MIDLAND, Texas, Feb. 19, 2014 (GLOBE NEWSWIRE) -- Diamondback Energy, Inc. (Nasdaq:FANG) ("Diamondback" or the "Company") today announced financial and operating results for the fourth quarter ended December 31, 2013.
During the fourth quarter of 2013, net income was $20.1 million, or $0.42 per diluted share. Net income for the fourth quarter includes a non-cash gain on commodity derivatives of $1.6 million ($1.0 million net of tax), or $0.02 per diluted share. Without the impact of this item, net income for the fourth quarter of 2013 would have been $19.1 million, or $0.40 per diluted share.
HIGHLIGHTS
- As previously announced, the Company entered into definitive purchase agreements to acquire 6,450 gross (2,825 net) acres in Martin County for approximately $174 million.
- Proved reserves as of December 31, 2013 increased 58% year over year to 63.6 MMboe (67% oil, 17% natural gas liquids, 16% natural gas), with a PV 10 value of approximately $1.3 billion as calculated below. Additions replace 975% (573% organically) of 2013 production.
- The ST S 705H Wolfcamp B well in Midland County, with a 33 stage 7,681' lateral, achieved a peak 24 hour initial production ("IP") rate of 1,185 Boe/d (96% oil) on electric submersible pump.
- Continued progress lowering lease operating expense ("LOE") by 17% to $6.04/Boe during the fourth quarter of 2013 from $7.27/Boe during the third quarter of 2013.
- EBITDA (as defined below) for the fourth quarter and full year ending 2013 was $61.8 million and $164.8 million, respectively.
"As previously announced, we are excited about expanding our horizontal inventory in Martin County, with the acquisition of 6,450 gross acres that we believe to be prospective in up to six zones. This is expected to be another accretive acquisition for our company and marks our fourth major transaction since becoming a public company," stated Travis Stice, Chief Executive Officer of Diamondback.
Mr. Stice added, "I'm proud of our results in 2013 and for the fourth quarter as our proved developed reserves grew by over 143% and we replaced 975% of our 2013 production (573% organically). Our finding and development costs in 2013 were an attractive $14.46/boe. In 2013, our production volumes grew by nearly 150% as compared to 2012 and we expect to grow by more than 110% in 2014 compared to 2013. We again demonstrated our ability to reduce operating expenses to what I believe is among the best in the Midland Basin. We have achieved five consecutive quarters of double digit declines in lease operating expense, which was down 55% in the fourth quarter of 2013 from this same period in the prior year. Our low cost operating metrics combined with higher percentage of oil production is driving our peer leading cash margins. We are excited about our most recent Wolfcamp B test in Midland County, as it is our highest 24 hour IP rate for a 7,500 foot lateral. We have previously indicated that our 8,926-foot lateral ST S 501H well in Midland County is our best well to-date. The well has produced over 75,000 barrels of oil, and is still making over 600 barrels of oil a day. We continue to be an aggressive developer of our horizontal inventory, and will add a 5th horizontal rig as planned in the coming weeks."
FINANCIAL HIGHLIGHTS
Fourth quarter 2013 income before income taxes was $31.8 million. During that same period the Company's net income after taxes was $20.1 million as compared to $14.6 million in the third quarter of 2013.
Fourth quarter 2013 EBITDA was $61.8 million and fourth quarter 2013 revenues were $75.9 million, compared to third quarter 2013 EBITDA of $47.7 million and third quarter revenues of $57.8 million.
The Company's liquidity position remains strong with approximately $16 million of cash on hand at December 31, 2013 and $10 million drawn on the revolver as of December 31, 2013 out of $225 million of availability.
During 2013, capital spent for drilling, completion and infrastructure were approximately $297.7 million. Additionally, the Company spent $640.0 million on acreage and minerals acquisitions.
RESERVES
Ryder Scott Company, L.P. prepared Diamondback's estimated proved reserves as of December 31, 2013. Reference prices of $96.78 per barrel of oil, $3.67 per MMcf of natural gas, and $41.23 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 $92.59 per barrel of oil, $4.13 per MMcf of natural gas and $37.82 per barrel of natural gas liquids.
Proved reserves at year-end 2013 of 63.6 MMBoe represent a 58% increase over year-end 2012 reserves.
