Crude Oil ( ) Brent Crude ( ) Natural Gas ( ) S&P 500 ( ) PHLX Oil ( )

Diamondback Energy, Inc. (FANG) (“Diamondback” or the “Company”) today announced financial and operating results for the third quarter ended September 30, 2014.

HIGHLIGHTS

  • Q3 2014 production was 20.6 Mboe/d, an increase of 16% from Q2 2014 and 178% from Q3 2013.
  • Diamondback reports strong Lower Spraberry results:
    • The ST NW 2507LS in Midland County has a 5,257 foot lateral, completed with 25 stages, achieving a peak 2-stream 24 hour initial production (“IP”) rate of 1,697 boe/d (85% oil) on electric submersible pump (“ESP”), with an average peak 30 day 2-stream IP rate of 1,405 boe/d (88% oil).
    • The Gridiron S002LS, part of the Company’s first operated stacked lateral test, has a 9,064 foot lateral, completed with 39 stages, and a peak 24 hour 2-stream IP rate to date of 1,395 boe/d (88% oil) on ESP.
    • The Mabee Breedlove 2301LS in northwest Martin County has a 6,454 foot lateral, completed with 28 stages, achieving a peak 24 hour 2-stream flowing IP rate of 1,145 boe/d (94% oil) with an average peak 30 day flowing 2-stream IP rate of 779 boe/d (87% oil).
  • Diamondback completed its first operated stacked lateral test in the Wolfcamp B and Lower Spraberry in Midland County. The Gridiron S001WB has a 9,320 foot lateral, completed in the Wolfcamp B with 40 stages, achieving a peak 24 hour flowing 2-stream IP rate of 1,513 boe/d (89% oil).
  • Diamondback’s agent lender under its revolving credit facility has approved a borrowing base increase of 114% to $750 million. The Company has elected to limit the lenders’ aggregate commitment to $500 million.
  • Diamondback has hedged an average of 8,989 bopd during Q4 2014 at an average price of $95.16/bbl and an average of 10,660 bopd in 2015 at an average price of $88.14/bbl.
  • During the third quarter of 2014, net income was $43.7 million, or $0.79 per diluted share. Net income for the third quarter includes a net gain on commodity derivatives of $14.9 million ($9.7 million net of tax), or $0.18 per diluted share. Without the impact of these items, net income for the third quarter of 2014 would have been $34.0 million, or $0.61 per diluted share.
  • Adjusted EBITDA (as defined below) for the third quarter of 2014 was $111.1 million.

FINANCIAL HIGHLIGHTS

Third quarter 2014 income before income taxes was $68.6 million. During that same period, the Company’s net income after taxes was $43.7 million as compared to $27.8 million during the second quarter of 2014.

Third quarter 2014 Adjusted EBITDA was $111.1 million and third quarter 2014 revenues were $139.1 million, compared to second quarter 2014 Adjusted EBITDA of $103.1 million and second quarter 2014 revenues of $127.0 million. Discretionary cash flow was $97.1 million, or $1.75 per diluted share, in the third quarter of 2014.

As of September 30, 2014, Diamondback had $40.6 million of cash on hand and had drawn $140.0 million on its secured revolving credit facility. Diamondback’s agent lender under its revolving credit facility has approved a borrowing base increase of 114% to $750 million. The Company has elected to limit the lenders’ aggregate commitment to $500 million.

Third quarter 2014 general and administrative expenses were $3.42/boe, which includes non-cash equity-based compensation, net of capitalized amounts of $2.1 million. Excluding equity-based compensation from that metric would have resulted in general and administrative expenses of $2.33/boe.

During the third quarter of 2014, capital spent for drilling, completion and infrastructure was approximately $103.3 million. Additionally, the Company spent approximately $528 million on acquisitions of leasehold interests.

