Diamondback Energy, Inc. Announces Second Quarter 2013 Financial and Operating Results

MIDLAND, Texas, Aug. 6, 2013 (GLOBE NEWSWIRE) -- Diamondback Energy, Inc. (Nasdaq:FANG) ("Diamondback" or the "Company") today announced financial and operating results for the second quarter ended June 30, 2013.

During the second quarter of 2013, net income was $14.5 million, or $0.36 per diluted share. Net income for the second quarter includes a net unrealized gain on commodity derivatives of $3.9 million ($2.5 million net of tax), or $0.06 per diluted share. Without the impact of this item, net income for the second quarter of 2013 would have been $11.9 million, or $0.30 per diluted share.


  • Q2 2013 production was 6.6 MBoe/d, a 38% increase from Q1 2013 with oil volumes increasing 49% over the same period, helping to drive EBITDA (as defined below) to $35.1 million (up 73% over the same period).
  • Continued progress lowering lease operating expense ("LOE") by 20% to $10.15/Boe during Q2 2013 from $12.61/Boe in Q1 2013.
  • The ST 4301H well in Midland County, with a 29 stage 7,141' lateral, achieved a peak 30 day rate of 916 Boe/d (85% oil) on submersible pump, with a previously reported peak 24 hour initial production ("IP") rate of 1,136 Boe/d.
  • The Jacee A Unit 1H well in Upton County, with a 30 stage 7,541' lateral, achieved a peak 24 hour IP of 1,085 Boe/d on submersible pump, with a peak 30 day rate of 632 Boe/d (83% oil).
  • The Janey 2H well in Upton County, with a 19 stage 4,572' lateral, was put on submersible pump and achieved a peak 24 hour IP rate of 930 Boe/d (87% oil).
  • The Janey 4H well in Upton County, with a 10 stage 4,564' lateral, was put on submersible pump and achieved a peak 24 hour IP rate of 880 Boe/d (77% oil).
  • The Company's 15 producing horizontal Wolfcamp B wells have achieved peak 24 hour IP rates that averaged 905 Boe/d (88% oil) from lateral lengths that averaged 5,687'.
  • Entered into two definitive agreements to purchase approximately 11,150 net acres in the Midland Basin for $165 million extending our horizontal inventory in the heart of the northern part of the basin.

"During the second quarter of 2013, we continued to ramp production, our operating efficiency continues to improve, and we've expanded our footprint by over 20% with these acquisitions. We are encouraged by the success of our horizontal drilling program, with our average curve from these wells 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 to a level we believe is among the best in the Midland Basin. We recently drilled our first 10,353 foot lateral (19,620' total measured depth) in 19 days. Our Q2 2013 average well cost for short laterals was $5.3 million which is a 12% improvement over Q1 2013, with our most recent approximately 5,000 foot lateral in Upton County drilled and completed at $4.8 million, our first sub $5.0 million well. Our longer 7,500 foot laterals averaged $7.6 million, with our most recent completion at $7.2 million. Finally, we continue to realize the benefits from our infrastructure investments, reducing our total LOE by approximately 20% to $10.15 per Boe for the second quarter of 2013 from $12.61 per Boe in the first quarter of 2013."


Diamondback Energy has entered into two definitive agreements with unrelated third party sellers to purchase an aggregate of approximately 13,900 gross (11,150 net) operated acres in the Midland Basin for an aggregate of approximately $165 million, subject to certain adjustments. The proposed transactions, which are expected to close by the end of September 2013, will increase the Company's leasehold interest in the Midland Basin to over 65,000 net acres.

The assets, located in Martin County and in southern Dawson County (straddling the Martin County line), provide a strategic opportunity to exploit the northern Midland Basin horizontally. Moreover, the acreage has an advantageous blended 78% net revenue interest compared to the more typical 75% net revenue interest found in the Permian Basin. The acreage includes 34 producing net vertical wells, with approximately 800 boe/d (81% oil) of production (as of June 2013).

Development potential within the footprint of the acquisitions includes approximately 69 net horizontal Wolfcamp B locations, based on 160 acre spacing per well. In addition, Diamondback Energy believes the acreage is prospective for horizontal development in multiple Spraberry intervals, Wolfcamp A and Cline intervals.


