S-1/A 1 d295327ds1a.htm AMENDMENT NO. 1 TO FORM S-1 Amendment No. 1 to Form S-1
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As filed with the Securities and Exchange Commission on May 7, 2012

Registration No. 333-179502

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

AMENDMENT NO. 1

to

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Diamondback Energy, Inc.

(Exact name of registrant as specified in its charter)

 

Delaware   1311   45-4502447

(State or other jurisdiction of

incorporation or organization)

  (Primary Standard Industrial Classification Code Number)  

(I.R.S. Employer

Identification Number)

 

 

500 West Texas

Suite 1225

Midland, Texas 79701

(432) 221-7400

(Address, including zip code and telephone number, including area code, of registrant’s principal executive offices)

 

 

Teresa Dick

Chief Financial Officer

Diamondback Energy, Inc.

14301 Caliber Drive

Suite 300

Oklahoma City, Oklahoma 73134

(405) 463-6900

(Name, address, including zip code and telephone number, including area code, of agent for service)

 

 

Copies to:

Seth R. Molay, P.C.

Akin Gump Strauss Hauer & Feld LLP

1700 Pacific Avenue, Suite 4100

Dallas, TX 75201

(214) 969-4780

 

J. Michael Chambers

Keith Benson

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, TX 77002

(713) 546-7416

 

 

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement is declared effective.

If any securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, as amended (the “Securities Act”), check the following box.  ¨

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer   ¨      Accelerated filer   ¨
Non-accelerated filer   x    (Do not check if a smaller reporting company)   Smaller reporting company   ¨

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act or until this Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

 

 

 


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The information in this prospectus is not complete and may be changed. We and the selling stockholders may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and we and the selling stockholders are not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

 

SUBJECT TO COMPLETION, DATED MAY 7, 2012.

PROSPECTUS

             Shares

 

LOGO

Diamondback Energy, Inc.

Common Stock

 

 

We are selling              shares of common stock and the selling stockholders are selling              shares of common stock. We will not receive any of the proceeds from the shares of common stock sold by the selling stockholders.

Prior to this offering, there has been no public market for our common stock. The initial public offering price of the common stock is expected to be between $         and $         per share. We have applied to list our common stock on The NASDAQ Global Market under the symbol “FANG.”

We and the selling stockholders granted the underwriters an option to purchase up to an aggregate of              additional shares of our common stock to cover the underwriters’ option to purchase additional shares.

We are an “emerging growth company” under applicable Securities and Exchange Commission rules and will be subject to reduced public company reporting requirements. Investing in our common stock involves risks. See “Risk Factors” beginning on page 14.

 

   

Price to
Public

  

Underwriting
Discounts and
Commissions

 

Proceeds to
Diamondback

 

Proceeds to
Selling

Stockholders

Per Share

  $                $               $               $            

Total

  $                    $                   $                   $                

Delivery of the shares of common stock will be made on or about                     , 2012.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

Credit Suisse

The date of this prospectus is                     , 2012.


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ABOUT THIS PROSPECTUS

You should rely only on the information contained in this prospectus. We have not, and the selling stockholders and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. We, the selling stockholders and the underwriters are only offering to sell, and only seeking offers to buy, our common stock in jurisdictions where offers and sales are permitted.

The information contained in this prospectus is accurate and complete only as of the date of this prospectus, regardless of the time of delivery of this prospectus or of any sale of our common stock by us, the selling stockholders or the underwriters. Our business, financial condition, results of operations and prospects may have changed since that date.

Dealer Prospectus Delivery Obligation

Until                      (25 days after the commencement of the offering), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

Industry and Market Data

This prospectus includes industry data and forecasts that we obtained from internal company surveys, publicly available information and industry publications and surveys. Our internal research and forecasts are based on management’s understanding of industry conditions, and such information has not been verified by independent sources. Industry publications and surveys generally state that the information contained therein has been obtained from sources believed to be reliable.

Unless the context otherwise requires, the information in this prospectus (other than in the historical financial statements) assumes that the underwriters will not exercise their option to purchase additional shares.

