UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Washington, D.C. 20549
___________
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Securities Exchange Act of 1934
Date of report (Date of earliest event reported): May 6, 2015
___________
DIAMONDBACK ENERGY, INC.
(Exact Name of Registrant as Specified in Charter)
Delaware (State or other jurisdiction of incorporation) | 001-35700 (Commission File Number) | 45-4502447 (I.R.S. Employer Identification Number) |
500 West Texas Suite 1200 Midland, Texas (Address of principal executive offices) | 79701 (Zip code) | |
(432) 221-7400 (Registrant’s telephone number, including area code) Not Applicable (Former name or former address, if changed since last report) | ||
Check the appropriate box below if the Form 8-K is intended to simultaneously satisfy the filing obligation of the Registrant under any of the following provisions:
o | Written communications pursuant to Rule 425 under the Securities Act | |
o | Soliciting material pursuant to Rule 14a-12 under the Exchange Act | |
o | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act | |
o | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act | |
Item 2.02. Results of Operations and Financial Condition.
On May 6, 2015, Diamondback Energy, Inc. issued a press release announcing financial and operating results for the first quarter ended March 31, 2015 and certain recently completed and pending acquisitions of additional acreage in the Midland Basin in West Texas. A copy of the press release is attached as Exhibit 99.1 to this Current Report on Form 8-K.
Item 9.01. Financial Statements and Exhibits
(d) | Exhibits |
Number | Exhibit | |
99.1 | Press release, dated May 6, 2015, entitled “Diamondback Energy, Inc. Announces First Quarter 2015 Financial and Operating Results and Accretive Acquisitions.” | |
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
DIAMONDBACK ENERGY, INC. | |
Date: May 6, 2015 | By: /s/ Teresa L. Dick Teresa L. Dick Senior Vice President and Chief Financial Officer |
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Exhibit Index
Number | Exhibit | |
99.1 | Press release, dated May 6, 2015, entitled “Diamondback Energy, Inc. Announces First Quarter 2015 Financial and Operating Results and Accretive Acquisitions.” | |
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Exhibit 99.1
Diamondback Energy, Inc. Announces First Quarter 2015 Financial And Operating Results and Accretive Acquisitions
Midland, TX (May 6, 2015) - Diamondback Energy, Inc. (NASDAQ: FANG) (“Diamondback” or the “Company”) today announced financial and operating results for the first quarter ended March 31, 2015.
HIGHLIGHTS
• | Since January 1, 2015, Diamondback has acquired or entered into definitive purchase agreements to acquire from unrelated third party sellers an aggregate of approximately 15,940 gross (11,948 net) acres in the Midland Basin, primarily in northwest Howard County, with approximately 2,500 boe/d of net production (on a three-stream basis) estimated for April 2015 based on data provided by the sellers, and an average approximate 1.5% overriding royalty interest in certain of the to-be-acquired acreage (the “Royalty Interest”) for an aggregate of approximately $437.8 million, subject to certain adjustments. |
• | The Company has offered the Royalty Interest to its subsidiary Viper Energy Partners LP (“Viper”) for approximately $33.7 million, which offer is subject to approval of the conflicts committee of Viper’s general partner and completion of the acquisition of this acreage. |
• | Diamondback’s Q1 2015 production increased 19% to 30.6 Mboe/d from 25.7 Mboe/d in Q4 2014. |
• | The Company is increasing its 2015 production guidance 11% to 29.0 Mboe/d to 31.0 Mboe/d from its previously announced guidance of 26.0 Mboe/d to 28.0 Mboe/d. This is a result of production increases and the Company’s plan to add a completion crew in June 2015 as well as the acquisitions described above (which are expected to contribute less than half of the production guidance increase). |
◦ | The Company no longer plans to defer completions and intends to add a second dedicated completion crew in June to work through its current backlog of wells that are drilled but not completed. |
◦ | If service cost reductions hold and prices continue to strengthen, the Company expects to increase its horizontal rig count from three to five later in 2015. |
◦ | Diamondback now intends to complete 55 to 65 gross horizontal wells in the year, up from the prior guidance range of 50 to 60. |
◦ | The Company is reiterating its $400 to $450 million guidance for capital expenditures. Capital costs incurred associated with increased activity are expected to be offset with cost savings. |
• | Diamondback continues to decrease drilling times, equating to lower well costs and higher rates of return, as compared to 2014. |
◦ | Diamondback recently drilled a two-well pad in Midland County with an average lateral length of approximately 10,000 feet (average measured depth of approximately 19,000 feet) in 31 days from the spud of the first well to total depth of the second. |
◦ | The Company also drilled an approximate 8,200 foot lateral (approximate measured depth of 18,000 feet) in southwest Martin County in 12 days. |
• | Diamondback completed its first Lower Spraberry test on its properties in southwest Martin County acquired in 2014. The Kimberly 714LS has a 7,472 foot lateral and was completed with 32 frac stages. This well is in initial flowback and is still cleaning up. |
“Initial results from our recent Lower Spraberry wells in Midland County continue to outperform the 990 Mboe type curve prepared by Ryder Scott Company, L.P., or Ryder Scott, our independent reserve engineers. Initial results from our recent Lower Spraberry completions in Martin and Andrews Counties are also exceeding the 810 Mboe Ryder Scott type curve. Throughout Q1 2015, we continued our aggressive pursuit of cost concessions. Current Authorities for Expenditure (“AFEs”) for a 7,500 foot lateral are trending below the $6.2 million to $6.7 million well cost range included in our guidance announced earlier this year and are down approximately 20%-30% from the peak last year. We are projecting that at $60/bbl for WTI, our leading edge cost savings and our efficiency gains will allow us to generate estimated project rates of return comparable to those generated when WTI was $75/bbl, but involved higher drilling and completion costs,” stated Travis Stice, Chief Executive Officer of Diamondback.
