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ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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¨
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TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
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Delaware
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45-4502447
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(State or Other Jurisdiction of
Incorporation or Organization)
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(IRS Employer
Identification Number)
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500 West Texas, Suite 1225
Midland, Texas
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79701
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(Address of Principal Executive Offices)
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(Zip Code)
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Securities registered pursuant to Section 12(b) of the Act:
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Stock, par value $0.01 per share
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The NASDAQ Stock Market LLC
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Securities registered pursuant to Section 12(g) of the Act: None
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Large Accelerated Filer
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¨
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Accelerated Filer
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Non-Accelerated Filer
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x
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Smaller Reporting Company
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¨
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DIAMONDBACK ENERGY, INC.
TABLE OF CONTENTS
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Page
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ITEMS 1 and 2.
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ITEM 1A.
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ITEM 1B.
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ITEM 3.
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ITEM 4.
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ITEM 5.
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ITEM 6.
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ITEM 7.
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ITEM 7A.
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ITEM 8.
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ITEM 9.
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ITEM 9A.
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ITEM 9B.
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ITEM 10.
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ITEM 11.
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ITEM 12.
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ITEM 13.
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ITEM 14
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ITEM 15.
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•
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business strategy;
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exploration and development drilling prospects, inventories, projects and programs;
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oil and natural gas reserves;
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identified drilling locations;
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ability to obtain permits and governmental approvals;
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technology;
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financial strategy;
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realized oil and natural gas prices;
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production;
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lease operating expenses, general and administrative costs and finding and development costs;
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future operating results; and
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plans, objectives, expectations and intentions.
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Grow production and reserves by developing our oil-rich resource base.
We intend to actively drill and develop our acreage base in an effort to maximize its value and resource potential. Through the conversion of our undeveloped reserves to developed reserves, we will seek to increase our production, reserves and cash flow while generating favorable returns on invested capital. As of December 31, 2012, we had 881 identified potential vertical drilling locations on our acreage in the Permian Basin based on 40-acre spacing and an additional 1,118 such locations based on 20-acre downspacing. We were using two vertical drilling rigs as of February 28, 2013.
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Focus on increasing hydrocarbon recovery through horizontal drilling and increased well density.
We believe there are opportunities to target various intervals in the Wolfberry play with horizontal wells. Our initial horizontal focus has been on the Wolfcamp B interval in Midland and Upton Counties. Our first two horizontal wells were completed in 2012 and had lateral lengths of less than 4,000 feet. Our next two horizontal wells were drilled in Upton County with lateral lengths of 7,652 and 6,685 feet, respectively. In the future, we expect that our optimal average lateral lengths will be in the range of 7,500 to 8,000 feet, although the actual length will vary depending on the layout of our acreage and other factors. We expect that longer lateral lengths will result in higher per well recoveries and lower development costs per BOE. Our future horizontal drilling program is designed to further capture the upside potential that may exist on our properties. We also believe our horizontal drilling program may significantly increase our recoveries per section as compared to drilling vertical wells alone. Horizontal drilling may also be economical in areas where vertical drilling is currently not economical or logistically viable. In addition, we believe increased well density opportunities may exist across our acreage base. We closely monitor industry trends with respect to higher well density, which could increase the recovery factor per section and enhance returns since infrastructure is typically in place. We were using two horizontal drilling rigs as of February 28, 2013.
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Leverage our experience operating in the Permian Basin.
Our executive team, which has an average of approximately 24 years of industry experience per person and significant experience in the Permian Basin, intends to continue to seek ways to maximize hydrocarbon recovery by refining and enhancing our drilling and completion techniques. The time to reach total depth, or TD, for our vertical Wolfberry wells decreased from an average of 20 days during the second quarter of 2011 to an average of 14 days during the period from April 2012 through August 2012 to an average of 11 days during the fourth quarter of 2012. Our focus on efficient drilling and completion techniques, and the reduction in time to reach TD, is an important part of the continuous drilling program we have planned for our significant inventory of identified potential drilling locations. In addition, we believe that the experience of our executive team in deviated and horizontal drilling and completions should help reduce the execution risk normally associated with these complex well paths. Additionally, our completion techniques are continually evolving as we evaluate hydraulic fracturing practices that may potentially increase recovery and reduce completion costs. Our executive team regularly evaluates our operating results against those of other operators in the area in an effort to benchmark our performance against the best performing operators and evaluate and adopt best practices.
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Enhance returns through our low cost development strategy of resource conversion, capital allocation and continued improvements in operational and cost efficiencies.
In the current commodity price environment, our oil and liquids rich asset base provides attractive returns. Our acreage position in the Wolfberry play is generally in contiguous blocks which allows us to develop this acreage efficiently with a “manufacturing” strategy that takes advantage of economies of scale and uses centralized production and fluid handling facilities. We are the operator of approximately 99% of our acreage. This operational control allows us to more efficiently manage the pace of development activities and the gathering and marketing of our production and control operating costs and technical applications, including horizontal development. Our average 87% working interest in our acreage allows us to realize the majority of the benefits of these expected improvements and cost efficiencies.
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Pursue strategic acquisitions with exceptional resource potential.
We have a proven history of acquiring leasehold positions in the Permian Basin that have substantial oil-weighted resource potential and can achieve attractive returns on invested capital. Our executive team, with its extensive experience in the Permian Basin, has what we believe is a competitive advantage in identifying acquisition targets and a proven ability to evaluate resource potential. We intend to continue to pursue acquisitions that meet our strategic and financial targets.
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Maintain financial flexibility
. We seek to maintain a conservative financial position. Upon completion of our initial public offering in October 2012, we used a portion of the net proceeds from the offering to repay the entire balance outstanding under our revolving credit facility. On December 28, 2012, the borrowing base under our revolving credit facility was redetermined, resulting in an increase in our availability to $135.0 million, of which the entire balance was fully available as of December 31, 2012.
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Oil rich resource base in one of North America’s leading resource plays
. All of our leasehold acreage is located in one of the most prolific oil plays in North America, the Permian Basin in West Texas. The majority of our current properties are well positioned in the core of the Wolfberry play. We believe that our historical vertical development success will be complemented with horizontal drilling locations that could ultimately translate into an increased recovery factor on a per section basis. Our production was approximately 70% oil, 17% natural gas liquids and 13% natural gas for the year ended December 31, 2012. As of December 31, 2012, our estimated net proved reserves were comprised of approximately 65% oil and 21% natural gas liquids. This oil and liquids exposure allows us to benefit from their currently more favorable prices as compared to natural gas.
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Multi-year drilling inventory in one of North America’s leading oil resource plays
. We have identified a multi-year inventory of potential drilling locations for our oil-weighted reserves that we believe provides attractive growth and return opportunities. As of December 31, 2012, we had 881 identified potential vertical drilling locations based on 40-acre spacing and an additional 1,118 identified potential vertical drilling locations based on 20-acre downspacing. We also believe that there are a significant number of horizontal locations that could be drilled on our acreage. Based on our initial results and those of other operators in the area to date, combined with our interpretation of various geologic and engineering data, we have identified 731 potential horizontal locations on our acreage. These locations exist across most of our acreage blocks and in multiple horizons. Of the 731 locations, 355 are in the Wolfcamp A horizon or the Wolfcamp B horizon, with the remaining locations in either the Clearfork, Wolfcamp C or Cline horizons. We have not assigned any horizontal locations to the Spraberry interval but believe that it may also have development potential. Our current horizontal location count is based on 1,320 foot spacing between wells. The ultimate inter-well spacing may be closer than 1,320 feet, which would result in a higher location count. In addition, we have approximately 182 square miles of proprietary 3-D seismic data covering our acreage. This data facilitates the evaluation of our existing drilling inventory and provides insight into future development activity, including horizontal drilling opportunities and strategic leasehold acquisitions.
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Experienced, incentivized and proven management team
. Our executive team has an average of approximately 24 years of industry experience per person, most of which is focused on resource play development. This team has a proven track record of executing on multi-rig development drilling programs and extensive experience in the Permian Basin. In addition, our executive team has significant experience with both drilling and completing horizontal wells as well as horizontal well reservoir and geologic expertise, which will be of strategic importance as we expand our horizontal drilling activity. Prior to joining us, our Chief Executive Officer held management positions at Apache Corporation, Laredo Petroleum Holdings, Inc. and Burlington Resources.
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Favorable and stable operating environment
. We have focused our drilling and development operations in the Permian Basin, one of the oldest hydrocarbon basins in the United States, with a long and well-established production history and developed infrastructure. With approximately 380,000 wells drilled in the Permian Basin since the 1940s, we believe that the geological and regulatory environment is more stable and predictable, and that we are faced with less operational risks, in the Permian Basin as compared to emerging hydrocarbon basins.
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High degree of operational control
. We are the operator of approximately 99% of our Permian Basin acreage. This operating control allows us to better execute on our strategies of enhancing returns through operational and cost efficiencies and increasing ultimate hydrocarbon recovery by seeking to continually improve our drilling techniques, completion methodologies and reservoir evaluation processes. Additionally, as the operator of substantially all of our acreage, we retain the ability to adjust our capital expenditure program based on commodity price outlooks. This operating control also enables us to obtain data needed for efficient exploration of horizontal prospects.
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Financial flexibility to fund expansion
. We have a conservative balance sheet. We will seek to maintain financial flexibility to allow us to actively develop our drilling, exploitation and exploration activities in the Wolfberry play and maximize the present value of our oil-weighted resource potential. As of December 31, 2012, we had no outstanding borrowings under our revolving credit facility and $135.0 million of available borrowing capacity. We expect that our borrowing base will be increased as we increase our reserves.
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Disclosure of unproved reserves: probable and possible reserves may be disclosed separately on a voluntary basis.
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Proved undeveloped reserve guidelines: reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.
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Reserves estimation using new technologies: reserves may be estimated through the use of reliable technology in addition to flow tests and production history.
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Reserves personnel and estimation process: additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.
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Non-traditional resources: the definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method of extraction.
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review and verification of historical production data, which data is based on actual production as reported by us;
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preparation of reserve estimates by our Vice President—Reservoir Engineering or under his direct supervision;
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review by our Vice President—Reservoir Engineering of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;
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direct reporting responsibilities by our Vice President—Reservoir Engineering to our Chief Executive Officer;
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verification of property ownership by our land department; and
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no employee’s compensation is tied to the amount of reserves booked.
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Historical
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Year Ended December 31,
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2012
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2011
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2010
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Estimated proved developed reserves:
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Oil (Bbls)
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7,189,367
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3,949,099
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3,371,460
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Natural gas (Mcf)
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12,864,941
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5,285,945
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4,336,720
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Natural gas liquids (Bbls)
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2,999,440
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1,263,710
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1,126,431
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Total (BOE)
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12,332,964
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6,093,800
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5,220,678
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Estimated proved undeveloped reserves:
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Oil (Bbls)
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19,007,492
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14,151,337
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16,258,700
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Natural gas (Mcf)
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21,705,207
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15,265,522
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18,358,360
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Natural gas liquids (Bbls)
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5,251,989
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3,785,849
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4,706,536
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Total (BOE)
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27,877,016
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20,481,440
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24,024,963
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Estimated Net Proved Reserves:
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Oil (Bbls)
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26,196,859
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18,100,436
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19,630,160
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Natural gas (Mcf)
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34,570,148
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20,551,467
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22,695,080
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Natural gas liquids (Bbls)
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8,251,429
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5,049,559
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5,832,967
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Total (BOE)
(1)
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40,209,979
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26,575,240
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29,245,641
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Percent proved developed
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30.7
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%
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22.9
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%
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17.9
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(1)
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Estimates of reserves as of December 31, 2012, 2011 and 2010 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods ended December 31, 2012, 2011 and 2010, respectively, in accordance with revised SEC guidelines applicable to reserves estimates as of the end of such periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.
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additions of 3,167 MBOE attributable to extensions resulting from strategic drilling of wells by us to delineate our acreage position;
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the conversion of approximately 3,224 MBOE attributable to PUDs into proved developed reserves;
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negative revisions of approximately 625 MBOE in PUDs due to a combination of lower product prices causing wells to reach economic limit earlier, adjustments in working interest and performance revisions; and
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purchases of reserves in place of 8,077 MBOE.