 

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PROSPECTUS SUMMARY

This summary contains basic information about us and the offering. Because it is a summary, it does not contain all the information that you should consider before investing in our common stock. Except as expressly noted otherwise, the historical assets, operations and results described in this prospectus are those of Windsor Permian LLC, or Windsor Permian, an entity controlled by Wexford Capital LP, or Wexford. Prior to the closing of this offering, Wexford will cause all of the outstanding equity interests in Windsor Permian to be contributed to us in exchange for shares of our common stock and Windsor Permian will become our wholly-owned subsidiary. On May 7, 2012, we entered into a contribution agreement with Gulfport Energy Corporation, or Gulfport, in which Gulfport, agreed to contribute to us, subject to certain conditions, all of its oil and natural gas interests in the Permian Basin in exchange for shares of our common stock and a promissory note. In addition, Wexford has agreed to cause all of the outstanding equity interests in Windsor UT LLC, or Windsor UT, to be contributed to Windsor Permian prior to the time Windsor Permian is contributed to us. Windsor UT owns oil and natural gas interests in the Permian Basin. In this prospectus, we refer to the Gulfport contribution and the Windsor UT contribution together as the Contributions. See “Summary—The Contributions” beginning on page 6 of this prospectus for more information regarding the Contributions. Except as expressly noted otherwise, references to our operations and assets as of March 31, 2012 and thereafter give effect to the Contributions. You should read and carefully consider this entire prospectus before making an investment decision, especially the information presented under the heading “Risk Factors” and our financial statements and the accompanying notes included elsewhere in this prospectus, as well as the other documents to which we refer you. We have provided definitions for some of the oil and natural gas industry terms used in this prospectus in the “Glossary of Oil and Natural Gas Terms.”

DIAMONDBACK ENERGY, INC.

Overview

We are an independent oil and natural gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. This basin, which is one of the major producing basins in the United States, is characterized by an extensive production history, a favorable operating environment, mature infrastructure, long reserve life, multiple producing horizons, enhanced recovery potential and a large number of operators.

We began operations in December 2007 with our acquisition of 4,174 net acres with production at the time of acquisition of approximately 800 net barrels of oil equivalent, or BOE, per day from 33 gross (16.5 net) wells in the Permian Basin. Subsequently, we acquired approximately 25,851 additional net acres, which brought our total net acreage position in the Permian Basin to 30,025 net acres at March 31, 2012 and, after giving effect to the Contributions, we had 49,703 net acres. We are the operator of approximately 99% of this acreage. As of March 31, 2012, after giving effect to the Contributions, we had drilled 147 gross (136 net) wells, and participated in an additional 11 gross (five net) non-operated wells, in the Permian Basin. Of these 158 gross wells, 149 were completed as producing wells and nine are in various stages of completion. In the aggregate, as of March 31, 2012, we held interests in 182 gross (166 net) producing wells in the Permian Basin.

Our activities are primarily focused on the Clearfork, Spraberry, Wolfcamp, Cline, Strawn and Atoka formations, which we refer to collectively as the Wolfberry play. The Wolfberry play is characterized by high oil and liquids rich natural gas, multiple vertical and horizontal target horizons, extensive production history, long-lived reserves and high drilling success rates. The Wolfberry play is a modification and extension of the Spraberry play, the majority of which is designated in the Spraberry trend area field. According to the U.S. Energy Information Administration, the Spraberry trend area ranks as the second largest oilfield in the United States, based on 2009 reserves.

 

 

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As of December 31, 2011, our estimated proved oil and natural gas reserves, pro forma for the Contributions, were 39,460 MBOE based on reserve reports prepared by Ryder Scott Company L.P., or Ryder Scott, our independent reserve engineers. Of these reserves, approximately 21.7% are classified as proved developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate are from 329 gross well locations on 40-acre spacing. As of December 31, 2011, these proved reserves were approximately 67% oil, 20% natural gas liquids and 13% natural gas.

We have 977 identified potential vertical drilling locations on 40-acre spacing based on our evaluation of applicable geologic and engineering data and we have an additional 1,162 identified potential vertical drilling locations based on 20-acre downspacing. These identified potential drilling locations do not include any potential horizontal drilling locations. We intend to grow our reserves and production through development drilling, exploitation and exploration activities on this multi-year project inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves. Our estimated ultimate recoveries, or EURs, from future PUD wells, as estimated by Ryder Scott, range from 89 MBOE to 147 MBOE per well, with an average EUR per well of 127 MBOE. Our 2012 drilling plan currently contemplates drilling 72 gross (65 net) vertical wells and nine gross (eight net) horizontal wells in the Wolfberry play. We are currently using four drilling rigs and intend to add two additional rigs later in 2012.