HORIZONTAL DRILLING UPDATE

  • The Company is currently running five horizontal rigs and one vertical rig.
  • 20 wells were completed in the third quarter of 2014, bringing the year to date total to 46 wells. Of the 46 total wells, 39 Wolfcamp B wells had sufficient production for an average peak 24 hour IP rate of 1,017 boe/d (90% oil) from an average lateral length of 6,441 feet. Additionally, during the nine months ended September 30, 2014, four Lower Spraberry wells were completed with an average peak 24 hour IP rate of 1,228 boe/d (90% oil) from an average lateral length of 5,736 feet.
  • 38 of these Wolfcamp B wells have sufficient production history for an average peak 30 day IP rate of 681 boe/d (85% oil) from an average lateral length of 6,342 feet, or 107 boe/d per 1,000 feet of lateral. The average peak 30 day IP rate for the four Lower Spraberry wells is 886 boe/d (88% oil) from an average lateral length of 5,736 feet, or 154 boe/d per 1,000 feet of lateral.
Significant Well Tests
Martin County
Lateral Length Number of
Stages
Zone Lift Method Peak 24 HR
IP (boe/d)
Peak 30 day
IP (boe/d)
% Oil(a)
Mabee Breedlove 2301LS 6,454′ 28 Lower Spraberry Naturally Flowing 1,145 779 87%
Kimberly 804H 7,201′ 31 Wolfcamp B Flowing Back
Midland County
Lateral Length Number of
Stages
Zone Lift Method Peak 24 HR
IP (boe/d)
Peak 30 day
IP (boe/d)
% Oil(a)
ST NW 2507LS 5,257′ 25 Lower Spraberry ESP 1,697 1,405 88%
ST 4006Hb 5,124′ 33 Wolfcamp B ESP 1,228 937 87%
ST 4007Hb 5,104′ 22 Wolfcamp B ESP 1,389 916 88%
Gridiron S001WBc 9,320′ 40 Wolfcamp B Naturally Flowing 1,513 boe/d (89% oil) peak rate to date
Gridiron S002LSc 9,064′ 39 Lower Spraberry ESP 1,395 boe/d (88% oil) peak rate to date
Dawson County
Lateral Length Number of
Stages
Zone Lift Method Peak 24 HR
IP (boe/d)
Peak 30 day
IP (boe/d)
% Oil(a)
Brown & Martin Unit 2101H 7,759′ 34 Cline ESP 136 N/A 100%
Estes B Unit 1602LS ~8,000′ Currently Drilling in Lower Spraberry
Andrews County
Lateral Length Number of
Stages
Zone Lift Method Peak 24 HR
IP (boe/d)
Peak 30 day
IP (boe/d)
% Oil(a)
UL Tawny 812 Unit 1LS 7,585′ 33 Lower Spraberry Flowing Back
(a) During the period for which the 30 day IP rate is presented, except in the case of the Brown & Martin Unit 2101H well, which is based on the Peak 24 hour IP rate; the Brown & Martin Unit 2101H’s gas was flared
(b) Diamondback’s first increased frac density test
(c) Diamondback’s first operated stacked lateral

“The industry has recently observed a decline in oil prices, combined with increasing service costs. This is not unique and happens during every cycle I have experienced. Service providers that have been busy raise prices, and are understandably slow to respond as prices for the underlying commodity decline. While we have not finalized our drilling plans for 2015, we believe that accelerating inventory development in the current environment is not consistent with our capital discipline. We intend to enter 2015 running five horizontal rigs, but if service costs aren’t reduced or commodity prices don’t improve, we expect to respond by drilling fewer wells next year than initially anticipated. However, we intend to continue to run two horizontal rigs on our Spanish Trail acreage, consistent with guidance from Viper Energy Partners LP. By drilling fewer wells, we expect to be cash flow positive during the second half of 2015 with continued production growth, albeit at a more measured pace,” stated Travis Stice, Chief Executive Officer of Diamondback. “Diamondback continues to be the most cost efficient producer in the basin among its peers, generating higher net cash flow per barrel produced than any of these other operators. We believe that this efficiency, combined with our strong balance sheet, will provide superior returns for our stockholders in the future as it has in the past.”

Mr. Stice added, “Operationally, we continue to deliver exceptional results with our sixth consecutive quarter of double digit production growth and are on track to deliver our second year of almost 150% growth year over year. Our ST NW 2507LS Lower Spraberry well in Midland County appears to be among the best wells in company history. We’ve seen promising early results in our first operated stacked Lower Spraberry and Wolfcamp B wells in Midland County. Our Cline test in Dawson County was our first uneconomic well in over 100 horizontal wells drilled, but with our successful Lower Spraberry test in northern Martin County, we remain optimistic about Lower Spraberry potential across our acreage base, including Dawson County. Most of our Lower Spraberry wells are significantly outperforming the 650 Mboe type curve.”

FULL YEAR 2014 GUIDANCE

Below is our full year 2014 guidance, which was previously updated in our July 21, 2014 news release providing an interim operational update.