Proved developed reserves increased by 143% to 30.0 MMBoe as of December 31, 2013 reflecting the development of the Company's horizontal well inventory. Horizontal wells now represent 38% of Diamondback's proved developed reserves and 46% of the Company's proved undeveloped reserves. Crude oil represents 67% of Diamondback's total proved reserves, up from 65% in the prior year period.
Net proved reserve additions of 26.0 MMBoe resulted in a reserve replacement ratio of 975% (as defined by the sum of extensions, discoveries, revisions, and purchases, divided by annual production). The organic reserve replacement ratio was 573% (as defined by the sum of extensions, discoveries, and revisions, divided by annual production).
Development of the Company's horizontal well inventory has caused us to defer development of our vertical well inventory. The Company currently does not plan to drill some of the previously recorded vertical proved undeveloped ("PUD") locations in a time frame consistent with the SEC five year PUD rule. As such, 7.9 MMBoe of PUD reserves were moved out of the proved category and into probable. These revisions constitute the majority of Diamondback's revisions to previous estimates.
| Oil (Bbl) | Gas (Mcf) | Liquids (Bbl) | BOE | |
| Proved Reserves at December 31, 2012 | 26,196,859 | 34,570,148 | 8,251,429 | 40,209,979 |
| Revisions of Previous Estimates | (5,943,164) | (5,786,180) | (3,455,306) | (10,362,833) |
| Extensions and Discoveries | 17,041,744 | 24,184,540 | 4,597,856 | 25,670,357 |
| Purchases of Reserves-In-Place | 7,328,162 | 10,441,485 | 1,672,824 | 10,741,233 |
| Production | (2,022,749) | (1,730,497) | (361,079) | (2,672,244) |
| Proved Reserves at December 31, 2013 | 42,600,852 | 61,679,496 | 10,705,724 | 63,586,492 |
Diamondback's exploration and development costs in 2013 were $331.4 million. Our drill bit finding and development ("F&D") costs were $14.46/Boe, with F&D costs defined as exploration and development costs divided by the sum of extensions and discoveries and revisions (with revisions excluding 7.9 MMBoe of vertical PUD downgrades and 0.3 MMBoe of positive revisions due to higher product pricing).
| Year ended December 31, | ||
| 2013 | 2012 | |
| Acquisition costs | ||
| Proved properties | $339,130,000 | $115,760,000 |
| Unproved properties | $279,402,000 | $117,395,000 |
| Development costs | $88,460,000 | $106,261,000 |
| Exploration costs | $242,929,000 | $17,547,000 |
| Capitalized asset retirement cost | $697,000 | $948,000 |
| Total | $950,618,000 | $357,911,000 |
FULL YEAR 2014 GUIDANCE
Previously announced guidance
| 2013 | 2014 Guidance | |||
| Diamondback | ||||
| excluding | Diamondback | |||
| Guidance | Minerals | Minerals | Energy Inc | |
| Total Net Production – MBoe/d | 7.2 - 7.5 | 12.5 - 13.0 | 2.5 - 3.0 | 15.0 - 16.0 |
| Unit costs ($/boe) | ||||
| Lease operating expenses (a) | $9.50 - $11.50 | $7.00 - $8.00 | $0.00 | $6.00 - $7.00 |
| G&A | $3.00 - $5.00 | $2.50 - $3.50 | $0.00 | $2.00 - $3.00 |
| DD&A | $22.00 - $25.00 | $22.00-$24.00 | $26.00-$28.00 | $23.00 - $25.00 |
| Production and Ad Valorem Taxes (% of Revenue) (b) | 6.9% -7.1% | 7.0% | 7.5% | 7.1% |
| $ - million | ||||
| Gross Horizontal Well Costs (c) | $7.5 - $8.5 | $6.9 - $7.4 | n/a | $6.9 - $7.4 |
| Horizontal Wells Drilled (net) | 65-75 (52 - 60) | n/a | 65-75 (52 - 60) | |
| Gross Vertical Well Costs | $2.0 - $2.2 | $2.0 - $2.2 | n/a | $2.0 - $2.2 |
| Gross Vertical Wells Drilled (net) | 20-25 (16 - 20) | n/a | 20-25 (16 - 20) | |
| Capital Expenditures | $290-$320 | $425 - $475 | n/a | $425 - $475 |
| Interest Expense (net of interest income) | n/a | n/a | $36.0 - $38.0 | |