Mr. Stice continued, “With the improvement in commodity prices and service costs, we plan to add a second dedicated completion crew in June to work down the inventory of drilled but uncompleted wells. Additionally, if conditions remain positive, we expect to increase our rig count from three to five horizontal rigs later this year. We could potentially add two or three additional rigs in 2016, increasing our rig count to seven or eight. On the results of our strong first quarter and from the anticipated effect of the announced acquisitions, we are increasing 2015 guidance to 29.0 Mboe/d to 31.0 Mboe/d from the 26.0 Mboe/d to 28.0 Mboe/d range previously announced. More than half of the increase is expected to result from continued production strength and completing more wells, while our recent and pending acquisitions are expected to account for the remainder of the projected increase.”
DIAMONDBACK TO ACQUIRE ADDITIONAL ACRES IN THE MIDLAND BASIN
Since January 1, 2015, Diamondback has acquired or entered into definitive purchase agreements to acquire from unrelated third party sellers an aggregate of approximately 15,940 gross (11,948 net) acres in the Midland Basin for an aggregate of approximately $437.8 million, subject to certain adjustments. These transactions, all of which are expected to have closed by the end of June 2015, will increase the Company’s leasehold interest in the Midland Basin to approximately 89,216 net acres if completed as anticipated.
The assets, primarily located in northwest Howard County, include approximately 2,500 boe/d of net production estimated by the Company for April 2015 based on data provided by the sellers. The acreage is 83% held by production from 117 gross producing vertical wells and three gross producing horizontal wells. Net proved developed reserves, based on Diamondback’s internal estimates as of the effective date for the acquisition of the applicable assets, were approximately 4,347 Mboe. The Company’s estimate of proved developed reserves is based on analysis of production data provided by the sellers, as well as available geologic and other data, and the Company may revise its estimates following ownership of these properties.
Recent horizontal wells in the northwest Howard County area have confirmed geochemical data that indicates the three primary targets (Lower Spraberry, Wolfcamp A and Wolfcamp B) are within the mature oil window. Diamondback believes that development potential within the footprint of the acquisitions includes approximately 232 net horizontal locations, primarily in the Wolfcamp B, Wolfcamp A and Lower Spraberry based on 660-foot interwell spacing per well. Additional development potential in northwest Howard County may exist in the Middle Spraberry.
The acreage is largely contiguous with minimal surface or urban encroachment issues. The blocky nature of the acreage is conducive for efficient infrastructure installation and development with long laterals.
Approximately 42% of the potential horizontal locations will be approximately 10,000 foot laterals, which can provide higher rates of return and capital efficiency than shorter laterals. Petrophysical analysis of over 60 wells with open hole logs indicates that the to-be-acquired acreage has similar original oil in place as Spanish Trail, which is currently Diamondback’s most prolific asset. There is also salt water disposal infrastructure already in place on the acreage in northwest Howard County, which is valued at approximately $4.9 million. Additionally, the acquisition includes 3-D seismic data which can be used to geosteer horizontal wells. Diamondback intends to implement its low-cost and efficient operations on this acreage in 2016 in an effort to bring its value forward for investors.