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Historical
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Year Ended December 31,
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2012
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2011
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2010
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Production Data:
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Oil (Bbls)
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756,286
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449,434
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280,721
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Natural gas (Mcf)
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833,516
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413,640
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323,847
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Natural gas liquids (Bbl)
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183,114
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86,815
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79,978
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Combined volumes (BOE)
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1,078,320
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605,189
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414,674
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Daily combined volumes (BOE/d)
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2,946
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1,658
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1,136
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Average Prices
(1)
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Oil (per Bbl)
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$
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86.88
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$
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92.24
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$
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76.51
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Natural gas (per Mcf)
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2.85
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3.98
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4.32
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Natural gas liquids (per Bbl)
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37.57
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54.98
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44.56
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Combined (per BOE)
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69.52
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79.11
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63.77
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Average Costs (per BOE):
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Lease operating expense
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$
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15.57
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$
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17.51
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$
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11.07
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Gathering and transportation expense
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$
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0.39
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$
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0.33
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$
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0.26
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Production taxes
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$
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3.42
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$
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3.91
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$
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3.25
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Production taxes as a % of sales
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4.9
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%
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4.9
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%
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5.1
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%
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Depreciation, depletion and amortization
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$
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24.36
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$
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25.78
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$
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19.64
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General and administrative
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$
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9.62
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$
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6.04
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$
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7.32
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(1)
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After giving effect to our hedging arrangements, the average prices per Bbl of oil and per BOE were $79.68 and $64.47, respectively, during the year ended December 31, 2012, and $92.15 and $79.05, respectively, during the year ended December 31, 2011. Average prices for our hydrocarbons were not impacted by hedging arrangements during 2010.
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Developed Acreage
(1)
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Undeveloped Acreage
(2)
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Total Acreage
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Basin
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Gross
(3)
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Net
(4)
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Gross
(3)
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Net
(4)
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Gross
(3)
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Net
(4)
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Permian
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9,560
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8,184
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49,645
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43,419
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59,205
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51,507
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(1)
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Developed acres are acres spaced or assigned to productive wells and do not include undrilled acreage held by production under the terms of the lease.
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(2)
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Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.
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(3)
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A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
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(4)
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A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
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2013
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2014
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2015
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2016
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2017
|
||||||||||||||||||||
|
Basin
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||||||
|
Permian
|
|
759
|
|
|
581
|
|
|
2,651
|
|
|
2,157
|
|
|
20,835
|
|
|
17,286
|
|
|
6,893
|
|
|
6,893
|
|
|
2,626
|
|
|
1,820
|
|
|
|
Year Ended December 31,
|
||||||||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
|
Development:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Productive
|
44
|
|
|
28
|
|
|
39
|
|
|
23
|
|
|
41
|
|
|
27
|
|
|
Dry
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Exploratory:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Productive
|
14
|
|
|
7
|
|
|
7
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
Dry
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Productive
|
58
|
|
|
35
|
|
|
46
|
|
|
27
|
|
|
41
|
|
|
27
|
|
|
Dry
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
•
|
the location of wells;
|
|
•
|
the method of drilling and casing wells;
|
|
•
|
the timing of construction or drilling activities, including seasonal wildlife closures;
|
|
•
|
the rates of production or “allowables”;
|
|
•
|
the surface use and restoration of properties upon which wells are drilled;
|
|
•
|
the plugging and abandoning of wells; and
|
|
•
|
notice to, and consultation with, surface owners and other third parties.
|
|
•
|
our proved reserves;
|
|
•
|
the volume of oil and natural gas we are able to produce from existing wells;
|
|
•
|
the prices at which our oil and natural gas are sold; and
|
|
•
|
our ability to acquire, locate and produce new reserves.
|
|
•
|
the domestic and foreign supply of oil and natural gas;
|
|
•
|
the level of prices and expectations about future prices of oil and natural gas;
|
|
•
|
the level of global oil and natural gas exploration and production;
|
|
•
|
the cost of exploring for, developing, producing and delivering oil and natural gas;
|
|
•
|
the price of foreign imports;
|
|
•
|
political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia;
|
|
•
|
the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
|
|
•
|
speculative trading in crude oil and natural gas derivative contracts;
|
|
•
|
the level of consumer product demand;
|
|
•
|
weather conditions and other natural disasters;
|
|
•
|
risks associated with operating drilling rigs;
|
|
•
|
technological advances affecting energy consumption;
|
|
•
|
domestic and foreign governmental regulations and taxes;
|
|
•
|
the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;
|
|
•
|
the proximity and capacity of oil and natural gas pipelines and other transportation facilities;
|
|
•
|
the price and availability of alternative fuels; and
|
|
•
|
overall domestic and global economic conditions.
|
|
•
|
unusual or unexpected geological formations;
|
|
•
|
loss of drilling fluid circulation;
|
|
•
|
title problems;
|
|
•
|
facility or equipment malfunctions;
|
|
•
|
unexpected operational events;
|
|
•
|
shortages or delivery delays of equipment and services;
|
|
•
|
compliance with environmental and other governmental requirements; and
|
|
•
|
adverse weather conditions.
|
|
•
|
a significant portion of our cash flows could be used to service our indebtedness;
|
|
•
|
a high level of debt could increase our vulnerability to general adverse economic and industry conditions;
|
|
•
|
the covenants contained in the agreements governing our current and future outstanding indebtedness will likely limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;
|
|
•
|
a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;
|
|
•
|
our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;
|
|
•
|
a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; and
|
|
•
|
a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.
|
|
•
|
incur additional indebtedness;
|
|
•
|
create additional liens;
|
|
•
|
sell assets;
|
|
•
|
merge or consolidate with another entity;
|
|
•
|
pay dividends or make other distributions;
|
|
•
|
engage in transactions with affiliates; and
|
|
•
|
enter into certain swap agreements.
|
|
•
|
permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested;
|
|
•
|
permits any of our stockholders, officers or directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and
|
|
•
|
provides that if any director or officer of one of our affiliates who is also one of our officers or directors becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as our director or officer), that director or officer will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to such affiliates and that director or officer will not be deemed to have (i) acted in a manner inconsistent with his or her fiduciary or other duties to us regarding the opportunity or (ii) acted in bad faith or in a manner inconsistent with our best interests.
|
|
•
|
our quarterly or annual operating results;
|
|
•
|
changes in our earnings estimates;
|
|
•
|
investment recommendations by securities analysts following our business or our industry;
|
|
•
|
additions or departures of key personnel;
|
|
•
|
changes in the business, earnings estimates or market perceptions of our competitors;
|
|
•
|
our failure to achieve operating results consistent with securities analysts’ projections;
|
|
•
|
changes in industry, general market or economic conditions; and
|
|
•
|
announcements of legislative or regulatory changes.
|
|
•
|
provisions regulating the ability of our stockholders to nominate directors for election or to bring matters for action at annual meetings of our stockholders;
|
|
•
|
limitations on the ability of our stockholders to call a special meeting and act by written consent;
|
|
•
|
the ability of our board of directors to adopt, amend or repeal bylaws, and the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained for stockholders to amend our bylaws;
|
|
•
|
the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained to remove directors;
|
|
•
|
the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained to amend our certificate of incorporation; and
|
|
•
|
the authorization given to our board of directors to issue and set the terms of preferred stock without the approval of our stockholders.
|
|
2012
|
|
High
|
|
Low
|
||||
|
4th Quarter (1)
|
|
$
|
19.89
|
|
|
$
|
15.65
|
|
|
|
|
|
|
|
||||
|
(1) Represents the period from October 12, 2012, the date on which our common stock began trading on the NASDAQ Global Select Market, through December 31, 2012.
|
||||||||
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2012
(1)
|
|
2011
(2)
|
|
2010
(2)
|
|
2009
|
|
2008
|
||||||||||
|
Statements of Operations Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Total revenues
|
$
|
74,962,000
|
|
|
$
|
49,366,000
|
|
|
$
|
27,253,000
|
|
|
$
|
12,716,000
|
|
|
$
|
18,239,000
|
|
|
Total costs and expenses
|
57,655,000
|
|
|
34,219,000
|
|
|
18,072,000
|
|
|
11,378,000
|
|
|
103,285,000
|
|
|||||
|
Income (loss) from operations
|
17,307,000
|
|
|
15,147,000
|
|
|
9,181,000
|
|
|
1,338,000
|
|
|
(85,046,000
|
)
|
|||||
|
Other income (expense)
|
1,075,000
|
|
|
(15,533,000
|
)
|
|
(950,000
|
)
|
|
(4,044,000
|
)
|
|
(8,903,000
|
)
|
|||||
|
Income (loss) before income taxes
|
18,382,000
|
|
|
(386,000
|
)
|
|
8,231,000
|
|
|
(2,706,000
|
)
|
|
(93,950,000
|
)
|
|||||
|
Net income (loss)
|
(36,521,000
|
)
|
|
(386,000
|
)
|
|
8,231,000
|
|
|
(2,706,000
|
)
|
|
(93,950,000
|
)
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Pro forma information
(3)
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Income before income taxes, as reported
|
18,382,000
|
|
|
|
|
|
|
|
|
|
|||||||||
|
Pro forma provision for income taxes
|
6,553,000
|
|
|
|
|
|
|
|
|
|
|||||||||
|
Pro forma net income
|
11,829,000
|
|
|
|
|
|
|
|
|
|
|||||||||
|
Pro forma earnings per common share
(4)
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Basic
|
$
|
0.60
|
|
|
|
|
|
|
|
|
|
||||||||
|
Diluted
|
$
|
0.60
|
|
|
|
|
|
|
|
|
|
||||||||
|
|
As of December 31,
|
||||||||||||||||||
|
|
2012
(1)
|
|
2011
(2)
|
|
2010
(2)
|
|
2009
|
|
2008
|
||||||||||
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Cash and cash equivalents
|
$
|
26,358,000
|
|
|
$
|
6,959,000
|
|
|
$
|
4,119,000
|
|
|
$
|
2,430,000
|
|
|
$
|
8,029,000
|
|
|
Net property and equipment
|
554,242,000
|
|
|
221,149,000
|
|
|
155,611,000
|
|
|
95,296,000
|
|
|
82,451,000
|
|
|||||
|
Total assets
|
606,701,000
|
|
|
263,578,000
|
|
|
181,315,000
|
|
|
100,073,000
|
|
|
91,869,000
|
|
|||||
|
Current liabilities
|
79,232,000
|
|
|
42,298,000
|
|
|
19,070,000
|
|
|
13,972,000
|
|
|
18,011,000
|
|
|||||
|
Long-term debt
|
193,000
|
|
|
85,000,000
|
|
|
44,767,000
|
|
|
—
|
|
|
—
|
|
|||||
|
Stockholders’/ Members’ Equity
|
462,068,000
|
|
|
129,037,000
|
|
|
115,362,000
|
|
|
84,202,000
|
|
|
70,615,000
|
|
|||||
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2012
(1)
|
|
2011
(2)
|
|
2010
(2)
|
|
2009
|
|
2008
|
||||||||||
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Net cash provided by operating activities
|
$
|
49,692,000
|
|
|
$
|
30,998,000
|
|
|
$
|
5,192,000
|
|
|
$
|
2,702,000
|
|
|
$
|
12,042,000
|
|
|
Net cash used in investing activities
|
(183,078,000
|
)
|
|
(81,108,000
|
)
|
|
(55,236,000
|
)
|
|
(32,150,000
|
)
|
|
(84,197,000
|
)
|
|||||
|
Net cash provided by financing activities
|
152,785,000
|
|
|
52,950,000
|
|
|
51,733,000
|
|
|
23,849,000
|
|
|
80,183,000
|
|
|||||
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2012
(1)
|
|
2011
(2)
|
|
2010
(2)
|
|
2009
|
|
2008
|
||||||||||
|
Adjusted EBITDA
(5)
|
$
|
48,223,000
|
|
|
$
|
31,864,000
|
|
|
$
|
17,398,000
|
|
|
$
|
4,617,000
|
|
|
$
|
8,966,000
|
|
|
(1
|
)
|
The year ended December 31, 2012 contains the historical results of operations of Windsor Permian LLC and Windsor UT LLC due to the transfer of a business between entities under common control. See Note 1 to our combined consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
|
|||
|
The year ended December 31, 2012 contains the results of operations attributable to the acquisition of properties from Gulfport Energy Corporation beginning October 11, 2012, the closing date of the property acquisition. See Note 2 to our combined consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
|
|||||
|
|
|
|
|
|
|
|
(2
|
)
|
The years ended December 31, 2011 and 2010 contain the historical results of operations of Windsor Permian LLC and Windsor UT LLC due to the transfer of a business between entities under common control. See Note 1 to our combined consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
|
|||
|
|
|
|
|
|
|
|
(3
|
)
|
Diamondback was formed as a holding company 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 is a C-Corp under the Internal Revenue Code and is subject to income taxes. The Company computed a pro forma income tax provision as if the Company and the Predecessors were subject to income taxes since December 31, 2011. The pro forma tax provision has been calculated at a rate based upon a federal corporate level tax rate and a state tax rate, net of federal benefit, incorporating permanent differences. See Note 1 to our combined consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
|
|||
|
|
|
|
|
|
|
|
(4
|
)
|
The Company’s pro forma basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period, as if the common shares issued upon the merger of Diamondback Energy LLC into Diamondback were outstanding for the entire year. Diluted earnings per share reflects the potential dilution, using the treasury stock method, which assumes that options were exercised and restricted stock awards and units were fully vested. During periods in which the Company realizes a net loss, options and restricted stock awards would not be dilutive to net loss per share and conversion into common stock is assumed not to occur. See Note 1 to our combined consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
|
|||
|
|
|
|
|
|
|
|
(5
|
)
|
Adjusted EBITDA is a supplemental non-GAAP financial measure. For a definition of Adjusted EBITDA to net income (loss) see “—Non-GAAP financial measures and reconciliations” below.
