,208 | ) |
| Standardized measure of discounted future net cash flows | 1,418,133 | |
Investor Contact:Adam Lawlis +1 432.221.7467 alawlis@diamondbackenergy.com
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