Diamondback intends to finance the acquisitions, subject to market conditions and other factors, primarily with proceeds from one or more capital markets transactions, which may include debt or equity offerings. Additionally, the Company has offered the Royalty Interest, an average approximate 1.5% overriding royalty interest in certain of the to-be-acquired acreage to its subsidiary Viper Energy Partners LP for approximately $33.7 million, which offer is subject to the approval of the conflicts committee of Viper’s general partner and completion of the acquisition of this acreage.
These acquisitions are all expected to have closed by the end of June 2015; however, certain of these transactions remain subject to completion of due diligence and satisfaction of other closing conditions, and there can be no assurance that all of the transactions will be completed as planned or at all.
“I am tremendously pleased to continue our track record for accretive transactions with these acquisitions of core Midland Basin acreage in northwest Howard County that combine our two acquisition strategies: pursuing large contiguous blocks as well as small bolt-ons near our existing acreage. Analysis of wells in the immediate vicinity of northwest Howard County suggests estimated ultimate recoveries (“EURs”) ranging from 600 to 900 Mboe in three proven zones with economics favorable to horizontal development, even at $50/bbl oil. The strong economics would place the assets included in these acquisitions among the top quartile of our existing acreage, and we intend to start developing these new assets early next year. Furthermore, the blocky nature lends itself to drilling longer laterals. Approximately 42% of the potential horizontal locations identified on these assets are approximately 10,000 foot laterals and, as a result, Diamondback’s peer-leading capital efficiency and finding costs are expected to improve even further,” stated Travis Stice.
FINANCIAL HIGHLIGHTS
First quarter 2015 income before income taxes was $9.8 million. During that same period, the Company’s net income after taxes and net income attributable to a non-controlling interest was $5.8 million.
First quarter 2015 Adjusted EBITDA was $110.3 million and first quarter 2015 revenues were $101.4 million. Adjusted EBITDA was approximately in line with Q4 2014 adjusted EBITDA of $111.7 million, despite the challenging commodity environment.
As of March 31, 2015, the Company had approximately $162 million drawn on its credit facility. In connection with its Spring 2015 redetermination, Diamondback’s agent lender under its revolving credit facility has recommended a borrowing base of $725 million; however, the Company currently has elected to limit the lenders' aggregate commitment to $500 million and intends to continue to do so.
During the first quarter of 2015, capital spent for drilling, completion and infrastructure was approximately $148.8 million. The majority of the Company’s first quarter 2015 capital spend was related to the completion of 2014 projects.
In April 2015, Standard and Poor’s raised Diamondback’s corporate credit rating to B+ from B and revised its outlook to stable from positive.
FULL YEAR 2015 GUIDANCE
Below is our full year 2015 guidance, which has been updated to reflect increased production and completion activity. Due to the pending addition of 117 gross vertical wells with the acquisitions announced above, the Company is increasing its guidance for lease operating expense (including workover costs) to $7.00 to $8.00/boe from previous guidance range of $6.50 to $7.50/boe. Despite the completion of additional horizontal wells, the Company is maintaining its initial guidance for capital expenditure spend for drilling, completion and infrastructure of $400 to $450 million.
2015 Guidance | ||
Diamondback Energy, Inc | Viper Energy Partners LP | |
Total Net Production – MBoe/d | 29.0 – 31.0 | 4.6 – 5.0 |
Unit costs ($/boe) | ||
Lease Operating Expenses, including workovers | $7.00 - $8.00 | $0.00 |
G&A | ||
Cash G&A | $1.00 - $2.00 | $1.00 - $2.00 |
Non-Cash Equity-Based Compensation | $1.00 - $2.00 | $2.00 - $3.00 |
DD&A | $20.00 - $22.00 | $20.00 - $22.00 |
Production and Ad Valorem Taxes (% of Revenue) (a) | 7.1% | 7.5% |
($ - million) | ||
Gross Horizontal Well Costs (b) | $6.2 - $6.7 | n/a |
Horizontal Wells Drilled & Completed (net) | 55 – 65 (45 – 53) | n/a |
Interest Expense (net of interest income) | $40.0 - $50.0 | n/a |
Capital Budget ($ - million) | ||