|
|||
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2012
|
|
2011
|
|
2010
|
|
2009
|
|
2008
|
||||||||||
|
Net income (loss):
|
$
|
(36,521,000
|
)
|
|
$
|
(386,000
|
)
|
|
$
|
8,231,000
|
|
|
$
|
(2,706,000
|
)
|
|
$
|
(93,950,000
|
)
|
|
(Gain) loss on derivative instruments
|
(2,617,000
|
)
|
|
13,009,000
|
|
|
148,000
|
|
|
4,068,000
|
|
|
9,528,000
|
|
|||||
|
Interest expense
|
3,610,000
|
|
|
2,528,000
|
|
|
836,000
|
|
|
11,000
|
|
|
—
|
|
|||||
|
Depreciation, depletion and amortization
|
26,273,000
|
|
|
16,104,000
|
|
|
8,145,000
|
|
|
3,216,000
|
|
|
10,200,000
|
|
|||||
|
Impairment of oil and gas properties
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
83,164,000
|
|
|||||
|
Non-cash equity based compensation expense
|
2,477,000
|
|
|
544,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
|
Asset retirement obligation accretion expense
|
98,000
|
|
|
65,000
|
|
|
38,000
|
|
|
28,000
|
|
|
24,000
|
|
|||||
|
Deferred income tax provision
|
54,903,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
|
Adjusted EBITDA
|
$
|
48,223,000
|
|
|
$
|
31,864,000
|
|
|
$
|
17,398,000
|
|
|
$
|
4,617,000
|
|
|
$
|
8,966,000
|
|
|
|
|
2012
|
|
2011
|
|
2010
|
|||
|
Estimated Net Proved Reserves:
|
|
|
|
|
|
|
|||
|
Oil (Bbls)
|
|
26,196,859
|
|
|
18,100,473
|
|
|
19,630,160
|
|
|
Natural gas (Mcf)
|
|
34,570,148
|
|
|
20,551,465
|
|
|
22,695,080
|
|
|
Natural gas liquids (Bbls)
|
|
8,251,429
|
|
|
5,049,560
|
|
|
5,832,967
|
|
|
Total (BOE)
|
|
40,209,979
|
|
|
26,575,277
|
|
|
29,245,640
|
|
|
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
|
|
Unweighted Arithmetic Average
|
||||||||||
|
|
|
First-Day-of-the-Month Prices
|
||||||||||
|
Oil (Bbls)
|
|
$
|
88.13
|
|
|
$
|
93.09
|
|
|
$
|
77.61
|
|
|
Natural gas (Mcf)
|
|
$
|
2.86
|
|
|
$
|
3.91
|
|
|
$
|
4.14
|
|
|
Natural gas liquids (Bbls)
|
|
$
|
43.88
|
|
|
$
|
56.33
|
|
|
$
|
40.74
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
Operating Results:
|
|
|
|
|
|
|
||||||
|
Revenues
|
|
|
|
|
|
|
||||||
|
Oil and natural gas revenues
|
|
$
|
74,962,000
|
|
|
$
|
47,875,000
|
|
|
$
|
26,442,000
|
|
|
Other revenue
|
|
—
|
|
|
1,491,000
|
|
|
811,000
|
|
|||
|
Operating Expenses
|
|
|
|
|
|
|
||||||
|
Lease operating expense
|
|
16,793,000
|
|
|
10,597,000
|
|
|
4,589,000
|
|
|||
|
Production taxes
|
|
3,691,000
|
|
|
2,366,000
|
|
|
1,347,000
|
|
|||
|
Gathering and transportation expense
|
|
424,000
|
|
|
202,000
|
|
|
106,000
|
|
|||
|
Oil and natural gas services
|
|
—
|
|
|
1,733,000
|
|
|
811,000
|
|
|||
|
Depreciation, depletion and amortization
|
|
26,273,000
|
|
|
15,601,000
|
|
|
8,145,000
|
|
|||
|
General and administrative
|
|
10,376,000
|
|
|
3,655,000
|
|
|
3,036,000
|
|
|||
|
Asset retirement obligation accretion expense
|
|
98,000
|
|
|
65,000
|
|
|
38,000
|
|
|||
|
Total expenses
|
|
57,655,000
|
|
|
34,219,000
|
|
|
18,072,000
|
|
|||
|
Income from operations
|
|
17,307,000
|
|
|
15,147,000
|
|
|
9,181,000
|
|
|||
|
Net interest expense
|
|
(3,607,000
|
)
|
|
(2,517,000
|
)
|
|
(802,000
|
)
|
|||
|
Other income - related party
|
|
2,132,000
|
|
|
—
|
|
|
—
|
|
|||
|
Gain (loss) on derivative instruments
|
|
2,617,000
|
|
|
(13,009,000
|
)
|
|
(148,000
|
)
|
|||
|
Loss from equity investment
|
|
(67,000
|
)
|
|
(7,000
|
)
|
|
—
|
|
|||
|
Total other income (expense)
|
|
1,075,000
|
|
|
(15,533,000
|
)
|
|
(950,000
|
)
|
|||
|
Income (loss) before income taxes
|
|
18,382,000
|
|
|
(386,000
|
)
|
|
8,231,000
|
|
|||
|
Provision for income taxes
|
|
54,903,000
|
|
|
—
|
|
|
—
|
|
|||
|
Net income (loss)
|
|
$
|
(36,521,000
|
)
|
|
$
|
(386,000
|
)
|
|
$
|
8,231,000
|
|
|
|
|
|
|
|
|
|
||||||
|
Production Data:
|
|
|
|
|
|
|
||||||
|
Oil (Bbls)
|
|
756,286
|
|
|
449,434
|
|
|
280,721
|
|
|||
|
Natural gas (Mcf)
|
|
833,516
|
|
|
413,640
|
|
|
323,847
|
|
|||
|
Natural gas liquids (Bbls)
|
|
183,114
|
|
|
86,815
|
|
|
79,978
|
|
|||
|
Combined volumes (Boe)
|
|
1,078,320
|
|
|
605,189
|
|
|
414,674
|
|
|||
|
Daily combined volumes (Boe/d)
|
|
2,946
|
|
|
1,658
|
|
|
1,136
|
|
|||
|
|
|
|
|
|
|
|
||||||
|
Average Prices
(1)
:
|
|
|
|
|
|
|
||||||
|
Oil (per Bbl)
|
|
$
|
86.88
|
|
|
$
|
92.24
|
|
|
$
|
76.51
|
|
|
Natural gas (per Mcf)
|
|
2.85
|
|
|
3.98
|
|
|
4.32
|
|
|||
|
Natural gas liquids (per Bbl)
|
|
37.57
|
|
|
54.98
|
|
|
44.56
|
|
|||
|
Combined (per BOE)
|
|
69.52
|
|
|
79.11
|
|
|
63.77
|
|
|||
|
|
|
|
|
|
|
|
||||||
|
Average Costs (per BOE)
|
|
|
|
|
|
|
||||||
|
Lease operating expense
|
|
$
|
15.57
|
|
|
$
|
17.51
|
|
|
$
|
11.07
|
|
|
Gathering and transportation expense
|
|
0.39
|
|
|
0.33
|
|
|
0.26
|
|
|||
|
Production taxes
|
|
3.42
|
|
|
3.91
|
|
|
3.25
|
|
|||
|
Production taxes as a % of sales
|
|
4.9
|
%
|
|
4.9
|
%
|
|
5.1
|
%
|
|||
|
Depreciation, depletion, and amortization
|
|
24.36
|
|
|
25.78
|
|
|
19.64
|
|
|||
|
General and administrative
|
|
9.62
|
|
|
6.04
|
|
|
7.32
|
|
|||
|
|
|
|
|
|
|
|
||||||
|
|
|
|
Change in prices
|
|
Production volumes
(1)
|
|
Total net dollar effect of change (in thousands)
|
||||||
|
|
Effect of changes in price:
|
|
|
|
|
|
|
||||||
|
|
Oil
|
|
$
|
(5.36
|
)
|
|
756,286
|
|
|
$
|
(4,055
|
)
|
|
|
|
Natural gas liquids
|
|
$
|
(17.41
|
)
|
|
183,114
|
|
|
$
|
(3,188
|
)
|
|
|
|
Natural gas
|
|
$
|
(1.13
|
)
|
|
833,516
|
|
|
$
|
(940
|
)
|
|
|
|
Total revenues due to change in price
|
|
|
|
|
|
$
|
(8,183
|
)
|
||||
|
|
|
|
Change in production volumes
(1)
|
|
Prior period Average Prices
|
|
Total net dollar effect of change (in thousands)
|
||||||
|
|
Effect of changes in production volumes:
|
|
|
|
|
|
|
||||||
|
|
Oil
|
|
306,852
|
|
|
$
|
92.24
|
|
|
$
|
28,304
|
|
|
|
|
Natural gas liquids
|
|
96,299
|
|
|
$
|
54.98
|
|
|
$
|
5,294
|
|
|
|
|
Natural gas
|
|
419,876
|
|
|
$
|
3.98
|
|
|
$
|
1,672
|
|
|
|
|
Total revenues due to change in production volumes
|
|
|
|
|
|
$
|
35,270
|
|
||||
|
|
Total change in revenues
|
|
|
|
|
|
$
|
27,087
|
|
||||
|
(1)
|
Production volumes are presented in Bbls for oil and natural gas liquids and Mcf for natural gas
|
||||||||||||
|
|
|
|
Change in prices
|
|
Production volumes
(1)
|
|
Total net dollar effect of change (in thousands)
|
||||||
|
|
Effect of changes in price:
|
|
|
|
|
|
|
||||||
|
|
Oil
|
|
$
|
15.73
|
|
|
449,434
|
|
|
$
|
7,069
|
|
|
|
|
Natural gas liquids
|
|
$
|
10.42
|
|
|
86,815
|
|
|
$
|
904
|
|
|
|
|
Natural gas
|
|
$
|
(0.34
|
)
|
|
413,640
|
|
|
$
|
(141
|
)
|
|
|
|
Total revenues due to change in price
|
|
|
|
|
|
$
|
7,832
|
|
||||
|
|
|
|
Change in production volumes
(1)
|
|
Prior period Average Prices
|
|
Total net dollar effect of change (in thousands)
|
||||||
|
|
Effect of changes in production volumes:
|
|
|
|
|
|
|
||||||
|
|
Oil
|
|
168,713
|
|
|
$
|
76.51
|
|
|
$
|
12,908
|
|
|
|
|
Natural gas liquids
|
|
6,837
|
|
|
$
|
44.56
|
|
|
$
|
305
|
|
|
|
|
Natural gas
|
|
89,793
|
|
|
$
|
4.32
|
|
|
$
|
388
|
|
|
|
|
Total revenues due to change in production volumes
|
|
|
|
|
|
$
|
13,601
|
|
||||
|
|
Total change in revenues
|
|
|
|
|
|
$
|
21,433
|
|
||||
|
(1)
|
Production volumes are presented in Bbls for oil and natural gas liquids and Mcf for natural gas
|
||||||||||||
|
|
|
Year Ended December 31,
|
||||||||||
|
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
Net cash provided by operating activities
|
|
$
|
49,692,000
|
|
|
$
|
30,998,000
|
|
|
$
|
5,192,000
|
|
|
Net cash used in investing activities
|
|
(183,078,000
|
)
|
|
(81,108,000
|
)
|
|
(55,236,000
|
)
|
|||
|
Net cash provided by financing activities
|
|
$
|
152,785,000
|
|
|
$
|
52,950,000
|
|
|
$
|
51,733,000
|
|
|
Net change in cash
|
|
$
|
19,399,000
|
|
|
$
|
2,840,000
|
|
|
$
|
1,689,000
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
Drilling and completion of wells
|
|
$
|
(100,090,000
|
)
|
|
$
|
(76,470,000
|
)
|
|
$
|
(39,230,000
|
)
|
|
Purchase of leasehold acquisitions
|
|
(11,707,000
|
)
|
|
(3,704,000
|
)
|
|
(5,344,000
|
)
|
|||
|
Acquisition of Gulfport properties
|
|
(63,590,000
|
)
|
|
—
|
|
|
—
|
|
|||
|
Purchase of other property and equipment
|
|
(1,102,000
|
)
|
|
(7,065,000
|
)
|
|
(11,741,000
|
)
|
|||
|
Proceeds from sale of property and equipment
|
|
48,000
|
|
|
55,000
|
|
|
1,270,000
|
|
|||
|
Settlement of non-hedge derivative instruments
|
|
(8,963,000
|
)
|
|
(4,127,000
|
)
|
|
(3,963,000
|
)
|
|||
|
Receipt on derivative margins
|
|
2,326,000
|
|
|
4,203,000
|
|
|
3,772,000
|
|
|||
|
Proceeds from equity investment, net
|
|
—
|
|
|
6,000,000
|
|
|
—
|
|
|||
|
Net cash used in investing activities
|
|
$
|
(183,078,000
|
)
|
|
$
|
(81,108,000
|
)
|
|
$
|
(55,236,000
|
)
|
|
Financial Covenant
|
|
|
Required Ratio
|
|
Ratio of EBITDAX to interest expense, as defined in the credit agreement
|
|
Not less than 2.5 to 1.0
|
|
|
Ratio of total debt to EBITDAX
|
|
Not greater than 4.0 to 1.0
|
|
|
Ratio of debt under revolving credit agreement to EBITDAX
|
|
Not greater than 3.0 to 1.0
|
|
|
Ratio of current assets to liabilities, as defined in the credit agreement
|
|
Not less than 1.0 to 1.0
|
|
|
•
|
$190.0 million for the drilling and completion of horizontal operated wells;
|
|
•
|
$66.0 million for the drilling and completion of vertical operated wells;
|
|
•
|
$12.0 million for our participation in the drilling and completion of non-operated wells; and
|
|
•
|
$17.0 million for the construction of infrastructure to support production, including investments in water disposal infrastructure and gathering line projects.