| a - Prior 2013 guidance included ad valorem taxes in lease operating expense. The Company has reclassified these taxes and these taxes will now be reported in production and ad valorem taxes. Corporate overhead, previously reported as indirect LOE, is now included as part of lease operating expenses. 2013 guidance has been adjusted to reflect this reclassification. | ||||
| b - Includes production taxes of 4.6% for crude oil and 7.5% for natural gas and NGLs and ad valorem taxes. Previous 2013 guidance excluded estimated ad valorem taxes of $1.50/boe of lease operating expense. | ||||
| c -Assumes a 7,500' average lateral length. |
CONFERENCE CALL
Diamondback will host a conference call and webcast for investors and analysts to discuss its results for the quarter on Thursday, February 20, 2014 at 7:00 a.m. CT. Participants should call (877) 440-7573 (United States/Canada) or (253) 237-1144 (International) and utilize the confirmation code 33641361. A telephonic replay will be available for anyone unable to participate in the live call. To access the replay, call (855) 859-2056 (United States/Canada) or (404) 537-3406 (International) and enter confirmation code 33641361. The recording will be available from 10:00 a.m. CT on Thursday, February 20, 2014 through Wednesday, February 26, 2014 at 10:59 p.m. CT. 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. The webcast will be archived on the site.
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 Wolfcamp, Clearfork, Spraberry, Cline, Strawn and Atoka formations.
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. 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, | Twelve Months Ended December 31, | |||
| 2013 | 2012 | 2013 | 2012 | |
| Revenues: | ||||
| Oil and natural gas revenues | $75,908 | $25,767 | $208,002 | $74,962 |
| Operating Expenses: | ||||
| Lease operating expense | 5,790 | 5,739 | 21,157 | 15,247 |
| Production and ad valorem taxes | 4,604 | 2,046 | 12,899 | 5,237 |
| Gathering and transportation expense | 277 | 160 | 918 | 424 |
| Depreciation, depletion and amortization | 23,621 | 9,721 | 66,597 | 26,273 |
| General and administrative | 3,823 | 5,889 | 11,036 | 10,376 |
| Asset retirement obligation accretion expense | 67 | 35 | 201 | 98 |
| Total expenses | 38,182 | 23,590 | 112,808 | 57,655 |
| Income from operations | 37,726 | 2,177 | 95,194 | 17,307 |
| Other income | 30 | 478 | 1,077 | 2,132 |
| Net interest expense | (5,950) | (426) | (8,058) | (3,607) |
| Non-cash gain on derivative instruments | 1,613 | 1,671 | 5,346 | 8,057 |
| Loss on derivative instruments | (1,604) | (1,071) | (7,218) | (5,440) |
| Loss from equity investment | ― | ― | ― | (67) |
| Total other income (expense) | (5,911) | 652 | (8,853) | 1,075 |
| Net income before income tax | 31,815 | 2,829 | 86,341 | 18,382 |
| Income tax provision | 11,691 | 54,903 | 31,754 | 54,903 |
| Net income (loss) | $20,124 | ($52,074) | $54,587 | ($36,521) |
| Basic earnings per common share | $ 0.43 | $ 1.30 | ||
| Diluted earnings per common share | $ 0.42 | $ 1.29 | ||
| Weighted average number of basic shares outstanding | 47,076,306 | 42,014,783 | ||
| Weighted average number of diluted shares outstanding | 47,411,602 | 42,255,014 | ||
| Pro forma basic loss per common share(1) | $ (1.50) | $ (1.85) | ||
| Pro forma diluted loss per common share(1) | $ (1.50) | $ (1.85) | ||
| Pro forma weighted average number of basic shares outstanding(1) | 34,626,648 | 19,720,734 | ||
| Pro forma weighted average number of diluted shares outstanding(1) | 34,629,689 | 19,723,774 | ||