Horizontal Drilling and Completion | $285.0 - $315.0 | n/a |
Infrastructure | $20.0 - $30.0 | n/a |
Non-op and Other | $20.0 - $30.0 | n/a |
2015 Capital Budget | $325.0 - $375.0 | n/a |
Net Carry In | $75.0 | n/a |
2015 Capital Spend | $400.0 - $450.0 | 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 quarter on Thursday, May 7, 2015 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 32225107. 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 32225107. The recording will be available from 10:00 a.m. CT
on Thursday, May 7, 2015 through Tuesday, May 12, 2015 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 horizontal exploitation of multiple intervals within the Wolfcamp, Spraberry, Clearfork and Cline 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, 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 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 March 31, | ||||
2015 | 2014 | |||
Revenues: | ||||
Oil and natural gas revenues | $101,401 | $98,004 | ||
Operating Expenses: | ||||
Lease operating expense | 22,456 | 7,915 | ||
Production and ad valorem taxes | 8,395 | 5,842 | ||
Gathering and transportation expense | 1,030 | 582 | ||
Depreciation, depletion and amortization | 59,677 | 30,973 | ||
General and administrative | 8,236 | 4,557 | ||
Asset retirement obligation accretion expense | 170 | 72 | ||
Total expenses | 99,964 | 49,941 | ||
Income from operations | 1,437 | 48,063 | ||
Other income | 515 | 30 | ||
Interest expense | (10,497) | (6,505) | ||
Non-cash gain (loss) on derivative instruments | (25,206) | (3,342) | ||
Gain (loss) on derivative instruments | 43,560 | (1,056) | ||
Total other income (expense) | 8,372 | (10,873) | ||
Net income before income tax | 9,809 | 37,190 | ||
Income tax provision | 3,370 | 13,601 | ||
Net income | 6,439 | 23,589 | ||
Less: Net income attributable to noncontrolling interest | 590 | 0 | ||
Net income attributable to Diamondback Energy, Inc. | $ 5,849 | $ 23,589 | ||
Basic earnings per common share | $ 0.10 | $ 0.49 | ||
Diluted earnings per common share | $ 0.10 | $ 0.48 | ||
Weighted average number of basic shares outstanding | 58,386 | 48,447 | ||
Weighted average number of diluted shares outstanding | 58,626 | 48,867 | ||
Diamondback Energy, Inc. | ||||||
Selected Operating Data | ||||||
(unaudited) | ||||||
Three Months Ended March 31, | ||||||
2015 | 2014 | |||||
Production Data: | ||||||
Oil (MBbl) | 2,132 | 960 | ||||
Natural gas (MMcf) | 1,599 | 708 | ||||
Natural gas liquids (MBbls) | 359 | 142 | ||||
Oil Equivalents (1)(2) (MBOE) | 2,757 | 1,220 | ||||
Average daily production(2) (BOE/d) | 30,636 | 13,552 | ||||
% Oil | 77% | 79% | ||||
Average sales prices: | ||||||
Oil, realized ($/Bbl) | $ 43.59 | $ 93.53 | ||||
Natural gas realized ($/Mcf) | $ 2.72 | $ 4.71 | ||||
Natural gas liquids ($/Bbl) | $ 11.53 | $ 34.58 | ||||
Average price realized ($/BOE) | $ 36.78 | $ 80.35 | ||||
Oil, hedged(3) ($/Bbl) | $ 64.01 | $ 92.43 | ||||
Average price, hedged(3) ($/BOE) | $ 52.57 | $ 79.48 | ||||
Average costs per BOE: | ||||||
Lease operating expenses | $ 8.14 | $ 6.49 | ||||
Production and ad valorem taxes | $ 3.04 | $ 4.79 | ||||
Gathering and transportation expense | $ 0.37 | $ 0.48 | ||||
Interest expense | $ 3.81 | $ 5.33 | ||||
General and administrative | $ 2.99 | $ 3.74 | ||||
Depreciation, depletion, and amortization | $ 21.64 | $ 25.39 | ||||
Total | $ 39.99 | $ 46.22 | ||||
Components of general and administrative expense: | ||||||
General and administrative - cash component | $ 1.20 | $ 1.94 | ||||
General and administrative - Diamondback non-cash stock-based compensation | 1.45 | 1.80 | ||||
General and administrative - Viper non-cash unit-based compensation | 0.34 | 0 | ||||
(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 derivative 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. | |||||
Non-GAAP Financial Measures
Adjusted net income is a non-GAAP financial measure equal to net income attributable to Diamondback Energy, Inc. plus non-cash (gain) loss on derivative instruments, net, and related income tax adjustments. 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 plus non-cash (gain) loss on derivative instruments, net,
interest expense, depreciation, depletion and amortization, non-cash stock-based compensation expense, capitalized stock-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, 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. 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.