|
|
|
|
Payments Due by Period
|
|
||||||||||||||||||
|
|
|
Total
|
|
Less Than 1 Year
|
|
1-3 Years
|
|
3-5 Years
|
|
More Than 5 Years
|
|
||||||||||
|
Long term debt
(1)
|
|
$
|
338,000
|
|
|
$
|
145,000
|
|
|
$
|
193,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
Interest and commitment fees
(2)
|
|
1,181,000
|
|
|
675,000
|
|
|
506,000
|
|
|
—
|
|
|
—
|
|
|
|||||
|
Derivative contracts
|
|
5,205,000
|
|
|
4,817,000
|
|
|
388,000
|
|
|
—
|
|
|
—
|
|
|
|||||
|
Asset retirement obligations
(3)
|
|
2,145,000
|
|
|
20,000
|
|
|
—
|
|
|
—
|
|
|
2,125,000
|
|
|
|||||
|
Fracturing and Well Stimulation Service Agreements
|
|
18,000,000
|
|
|
14,400,000
|
|
|
3,600,000
|
|
|
—
|
|
|
—
|
|
|
|||||
|
Operating lease obligations
|
|
2,195,000
|
|
|
485,000
|
|
|
992,000
|
|
|
693,000
|
|
|
25,000
|
|
|
|||||
|
|
|
$
|
29,064,000
|
|
|
$
|
20,542,000
|
|
|
$
|
5,679,000
|
|
|
$
|
693,000
|
|
|
$
|
2,150,000
|
|
|
|
(1)
|
Long term debt consists of the outstanding principal amount under our revolving credit facility and an installment payment contract for the purchase of computer equipment. We have no outstanding borrowings under our revolving credit facility at December 31, 2012. Any subsequent borrowings under our revolving credit facility are due on October 15, 2014.
|
|||
|
(2)
|
This table reflects only the minimum amount of interest and commitment fees due, which as of December 31, 2012 includes a commitment fee equal to 0.5% per year of the unused portion of the borrowing base of our revolving credit facility. The table does not include interest expense or other fees payable under this floating rate facility as we cannot predict the timing of future borrowings and repayments or interest rates to be charged.
|
|||
|
(3)
|
Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 4 of the notes to our combined consolidated financial statements set forth in Part IV, Item 15 of this Form 10-K.
|
|||
|
(a)
|
Documents included in this report:
|
|
|
|
|
1.
Financial Statements
|
|
|
|
|
|
|
|
|
|
|||
|
|
|||
|
|
|||
|
|
|||
|
|
|||
|
|
|||
|
|
|
|
|
|
|
2.
Financial Statement Schedules
|
|
|
|
|
Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company’s combined consolidated financial statements and related notes.
|
|
|
|
|
|
|
|
|
|
3.
Exhibits
|
|
|
|
|
The Exhibit Index beginning on page E–1 of this report is incorporated herein by reference.
|
|
|
|
|
|
|
|
DIAMONDBACK ENERGY, INC.
|
|
|
|
|
|
|
|
Date:
|
March 1, 2013
|
|
|
/s/ Travis D. Stice
|
|
|
|
|
|
Travis D. Stice
|
|
|
|
|
|
Chief Executive Officer and Director
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
|
/s/ Steven E. West
|
|
Chairman of the Board and Director
|
|
March 1, 2013
|
|
Steven E. West
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Travis D. Stice
|
|
Chief Executive Officer and Director
|
|
March 1, 2013
|
|
Travis D. Stice
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Michael P. Cross
|
|
Director
|
|
March 1, 2013
|
|
Michael P. Cross
|
|
|
|
|
|
|
|
|
|
|
|
/s/ David L. Houston
|
|
Director
|
|
March 1, 2013
|
|
David L. Houston
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Mark L. Plaumann
|
|
Director
|
|
March 1, 2013
|
|
Mark L. Plaumann
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Teresa L. Dick
|
|
Chief Financial Officer, Senior Vice President, and Assistant Secretary
|
|
March 1, 2013
|
|
Teresa L. Dick
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
||||||
|
|
|
2012
|
|
2011
|
||||
|
Assets
|
|
|
|
|
||||
|
Current assets:
|
|
|
|
|
||||
|
Cash and cash equivalents
|
|
$
|
26,358,000
|
|
|
$
|
6,959,000
|
|
|
Accounts receivable:
|
|
|
|
|
||||
|
Joint interest and other
|
|
5,959,000
|
|
|
3,734,000
|
|
||
|
Oil and natural gas sales
|
|
8,081,000
|
|
|
839,000
|
|
||
|
Related party
|
|
772,000
|
|
|
12,937,000
|
|
||
|
Inventories
|
|
6,195,000
|
|
|
6,007,000
|
|
||
|
Deferred income taxes
|
|
1,857,000
|
|
|
—
|
|
||
|
Prepaid expenses and other
|
|
1,053,000
|
|
|
336,000
|
|
||
|
Total current assets
|
|
50,275,000
|
|
|
30,812,000
|
|
||
|
|
|
|
|
|
||||
|
Property and equipment
|
|
|
|
|
||||
|
Oil and natural gas properties, at cost, based on the full cost method of accounting ($121,245,000 and $4,528,000 excluded from amortization at December 31, 2012 and December 31, 2011, respectively)
|
|
697,742,000
|
|
|
339,831,000
|
|
||
|
Other property and equipment
|
|
2,337,000
|
|
|
1,017,000
|
|
||
|
Accumulated depletion, depreciation, amortization and impairment
|
|
(145,837,000
|
)
|
|
(119,699,000
|
)
|
||
|
|
|
554,242,000
|
|
|
221,149,000
|
|
||
|
|
|
|
|
|
||||
|
Investments-equity method
|
|
—
|
|
|
10,310,000
|
|
||
|
Other assets
|
|
2,184,000
|
|
|
1,307,000
|
|
||
|
Total assets
|
|
$
|
606,701,000
|
|
|
$
|
263,578,000
|
|
|
Liabilities and Stockholders’ Equity/Members’ Equity
|
|
|
|
|
||||
|
Current liabilities:
|
|
|
|
|
||||
|
Accounts payable trade
|
|
$
|
12,141,000
|
|
|
$
|
8,770,000
|
|
|
Accounts payable-related party
|
|
18,813,000
|
|
|
3,230,000
|
|
||
|
Accrued capital expenditures
|
|
29,397,000
|
|
|
13,919,000
|
|
||
|
Other accrued liabilities
|
|
10,649,000
|
|
|
4,894,000
|
|
||
|
Revenues and royalties payable
|
|
3,270,000
|
|
|
3,165,000
|
|
||
|
Derivative instruments
|
|
4,817,000
|
|
|
8,320,000
|
|
||
|
Note payable-short term
|
|
145,000
|
|
|
—
|
|
||
|
Total current liabilities
|
|
79,232,000
|
|
|
42,298,000
|
|
||
|
|
|
|
|
|
||||
|
Note payable–long term
|
|
193,000
|
|
|
—
|
|
||
|
Note payable–credit facility–long term
|
|
—
|
|
|
85,000,000
|
|
||
|
Derivative instruments-long term
|
|
388,000
|
|
|
6,139,000
|
|
||
|
Asset retirement obligations-long term
|
|
2,125,000
|
|
|
1,104,000
|
|
||
|
Deferred income taxes-noncurrent
|
|
62,695,000
|
|
|
—
|
|
||
|
Total liabilities
|
|
144,633,000
|
|
|
134,541,000
|
|
||
|
Commitments and contingencies (Note 13)
|
|
|
|
|
|
|
||
|
Members’ equity
|
|
—
|
|
|
129,037,000
|
|
||
|
Stockholders’ equity:
|
|
|
|
|
||||
|
Common stock, $0.01 par value, 100,000,000 shares authorized, 36,986,532 issued and outstanding at December 31, 2012; zero issued and outstanding at December 31, 2011
|
|
370,000
|
|
|
—
|
|
||
|
Additional paid-in capital
|
|
513,772,000
|
|
|
—
|
|
||
|
Accumulated deficit
|
|
(52,074,000
|
)
|
|
—
|
|
||
|
Total stockholders’ equity/members’ equity
|
|
462,068,000
|
|
|
129,037,000
|
|
||
|
Total liabilities and stockholders’ equity/members’ equity
|
|
$
|
606,701,000
|
|
|
$
|
263,578,000
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
Revenues:
|
|
|
|
|
|
|
||||||
|
Oil sales
|
|
$
|
65,704,000
|
|
|
$
|
2,582,000
|
|
|
$
|
75,000
|
|
|
Oil sales - related party
|
|
—
|
|
|
38,873,000
|
|
|
21,403,000
|
|
|||
|
Natural gas sales
|
|
1,369,000
|
|
|
1,061,000
|
|
|
1,400,000
|
|
|||
|
Natural gas sales - related party
|
|
1,010,000
|
|
|
586,000
|
|
|
—
|
|
|||
|
Natural gas liquid sales
|
|
3,839,000
|
|
|
3,169,000
|
|
|
3,564,000
|
|
|||
|
Natural gas liquid sales - related party
|
|
3,040,000
|
|
|
1,604,000
|
|
|
—
|
|
|||
|
Oil and natural gas services - related party
|
|
—
|
|
|
1,491,000
|
|
|
811,000
|
|
|||
|
Total revenues
|
|
74,962,000
|
|
|
49,366,000
|
|
|
27,253,000
|
|
|||
|
|
|
|
|
|
|
|
||||||
|
Costs and expenses:
|
|
|
|
|
|
|
||||||
|
Lease operating expenses
|
|
15,777,000
|
|
|
8,470,000
|
|
|
3,040,000
|
|
|||
|
Lease operating expenses - related party
|
|
1,016,000
|
|
|
2,127,000
|
|
|
1,549,000
|
|
|||
|
Production taxes
|
|
3,404,000
|
|
|
574,000
|
|
|
354,000
|
|
|||
|
Production taxes - related party
|
|
287,000
|
|
|
1,792,000
|
|
|
993,000
|
|
|||
|
Gathering and transportation
|
|
124,000
|
|
|
53,000
|
|
|
106,000
|
|
|||
|
Gathering and transportation - related party
|
|
300,000
|
|
|
149,000
|
|
|
—
|
|
|||
|
Oil and natural gas services
|
|
—
|
|
|
1,207,000
|
|
|
228,000
|
|
|||
|
Oil and natural gas services - related party
|
|
—
|
|
|
526,000
|
|
|
583,000
|
|
|||
|
Depreciation, depletion and amortization
|
|
26,273,000
|
|
|
15,601,000
|
|
|
8,145,000
|
|
|||
|
General and administrative expenses
|
|
9,178,000
|
|
|
495,000
|
|
|
380,000
|
|
|||
|
General and administrative expenses - related party
|
|
1,198,000
|
|
|
3,160,000
|
|
|
2,656,000
|
|
|||
|
Asset retirement obligation accretion expense
|
|
98,000
|
|
|
65,000
|
|
|
38,000
|
|
|||
|
Total costs and expenses
|
|
57,655,000
|
|
|
34,219,000
|
|
|
18,072,000
|
|
|||
|
|
|
|
|
|
|
|
||||||
|
Income from operations
|
|
17,307,000
|
|
|
15,147,000
|
|
|
9,181,000
|
|
|||
|
|
|
|
|
|
|
|
||||||
|
Other income (expense)
|
|
|
|
|
|
|
||||||
|
Interest income
|
|
3,000
|
|
|
11,000
|
|
|
34,000
|
|
|||
|
Interest expense
|
|
(3,610,000
|
)
|
|
(2,528,000
|
)
|
|
(836,000
|
)
|
|||
|
Other income - related party
|
|
2,132,000
|
|
|
—
|
|
|
—
|
|
|||
|
Gain (loss) on derivative instruments
|
|
2,617,000
|
|
|
(13,009,000
|
)
|
|
(148,000
|
)
|
|||
|
Loss from equity investment
|
|
(67,000
|
)
|
|
(7,000
|
)
|
|
—
|
|
|||
|
Total other income (expense), net
|
|
1,075,000
|
|
|
(15,533,000
|
)
|
|
(950,000
|
)
|
|||
|
|
|
|
|
|
|
|
||||||
|
Income (loss) before income taxes
|
|
18,382,000
|
|
|
(386,000
|
)
|
|
8,231,000
|
|
|||
|
Provision for income taxes
|
|
|
|
|
|
|
||||||
|
Deferred income tax provision
|
|
54,903,000
|
|
|
—
|
|
|
—
|
|
|||
|
Net income (loss)
|
|
$
|
(36,521,000
|
)
|
|
$
|
(386,000
|
)
|
|
$
|
8,231,000
|
|
|
|
|
|
|
|
|
|
||||||
|
|
|
Year Ended December 31,
|
|
||
|
|
|
2012
|
|
||
|
|
|
|
|
||
|
Pro forma information (unaudited)
|
|
|
|
||
|
Income before income taxes, as reported
|
|
$
|
18,382,000
|
|
|
|
