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): November 4, 2013
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 1225 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 November 4, 2013, Diamondback Energy, Inc. (the “Company”) issued a press release announcing financial and operating results for the three months ended September 30, 2013 and providing an update on its 2013 activities. 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 November 4, 2013 announcing financial and operating results for the three months ended September 30, 2013. | ||
2
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: | November 4, 2013 | By: | /s/ Teresa L. Dick | |
Teresa L. Dick | ||||
Senior Vice President and Chief Financial Officer | ||||
3
Exhibit Index
Number | Exhibit | ||
99.1 | Press release dated November 4, 2013 announcing financial and operating results for the three months ended September 30, 2013. | ||
4
Exhibit 99.1
News Release
Investor Contact:
Adam Lawlis
+1 432.221.7467
alawlis@diamondbackenergy.com
DIAMONDBACK ENERGY, INC. ANNOUNCES THIRD QUARTER 2013
FINANCIAL AND OPERATING RESULTS
Midland, TX (November 4, 2013) – Diamondback Energy, Inc. (NASDAQ: FANG) (“Diamondback” or the “Company”) today announced financial and operating results for the third quarter ended September 30, 2013.
During the third quarter of 2013, net income was $14.6 million, or $0.33 per diluted share. Net income for the third quarter includes a non-cash loss on commodity derivatives of $1.7 million ($1.0 million net of tax), or $0.02 per diluted share. Without the impact of this item, net income for the third quarter of 2013 would have been $15.6 million, or $0.35 per diluted share.
HIGHLIGHTS
● The Company's first horizontal Middle Spraberry test well, the Sarah Ann 3814H, a non- operated well in Midland County, had a peak 24 hour initial production ("IP") rate of 733 Boe/d (90% oil) on electric submersible pump. The well was completed with a 16 stage5,041' lateral. Early oil production rates are comparable to Wolfcamp B rates. This Middle Spraberry test defines a new horizontal bench that has meaningfully increased the Company's identified potential horizontal drilling Spraberry locations to 360 gross (276 net) from 181 gross (139 net).
● The ST S 501H well in Midland County, with a 36 stage 8,926' lateral, achieved a peak naturally flowing 24 hour "IP" rate of 1,033 Boe/d (90% oil). This well has flowed for 38 days, which is encouraging since the natural flowback period is longer than any horizontal well Diamondback has completed to date. Diamondback typically experiences a significant increase in IP rates from artificial lift.
● The ST NW 3602H well in Midland County, with a 21 stage 5,020' lateral, achieved a peak 24 hour IP rate of 1,069 Boe/d (94% oil). This well is currently on gas lift.
● The ST NW 3603H well in Midland County, with a 21 stage 5,105' lateral, achieved a peak 24 hour IP rate of 934 Boe/d (89% oil). This well is currently on gas lift.
● The ST 4105H and ST 4106H wells, drilled from the Company's first two well pad, were completed with a total drilling and completion cost for both wells in the range of $10.5 million to $11.0 million. These wells were completed using the "zipper" frac technique with no operational issues. The ST 4105H well was completed with a 5,041' lateral length and 22 stages while the ST 4106H well was completed with a 4,801' lateral length and 21 stages. Flowback operations on both wells are underway.
● Continued progress lowering lease operating expense ("LOE") by 21% to $7.27/Boe during the third quarter of 2013 from $9.16/Boe in the second quarter of 2013 (after giving effect to the reclassification described in notes (a) and (b) in the guidance table below).
● EBITDA (as defined below) was $47.7 million.
"I'm proud of the quarterly results as we again demonstrated our ability to reduce total well costs, reduce drilling cycle time, reduce our operating expenses, and continue our production ramp. Our cash margins during the third quarter were almost $70/boe and I believe we are delivering results and returns to our stockholders that are among the best in the Midland Basin. We are extremely excited about the early results from a test in the Middle Spraberry zone in Midland County as a non-operated partner furthering our belief that multiple shale benches are viable development horizons. These results have meaningfully increased our identified potential Spraberry horizontal drilling locations from 181 gross locations to 360 gross locations. Finally, our first 9,000 foot lateral was drilled and completed in Midland County for $8.5 million and has the potential to be the best horizontal well to date for Diamondback once placed on artificial lift. We have now drilled over 200,000 feet of horizontal laterals and remain encouraged by the success of our development program. Our average production from these wells is performing at or above the type curve we predicted," stated Travis Stice, Chief Executive Officer of Diamondback.