2014 Guidance
Diamondback
excluding Viper
Viper Energy
Partners
Diamondback
Energy Inc
Total Net Production — MBoe/d 14.5 — 16.0 2.5 — 3.0 17.0 — 19.0
Unit costs ($/boe)
Lease operating expenses $7.00 — $8.00 $0.00 $6.00 — $7.00
G&A $2.50 — $3.50 $0.00 $2.00 — $3.00
DD&A $22.00 — $24.00 $26.00 — $28.00 $23.00 — $25.00
Production and Ad Valorem Taxes (% of Revenue) (a) 7.0% 7.5% 7.1%
$ – million
Gross Horizontal Well Costs (b) $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 n/a $2.0 — $2.2
Gross Vertical Wells Drilled (net) 20-25 (16 — 20) n/a 20-25 (16 — 20)
Capital Expenditures $425 — $475 n/a $425 — $475
Interest Expense (net of interest income) n/a n/a $36.0 — $38.0
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 Energy, Inc. and Viper Energy Partners LP will host a joint conference call and webcast for investors and analysts to discuss their respective results for the quarter ended September 30, 2014, on Wednesday, November 5, 2014 at 10:00 a.m. CT. Participants should call (877) 440-7573 (United States/Canada) or (253) 237-1144 (International) and utilize the confirmation code 25426681. 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 25426681. The recording will be available from 1:00 p.m. CT on Wednesday, November 5, 2014 through Monday, November 10, 2014 at 10:59 p.m. CT. A live broadcast of the earnings conference call will also be available via the internet atwww.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 including those relating to Viper 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 per share data)
Three Months Ended September 30, Nine Months Ended September 30,
2014 2013 2014 2013
Revenues:
Oil and natural gas revenues $ 139,127 $ 57,791 $ 364,135 $ 132,094
Operating Expenses:
Lease operating expense 13,805 4,964 32,216 15,367
Production and ad valorem taxes 8,954 3,553 23,350 8,295
Gathering and transportation expense 860 261 2,145 641
Depreciation, depletion and amortization 45,370 17,423 116,364 42,976
General and administrative 6,495 2,121 14,986 7,213
Asset retirement obligation accretion expense 127 46 303 134
Total expenses 75,611 28,368 189,364 74,626
Income from operations 63,516 29,423 174,771 57,468
Other income 48 270 108 1,047
Interest expense (9,846) (1,088) (24,090) (2,108)
Other expense (8) (1,416)
Non-cash gain (loss) on derivative instruments 16,440 (1,695) 5,630 3,733
Loss on derivative instruments, net (1,531) (3,215) (6,207) (5,614)
Total other income (expense) 5,103 (5,728) (25,975) (2,942)
Income before income taxes 68,619 23,695 148,796 54,526
Income tax provision 23,978 9,099 52,742 20,063
Net income 44,641 14,596 96,054 34,463
Less: Net income attributable to noncontrolling interest 902 973
Net income attributable to Diamondback Energy, Inc. $ 43,739 $ 14,596 $ 95,081 $ 34,463
Basic earnings per common share(1) $ 0.79 $ 0.33 $ 1.85 $ 0.85
Diluted earnings per common share(1) $ 0.79 $ 0.33 $ 1.83 $ 0.85
Weighted average number of basic shares outstanding 55,152 44,385 51,489 40,309
Weighted average number of diluted shares outstanding 55,442 44,698 51,888 40,524
(1)The Company’s earnings per common share amounts are calculated in accordance with ASC 260, with an adjustment included for the awards issued by a consolidated subsidiary.
Diamondback Energy, Inc.
Selected Operating Data
(unaudited, in thousands, except per BOE data)
Three Months Ended September 30, Nine Months Ended September 30,
2014 2013 2014 2013
Production Data:
Oil (MBbl) 1,426 515 3,597 1,263
Natural gas (MMcf) 1,201 446 2,899 1,206
Natural gas liquids (MBbls) 272 93 661 249
Oil Equivalents (1)(2) (MBOE) 1,898 683 4,741 1,713
Average daily production(2) (BOE/d) 20,636 7,419 17,367 6,275
% Oil 75% 75% 76% 74%
Average sales prices:
Oil, realized ($/Bbl) $ 88.63 $ 103.11 $ 92.15 $ 94.51
Natural gas realized ($/Mcf) 3.92 3.50 4.27 3.63
Natural gas liquids ($/Bbl) 29.44 33.67 30.72 33.49
Average price realized ($/BOE) 73.28 84.67 76.80 77.11
Oil, hedged(3) ($/Bbl) 87.55 96.86 90.42 90.06
Average price, hedged(3) ($/BOE) 72.48 79.96 75.49 73.83
Average costs per BOE:
Lease operating expenses $ 7.27 $ 7.27 $ 6.79 $ 8.97