Pro forma provision for income taxes
|
|
6,553,000
|
|
|
|
|
Pro forma net income
|
|
$
|
11,829,000
|
|
|
|
Pro forma earnings per common share
|
|
|
|
||
|
Basic
|
|
$
|
0.60
|
|
|
|
Diluted
|
|
$
|
0.60
|
|
|
|
Pro forma weighted average common shares outstanding
|
|
|
|
||
|
Basic
|
|
19,720,734
|
|
|
|
|
Diluted
|
|
19,723,774
|
|
|
|
|
|
|
Members’ Equity
|
|
|
Common Stock
|
|
Additional
|
|
Accumulated
|
|
|
|
||||||||||||
|
|
|
|
|
Shares
|
Amount
|
|
paid-in capital
|
|
Deficit
|
|
Total
|
|
||||||||||||
|
Balance, December 31, 2009
|
|
$
|
84,202,000
|
|
|
|
—
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
84,202,000
|
|
|
|
Contributions
|
|
28,508,000
|
|
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
28,508,000
|
|
|
|||||
|
Distributions
|
|
(5,579,000
|
)
|
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5,579,000
|
)
|
|
|||||
|
Net income
|
|
8,231,000
|
|
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,231,000
|
|
|
|||||
|
Balance, December 31, 2010
|
|
115,362,000
|
|
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
115,362,000
|
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
Contributions
|
|
13,517,000
|
|
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
13,517,000
|
|
|
|||||
|
Equity based compensation
|
|
544,000
|
|
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
544,000
|
|
|
|||||
|
Net loss
|
|
(386,000
|
)
|
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(386,000
|
)
|
|
|||||
|
Balance December 31, 2011
|
|
129,037,000
|
|
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
129,037,000
|
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
Contributions
|
|
4,008,000
|
|
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,008,000
|
|
|
|||||
|
Distributions of equity method investments
|
|
(10,504,000
|
)
|
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(10,504,000
|
)
|
|
|||||
|
Equity based compensation
|
|
873,000
|
|
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
873,000
|
|
|
|||||
|
Earnings prior to merger
|
|
15,553,000
|
|
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
15,553,000
|
|
|
|||||
|
Common shares issued upon Merger
|
|
(138,967,000
|
)
|
|
|
14,697,496
|
|
147,000
|
|
|
138,820,000
|
|
|
—
|
|
|
—
|
|
|
|||||
|
Common shares issued upon acquisition of Gulfport properties
|
|
—
|
|
|
|
7,914,036
|
|
79,000
|
|
|
138,417,000
|
|
|
—
|
|
|
138,496,000
|
|
|
|||||
|
Common shares issued at initial public offering, net of offering costs
|
|
—
|
|
|
|
14,375,000
|
|
144,000
|
|
|
234,000,000
|
|
|
—
|
|
|
234,144,000
|
|
|
|||||
|
Stock-based compensation
|
|
—
|
|
|
|
—
|
|
—
|
|
|
2,535,000
|
|
|
—
|
|
|
2,535,000
|
|
|
|||||
|
Net loss subsequent to merger
|
|
—
|
|
|
|
—
|
|
—
|
|
|
—
|
|
|
(52,074,000
|
)
|
|
(52,074,000
|
)
|
|
|||||
|
Balance December 31, 2012
|
|
$
|
—
|
|
|
|
36,986,532
|
|
$
|
370,000
|
|
|
$
|
513,772,000
|
|
|
$
|
(52,074,000
|
)
|
|
$
|
462,068,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
|
|
Year Ended December 31,
|
||||||||||
|
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
Cash flows from operating activities:
|
|
|
|
|
|
|
||||||
|
Net income (loss)
|
|
$
|
(36,521,000
|
)
|
|
$
|
(386,000
|
)
|
|
$
|
8,231,000
|
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
||||||
|
Provision for deferred income taxes
|
|
54,903,000
|
|
|
—
|
|
|
—
|
|
|||
|
Asset retirement obligation accretion expense
|
|
98,000
|
|
|
65,000
|
|
|
38,000
|
|
|||
|
Depreciation, depletion, and amortization
|
|
26,273,000
|
|
|
16,104,000
|
|
|
8,145,000
|
|
|||
|
Amortization of debt issuance costs
|
|
494,000
|
|
|
250,000
|
|
|
163,000
|
|
|||
|
(Gain) loss on derivative instruments
|
|
(2,617,000
|
)
|
|
13,009,000
|
|
|
148,000
|
|
|||
|
Loss from equity investment
|
|
67,000
|
|
|
—
|
|
|
—
|
|
|||
|
Equity-based compensation expense
|
|
3,482,000
|
|
|
544,000
|
|
|
—
|
|
|||
|
Gain on sale of assets
|
|
(37,000
|
)
|
|
(23,000
|
)
|
|
(5,000
|
)
|
|||
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
||||||
|
Accounts receivable
|
|
(5,036,000
|
)
|
|
(1,547,000
|
)
|
|
(1,822,000
|
)
|
|||
|
Accounts receivable-related party
|
|
6,096,000
|
|
|
(4,133,000
|
)
|
|
(6,793,000
|
)
|
|||
|
Inventories
|
|
(639,000
|
)
|
|
(872,000
|
)
|
|
(4,897,000
|
)
|
|||
|
Prepaid expenses and other
|
|
(606,000
|
)
|
|
(202,000
|
)
|
|
(326,000
|
)
|
|||
|
Accounts payable and accrued liabilities
|
|
7,151,000
|
|
|
2,656,000
|
|
|
1,954,000
|
|
|||
|
Accounts payable and accrued liabilities-related party
|
|
(1,218,000
|
)
|
|
830,000
|
|
|
(409,000
|
)
|
|||
|
Revenues and royalties payable
|
|
105,000
|
|
|
2,666,000
|
|
|
499,000
|
|
|||
|
Revenues and royalties payable-related party
|
|
(2,303,000
|
)
|
|
2,037,000
|
|
|
266,000
|
|
|||
|
Net cash provided by operating activities
|
|
49,692,000
|
|
|
30,998,000
|
|
|
5,192,000
|
|
|||
|
|
|
|
|
|
|
|
||||||
|
Cash flows from investing activities:
|
|
|
|
|
|
|
||||||
|
Additions to oil and natural gas properties
|
|
(102,122,000
|
)
|
|
(58,160,000
|
)
|
|
(7,624,000
|
)
|
|||
|
Additions to oil and natural gas properties-related party
|
|
(9,675,000
|
)
|
|
(22,014,000
|
)
|
|
(36,950,000
|
)
|
|||
|
Acquisition of Gulfport properties
|
|
(63,590,000
|
)
|
|
—
|
|
|
—
|
|
|||
|
Proceeds from sale of oil and natural gas properties
|
|
—
|
|
|
—
|
|
|
1,250,000
|
|
|||
|
Purchase of other property and equipment
|
|
(1,102,000
|
)
|
|
(7,065,000
|
)
|
|
(11,741,000
|
)
|
|||
|
Proceeds from sale of property and equipment
|
|
48,000
|
|
|
55,000
|
|
|
20,000
|
|
|||
|
Settlement of non-hedge derivative instruments
|
|
(8,963,000
|
)
|
|
(4,127,000
|
)
|
|
(3,963,000
|
)
|
|||
|
Receipt on derivative margins
|
|
2,326,000
|
|
|
4,203,000
|
|
|
3,772,000
|
|
|||
|
Deconsolidation of Bison
|
|
—
|
|
|
(10,000
|
)
|
|
—
|
|
|||
|
Proceeds from sale of membership interest in equity investment
|
|
—
|
|
|
6,010,000
|
|
|
—
|
|
|||
|
Net cash used in investing activities
|
|
(183,078,000
|
)
|
|
(81,108,000
|
)
|
|
(55,236,000
|
)
|
|||
|
Cash flows from financing activities:
|
|
|
|
|
|
|
||||||
|
Proceeds from borrowings on credit facility
|
|
15,000,000
|
|
|
40,233,000
|
|
|
61,066,000
|
|
|||
|
Repayment on credit facility
|
|
(100,000,000
|
)
|
|
—
|
|
|
(23,950,000
|
)
|
|||
|
Proceeds from note payable- related party
|
|
30,000,000
|
|
|
—
|
|
|
—
|
|
|||
|
Payment of note payable- related party
|
|
(30,050,000
|
)
|
|
—
|
|
|
—
|
|
|||
|
Debt issuance costs
|
|
(450,000
|
)
|
|
(770,000
|
)
|
|
(718,000
|
)
|
|||
|
Initial public offering costs
|
|
(2,887,000
|
)
|
|
(30,000
|
)
|
|
—
|
|
|||
|
Proceeds from initial public offering
|
|
237,164,000
|
|
|
—
|
|
|
—
|
|
|||
|
Contributions by members
|
|
4,008,000
|
|
|
13,517,000
|
|
|
20,914,000
|
|
|||
|
Distributions to members
|
|
—
|
|
|
—
|
|
|
(5,579,000
|
)
|
|||
|
Net cash provided by financing activities
|
|
152,785,000
|
|
|
52,950,000
|
|
|
51,733,000
|
|
|||
|
|
|
|
|
|
|
|
||||||
|
Net increase in cash and cash equivalents
|
|
19,399,000
|
|
|
2,840,000
|
|
|
1,689,000
|
|
|||
|
Cash and cash equivalents at beginning of period
|
|
6,959,000
|
|
|
4,119,000
|
|
|
2,430,000
|
|
|||
|
Cash and cash equivalents at end of period
|
|
$
|
26,358,000
|
|
|
$
|
6,959,000
|
|
|
$
|
4,119,000
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
Supplemental disclosure of cash flow information:
|
|
|
|
|
|
|
||||||
|
Interest paid, net of capitalized interest
|
|
$
|
3,017,000
|
|
|
$
|
2,265,000
|
|
|
$
|
600,000
|
|
|
Supplemental disclosure of non-cash transactions:
|
|
|
|
|
|
|
||||||
|
Asset retirement obligation incurred, including changes in estimate
|
|
$
|
386,000
|
|
|
$
|
297,000
|
|
|
$
|
223,000
|
|
|
Distribution of equity method investments
|
|
$
|
10,504,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Note payable exchanged for equipment
|
|
$
|
411,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Property Contributed
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
7,594,000
|
|
|
Common stock issued as a result of the Gulfport transaction
|
|
$
|
138,496,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Asset retirement obligation acquired as a result of the Gulfport transaction
|
|
$
|
562,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Post-closing adjustment payable as a result of the Gulfport transaction
|
|
$
|
18,550,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
December 31,
|
||||||
|
|
|
2012
|
|
2011
|
||||
|
Tubular goods and equipment
|
|
$
|
5,725,000
|
|
|
$
|
5,631,000
|
|
|
Crude oil
|
|
470,000
|
|
|
376,000
|
|
||
|
|
|
$
|
6,195,000
|
|
|
$
|
6,007,000
|
|
|
Common Stock (7,914,036 shares)
|
|
$
|
138,496,000
|
|
|
Promissory note paid in full from IPO proceeds
|
|
63,590,000
|
|
|
|
Closing adjustment payable
|
|
18,550,000
|
|
|
|
Total
|
|
$
|
220,636,000
|
|
|
Proved oil and natural gas properties
|
|
$
|
115,760,000
|
|
|
|
Unevaluated oil and natural gas properties
|
|
111,373,000
|
|
|
|
|
Asset retirement obligations
|
|
(562,000
|
)
|
|
|
|
Deferred income tax liability
|
|
(5,935,000
|
)
|
|
|
|
Total fair value of net assets
|
|
$
|
220,636,000
|
|
|
|
|
|
Pro Forma
|
|
||||||
|
|
|
(Unaudited)
|
|
||||||
|
|
|
Year Ended December 31,
|
|
||||||
|
|
|
2012
|
|
2011
|
|
||||
|
Pro forma total revenues
|
|
$
|
97,455,000
|
|
|
$
|
72,418,000
|
|
|
|
Pro forma income from operations
|
|
24,064,000
|
|
|
23,189,000
|
|
|
||
|
Pro forma net income (loss)
|
|
(29,764,000
|
)
|
|
7,666,000
|
|
(1)
|
||
|
|
|
|
|
|
|
||||
|
|
|
December 31,
|
||||||
|
|
|
2012
|
|
2011
|
||||