Mr. Stice added, "Our operations team continues to improve performance by reducing cycle times and costs. We have achieved four consecutive quarters of double digit declines in lease operating expense reduction, which are down over 50% from this same period last year."
HORIZONTAL DRILLING UPDATE – COSTS COMING DOWN / EFFICIENCIES UP
During the third quarter of 2013, Diamondback drilled 11 horizontal wells with an average lateral length of 6,664 feet. The Company concentrated its horizontal drilling activity in the Wolfcamp B shale, where it currently operates two rigs in Midland County and one in Upton County. Diamondback has added a fourth horizontal rig to test its recently acquired Martin County acreage. During the third quarter of 2013, 7,500 foot laterals averaged approximately $7.2 million, down from $7.6 million in the previous quarter and now average approximately 14 days from spud to total depth ("TD") for a 7,500 foot lateral with one 7,500 foot lateral well reaching TD in 12 days. As previously reported, Diamondback drilled its first Wolfcamp B and Clearfork Shale wells in Andrews County with encouraging results.
VERTICAL DRILLING UPDATE
During the third quarter of 2013, the Company drilled nine vertical wells and is currently running one rig. Diamondback reached TD in an average of 7.6 days (down from an average of eight days in the second quarter of 2013), with four of those recent vertical wells reaching TD in less than seven days. The Company's vertical well costs averaged $1.9 million in the third quarter of 2013, which is below its previous guidance of $2.0 to $2.2 million per well.
FINANCIAL HIGHLIGHTS
Third quarter 2013 income before income taxes was $23.7 million. The Company's net income after taxes was $14.6 million in the third quarter of 2013 as compared to $14.5 million in the second quarter of 2013.
Third quarter 2013 EBITDA was $47.7 million and third quarter 2013 revenues were $57.8 million, compared to second quarter 2013 EBITDA of $35.1 million and second quarter revenues of $45.4 million.
The Company's liquidity position remains strong with approximately $53 million of cash on hand at September 30, 2013 and an undrawn revolver with $225 million of availability.
During the third quarter of 2013, capital expenditures were approximately $84.9 million, which included approximately $78.0 million for drilling and completion, $3.5 million for leasehold acquisitions (excluding the previously announced minerals and Martin and Dawson County acquisition) and the remainder for infrastructure and facilities.
FULL YEAR 2014 GUIDANCE
Previously announced guidance:
2013 | 2014 Guidance | ||||||
Guidance | Diamondback excluding Minerals | Minerals | Diamondback Energy Inc | ||||
Total Net Production – MBoe/d | 7.2 - 7.5 | 12.5 – 13.0 | 2.5 – 3.0 | 15.0 – 16.0 | |||
Unit costs ($/boe) | |||||||
Lease operating expenses (a) | $9.50 - $11.50 | $7.00 - $8.00 | — | $6.00 - $7.00 | |||
G&A | $3.00 - $5.00 | $2.50 - $3.50 | — | $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) | ||||
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 Tuesday, November 5, 2013 at 8:00 a.m. CT. Participants should call (877) 440-7573 (United States/Canada) or (253) 237-1144 (International) and utilize the confirmation code 95215225. 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 95215225. The recording will be available from 11:00 a.m. CT on Tuesday, November 5, 2013 through Monday, November 11, 2013 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 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 Clearfork, Spraberry, Wolfcamp, 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 belief, based on currently available information, as to the outcome and timing of future events. These forward-looking statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include the factors discussed or referenced in the Company's filings with the Securities and Exchange Commission ("SEC"), including its Annual Report on Form 10-K and Quarterly Reports on Form 10-Q, that could cause actual results to differ materially from those projected. These filings are available for free at the SEC's website (http://www.sec.gov). Any forward-looking statement made in this new release speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.
