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FANG > SEC Filings for FANG > Form 10-Q on 8-Aug-2013All Recent SEC Filings

Show all filings for DIAMONDBACK ENERGY, INC.

Form 10-Q for DIAMONDBACK ENERGY, INC.


8-Aug-2013

Quarterly Report


ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our unaudited combined consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10-Q as well as our audited combined consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2012. The following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See "Part II, Item 1A. Risk Factors" and "Cautionary Statement Regarding Forward-Looking Statements".

Overview

We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, long-life, onshore oil and natural gas reserves in the Permian Basin in West Texas. Our activities are primarily directed at the Clearfork, Spraberry, Wolfcamp, Cline, Strawn and Atoka formations which we refer to as the Wolfberry play. We intend to grow our reserves and production through development drilling, exploitation and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves. Substantially all of our revenues are generated through the sale of oil, natural gas liquids and natural gas production. Our production was approximately 75% oil, 14% natural gas liquids and 11% natural gas for the three months ended June 30, 2013, and was approximately 73% oil, 16% natural gas liquids and 11% natural gas for the three months ended June 30, 2012. Our production was approximately 73% oil, 15% natural gas liquids and 12% natural gas for the six months ended June 30, 2013, and was approximately 74% oil, 15% natural gas liquids and 11% natural gas for the six months ended June 30, 2012. On June 30, 2013, our net acreage position in the Permian Basin was approximately 54,035 net acres.

Diamondback was incorporated in Delaware on December 30, 2011, and did not conduct any material business operations until October 11, 2012 when Diamondback merged with its parent entity, Diamondback Energy LLC, with Diamondback continuing as the surviving entity. Diamondback Energy LLC was a holding company and did not conduct any material business operations other than its ownership of our common stock and the membership interests in Windsor Permian LLC, or Windsor Permian. As a result of the merger, Windsor Permian became a wholly-owned subsidiary of Diamondback and subsequently changed its name to Diamondback O&G
LLC. Also on October 11, 2012, Wexford Capital LP, or Wexford, our equity sponsor, caused all of the outstanding equity interests in Windsor UT LLC, or Windsor UT, to be contributed to Windsor Permian prior to the merger in a transaction we refer to as the "Windsor UT Contribution." The Windsor UT Contribution was treated as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests. We refer to the historical results of Windsor Permian and Windsor UT prior to October 11, 2012 as our "Predecessors."

Also on October 11, 2012, we acquired all of the oil and natural gas properties of Gulfport located in the Permian Basin in exchange for (i) 7,914,036 shares of our common stock, (ii) approximately $63.6 million in the form of a non-interest bearing promissory note that was repaid in full upon the closing of our initial public offering, or IPO, and (iii) a post-closing cash adjustment of approximately $18.6 million. We are the operator of the acreage acquired by us from Gulfport.

On October 17, 2012, we completed our IPO of 14,375,000 shares of common stock, which included 1,875,000 shares of common stock issued pursuant to the over-allotment option exercised by the underwriters. The stock was priced at $17.50 per share and we received net proceeds of approximately $234.1 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.
In the first quarter of 2013, Windsor UT merged with and into Windsor Permian and Windsor Permian, the surviving entity in the merger, was renamed Diamondback O&G LLC, or Diamondback O&G.
On May 22, 2013, we completed an underwritten primary public offering of 5,175,000 shares of common stock, which included 675,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the public at $29.25 per share and we received net proceeds of approximately $144.4 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.


Table of Contents

On June 24, 2013, Gulfport Energy Corporation, which we refer to as "Gulfport," and certain entities controlled by Wexford Capital LP, which we refer to as "Wexford," completed an underwritten secondary public offering of 6,000,000 shares of our common stock and, on July 5, 2013, the underwriters purchased an additional 869,222 shares of our common stock from these selling stockholders pursuant to an option to purchase such additional shares granted to the underwriters. The shares were sold to the public at $34.75 per share and the selling stockholders received all proceeds from this offering. Recent Developments

We have 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 $165.0 million, subject to certain adjustments. We entered into one agreement on August 1, 2013 and one agreement on August 2, 2013. The proposed transactions are expected to close by the end of September 2013.