|
Oil and natural gas properties:
|
|
|
|
|
||||
|
Subject to depletion
|
|
$
|
576,497,000
|
|
|
$
|
335,303,000
|
|
|
Not subject to depletion-acquisition costs
|
|
|
|
|
||||
|
Incurred in 2012
|
|
117,395,000
|
|
|
—
|
|
||
|
Incurred in 2011
|
|
1,670,000
|
|
|
1,689,000
|
|
||
|
Incurred in 2010
|
|
1,647,000
|
|
|
2,306,000
|
|
||
|
Incurred in 2009
|
|
533,000
|
|
|
533,000
|
|
||
|
Total not subject to depletion
|
|
121,245,000
|
|
|
4,528,000
|
|
||
|
|
|
|
|
|
||||
|
Gross oil and natural gas properties
|
|
697,742,000
|
|
|
339,831,000
|
|
||
|
Less accumulated depreciation, depletion, amortization and impairment
|
|
(145,102,000
|
)
|
|
(119,366,000
|
)
|
||
|
Oil and natural gas properties, net
|
|
552,640,000
|
|
|
220,465,000
|
|
||
|
|
|
|
|
|
||||
|
Other property and equipment
|
|
2,337,000
|
|
|
1,017,000
|
|
||
|
Less accumulated depreciation
|
|
(735,000
|
)
|
|
(333,000
|
)
|
||
|
Other property and equipment, net
|
|
1,602,000
|
|
|
684,000
|
|
||
|
|
|
|
|
|
||||
|
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment
|
|
$
|
554,242,000
|
|
|
$
|
221,149,000
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
Asset retirement obligation, beginning of period
|
$
|
1,104,000
|
|
|
$
|
742,000
|
|
|
$
|
482,000
|
|
|
Additional liability incurred
|
201,000
|
|
|
297,000
|
|
|
222,000
|
|
|||
|
Liabilities acquired
|
562,000
|
|
|
—
|
|
|
—
|
|
|||
|
Liabilities settled
|
(5,000
|
)
|
|
—
|
|
|
—
|
|
|||
|
Accretion expense
|
98,000
|
|
|
65,000
|
|
|
38,000
|
|
|||
|
Revisions in estimated liabilities
|
185,000
|
|
|
—
|
|
|
—
|
|
|||
|
Asset retirement obligation, end of period
|
2,145,000
|
|
|
1,104,000
|
|
|
742,000
|
|
|||
|
Less current portion
|
20,000
|
|
|
—
|
|
|
—
|
|
|||
|
Asset retirement obligations - long-term
|
$
|
2,125,000
|
|
|
$
|
1,104,000
|
|
|
$
|
742,000
|
|
|
|
|
December 31, 2011
|
||
|
Current Assets
|
|
$
|
4,438,000
|
|
|
Property and equipment, net
|
|
21,708,000
|
|
|
|
Other assets
|
|
880,000
|
|
|
|
Current liabilities
|
|
2,419,000
|
|
|
|
Equity
|
|
24,607,000
|
|
|
|
|
|
December 31, 2011
|
||
|
Current assets
|
|
$
|
994,000
|
|
|
Property and equipment, net
|
|
7,585,000
|
|
|
|
Current liabilities
|
|
27,000
|
|
|
|
Equity
|
|
8,552,000
|
|
|
|
Financial Covenant
|
|
|
Required Ratio
|
|
Ratio of EBITDAX to interest expense, as defined in the credit agreement
|
|
Not less than 2.5 to 1.0
|
|
|
Ratio of total debt to EBITDAX
|
|
Not greater than 4.0 to 1.0
|
|
|
Ratio of debt under revolving credit agreement to EBITDAX
|
|
Not greater than 3.0 to 1.0
|
|
|
Ratio of current assets to liabilities, as defined in the credit agreement
|
|
Not less than 1.0 to 1.0
|
|
|
|
|
2012
|
|||||||||
|
|
|
|
|
|
|
Per
|
|||||
|
|
|
Income
|
|
Shares
|
|
Share
|
|||||
|
Basic:
|
|
|
|
|
|
|
|||||
|
Pro forma net income attributable to common stock
|
|
$
|
11,829,000
|
|
|
19,720,734
|
|
|
$
|
0.60
|
|
|
Effect of Dilutive Securities:
|
|
|
|
|
|
|
|||||
|
Dilutive effect of potential common shares issuable
|
|
$
|
—
|
|
|
3,040
|
|
|
|
||
|
Diluted:
|
|
|
|
|
|
|
|||||
|
Pro forma net income attributable to common stock
|
|
$
|
11,829,000
|
|
|
19,723,774
|
|
|
$
|
0.60
|
|
|
|
|
2012
|
|
2011
|
||||
|
General and administrative expenses
|
|
$
|
3,757,000
|
|
|
$
|
438,000
|
|
|
Stock-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties
|
|
2,537,000
|
|
|
106,000
|
|
||
|
Related income tax benefit
|
|
930,000
|
|
|
—
|
|
||
|
|
|
2012
|
||
|
Grant-date fair value
|
|
$
|
4.41
|
|
|
Expected volatility
|
|
40.0
|
%
|
|
|
Expected dividend yield
|
|
0.0
|
%
|
|
|
Expected term (in years)
|
|
3.8
|
|
|
|
Risk-free rate
|
|
0.33
|
%
|
|
|
|
|
|
|
Weighted Average
|
|
|
|||||||
|
|
|
|
|
Exercise
|
|
Remaining
|
|
Intrinsic
|
|||||
|
|
|
Options
|
|
Price
|
|
Term
|
|
Value
|
|||||
|
|
|
|
|
|
|
(In years)
|
|
|
|||||
|
Outstanding at December 31, 2011
|
|
—
|
|
|
$
|
—
|
|
|
|
|
|
||
|
Granted
|
|
850,000
|
|
|
$
|
17.50
|
|
|
|
|
|
||
|
Exercised
|
|
—
|
|
|
$
|
—
|
|
|
|
|
|
||
|
Outstanding at December 31, 2012
|
|
850,000
|
|
|
$
|
17.50
|
|
|
3.58
|
|
$
|
1,377,000
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Vested and Expected to vest at December 31, 2012
|
|
850,000
|
|
|
$
|
17.50
|
|
|
3.58
|
|
$
|
1,377,000
|
|
|
Exercisable at December 31, 2012
|
|
212,500
|
|
|
$
|
17.50
|
|
|
3.55
|
|
$
|
344,000
|
|
|
|
|
|
|
Weighted Average
|
|||
|
|
|
Restricted Stock
|
|
Grant-Date
|
|||
|
|
|
Awards & Units
|
|
Fair Value
|
|||
|
Unvested at December 31, 2011
|
|
—
|
|
|
$
|
—
|
|
|
Granted
|
|
279,046
|
|
|
$
|
17.50
|
|
|
Vested
|
|
(72,539
|
)
|
|
$
|
17.50
|
|
|
Forfeited
|
|
—
|
|
|
$
|
—
|
|
|
Unvested at December 31, 2012
|
|
206,507
|
|
|
$
|
17.50
|
|
|
Grants Made During the Months Ended
|
Membership Interest Granted
|
|
Exercise Price
|
|
Fair Value at Date of Grant
|
||||
|
April 2011
|
1.00%
|
|
$
|
3,600,000
|
|
|
$
|
1,453,000
|
|
|
August 2011
|
1.20%
|
|
6,000,000
|
|
|
1,384,000
|
|
||
|
September 2011
|
1.25%
|
|
5,900,000
|
|
|
1,533,000
|
|
||
|
November 2011
|
0.25%
|
|
1,250,000
|
|
|
288,000
|
|
||
|
|
3.70%
|
|
$
|
16,750,000
|
|
|
$
|
4,658,000
|
|
|
Expected term
|
5 years
|
|
Risk-free interest rate
|
0.96%
|
|
Expected volatility
|
45.5%
|
|
Expected dividend yield
|
0.00%
|
|
Deferred tax provision:
|
|
|
||
|
Deferred recognized at date of Merger - change in tax status of Predecessors
|
|
$
|
54,142,000
|
|
|
Deferred as a result of operations from October 11, 2012 through December 31, 2012
|
|
761,000
|
|
|
|
Total provision for income taxes
|
|
$
|
54,903,000
|
|
|
Income tax expense at the federal statutory rate (35%)
|
|
$
|
6,434,000
|
|
|
Deduction for pre-merger LLC earnings
|
|
(5,717,000
|
)
|
|
|
Income tax expense at 35% for period from October 11, 2012 through December 31, 2012
|
|
717,000
|
|
|
|
Income tax expense relating to change in tax status
|
|
54,142,000
|
|
|
|
State income tax
|
|
42,000
|
|
|
|
Non-deductible expenses
|
|
2,000
|
|
|
|
Provision for income taxes
|
|
$
|
54,903,000
|
|
|
Current:
|
|
|
||
|
Deferred tax assets
|
|
|
||
|
Derivative instruments
|
|
$
|
1,857,000
|
|
|
Total current deferred tax assets
|
|
1,857,000
|
|
|
|
Noncurrent:
|
|
|
||
|
Deferred tax assets
|
|
|
||
|
Net operating loss carryforwards (subject to 20 year expiration)
|
|
1,577,000
|
|
|
|
Stock based compensation
|
|
930,000
|
|
|
|
Total noncurrent deferred tax assets
|
|
2,507,000
|
|
|
|
Deferred tax liabilities
|
|
|
||
|
Oil and natural gas properties and equipment
|
|
64,636,000
|
|
|
|
Other
|
|
566,000
|
|
|
|
Total noncurrent deferred tax liabilities
|
|
65,202,000
|
|
|
|
Net noncurrent deferred tax liabilities
|
|
62,695,000
|
|
|
|
Net deferred tax liabilities
|
|
$
|
60,838,000
|
|
|
|
|
|
|
|
|
December 31,
|
|||||||
|
Description and Production Period
|
|
Volume (Bbls)
|
|
Original Strike Price (per Bbl)
|
|
2012
|
|
2011
|
|||||
|
|
|
|
Fair Value
Liability
|
|
Fair Value
Liability
|
||||||||
|
|
|
|
|||||||||||
|
Crude Oil Swaps:
|
|
|
|
|
|
|
|
|
|||||
|
January – November 2012
|
|
335,000
|
|
|
$78.50
|
|
$
|
—
|
|
|
$
|
6,833,000
|
|
|
December 2012
|
|
31,000
|
|
|
$78.50
|
|
302,000
|
|
|
594,000
|
|
||
|
January – December 2013
|
|
365,000
|
|
|
$80.55
|
|
4,614,000
|
|
|
5,545,000
|
|
||
|
|
|
|
|
|
|
|
|
December 31,
|
||||||
|
Description and Production Period
|
|
Volume (Bbls)
|
|
Original Strike Price (per Bbl)
|
|
Lock-in Price(per Bbl)
|
|
2012
|
|
2011
|
||||
|
|
|
|
|
Fair Value
Liability
|
|
Fair Value
Liability
|
||||||||
|
|
|
|
|
|
||||||||||
|
Crude Oil Swaps:
|
|
|
|
|
|
|
|
|
|
|
||||
|
December 2011
|
|
22,500
|
|
$82.90
|
|
$98.50–$102.20
|
|
$
|
—
|
|
|
$
|
379,000
|
|
|
January-November 2012
|
|
247,500
|
|
$85.07
|
|
$98.25–$101.80
|
|
—
|
|
|
3,554,000
|
|
||
|
December 2012
|
|
22,500
|
|
$85.07
|
|
$98.25–$101.80
|
|
323,000
|
|
|
323,000
|
|
||
|
|
|
|
|
|
|
|
|
December 31,
|
||||||
|
Description and Production Period
|
|
Volume (Bbls)
|
|
Original Strike Price (per Bbl)
|
|
Lock-in Price(per Bbl)
|
|
2012
|
|
2011
|
||||
|
|
|
|
|
Fair Value
Asset
|
|
Fair Value
Asset
|
||||||||
|
|
|
|
|
|
||||||||||
|
Crude Oil Swaps:
|
|
|
|
|
|
|
|
|
|
|
||||
|
December 2011
|
|
7,500
|
|
$82.90
|
|
$78.42
|
|
$
|
—
|
|
|
$
|
34,000
|
|
|
January-November 2012
|
|
82,500
|
|
$85.07
|
|
$80.52
|
|
—
|
|
|
375,000
|
|
||
|
December 2012
|
|
7,500
|
|
$85.07
|
|
$80.52
|
|
34,000
|
|
|
34,000
|
|
||
|
|
|
Year Ended December 31,
|
||||||||||
|
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
Unrealized gain (loss) on open non-hedge derivative instruments
|
|
$
|
8,057,000
|
|
|
$
|
(12,972,000
|
)
|
|
$
|
—
|
|
|
Loss on settlement of non-hedge derivative instruments
|
|
(5,440,000
|
)
|
|
(37,000
|
)
|
|
(148,000
|
)
|
|||
|
Gain (loss) on derivative instruments
|
|
$
|
2,617,000
|
|
|
$
|
(13,009,000
|
)
|
|
$
|
(148,000
|
)
|
|
|
|
Quoted Prices in Active Markets Level 1
|
|
Significant Other Observable Inputs
Level 2
|
|
Significant Unobservable Inputs
Level 3
|
|
Cash
Collateral
(1)
|
|
Net Fair Value
|
|||||||||||
|
Financial Liabilities
|
|
|
|||||||||||||||||||
|
|
|
December 31, 2012
|
|||||||||||||||||||
|
Derivative instruments
|
|
$
|
—
|
|
|
$
|
5,205,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5,205,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
|
|
December 31, 2011
|
|||||||||||||||||||
|
Derivative instruments
|
|
$
|
—
|
|
|
$
|
16,785,000
|
|
|
$
|
—
|
|
|
$
|
(2,326,000
|
)
|
|
$
|
14,459,000
|
|
|
|
(1)
|
Represents the impact of netting cash collateral with a counterparty with which the right of offset exists.