Diamondback Energy, Inc. | |||||||||||||||
Consolidated Statements of Operations | |||||||||||||||
(unaudited, in thousands) | |||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2013 | 2012(1) | 2013 | 2012(1) | ||||||||||||
Revenues: | |||||||||||||||
Oil and natural gas revenues | $ | 57,791 | $ | 16,814 | $ | 132,094 | $ | 49,195 | |||||||
Operating Expenses: | |||||||||||||||
Lease operating expense | 4,964 | 3,509 | 15,367 | 9,508 | |||||||||||
Production and ad valorem taxes | 3,553 | 1,293 | 8,295 | 3,191 | |||||||||||
Gathering and transportation expense | 261 | 118 | 641 | 264 | |||||||||||
Depreciation, depletion and amortization | 17,423 | 6,136 | 42,976 | 16,552 | |||||||||||
General and administrative | 2,121 | 1,650 | 7,213 | 4,487 | |||||||||||
Asset retirement obligation accretion expense | 46 | 22 | 134 | 63 | |||||||||||
Total expenses | 28,368 | 12,728 | 74,626 | 34,065 | |||||||||||
Income from operations | 29,423 | 4,086 | 57,468 | 15,130 | |||||||||||
Other income | 270 | 643 | 1,047 | 1,654 | |||||||||||
Net interest expense | (1,088 | ) | (1,129 | ) | (2,108 | ) | (3,181 | ) | |||||||
Non-cash gain (loss) on derivative instruments | (1,695 | ) | (2,252 | ) | 3,733 | 6,386 | |||||||||
Loss on derivative instruments | (3,215 | ) | (896 | ) | (5,614 | ) | (4,369 | ) | |||||||
Loss from equity investment | ― | ― | ― | (67 | ) | ||||||||||
Total other income (expense) | (5,728 | ) | (3,634 | ) | (2,942 | ) | 423 | ||||||||
Net income before income tax | 23,695 | 452 | 54,526 | 15,553 | |||||||||||
Income tax provision | 9,099 | ― | 20,063 | ― | |||||||||||
Net income | $ | 14,596 | $ | 452 | $ | 34,463 | $ | 15,553 | |||||||
Basic earnings per common share | $ | 0.33 | $ | 0.85 | |||||||||||
Diluted earnings per common share | $ | 0.33 | $ | 0.85 | |||||||||||
Weighted average number of basic shares outstanding | 44,385,107 | 40,308,989 | |||||||||||||
Weighted average number of basic shares outstanding | 44,697,609 | 40,523,764 | |||||||||||||
¹The company does not include earnings per common share basic and diluted, weighted average number of basic shares outstanding or weighted average number of diluted shares outstanding for the three and nine months ended September 30, 2012 as Diamondback was not yet a public company and its assets and operations were owned by a limited liability company. | |||||||||||||||
Diamondback Energy, Inc. | ||||||||||||||||||
Selected Operating Data | ||||||||||||||||||
(unaudited) | ||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||||
Production Data: | ||||||||||||||||||
Oil (MBbl) | 515 | 166 | 1,263 | 484 | ||||||||||||||
Natural gas (MMcf) | 446 | 204 | 1,206 | 494 | ||||||||||||||
Natural gas liquids (MBbls) | 93 | 45 | 249 | 110 | ||||||||||||||
Oil Equivalents (1)(2) (MBOE) | 683 | 245 | 1,713 | 677 | ||||||||||||||
Average daily production(2) (BOE/d) | 7,419 | 2,664 | 6,275 | 2,469 | ||||||||||||||
% Oil | 75 | % | 68 | % | 74 | % | 72 | % | ||||||||||
Average sales prices: | ||||||||||||||||||
Oil, realized ($/Bbl) | $ | 103.11 | $ | 87.42 | $ | 94.51 | $ | 89.94 | ||||||||||
Natural gas realized ($/Mcf) | 3.50 | 2.83 | 3.63 | 2.50 | ||||||||||||||
Natural gas liquids ($/Bbl) | 33.67 | 38.04 | 33.49 | 40.14 | ||||||||||||||
Average price realized ($/BOE) | 84.67 | 68.60 | 77.11 | 72.71 | ||||||||||||||
Oil, hedged(3) ($/Bbl) | 96.86 | 82.03 | 90.06 | 80.92 | ||||||||||||||
Average price, hedged(3) ($/BOE) | 79.96 | 64.94 | 73.83 | 66.26 | ||||||||||||||
Average costs per BOE: | ||||||||||||||||||
Lease operating expenses | $ | 7.27 | $ | 14.32 | $ | 8.97 | $ | 14.05 | ||||||||||
Production and ad valorem taxes | 5.21 | 5.28 | 4.84 | 4.71 | ||||||||||||||
Gathering and transportation expense | 0.38 | 0.48 | 0.37 | 0.39 | ||||||||||||||
Interest expense | 1.59 | 4.61 | 1.23 | 4.70 | ||||||||||||||
General and administrative(4) | 3.11 | 6.73 | 4.21 | 6.63 | ||||||||||||||
Depreciation, depletion, and amortization | 25.53 | 25.03 | 25.09 | 24.46 | ||||||||||||||
Total | $ | 43.09 | $ | 56.45 | $ | 44.71 | $ | 54.96 | ||||||||||