Diamondback Energy, Inc. | ||||
Reconciliation of EBITDA to Net Income | ||||
(unaudited, in thousands) | ||||
Three Months Ended March 31, | ||||
2015 | 2014 | |||
Net income | 6,439 | $23,589 | ||
Non-cash (gain) loss on derivative instruments, net | 25,206 | 3,342 | ||
Interest expense | 10,497 | 6,505 | ||
Depreciation, depletion and amortization | 59,677 | 30,973 | ||
Non-cash stock-based compensation expense | 7,063 | 3,256 | ||
Capitalized stock-based compensation expense | (2,139) | (1,066) | ||
Asset retirement obligation accretion expense | 170 | 72 | ||
Income tax provision | 3,370 | 13,601 | ||
Adjusted EBITDA | $110,283 | $80,272 | ||
Diamondback Energy, Inc. | |||||
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. | |||||
The following table presents a reconciliation of adjusted net income to net income: | |||||
Three Months Ended March 31, | |||||
2015 | 2014 | ||||
Net income attributable to Diamondback Energy, Inc. | $5,849 | $23,589 | |||
Plus: | |||||
Non-cash (gain) loss on derivative instruments | 25,206 | 3,342 | |||
Income tax adjustment for above items | (8,660) | (1,222) | |||
Adjusted net income | $ 22,395 | $ 25,709 | |||
Adjusted net income per common share: | |||||
Basic | $ 0.38 | $ 0.53 | |||
Diluted | $ 0.38 | $ 0.53 | |||
Weighted average common shares outstanding: | |||||
Basic | 58,386 | 48,447 | |||
Diluted | 58,626 | 48,867 | |||
Diamondback Energy, Inc.
Reconciliation of Discretionary Cash Flow to Net Cash Flow from Operating Activities
(unaudited, in thousands)
Discretionary cash flow is used by the investment community as a financial indicator of an oil and natural gas company’s ability to generate cash to internally fund exploration and development activities and to service debt. Discretionary cash flow is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions.
Discretionary cash flow should not be considered an alternative to net cash provided by operating activities or net income, as defined by GAAP. Discretionary cash flow equals cash flows from operations before changes in working capital accounts. Diamondback’s definition of discretionary cash flow may not be comparable to other similarly titled measures of other companies because all companies may not calculate discretionary cash flow in the same manner. The following table presents reconciliation of discretionary cash flow to net cash provided by operating activities.
Three Months Ended March 31, | |||
2015 | 2014 | ||
Net Income | $ 6,439 | $ 23,589 | |
Depreciation, depletion and amortization | 59,677 | 30,973 | |
Income tax provision | 3,370 | 13,601 | |
Accretion expense | 170 | 72 | |
Non-cash stock based compensation | 4,924 | 2,190 | |
Non-cash (gain) loss on derivatives | 25,206 | 3,342 | |
Non-cash interest expense | 8,759 | 5,728 | |
Other non-cash operating items | 630 | 447 | |
Discretionary cash flow | 109,175 | 79,942 | |
Changes in working capital accounts | (10,032) | (8,476) | |
Net cash provided by operating activities | $ 99,143 | $ 71,466 | |
Discretionary cash flow per share: | |||
Basic | $ 1.87 | $ 1.65 | |
Diluted | $ 1.86 | $ 1.64 | |
Weighted average common shares outstanding: | |||
Basic | 58,386 | 48,447 | |
Diluted | 58,626 | 48,867 | |
Diamondback Energy, Inc. | ||||
Derivatives Information | ||||
(unaudited) | ||||
The table below provides data regarding the details of Diamondback's current price swap contracts through 2015. | ||||
Average Bbls | Average | |||
Oil Swaps | Per Day | Price per Bbl | ||
2015 | ||||
First Quarter-LLS | 6,344 | $ 95.57 | ||
First Quarter-WTI | 5,000 | $ 84.10 | ||
First Quarter-Brent | 1,000 | $ 88.83 | ||
Second Quarter-LLS | 3,330 | $ 91.89 | ||
Second Quarter-WTI | 5,000 | $ 84.10 | ||
Second Quarter-Brent | 2,000 | $ 88.78 | ||
Third Quarter-LLS | 3,000 | $ 90.99 | ||
Third Quarter-WTI | 5,000 | $ 84.10 | ||
Third Quarter-Brent | 2,000 | $ 88.78 | ||
Fourth Quarter-LLS | 3,000 | $ 90.99 | ||
Fourth Quarter-WTI | 5,000 | $ 84.10 | ||
Fourth Quarter-Brent | 2,000 | $ 88.78 | ||
2015 Average | 10,660 | $ 88.14 | ||
Investor Contact:
Adam Lawlis
+1 432.221.7467
alawlis@diamondbackenergy.com