During the second quarter of 2013, Diamondback concentrated its horizontal drilling activity in the Wolfcamp B shale, where it currently operates two rigs in Midland County and another in Upton County. Additionally, Diamondback drilled its first Wolfcamp B and Clearfork Shale well in Andrews County. Diamondback plans to add a fourth horizontal rig in Q4 2013.

As of July 31, 2013, Diamondback had drilled (or was a non-operating partner in drilling) a total of 20 gross horizontal Wolfcamp B wells with lateral lengths ranging from 3,733' to 10,353', with three wells currently being drilled.

Horizontal Focus: Midland County
Number of
Peak 24 HR
IP (Boe/d)
Peak 30 day
IP (Boe/d)

% Oil(a)
Kemmer 4209H(b) 3,733' 15 892 712(d) 85%
ST NW 2501H 4,451' 19 1,054 655(d) 90%
ST NW 2502H 4,351' 16 651 500(c) 88%
Sarah Ann 3812H(b) 4,830' 18 892 711(d) 88%
ST W 4301H 7,141' 29 1,136 916(d) 85%
ST W 701H 7,280' 29 1,042(d) N/A(e) 94%
ST W 4302H 7,071' 30 701(d) N/A(e) 93%
ST W 706H 7,541' Currently Completing 30 Stage Frac
Horizontal Focus: Upton County
Number of
Peak 24 HR
IP (Boe/d)
Peak 30 day
IP (Boe/d)

% Oil(a)
Janey 16H 3,842' 16 618 486(c) 86%
Neal A Unit 8 1H 7,441' 32 871 697(c) 87%
Janey 3H 4,411' 19 724 488(d) 82%
Neal B Unit 8 2H 6,501' 26 1,134 617(d) 73%
Kendra A Unit 1H 7,411' 30 970 677(d) 82%
Jacee A Unit 1H 7,541' 30 1,085 632(d) 83%
Janey 2H 4,572' 19 930(d) N/A(e) 87%
Janey 4H 4,564' 10 880(d) N/A(e) 77%
Charlotte A Unit #1H 10,353' Currently Completing 39 Stage Frac
Neal C Unit 8 #3H 6,851' Currently Completing 15 Stage Frac
Horizontal Focus: Andrews County
Number of
Peak 24 HR
IP (Boe/d)
Peak 30 day
IP (Boe/d)

% Oil(a)
UL III 4-1H 4,051' Flowback Operations Underway
UL Viper 6-1H 7,540' Well Drilled; Frac Scheduled
(a) During the period for which the 30 day IP rate is presented, except in the case of the ST W 701H, ST W 4302H, Janey 2H and 4H wells, which are based on the Peak 24 hour IP rate
(b) Non-Operated
(c) On gas lift
(d) On sub pump
(e) A peak 30 day IP rate is not available


During the second quarter of 2013, the Company drilled 11 vertical wells while running an average of two rigs during the period and we are currently running one rig. Diamondback reached total depth ("TD") in an average of eight days (down from an average of nine days in Q1 2013), with three of those recent vertical wells reaching TD in less than seven days. Diamondback anticipates drilling a total of 35 to 40 gross vertical wells during 2013. The Company's vertical well costs averaged $1.9 million for the quarter, which is below its previous guidance of $2.0 to $2.2 million per well.

PRODUCTION (unaudited)

2nd Quarter 1st Quarter
2013 2013
Production Volumes
Oil (MBbls) 447.2 301.0
Gas (MMcf) 408.5 351.0
Liquids (MBbls) 84.4 71.3
Oil Equivalents (MBoe) 599.7 430.9
Avg. Daily Production (MBoe/d) 6.6 4.8
Average Realized Price
Oil (per Bbl) $91.76 $83.89
Oil with Effect of Hedges (per Bbl) $89.84 $78.76
Natural Gas (per Mcf) $4.08 $3.28
Natural Gas Liquids (per Bbl) $31.91 $35.12
Oil Equivalents (per Boe) $75.70 $67.09
Oil Equivalents with Effect of Hedges (per Boe) $74.27 $63.51


Second quarter 2013 income before income taxes was $22.3 million. The Company's net income after taxes was $14.5 million in the second quarter of 2013 as compared to $5.4 million in the first quarter of 2013.