Basis of Presentation

Transfers of a business between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information. As discussed above, the Windsor UT Contribution was accounted for as a transaction between entities under common control. Accordingly, the financial information and production data contained in this report have been retrospectively adjusted to include the historical results of Windsor UT at historical carrying values and its operations prior to October 11, 2012, the effective date of the Windsor UT Contribution.
Since we began operations in 2007, we have increased our drilling activity, evaluated potential acquisitions and added to our acreage portfolio. Because of our growth through acquisitions and development of our properties, our historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful or indicative of future results.
Operating Results Overview
During the three months ended June 30, 2013, our average daily production was approximately 6,590 BOE/d, consisting of 4,914 Bbls/d of oil, 4,489 Mcf/d of natural gas and 927 Bbls/d of natural gas liquids, an increase of 4,080 BOE/d, or 163%, from average daily production of 2,510 BOE/d for the three months ended June 30, 2012, consisting of 1,828 Bbls/d of oil, 1,734 Mcf/d of natural gas and 392 Bbls/d of natural gas liquids. The ST 4301H well in Midland County, with a 29 stage 7,141 foot lateral, achieved a peak 30 day rate of 916 BOE/d on submersible pump, with a previously reported peak 24 hour initial production, or IP, rate of 1,136 BOE/d. Our 14 producing horizontal Wolfcamp B wells have achieved peak 24 hour IP rates that averaged 920 BOE/d (88% oil) from lateral lengths that averaged 5,576 feet.

During the six months ended June 30, 2013, our average daily production was approximately 5,694 BOE/d, consisting of 4,134 Bbls/d of oil, 4,197 Mcf/d of natural gas and 860 Bbls/d of natural gas liquids, an increase of 3,323 BOE/d, or 140%, from average daily production of 2,371 BOE/d for the six months ended June 30, 2012, consisting of 1,747 Bbls/d of oil, 1,594 Mcf/d of natural gas and 358 Bbls/d of natural gas liquids.

During the three months ended June 30, 2013, we drilled 19 gross (16 net) wells, and participated in one additional gross non-operated well, in the Permian Basin. During the six months ended June 30, 2013, we drilled 38 gross (33 net) wells, and participated in one additional gross non-operated well, in the Permian Basin.

Sources of our revenue
Our revenues are derived from the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from our natural gas during processing. Our oil and natural gas revenues do not include the effects of derivatives. For the three months ended June 30, 2013 and 2012, our revenues were derived 90% and 90%, respectively, from oil sales, 6% and 8%, respectively, from natural gas liquids sales and 4% and 2%, respectively, from natural gas sales. For the six months ended June 30, 2013 and 2012, our revenues were derived 89% and 90%, respectively, from oil sales, 7% and 8%, respectively, from natural gas liquids sales and 4% and 2%, respectively, from natural gas sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.


Table of Contents

Results of Operations
The following table sets forth selected historical operating data for the
periods indicated.
                                  Three Months Ended June 30,         Six Months Ended June 30,
                                     2013              2012             2013             2012
                                          (unaudited)                        (unaudited)
Operating Results:
Revenues
Oil and natural gas revenues   $   45,394,000     $ 16,030,000     $ 74,303,000     $ 32,381,000
Operating Expenses
Lease operating expense             6,087,000        3,529,000       11,522,000        6,318,000
Production taxes                    2,196,000          782,000        3,623,000        1,579,000
Gathering and transportation
expense                               247,000           79,000          380,000          146,000
Depreciation, depletion and
amortization                       14,815,000        5,659,000       25,553,000       10,416,000
General and administrative          2,621,000        1,653,000        5,092,000        2,837,000
Asset retirement obligation
accretion expense                      45,000           21,000           88,000           41,000
Total expenses                     26,011,000       11,723,000       46,258,000       21,337,000
Income from operations             19,383,000        4,307,000       28,045,000       11,044,000
Net interest expense                 (535,000 )     (1,172,000 )     (1,020,000 )     (2,052,000 )
Other income - related party          388,000          586,000          777,000        1,011,000
Gain on derivative
instruments, net                    3,037,000        9,957,000        3,029,000        5,165,000
Loss from equity investment                 -          (54,000 )              -          (67,000 )
Total other income                  2,890,000        9,317,000        2,786,000        4,057,000
Income before income taxes         22,273,000       13,624,000       30,831,000       15,101,000
Provision for deferred
income taxes                        7,802,000                -       10,964,000                -
Net income                     $   14,471,000     $ 13,624,000     $ 19,867,000     $ 15,101,000