| ¹The Company's pro forma basic loss per share amounts have been computed based on the weighted average number of shares of common stock outstanding for the period, as if the common shares issued on October 11, 2012, when Diamonback Energy, Inc. merged with its parent entity, Diamondback Energy LLC, with Diamondback Energy, Inc. continuing as the surviving entity, were outstanding for the entire year. Diluted loss per share reflects the potential dilution, using the treasury stock method. During periods in which the Company realizes a net loss, options and restricted stock awards would not be dilutive to the net loss per share and conversion into common stock is assumed not to occur. |
| Diamondback Energy, Inc. | ||||
| Selected Operating Data | ||||
| (unaudited) | ||||
| Three Months Ended December 31, | Twelve Months Ended December 31, | |||
| 2013 | 2012 | 2013 | 2012 | |
| Production Data: | ||||
| Oil (MBbl) | 760 | 272 | 2,023 | 756 |
| Natural gas (MMcf) | 525 | 339 | 1,730 | 834 |
| Natural gas liquids (MBbls) | 112 | 73 | 361 | 183 |
| Oil Equivalents (1)(2) (MBOE) | 959 | 402 | 2,672 | 1,078 |
| Average daily production(2) (BOE/d) | 10,426 | 4,367 | 7,321 | 2,946 |
| % Oil | 79% | 68% | 76% | 70% |
| Average sales prices: | ||||
| Oil, realized ($/Bbl) | $ 91.33 | $ 81.44 | $ 93.32 | $ 86.88 |
| Natural gas realized ($/Mcf) | 3.56 | 3.37 | 3.61 | 2.85 |
| Natural gas liquids ($/Bbl) | 41.59 | 33.69 | 36.00 | 37.57 |
| Average price realized ($/BOE) | 79.14 | 64.14 | 77.84 | 69.52 |
| Oil, hedged(3) ($/Bbl) | 89.22 | 77.50 | 89.75 | 79.68 |
| Average price, hedged(3) ($/BOE) | 77.47 | 61.47 | 75.14 | 64.47 |
| Average costs per BOE: | ||||
| Lease operating expenses | $ 6.04 | $ 14.28 | $ 7.92 | $ 14.14 |
| Production and ad valorem taxes | 4.80 | 5.09 | 4.83 | 4.86 |
| Gathering and transportation expense | 0.29 | 0.40 | 0.34 | 0.39 |
| Interest expense | 6.20 | 1.06 | 3.02 | 3.35 |
| General and administrative(4) | 3.99 | 14.66 | 4.13 | 9.62 |
| Depreciation, depletion, and amortization | 24.63 | 24.20 | 24.92 | 24.36 |
| Total | $ 45.95 | $ 59.69 | $ 45.16 | $ 56.72 |
| (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 after effect of our commodity hedging transactions on our average sales prices. Our calculation of such after effects include realized gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting. |
| (4) General and administrative includes non-cash stock based compensation, net of capitalized amounts, of $326 and $1,942 for the three months ended December 31, 2013 and 2012, respectively, and $1,752 and $2,477 for the twelve months ended December 31, 2013 and 2012, respectively. Excluding stock based compensation from the above metric results in general and administrative cost per BOE of $3.65 and $9.82 for the three months ended December 31, 2013 and 2012, respectively, and $3.47 and $7.33 for the twelve months ended December 31, 2013 and 2012, respectively. |
Non-GAAP Financial Measures
Adjusted net income is a non-GAAP financial measure equal to net income plus non-cash (gain) loss on derivative instruments and related income tax adjustments. 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 EBITDA as net income (loss) plus non-cash (gain) loss on derivative contracts, loss on derivative contracts, interest expense, depreciation, depletion and amortization, non-cash equity-based compensation, capitalized equity-based compensation, asset retirement obligation accretion expense and deferred income tax provision. EBITDA is not a measure of net income (loss) as determined by United States' generally accepted accounting principles, or GAAP. Management believes 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 excludes the items listed above from net income (loss) in arriving at 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. 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 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 EBITDA. The Company's computations of 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.