|
||||||||||||||||||||
|
Year Ending December 31,
|
|
Office and Equipment Leases
|
|
|||
|
|
|
|
|
|
||
|
2013
|
|
$
|
485,000
|
|
|
|
|
2014
|
|
491,000
|
|
|
||
|
2015
|
|
501,000
|
|
|
||
|
2016
|
|
412,000
|
|
|
||
|
2017
|
|
281,000
|
|
|
||
|
Thereafter
|
|
25,000
|
|
|
||
|
Total
|
|
$
|
2,195,000
|
|
|
|
|
|
|
For the years ended
|
||||||||||
|
|
|
December 31,
|
||||||||||
|
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
Rent Expense
|
|
$
|
547,000
|
|
|
$
|
74,000
|
|
|
$
|
—
|
|
|
Year Ending December 31,
|
|
Fracturing and Well Stimulation Service Agreements
|
|||
|
|
|
|
|
||
|
2013
|
|
$
|
14,400,000
|
|
|
|
2014
|
|
3,600,000
|
|
||
|
Total
|
|
$
|
18,000,000
|
|
|
|
|
|
Aggregate
|
|
|
|
|
|
|
|||
|
|
|
volumes (Bbls)
|
|
Swap Price
|
|
Contract Period
|
|||||
|
Fixed-Price Swap
|
|
365,000
|
|
|
$
|
109.70
|
|
|
May 2013
|
-
|
April 2014
|
|
|
|
December 31,
|
|||||||
|
|
|
2012
|
|
2011
|
|
||||
|
Oil and Natural Gas Properties:
|
|
|
|
|
|
||||
|
Proved properties
|
|
$
|
576,497,000
|
|
|
$
|
335,303,000
|
|
|
|
Unproved properties
|
|
121,245,000
|
|
|
4,528,000
|
|
|
||
|
Total Oil and Natural Gas Properties
|
|
697,742,000
|
|
|
339,831,000
|
|
|
||
|
Less Accumulated depreciation, depletion, amortization and impairment
|
|
(145,102,000
|
)
|
|
(119,366,000
|
)
|
|
||
|
Net oil and natural gas properties capitalized
|
|
$
|
552,640,000
|
|
|
$
|
220,465,000
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
|
|
|
|
|
|
|
||||||
|
Acquisition costs
|
|
|
|
|
|
|
||||||
|
Proved properties
|
|
$
|
115,760,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Unproved properties
|
|
117,395,000
|
|
|
3,704,000
|
|
|
9,930,000
|
|
|||
|
Development costs
|
|
106,261,000
|
|
|
75,374,000
|
|
|
48,817,000
|
|
|||
|
Exploration costs
|
|
17,547,000
|
|
|
11,226,000
|
|
|
3,920,000
|
|
|||
|
Capitalized asset retirement costs
|
|
948,000
|
|
|
297,000
|
|
|
222,000
|
|
|||
|
Total
|
|
$
|
357,911,000
|
|
|
$
|
90,601,000
|
|
|
$
|
62,889,000
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
|
|
|
|
|
|
|
||||||
|
Oil, natural gas and natural gas liquid sales
|
|
$
|
74,962,000
|
|
|
$
|
47,875,000
|
|
|
$
|
26,442,000
|
|
|
Lease operating expenses
|
|
(16,793,000
|
)
|
|
(10,597,000
|
)
|
|
(4,589,000
|
)
|
|||
|
Production taxes
|
|
(3,691,000
|
)
|
|
(2,366,000
|
)
|
|
(1,347,000
|
)
|
|||
|
Gathering and transportation
|
|
(424,000
|
)
|
|
(202,000
|
)
|
|
(106,000
|
)
|
|||
|
Depreciation, depletion, and amortization
|
|
(25,772,000
|
)
|
|
(15,377,000
|
)
|
|
(7,373,000
|
)
|
|||
|
Results of operations from oil, natural gas and natural gas liquids before income taxes
|
|
$
|
28,282,000
|
|
|
$
|
19,333,000
|
|
|
$
|
13,027,000
|
|
|
|
|
|
|
|
|
|
||||||
|
Pro forma information
|
|
|
|
|
|
|
||||||
|
Pro forma income tax
(1)
|
|
10,083,000
|
|
|
|
|
|
|||||
|
Pro forma results of operations
|
|
$
|
18,199,000
|
|
|
|
|
|
||||
|
(1
|
)
|
Diamondback Energy, Inc. was formed as a holding company on December 30, 2011, and did not conduct any material business operations prior to the Merger. Diamondback Energy, Inc. is a C-Corp under the Internal Revenue Code and is subject to income taxes. The Company computed a pro forma income tax provision as if the Company and the Predecessors were subject to income taxes since December 31, 2011. The pro forma tax provision has been calculated at a rate based upon a federal corporate level tax rate and a state tax rate, net of federal benefit, incorporating permanent differences.
|
|
|
|
|
|
Natural Gas
|
|
|
|||
|
|
|
Oil
|
|
Liquids
|
|
Natural Gas
|
|||
|
|
|
(Bbls)
|
|
(Bbls)
|
|
(Mcf)
|
|||
|
Proved Developed and Undeveloped Reserves:
|
|
|
|
|
|
|
|||
|
As of January 1, 2010
|
|
29,230,940
|
|
|
7,522,225
|
|
|
27,481,820
|
|
|
Extensions and discoveries
|
|
2,402,204
|
|
|
1,463,206
|
|
|
14,043,737
|
|
|
Revisions of previous estimates
|
|
(11,722,263
|
)
|
|
(3,072,486
|
)
|
|
(18,506,630
|
)
|
|
Purchase of reserves in place
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Production
|
|
(280,721
|
)
|
|
(79,978
|
)
|
|
(323,847
|
)
|
|
Sales of reserves in place
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|||
|
As of December 31, 2010
|
|
19,630,160
|
|
|
5,832,967
|
|
|
22,695,080
|
|
|
|
|
|
|
|
|
|
|||
|
Extensions and discoveries
|
|
1,799,175
|
|
|
466,538
|
|
|
1,884,192
|
|
|
Revisions of previous estimates
|
|
(2,879,429
|
)
|
|
(1,163,130
|
)
|
|
(3,614,167
|
)
|
|
Purchase of reserves in place
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Production
|
|
(449,433
|
)
|
|
(86,815
|
)
|
|
(413,640
|
)
|
|
Sales of reserves in place
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|||
|
As of December 31, 2011
|
|
18,100,473
|
|
|
5,049,560
|
|
|
20,551,465
|
|
|
|
|
|
|
|
|
|
|||
|
Extensions and discoveries
|
|
3,106,433
|
|
|
869,741
|
|
|
3,759,684
|
|
|
Revisions of previous estimates
|
|
(1,464,243
|
)
|
|
(5,811
|
)
|
|
383,335
|
|
|
Purchase of reserves in place
|
|
7,210,482
|
|
|
2,521,053
|
|
|
10,709,180
|
|
|
Production
|
|
(756,286
|
)
|
|
(183,114
|
)
|
|
(833,516
|
)
|
|
Sales of reserves in place
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|||
|
As of December 31, 2012
|
|
26,196,859
|
|
|
8,251,429
|
|
|
34,570,148
|
|
|
|
|
|
|
|
|
|
|||
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|||
|
January 1, 2010
|
|
1,954,060
|
|
|
591,532
|
|
|
2,453,750
|
|
|
December 31, 2010
|
|
3,371,460
|
|
|
1,126,431
|
|
|
4,336,720
|
|
|
December 31, 2011
|
|
3,949,099
|
|
|
1,263,711
|
|
|
5,285,945
|
|
|
December 31, 2012
|
|
7,189,367
|
|
|
2,999,440
|
|
|
12,864,941
|
|
|
|
|
|
|
|
|
|
|||
|
Proved Undeveloped Reserves:
|
|
|
|
|
|
|
|||
|
January 1, 2010
|
|
27,276,880
|
|
|
6,930,693
|
|
|
25,028,070
|
|
|
December 31, 2010
|
|
16,258,700
|
|
|
4,706,536
|
|
|
18,358,360
|
|
|
December 31, 2011
|
|
14,151,375
|
|
|
3,785,850
|
|
|
15,265,520
|
|
|
December 31, 2012
|
|
19,007,492
|
|
|
5,251,989
|
|
|
21,705,207
|
|
|
|
|
December 31,
|
||||||||||
|
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
Future cash inflows
|
|
$
|
2,769,485,000
|
|
|
$
|
2,049,520,000
|
|
|
$
|
1,856,294,000
|
|
|
Future development costs
|
|
(541,445,000
|
)
|
|
(410,350,000
|
)
|
|
(398,305,000
|
)
|
|||
|
Future production costs
|
|
(773,611,000
|
)
|
|
(497,808,000
|
)
|
|
(384,916,000
|
)
|
|||
|
Future production taxes
|
|
(140,758,000
|
)
|
|
(104,856,000
|
)
|
|
(126,090,000
|
)
|
|||
|
Future income tax expenses
|
|
(334,903,000
|
)
|
|
—
|
|
|
—
|
|
|||
|
|
|
|
|
|
|
|
||||||
|
Future net cash flows
|
|
978,768,000
|
|
|
1,036,506,000
|
|
|
946,983,000
|
|
|||
|
10% discount to reflect timing of cash flows
|
|
(611,548,000
|
)
|
|
(671,894,000
|
)
|
|
(607,982,000
|
)
|
|||
|
|
|
|
|
|
|
|
||||||
|
Standardized measure of discounted future net cash flows
|
|
$
|
367,220,000
|
|
|
$
|
364,612,000
|
|
|
$
|
339,001,000
|
|
|
|
|
December 31,
|
||||||||||
|
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
|
|
Unweighted Arithmetic Average
|
||||||||||
|
|
|
First-Day-of-the-Month Prices
|
||||||||||
|
Oil (per Bbl)
|
|
$
|
88.13
|
|
|
$
|
93.09
|
|
|
$
|
77.61
|
|
|
Natural gas (per Mcf)
|
|
$
|
2.86
|
|
|
$
|
3.91
|
|
|
$
|
4.14
|
|
|
Natural gas liquids (per Bbl)
|
|
$
|
43.88
|
|
|
$
|
56.33
|
|
|
$
|
40.74
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
Standardized measure of discounted future net cash flows at the beginning of the period
|
|
$
|
364,612,000
|
|
|
$
|
339,001,000
|
|
|
$
|
392,919,000
|
|
|
Sales of oil and natural gas, net of production costs
|
|
(54,208,000
|
)
|
|
(34,711,000
|
)
|
|
(20,401,000
|
)
|
|||
|
Purchase of minerals in place
|
|
107,897,000
|
|
|
—
|
|
|
—
|
|
|||
|
Extensions and discoveries, net of future development costs
|
|
79,293,000
|
|
|
73,571,000
|
|
|
59,414,000
|
|
|||
|
Previously estimated development costs incurred during the period
|
|
88,849,000
|
|
|
87,530,000
|
|
|
52,932,000
|
|
|||
|
Net changes in prices and production costs
|
|
(76,515,000
|
)
|
|
82,364,000
|
|
|
178,198,000
|
|
|||
|
Changes in estimated future development costs
|
|
8,309,000
|
|
|
(82,855,000
|
)
|
|
(23,992,000
|
)
|
|||
|
Revisions of previous quantity estimates
|
|
(22,882,000
|
)
|
|
(98,533,000
|
)
|
|
(292,306,000
|
)
|
|||
|
Sales of reserves in place, net of future development costs
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
|
Accretion of discount
|
|
36,461,000
|
|
|
33,900,000
|
|
|
39,292,000
|
|
|||
|
Net change in income taxes
|
|
(125,542,000
|
)
|
|
—
|
|
|
—
|
|
|||
|
Net changes in timing of production and other
|
|
(39,054,000
|
)
|
|
(35,655,000
|
)
|
|
(47,055,000
|
)
|
|||
|
|
|
|
|
|
|
|
||||||
|
Standardized measure of discounted future net cash flows at the end of the period
|
|
$
|
367,220,000
|
|
|
$
|
364,612,000
|
|
|
$
|
339,001,000
|
|
|
|
|
2012
|
|
||||||||||||||
|
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
||||||||
|
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
||||||||
|
Revenues
|
|
$
|
16,351,000
|
|
|
$
|
16,030,000
|
|
|
$
|
16,814,000
|
|
|
$
|
25,767,000
|
|
|
|
Income from operations
|
|
6,737,000
|
|
|
4,307,000
|
|
|
4,086,000
|
|
|
2,177,000
|
|
|
||||
|
Income tax expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
54,903,000
|
|
|
||||
|
Net income (loss)
|
|
$
|
1,477,000
|
|
|
$
|
13,624,000
|
|
|
$
|
452,000
|
|
|
$
|
(52,074,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
|
Pro forma information
|
|
|
|
|
|
|
|
|
|
||||||||
|
Income before income taxes
|
|
$
|
1,477,000
|
|
|
$
|
13,624,000
|
|
|
$
|
452,000
|
|
|
$
|
2,829,000
|
|
|
|
Pro forma provision for income taxes
|
|
526,000
|
|
|
4,857,000
|
|
|
161,000
|
|
|
1,009,000
|
|
|
||||
|
Pro forma net income
|
|
$
|
951,000
|
|
|
$
|
8,767,000
|
|
|
$
|
291,000
|
|
|
$
|
1,820,000
|
|
|
|
Pro forma earnings per share:
|
|
|
|
|
|
|
|
|
|
||||||||
|
Basic
|
|
$
|
0.06
|
|
|
$
|
0.60
|
|
|
$
|
0.02
|
|
|
$
|
0.05
|
|
|
|
Diluted
|
|
$
|
0.06
|
|
|
$
|
0.60
|
|
|
$
|
0.02
|
|
|
$
|
0.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
|
|
|
2011
|
|
||||||||||||||
|
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
||||||||
|
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
||||||||
|
Revenues
|
|
$
|
12,087,000
|
|
|
$
|
11,572,000
|
|
|
$
|
11,216,000
|
|
|
$
|
14,491,000
|
|
|
|
Income from operations
|
|
3,328,000
|
|
|
4,067,000
|
|
|
2,928,000
|
|
|
4,824,000
|
|
|
||||
|
Net income (loss)
|
|
$
|
2,824,000
|
|
|
$
|
3,453,000
|
|
|
$
|
2,205,000
|
|
|