Second quarter 2013 EBITDA was $35.1 million and second quarter 2013 revenues were $45.4 million, compared to first quarter 2013 EBITDA of $20.3 million and first quarter revenues of $28.9 million.

As of June 30, 2013, Diamondback had an undrawn revolving credit facility of $180.0 million and $81.9 million in cash and cash equivalents on its balance sheet for total liquidity of approximately $262 million.

During the second quarter of 2013, capital expenditures were approximately $64.6 million, which included approximately $55.6 million for drilling and completion, $5.2 million for leasehold acquisitions and the remainder for infrastructure and facilities.


2013 guidance remains unchanged at this time.

2013 Guidance
Production 7,200 - 7,500 Boe/d
Capital Expenditures $290 - $320 million
Horizontal Per Well Costs $7.5 - $8.5 million
Vertical Per Well Costs $2.0 - $2.2 million
Direct Lease Operating Expense $8.50 - $10.00/ Boe
Indirect Operating Expense (Ad valorem and overhead) $2.50 - $3.00 / Boe
Production Tax 4.6% oil, 7.5% gas and NGLs
General and Administrative Expenses $3.00 - $5.00 / Boe
Depreciation, Depletion and Amortization Expenses $22.00 - $25.00 / Boe


Diamondback will host a conference call with investors and analysts to discuss its second quarter 2013 results on August 7, 2013, at 10:00 a.m. ET (9:00 a.m. CT). Interested parties should call (877) 440-7573 (United States/Canada) or (253) 237-1144 (International) and utilize the confirmation code 22840355. A live broadcast of the earnings conference call will also be available via the internet at www.diamondbackenergy.com under the "Investor Relations" section of the site. A 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 22840355. The recording will be available from 2:30 p.m. ET on Wednesday, August 7, 2013 through Wednesday, August 14, 2013 at 11:59 p.m. ET. The webcast will be archived on the Company's website for 30 days.

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, which we refer to collectively as the Wolfberry play.

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 (including the pending acquisitions) 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
June 30, 2013
Three months ended
March 31, 2013
Three months ended
June 30, 2012(1)
Oil and natural gas revenues $45,394 $28,909 $16,030
Operating Expenses:
Lease operating expense 6,087 5,435 3,529
Production taxes 2,196 1,427 782
Gathering and transportation expense 247 133 79
Depreciation, depletion and amortization 14,815 10,738 5,659
General and administrative 2,621 2,471 1,653
Asset retirement obligation accretion expense 45 43 21
Total expenses 26,011 20,247 11,723
Income from operations 19,383 8,662 4,307
Other income 388 389 586
Net interest income (expense) (535) (485) (1,172)
Unrealized gain on derivative instruments 3,893 1,535 12,065
Loss on derivative instruments (856) (1,543) (2,108)
Loss from equity investment (54)
Total other income (expense) 2,890 (104) 9,317
Net income before income tax 22,273 8,558 13,624
Income tax provision 7,802 3,162
Net income $14,471 $5,396 $13,624
Basic earnings per common share $0.37 $0.15
Diluted earnings per common share $0.36 $0.15
Weighted average number of basic shares outstanding 39,402,282 37,059,071
Weighted average number of diluted shares outstanding 39,718,574 37,205,690
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 months ended June 30, 2012 as Diamondback was not yet a public company and its assets and operations were owned by a limited liability company.

Non-GAAP Financial Measures

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 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.
Reconciliation of EBITDA to Net income
(in thousands)
Three months ended
June 30, 2013
Three months ended
March 31, 2013
Net income $14,471 $5,396
Unrealized (Gain) on derivatives (3,893) (1,535)
Loss on derivatives 856 1,543
Interest expense 535 485
Depreciation, depletion and amortization 14,815 10,738
Non-cash equity-based compensation expense 700 655
Capitalized equity-based compensation expense (223) (197)
Asset retirement obligation accretion expense 45 43
Deferred income tax provision 7,802 3,162
EBITDA $35,108 $20,290

CONTACT: Investor Contact: Adam Lawlis +1 432.221.7467 alawlis@diamondbackenergy.com

Source:Diamondback Energy, Inc.