Production Data:
Oil (Bbls)                            447,203          166,385          748,244          317,906
Natural gas (Mcf)                     408,530          157,835          759,568          290,171
Natural gas liquids (Bbls)             84,360           35,678          155,689           65,188
Combined volumes (Boe)                599,651          228,369        1,030,528          431,456
Daily combined volumes
(Boe/d)                                 6,590            2,510            5,694            2,371

Average Prices(1):
Oil (per Bbl)                  $        91.76     $      86.34     $      88.59     $      91.26
Natural gas (per Mcf)                    4.08             1.97             3.71             2.27
Natural gas liquids (per
Bbl)                                    31.91            37.92            33.38            41.59
Combined (per BOE)                      75.70            70.19            72.10            75.05

Average Costs (per BOE)
Lease operating expense        $        10.15     $      15.45     $      11.18     $      14.64
Gathering and transportation
expense                                  0.41             0.35             0.37             0.34
Production taxes                         3.66             3.42             3.52             3.66
Production taxes as a % of
sales                                     4.8 %            4.9 %            4.9 %            4.9 %
Depreciation, depletion, and
amortization                            24.71            24.78            24.80            24.14
General and administrative               4.37             7.24             4.94             6.58

(1) After giving effect to our derivative instruments, the average prices per Bbl of oil and per BOE were $89.84 and $74.27, respectively, during the three months ended June 30, 2013, and $73.67 and $60.96, respectively, during the three months ended June 30, 2012. After giving effect to our derivative instruments, the average prices per Bbl of oil and per BOE were $85.38 and $69.77, respectively, during the six months ended June 30, 2013, and $80.34 and $67.00, respectively, during the six months ended June 30, 2012.


Table of Contents

Comparison of the Three Months Ended June 30, 2013 and 2012 Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $29,364,000, or 183%, to $45,394,000 for the three months ended June 30, 2013 from $16,030,000 for the three months ended June 30, 2012. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 4,080 BOE/d to 6,590 BOE/d during the three months ended June 30, 2013 from 2,510 BOE/d during the three months ended June 30, 2012. The total increase in revenue of approximately $29,364,000 is largely attributable to higher oil, natural gas liquids and natural gas production volumes for the three months ended June 30, 2013 as compared to the three months ended June 30, 2012. The increases in production volumes were due to a combination of increased drilling activity and the effect of the contribution of Gulfport's Permian Basin assets on October 11, 2012. Our production increased by 280,818 Bbls of oil, 48,682 Bbls of natural gas liquids and 250,695 Mcf of natural gas for the three months ended June 30, 2013 as compared to the three months ended June 30, 2012. The net dollar effect of the increases in prices of approximately $2,778,000 (calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the increase in production of approximately $26,586,000 (calculated as the increase in period-to-period volumes for oil, natural gas liquids and natural gas multiplied by the period average prices) are shown below.