The following tables present a reconciliation of the non-GAAP financial measure of EBITDA to the GAAP financial measure of net income.
| Diamondback Energy, Inc. | ||||
| Adjusted Net Income (Loss) | ||||
| (unaudited) | ||||
| Adjusted net income (loss) is a performance measure used by management to evaluate performance, prior to non-cash (gains) losses on derivatives. | ||||
| The following presents a reconciliation of net income to adjusted net income (loss): | ||||
| Three Months Ended December 31, | Twelve Months Ended December 31, | |||
| (in thousands, except for per share data) | 2013 | 2012 | 2013 | 2012 |
| Net income (loss) | $20,124 | ($52,074) | $54,587 | ($36,521) |
| Plus: | ||||
| Non-cash (gain) on derivative instruments | (1,613) | (1,671) | (5,346) | (8,057) |
| Income tax adjustment for above items | 593 | 610 | 1,966 | 2941 |
| Adjusted net income (loss) | $ 19,104 | $ (53,135) | $ 51,207 | $ (41,637) |
| Adjusted net income per common share: | ||||
| Basic | $ 0.41 | $ 1.22 | ||
| Diluted | $ 0.40 | $ 1.21 | ||
| Weighted average common shares outstanding: | ||||
| Basic | 47,076,306 | 42,014,783 | ||
| Diluted | 47,411,602 | 42,255,014 | ||
| Pro forma adjusted net loss per common share(1): | ||||
| Basic | $ (1.53) | $ (2.11) | ||
| Diluted | $ (1.53) | $ (2.11) | ||
| Pro forma weighted average common shares outstanding(1): | ||||
| Basic | 34,626,648 | 19,720,734 | ||
| Diluted | 34,629,689 | 19,723,774 | ||
| ¹The Company's pro forma basic loss per share amounts have been computed based on the weighted average number of shares of common stock outstanding for the period, as if the common shares issued on October 11, 2012, when Diamonback Energy, Inc. merged with its parent entity, Diamondback Energy LLC, with Diamondback Energy, Inc. continuing as the surviving entity, were outstanding for the entire year. Diluted loss per share reflects the potential dilution, using the treasury stock method. During periods in which the Company realizes a net loss, options and restricted stock awards would not be dilutive to the net loss per share and conversion into common stock is assumed not to occur. |
| Diamondback Energy, Inc. | ||||
| Reconciliation of EBITDA to Net Income | ||||
| (unaudited, in thousands) | ||||
| Three Months Ended December 31, | Twelve Months Ended December 31, | |||
| 2013 | 2012 | 2013 | 2012 | |
| Net income | $20,124 | ($52,074) | $54,587 | ($36,521) |
| Non-cash (gain) loss on derivatives instruments, net | (1,613) | (1,671) | (5,346) | (8,057) |
| Loss on settlement of derivatives instruments, net | 1,604 | 1,071 | 7,218 | 5,440 |
| Interest expense | 5,950 | 426 | 8,059 | 3,610 |
| Depreciation, depletion and amortization | 23,621 | 9,721 | 66,597 | 26,273 |
| Non-cash equity-based compensation expense | 619 | 2,609 | 2,724 | 3,482 |
| Capitalized equity-based compensation expense | (293) | (667) | (972) | (1,005) |
| Asset retirement obligation accretion expense | 67 | 35 | 201 | 98 |
| Deferred income tax provision | 11,691 | 54,903 | 31,754 | 54,903 |
| EBITDA | $61,770 | $14,353 | $164,822 | $48,223 |
| Diamondback Energy, Inc. | ||
| Derivatives Information | ||
| (unaudited) | ||
| The table below provides data regarding the settlement details through 2014 of our current price swap contracts. | ||
| Average Bbls | Average | |
| Oil Swaps | Per Day | Price per Bbl |
| 2014 | ||
| First Quarter-LLS | 2,655 | $ 99.60 |
| First Quarter-Brent | 1,000 | $ 109.70 |
| Second Quarter-LLS | 4,670 | $ 99.23 |
| Second Quarter-Brent | 330 | $ 109.70 |
| Third Quarter-LLS | 5,000 | $ 98.23 |
| Fourth Quarter-LLS | 5,000 | $ 98.23 |
| 2014 Average | 4,668 | $ 99.48 |
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) | 31-Dec-13 |
| PV-10 | $1,269,751 |
| Less income taxes: | |
| Undiscounted future income taxes | ($674,260) |
| 10% discount factor | $380,148 |
| Future discounted income taxes | ($294,112) |
| Standardized measure of discounted future net cash flows | $975,639 |