(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 $490 and $176 for the three months ended September 30, 2013 and 2012, respectively, and $1,426 and $535 for the nine months ended September 30, 2013 and 2012, respectively. Excluding stock based compensation from the above metric results in general and administrative cost per BOE of $2.39 and $6.01 for the three months ended September 30, 2013 and 2012, respectively, and $3.38 and $5.84 for the nine months ended September 30, 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 gain (loss) on derivative contracts, interest expense, depreciation, depletion and amortization; 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 | ||||||||||||||||
(unaudited) | ||||||||||||||||
Adjusted net income is a performance measure used by management to evaluate performance, prior to non-cash (gains) losses on derivatives and impairment of long-lived assets. | ||||||||||||||||
The following presents a reconciliation of net income to adjusted net income: | ||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
(in thousands, except for per share data) | 2013 | 2012(1) | 2013 | 2012(1) | ||||||||||||
Net income | $ | 14,596 | $ | 452 | $ | 34,463 | $ | 15,553 | ||||||||
Plus: | ||||||||||||||||
Non-cash (gain) loss on derivative instruments | 1,695 | 2,252 | (3,733 | ) | (6,386 | ) | ||||||||||
Income tax adjustment for above items | (651 | ) | ― | 1,374 | ― | |||||||||||
Adjusted net income | $ | 15,640 | $ | 2,704 | $ | 32,104 | $ | 9,167 | ||||||||
Adjusted net income per common share: | ||||||||||||||||
Basic | $ | 0.35 | $ | 0.80 | ||||||||||||
Diluted | $ | 0.35 | $ | 0.79 | ||||||||||||
Weighted average common shares outstanding: | ||||||||||||||||
Basic | 44,385,107 | 40,308,989 | ||||||||||||||
Diluted | 44,697,609 | 40,523,764 | ||||||||||||||
¹The company does not include earnings per common share basic and diluted, weighted average number of basic shares outstanding or weighted average number of diluted shares outstanding for the three and nine months ended September 30, 2012 as Diamondback was not yet a public company and its assets and operations were owned by a limited liability company. | ||||||||||||||||
Diamondback Energy, Inc. | |||||||||||||||
Reconciliation of EBITDA to Net Income | |||||||||||||||
(unaudited, in thousands) | |||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
Net income | $ | 14,596 | $ | 452 | $ | 34,463 | $ | 15,553 | |||||||
Non-cash (gain) loss on derivatives | 1,695 | 2,252 | (3,733 | ) | (6,386 | ) | |||||||||
Loss on derivatives | 3,215 | 896 | 5,614 | 4,369 | |||||||||||
Interest expense | 1,089 | 1,130 | 2,109 | 3,184 | |||||||||||
Depreciation, depletion and amortization | 17,423 | 6,136 | 42,976 | 16,552 | |||||||||||
Non-cash equity-based compensation expense | 749 | 291 | 2,105 | 873 | |||||||||||
Capitalized equity-based compensation expense | (259 | ) | (115 | ) | (679 | ) | (338 | ) | |||||||
Asset retirement obligation accretion expense | 46 | 22 | 134 | 63 | |||||||||||
Deferred income tax provision | 9,099 | — | 20,063 | — | |||||||||||
EBITDA | $ | 47,653 | $ | 11,064 | $ | 103,052 | $ | 33,870 | |||||||
Diamondback Energy, Inc. | |||||||||||||||||||||
Derivatives Information | |||||||||||||||||||||
(unaudited) | |||||||||||||||||||||
The table below provides data regarding the settlement details through 2014 of our current price swap contracts. | |||||||||||||||||||||
4Q13 | 1Q14 | 2Q14 | 3Q14 | 4Q14 | |||||||||||||||||
Oil Swaps: | |||||||||||||||||||||
Volumes (Bbl) | 92,000 | ||||||||||||||||||||
LLS Price (Bbl) | $ | 80.55 | |||||||||||||||||||
Volumes (Bbl) | 92,000 | 90,000 | 91,000 | ||||||||||||||||||
LLS Price (Bbl) | $ | 100.20 | $ | 100.20 | $ | 100.20 | |||||||||||||||
Volumes (Bbl) | 92,000 | 90,000 | 30,000 | ||||||||||||||||||
Brent Price (Bbl) | $ | 109.70 | $ | 109.70 | $ | 109.70 | |||||||||||||||
Volumes (Bbl) | 59,000 | 91,000 | 92,000 | 92,000 | |||||||||||||||||
LLS Price (Bbl) | $ | 101.00 | $ | 101.00 | $ | 101.00 | $ | 101.00 | |||||||||||||