Production and ad valorem taxes 4.72 5.21 4.92 4.84
Gathering and transportation expense 0.45 0.38 0.45 0.37
Interest expense 5.19 1.59 5.08 1.23
General and administrative 3.42 3.11 3.16 4.21
Depreciation, depletion, and amortization 23.90 25.53 24.54 25.09
Total $ 44.95 $ 43.09 $ 44.94 $ 44.71
Components of general and administrative expense:
General and administrative – cash component $ 2.33 $ 2.39 $ 2.03 $ 3.38
General and administrative – Diamondback non-cash stock-based compensation 0.62 0.72 0.92 0.83
General and administrative – Viper non-cash unit-based compensation 0.47 0.21
(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 (gain) loss on derivative instruments, net, (gain) loss on sale of assets, 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, 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 deferred 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 Adjusted EBITDA to Net Income
(unaudited, in thousands)
Three Months Ended September 30, Nine Months Ended September 30,
2014 2013 2014 2013
Net income $ 44,641 $ 14,596 $ 96,054 $ 34,463
Non-cash (gain) loss on derivative instruments, net (16,440) 1,695 (5,630) (3,733)
Loss on derivative instruments, net 1,531 3,215 6,207 5,614
Interest expense 9,846 1,089 24,090 2,109
Depreciation, depletion and amortization 45,370 17,423 116,364 42,976
Non-cash stock-based compensation expense 4,112 749 10,145 2,105
Capitalized stock-based compensation expense (2,043) (259) (4,758) (679)
Asset retirement obligation accretion expense 127 46 303 134
Income tax provision 23,978 9,099 52,742 20,063
Adjusted EBITDA $ 111,122 $ 47,653 $ 295,517 $ 103,052
Diamondback Energy, Inc.
Adjusted Net Income
(unaudited, in thousands, except per share data)
Adjusted net income is a performance measure used by management to evaluate performance, prior to (gain) loss on derivatives, net and (gain) loss on sale of assets, net.
The following table presents a reconciliation of adjusted net income to net income:
Three Months Ended September 30, Nine Months Ended September 30,
2014 2013 2014 2013
Net income attributable to Diamondback Energy, Inc. $ 43,739 $ 14,596 $ 95,081 $ 34,463
Plus:
Non-cash (gain) loss on derivative instruments, net (16,440) 1,695 (5,630) (3,733)
Loss on derivative instruments, net 1,531 3,215 6,207 5,614
(Gain) loss on sale of assets, net 8 (1) 1,405 (31)
Income tax adjustment for above items 5,207 (1,885) (703) (681)
Adjusted net income $ 34,045 $ 17,620 $ 96,360 $ 35,632
Adjusted net income per common share:
Basic $ 0.62 $ 0.40 $ 1.87 $ 0.88
Diluted $ 0.61 $ 0.39 $ 1.86 $ 0.88
Weighted average common shares outstanding:
Basic 55,152 44,385 51,489 40,309
Diluted 55,442 44,698 51,888 40,524
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 operating assets and liabilities. 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 September 30, Nine Months Ended September 30,
2014 2013 2014 2013
Net income $ 44,641 $ 14,596 $ 96,054 $ 34,463
Depreciation, depletion and amortization 45,370 17,423 116,364 42,976
Deferred income tax provision 19,996 9,099 48,760 20,063
Excess tax benefit 749 749
Accretion expense 127 46 303 134
Non-cash stock based compensation, net 2,069 490 5,387 1,426
Non-cash (gain) loss on derivative instruments, net (16,440) 1,695 (5,630) (3,733)
Non-cash interest expense 559 208 1,505 526
Other non-cash operating items 8 (1) 1,405 (31)
Discretionary cash flow 97,079 43,556 264,897 95,824
Changes in working capital accounts (4,790) (1,707) (12,902) (4,177)
Net cash provided by operating activities $ 92,289 $ 41,849 $ 251,995 $ 91,647
Discretionary cash flow per share:
Basic $ 1.76 $ 0.98 $ 5.14 $ 2.38
Diluted $ 1.75 $ 0.97 $ 5.11 $ 2.36
Weighted average common shares outstanding:
Basic 55,152 44,385 51,489 40,309
Diluted 55,442 44,698 51,888 40,524
Diamondback Energy, Inc.
Derivatives Information
(unaudited)
The table below provides data regarding the details of Diamondback’s current price swap contracts through 2015.
Oil Swaps Average Bbls
Per Day
Average
Price per Bbl
2014
Fourth Quarter-LLS 8,989 $ 95.16
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