                                                                     Production          Total net dollar
                                          Change in prices           volumes(1)          effect of change
     Effect of changes in price:
     Oil                                $              5.42                447,203     $      2,423,000
     Natural gas liquids                $             (6.01 )               84,360     $       (507,000 )
     Natural gas                        $              2.11                408,530     $        862,000
     Total revenues due to change in
     price                                                                             $      2,778,000
                                        Change in production    Prior period Average     Total net dollar
                                             volumes(1)                Prices            effect of change
     Effect of changes in production
     volumes:
     Oil                                            280,818     $            86.34     $     24,246,000
     Natural gas liquids                             48,682     $            37.92     $      1,846,000
     Natural gas                                    250,695     $             1.97     $        494,000
     Total revenues due to change in
     production volumes                                                                $     26,586,000
     Total change in revenues                                                          $     29,364,000

(1 ) Production volumes are presented in Bbls for oil and natural gas liquids and Mcf for natural gas

Lease Operating Expense. Lease operating expense was $6,087,000 ($10.15 per BOE) for the three months ended June 30, 2013, an increase of $2,558,000, or 72%, from $3,529,000 ($15.45 per BOE) for the three months ended June 30, 2012. The increase is due to increased drilling activity, which resulted in additional producing wells for the three months ended June 30, 2013 as compared to the three months ended June 30, 2012. Our lease operating expense during the three months ended June 30, 2012 was adversely impacted by the cost of processing and treating non-hydrocarbon gases from certain of our wells that came on-line in 2011. During the fourth quarter of 2012, we completed construction of a gas gathering system that transports this gas stream to a sour gas pipeline, thereby eliminating the monthly processing and treating expense, which savings are reflected in our lease operating expense for the three months ended June 30, 2013. In addition, in the first quarter 2013, we moved a portion of our produced water by a pipeline connected to a commercial salt water disposal well rather than by truck. During the remainder of 2013, we intend to continue the migration of water disposal and oil transportation from truck carriers to pipelines. We believe that the connection to salt water disposal wells and other actions will help reduce our lease operating expense in future periods.


Table of Contents

Production Tax Expense. Production taxes as a percentage of oil and natural gas sales were 4.8% for the three months ended June 30, 2013, a decrease of 0.1% from 4.9% for the three months ended June 30, 2012. Production taxes are primarily based on the market value of our production at the wellhead and may vary across the different counties in which we operate. Total production taxes increased $1,414,000 from $782,000 during the three months ended June 30, 2012 to $2,196,000 during the three months ended June 30, 2013, as a result of higher production and an increase in the market value of our production. Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $9,156,000, or 162%, from $5,659,000 for the three months ended June 30, 2012 to $14,815,000 for the three months ended June 30, 2013. This increase was due to an increase in our full cost pool as a result of the acquisition of the Gulfport properties and increased capital expenditures in conjunction with our drilling program during the three months ended June 30, 2013. The average depletion rate was $24.71 for the three months ended June 30, 2013 and $24.78 for the three months ended June 30, 2012. The average depletion rate includes oil and gas depletion and other property and equipment depreciation.
General and Administrative Expense. General and administrative expense increased $968,000 from $1,653,000 for the three months ended June 30, 2012 to $2,621,000 for the three months ended June 30, 2013. The increase was due to increases in salary, stock-based compensation, legal, secondary offering expenses, professional service and advisory service expenses. These increases were partially offset by increases in general and administrative costs related to exploration and development activity capitalized to the full cost pool and increases in COPAS overhead reimbursements due to increased drilling activity. Net Interest Expense. Net interest expense for the three months ended June 30, 2013 was $535,000, as compared to $1,172,000 for the three months ended June 30, 2012, a decrease of $637,000, or 54%. This decrease was due primarily to a decrease in our weighted average outstanding borrowings under our credit agreement to $23,071,000 for the three months ended June 30, 2013 from $99,724,000 for the same period in 2012.
Derivatives. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the realized and unrealized changes in fair value on derivative instruments in our combined consolidated statements of operations under the line item captioned "Gain on derivative instruments." For the three months ended June 30, 2013 and 2012, we had a realized loss on settlement of derivative instruments of $856,000 and $2,108,000, respectively. For the three months ended June 30, 2013 and 2012, we had an unrealized gain on open derivative instruments of $3,893,000 and $12,065,000, respectively.
Income tax expense. Prior to our IPO in October 2012, the operations of Windsor Permian and Windsor UT, as limited liability companies, were not subject to federal income taxes. Deferred income tax expense of $7,802,000 was incurred as a result of operations for the three months ended June 30, 2013. Comparison of the Six Months Ended June 30, 2013 and 2012 Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $41,922,000, or 129%, to $74,303,000 for the six months ended June 30, 2013 from $32,381,000 for the six months ended June 30, 2012. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 3,323 BOE/d to 5,694 BOE/d during the six months ended June 30, 2013 from 2,371 BOE/d during the six months ended June 30, 2012. The total increase in revenue of approximately $41,922,000 is largely attributable to higher oil, natural gas liquids and natural gas production volumes for the six months ended June 30, 2013 as compared to the six months ended June 30, 2012, partially offset by a decrease in the average sales price received for these volumes. The increases in production volumes were due to a combination of increased drilling activity and the effect of the contribution of Gulfport's Permian Basin assets on October 11, 2012. Our production increased by 430,338 Bbls of oil, 90,501 Bbls of natural gas liquids and 469,397 Mcf of natural gas for the six months ended June 30, 2013 as compared to the six months ended June 30, 2012. The net dollar effect of the decreases in prices of approximately $2,180,000 (calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the increase in production of approximately $44,102,000 (calculated as the increase in period-to-period volumes for oil, natural gas liquids and natural gas multiplied by the period average prices) are shown below.