We believe the experience gained from our historical drilling programs and the information obtained from the results of extensive industry drilling activity in the Permian Basin have helped us reduce the risk and uncertainity associated with drilling vertical wells on our Permian Basin acreage. We intend to supplement our vertical development drilling activity with horizontal wells targeting various intervals in the Wolfberry play. Our horizontal drilling program is intended to further capture the upside potential that may exist on our properties and increase our well performance and recoveries as compared to drilling vertical wells alone.

During 2011, we assembled a new executive team and, beginning with the fourth quarter of 2011, this team assumed management control of our operations and development activities in the Permian Basin. With an average of approximately 26 years of industry experience per person, this team has extensive experience in the Permian Basin as well as other resource plays in North America, including significant experience in drilling and completing horizontal wells. Under the direction of our new executive team, the average drilling time required to reach total depth, or TD, was shortened by 25% to 15 days during the fourth quarter of 2011 from 20 days during the second quarter of 2011, reducing average drilling costs (excluding completion costs) by 8.3% from $1.2 million to $1.1 million period-to-period, while also decreasing the time from spud to spud to 23 days from 25 days. Also, during the quarter ended March 31, 2012 our average daily production, pro forma for the Contributions, was 3,280 BOE/d, an increase of 11%, or 333 BOE/d, from 2,947 BOE/d for the quarter ended December 31, 2011. This increase was due primarily to improved strategies and procedures introduced by our new executive team relating to wellbore configuration, completion, execution, fluid recovery and well pumping practices that significantly reduced the level of required well remediation and the associated loss of production. We anticipate further increases in efficiencies as our new executive team executes on our development strategies across our acreage base.

 

 

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The following table provides a summary of selected operating information of our properties, pro forma for the Contributions. The information is as of March 31, 2012 except as otherwise noted.

 

     Net
Acreage
     Average
Working
Interest
    Identified Potential
Drilling Locations(1)
     2012 Budget      Estimated Net Proved
Reserves at
December 31, 2011
     Average
Daily
Production
(BOE/d)(3)
 

Basin

            Gross              Net          Gross
Wells(2)
     Net
Wells(2)
     Capex
(In millions)
     MBOE      %
Developed
    

Permian

     49,703         86.2     977         926         90         75       $ 180.0         39,460         24         3,378   

 

(1) Reflects identified potential vertical drilling locations on 40-acre spacing based on our evaluation of applicable geologic and engineering data. We have an additional 1,162 potential vertical drilling locations based on 20-acre downspacing. These identified potential drilling locations do not include any potential horizontal drilling locations. The drilling locations on which we actually drill wells will ultimately depend on the availability of capital, regulatory approvals, oil and natural gas prices, costs, actual drilling results and other factors.
(2) Includes 81 gross (72 net) wells for which we are the operator and nine gross (three net) non-operated wells.
(3) During February 2012.

Our current exploration and development budget for our oil and natural gas properties for the year ending December 31, 2012 is approximately $180.0 million. In 2012, we plan to spend approximately $158.0 million on the drilling and completion of 72 gross (65 net) operated vertical wells and nine gross (eight net) horizontal wells, $8.0 million for the drilling and completion of nine non-operated wells, $8.0 million for leasehold acquisitions and $6.0 million for the construction of infrastructure to support production, including investments in water disposal infrastructure and gathering line projects.

Our Business Strategy

Our business strategy is to increase stockholder value through the following:

 

   

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 March 31, 2012, after giving effect to the Contributions, we had 977 identified potential vertical drilling locations on our acreage in the Permian Basin based on 40-acre spacing and an additional 1,162 such locations based on 20-acre downspacing. We believe the drilling of these locations will provide us with the critical subsurface data necessary to target potential horizontal horizons. Our 2012 drilling plan currently contemplates drilling 72 gross (65 net) vertical wells and nine gross (eight net) horizontal wells in the Wolfberry play. We ended 2011 with a two rig drilling program and are currently using four drilling rigs. We intend to add two additional rigs later in the year. Subject to market conditions and rig availability, we expect to operate up to eight rigs in 2013, which we expect will allow us to significantly increase our drilling program in 2013.

 

   

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 and we currently plan to drill nine gross (eight net) horizontal wells in 2012 to target these producing horizons. Our 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.