$
|
(8,868,000
|
)
|
|
|
Exhibit
Number
|
|
Description
|
|
|
|
|
|
3.1
|
|
Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
|
|
3.2
|
|
Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
|
|
4.1
|
|
Specimen certificate for shares of common stock, par value $0.01 per share, of the Company (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
|
|
4.2
|
|
Registration Rights Agreement, dated as of October 11, 2012, by and between the Company and DB Energy Holdings LLC (incorporated by reference to Exhibit 4.2 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
|
|
4.3
|
|
Investor Rights Agreement, dated as of October 11, 2012, by and between the Company and Gulfport Energy Corporation (incorporated by reference to Exhibit 4.3 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
|
|
10.1+
|
|
Equity Incentive Plan (incorporated by reference to Exhibit 10.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
|
|
10.2+
|
|
Form of Stock Option Agreement (incorporated by reference to Exhibit 10.13 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
|
|
10.3+
|
|
Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.14 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
|
|
10.4+
|
|
Form of Director and Officer Indemnification Agreement (incorporated by reference to Exhibit 10.15 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
|
|
10.5
|
|
Advisory Services Agreement, dated as of October 11, 2012, by and between Diamondback Energy, Inc. and Wexford Capital LP (incorporated by reference to Exhibit 10.4 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
|
|
10.6
|
|
Merger Agreement, dated as of October 11, 2012, by and between the Company and Diamondback Energy LLC (incorporated by reference to Exhibit 10.5 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
|
|
10.7+
|
|
Amended and Restated Employment Agreement, dated as of August 20, 2012, by and between Travis Stice and Windsor Permian LLC (incorporated by reference to Exhibit 10.29 to Amendment No. 5 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on October 2, 2012).
|
|
10.8+
|
|
First Amendment effective as of January 1, 2013 to the Amended and Restated Employment Agreement dated as of August 20, 2012 by and between Travis Stice and Windsor Permian LLC, as subsequently assigned to Diamondback E&P LLC (incorporated by reference to Exhibit 10.3 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 1, 2013).
|
|
10.9+
|
|
Amended and Restated Employment Agreement, dated as of January 1, 2012, by and between Teresa Dick and Windsor Permian LLC (incorporated by reference to Exhibit 10.30 to Amendment No. 3 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on July 5, 2012).
|
|
10.10+
|
|
First Amendment effective as of January 1, 2013 to the Amended and Restated Employment Agreement dated as of August 20, 2012 by and between Teresa Dick and Windsor Permian LLC, as subsequently assigned to Diamondback E&P LLC (incorporated by reference to Exhibit 10.4 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 1, 2013).
|
|
10.11+
|
|
Amended and Restated Employment Agreement, dated as of January 1, 2012, by and between Jeff White and Windsor Permian LLC (incorporated by reference to Exhibit 10.31 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
|
|
Exhibit
Number
|
|
Description
|
|
10.12+
|
|
First Amendment effective as of January 1, 2013 to the Amended and Restated Employment Agreement dated as of August 20, 2012 by and between Jeff White and Windsor Permian LLC, as subsequently assigned to Diamondback E&P LLC (incorporated by reference to Exhibit 10.5 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 1, 2013).
|
|
10.13
|
|
Amended and Restated Credit Agreement, dated July 24, 2012, by and among Diamondback Energy LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.33 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
|
|
10.14
|
|
First Amendment to Credit Agreement, dated July 31, 2012, by and among Diamondback Energy LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.34 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
|
|
10.15
|
|
Lease Agreement, dated as of April 19, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.7 to Amendment No. 2 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on June 11, 2012).
|
|
10.16
|
|
Lease Amendment No. 1 to Lease Agreement, dated as of June 6, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
|
|
10.17
|
|
Lease Amendment No. 2 to Lease Agreement, dated as of August 5, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.9 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
|
|
10.18
|
|
Lease Amendment No. 3 to Lease Agreement, dated as of September 28, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
|
|
10.19
|
|
Lease Amendment No. 4 to Lease Agreement, dated February 6, 2012, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.11 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
|
|
10.20
|
|
Lease Amendment No. 5 to Lease Agreement, dated as of July 25, 2012, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.36 to Amendment No. 5 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on October 2, 2012).
|
|
10.21
|
|
Contribution Agreement, dated May 7, 2012, by and between the Company and Gulfport Energy Corporation (incorporated by reference to Exhibit 10.18 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
|
|
10.22
|
|
Master Drilling Agreement, dated January 1, 2012, by and between Windsor Permian LLC and Bison Drilling and Field Services LLC (incorporated by reference to Exhibit 10.19 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
|
|
10.23
|
|
Gas Purchase Agreement, dated May 1, 2009, by and between Windsor Permian LLC and Feagan Gathering Company (incorporated by reference to Exhibit 10.20 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
|
|
10.24
|
|
Amendment to Gas Purchase Agreement, dated July 1, 2011, by and between Windsor Permian LLC and MidMar Gas LLC (incorporated by reference to Exhibit 10.21 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
|
|
10.25
|
|
Amendment to Gas Purchase Agreement, dated January 11, 2012, by and between Windsor Permian LLC and MidMar Gas LLC (incorporated by reference to Exhibit 10.22 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
|
|
Exhibit
Number
|
|
Description
|
|
10.26
|
|
Shared Services Agreement, dated January 1, 2012 by and between Windsor Permian LLC and Everest Operations Management LLC (incorporated by reference to Exhibit 10.23 to Amendment No. 2 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on June 11, 2012).
|
|
10.27
|
|
Subordinated note made by Windsor Permian LLC in favor of Lambda Investors LLC, dated May 14, 2012 (incorporated by reference to Exhibit 10.23 to Amendment No. 2 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on June 11, 2012).
|
|
10.28
|
|
First Amendment to Subordinated Note made by Windsor Permian LLC in favor of Lambda Investors LLC, dated September 28, 2012 (incorporated by reference to Exhibit 10.35 to Amendment No. 5 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on October 2, 2012).
|
|
10.29
|
|
Crude Oil Purchase Agreement, dated May 24, 2012, by and between Windsor Permian LLC and Shell Trading (US) Company (incorporated by reference to Exhibit 10.26 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
|
|
10.30
|
|
Shared Services Agreement, dated as of March 1, 2008, by and between Windsor Energy Resources LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.6 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
|
|
10.31
|
|
Office Lease Agreement, dated June 8, 2012, by and between Windsor Permian LLC and Caliber Investment Group LLC (incorporated by reference to Exhibit 10.27 to Amendment No. 3 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on July 5, 2012).
|
|
10.32
|
|
Assignment and Assumption of Office Lease Agreement, effective June 1, 2012, by and between Windsor Permian LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.28 to Amendment No. 3 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on July 5, 2012).
|
|
10.33
|
|
Master Drilling Agreement, effective as of January 1, 2013, by and between Diamondback E&P LLC and Bison Drilling and Field Services LLC (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 1, 2013).
|
|
10.34
|
|
Master Field Services Agreement, effective as of January 1, 2013, by and between Diamondback E&P LLC and Bison Drilling and Field Services LLC (incorporated by reference to Exhibit 10.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 1, 2013).
|
|
10.35*
|
|
First Amendment to Master Field Services Agreement, dated as of February 21, 2013, by and between Diamondback E&P LLC and Bison Drilling and Field Services LLC.
|
|
21.1*
|
|
List of Significant Subsidiaries of the Company.
|
|
31.1*
|
|
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
|
|
31.2*
|
|
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
|
|
32.1++
|
|
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
|
|
32.2++
|
|
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
|
|
99.1*
|
|
Report of Ryder Scott Company, L.P.
|
|
101.INS**
|
|
XBRL Instance Document.
|
|
101.SCH**
|
|
XBRL Taxonomy Extension Schema Document.
|
|
101.CAL**
|
|
XBRL Taxonomy Extension Calculation Linkbase.
|
|
101.DEF**
|
|
XBRL Taxonomy Extension Definition Linkbase Document.
|
|
101.LAB**
|
|
XBRL Taxonomy Extension Labels Linkbase Document.
|
|
Exhibit
Number
|
|
Description
|
|
101.PRE**
|
|
XBRL Taxonomy Extension Presentation Linkbase Document.
|
|
*
|
Filed herewith.
|
|
**
|
Furnished herewith. Pursuant to Rule 406T of Regulation S-T, these interactive data files are being furnished herewith and are not deemed filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are not deemed filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under these sections.
|
|
+
|
Management contract, compensatory plan or arrangement.
|
|
++
|
The certifications attached as Exhibit 32.1 and Exhibit 32.2 accompany this Annual Report on Form 10-K pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.
|
No information found
* THE VALUE IS THE MARKET VALUE AS OF THE LAST DAY OF THE QUARTER FOR WHICH THE 13F WAS FILED.
| FUND | NUMBER OF SHARES | VALUE ($) | PUT OR CALL |
|---|
| DIRECTORS | AGE | BIO | OTHER DIRECTOR MEMBERSHIPS |
|---|
No information found
No Customers Found
No Suppliers Found
Price
Yield
| Owner | Position | Direct Shares | Indirect Shares |
|---|