Table of Contents

                                                                     Production          Total net dollar
                                          Change in prices           volumes(1)          effect of change
     Effect of changes in price:
     Oil                                $             (2.67 )              748,244     $     (1,998,000 )
     Natural gas liquids                $             (8.21 )              155,689     $     (1,278,000 )
     Natural gas                        $              1.44                759,568     $      1,096,000
     Total revenues due to change in
     price                                                                             $     (2,180,000 )
                                        Change in production    Prior period Average     Total net dollar
                                             volumes(1)                Prices            effect of change
     Effect of changes in production
     volumes:
     Oil                                            430,338     $            91.26     $     39,273,000
     Natural gas liquids                             90,501     $            41.59     $      3,764,000
     Natural gas                                    469,397     $             2.27     $      1,065,000
     Total revenues due to change in
     production volumes                                                                $     44,102,000
     Total change in revenues                                                          $     41,922,000

(1 ) Production volumes are presented in Bbls for oil and natural gas liquids and Mcf for natural gas

Lease Operating Expense. Lease operating expense was $11,522,000 ($11.18 per BOE) for the six months ended June 30, 2013, an increase of $5,204,000, or 82%, from $6,318,000 ($14.64 per BOE) for the six months ended June 30, 2012. The increase is due to increased drilling activity, which resulted in additional producing wells for the six months ended June 30, 2013 as compared to the six months ended June 30, 2012. Our lease operating expense during the six months ended June 30, 2012 was adversely impacted by the cost of processing and treating non-hydrocarbon gases from certain of our wells that came on-line in 2011. During the fourth quarter of 2012, we completed construction of a gas gathering system that transports this gas stream to a sour gas pipeline, thereby eliminating the monthly processing and treating expense, which savings are reflected in our lease operating expense for the six months ended June 30, 2013. In addition, in the first quarter 2013, we moved a portion of our produced water by a pipeline connected to a commercial salt water disposal well rather than by truck. During the remainder of 2013, we intend to continue the migration of water disposal and oil transportation from truck carriers to pipelines. We believe that the connection to salt water disposal wells and other actions will help reduce our lease operating expense in future periods.
Production Tax Expense. Production taxes as a percentage of oil and natural gas sales were 4.9% for both the six months ended June 30, 2013 and 2012. Production taxes are primarily based on the market value of our production at the wellhead and may vary across the different counties in which we operate. Total production taxes increased $2,044,000 from $1,579,000 during the six months ended June 30, 2012 to $3,623,000 during the six months ended June 30, 2013, as a result of higher production and an increase in the market value of our production. Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $15,137,000, or 145%, from $10,416,000 for the six months ended June 30, 2012 to $25,553,000 for the six months ended June 30, . . .

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