 

 

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Focus on enhancing advanced drilling and completion techniques to maximize recovery. Our eight member executive team, which has an average of approximately 26 years of industry experience per person, intends to continue to seek ways to maximize hydrocarbon recovery by refining and enhancing our drilling and completion techniques. The time to reach TD for our vertical Wolfberry wells decreased from an average of 20 days during the second quarter of 2011 to an average of 15 days during the fourth quarter of 2011, resulting in a lower total well cost. Our focus on efficient drilling and completion techniques, and the resulting 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 new 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.

 

   

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 86.2% working interest in our acreage pro forma for the Contributions allows us to realize the majority of the benefits of these expected improvements and cost efficiencies.

 

   

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.

 

   

Maintain Financial flexibility. We seek to maintain a conservative financial position. As of December 31, 2011, on a pro forma basis after giving effect to this offering and the use of the net proceeds from this offering to repay borrowings under our revolving credit facility, we would have had approximately $             million of available borrowing capacity under such facility. We expect that we will fund our capital development plans for 2012 from our operating cash flow, proceeds from this offering and borrowings under our revolving credit facility.

Our Strengths

We believe that the following strengths will help us achieve our business goals:

 

   

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. As of April 27, 2012, the Baker Hughes Rig Count survey reported that there were 510 rigs drilling in the Permian Basin. 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.

 

 

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Our production for the year ended December 31, 2011 was approximately 74% oil, 15% natural gas liquids and 11% natural gas. As of December 31, 2011, our estimated net proved reserves were comprised of approximately 68% oil and 19% natural gas liquids. This oil and liquids exposure allows us to benefit from their currently more favorable prices as compared to natural gas.

 

   

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 March 31, 2012, after giving effect to the Contributions, we had 977 identified potential vertical drilling locations based on 40-acre spacing and an additional 1,162 identified potential vertical drilling locations based on 20-acre downspacing. In 2012, after giving effect to the Contributions, we anticipate drilling 72 gross (65 net) vertical operated wells and nine gross (eight net) horizontal operated wells, which represent only approximately 7.4% of our identified potential vertical drilling locations at March 31, 2012. We also believe that there are multiple horizontal locations that could be drilled on our acreage. In addition, the liquids rich natural gas component of our inventory adds value with Btu content ranging from 1,243 MMBtu to 1,578 MMBtu and our March 2012 natural gas liquids yield was 125 Bbls/MMcf. In addition, we have approximately 117 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.

 

   

Experienced, incentivized and proven management team. Our new executive team has an average of approximately 26 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 future development plans to include horizontal drilling. Prior to joining us, our Chief Executive Officer held management positions at Apache Corporation, Laredo Petroleum Holdings, Inc. and Burlington Resources.

 

   

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 over 400,000 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.

 

   

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 processees. This operating control also enables us to obtain data needed for efficient exploration of horizontal prospects.

 

   

Financial flexibility to fund expansion. Upon the completion of this offering, we will 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, 2011, on a pro forma basis after giving effect to this offering and the use of the net proceeds from this offering to repay borrowings under our revolving credit facility, we would have had approximately $             million of available borrowing capacity under our revolving credit facility. We expect that our borrowing base will be increased as a result of the Contributions.

 

 

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Risk Factors

Investing in our common stock involves risks that include the speculative nature of oil and natural gas exploration, competition, volatile oil and natural gas prices and other material factors. You should read carefully the section of this prospectus entitled “Risk Factors” beginning on page 14 for an explanation of these risks before investing in our common stock. In particular, the following considerations may offset our competitive strengths or have a negative effect on our strategy or operating activities, which could cause a decrease in the price of our common stock and a loss of all or part of your investment:

 

   

Our business is difficult to evaluate because of our limited operating history.

 

   

Difficulties managing the growth of our business may adversely affect our financial condition and results of operations.

 

   

Failure to develop our undeveloped acreage could adversely affect our future cash flow and income.

 

   

Our exploration and development operations require substantial capital that we may be unable to obtain, which could lead to a loss of properties and a decline in our reserves.

 

   

Our future success depends on our ability to find, develop or acquire additional oil and natural gas reserves.

 

   

The volatility of oil and natural gas prices due to factors beyond our control greatly affects our profitability.

 

   

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present values of our reserves.

 

   

Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with a concentration of operations in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.

 

   

We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could limit our access to suitable markets for the oil and natural gas we produce.

 

   

Our operations are subject to various governmental regulations which require compliance that can be burdensome and expensive.

 

   

Any failure by us to comply with applicable environmental laws and regulations, including those relating to hydraulic fracturing, could result in governmental authorities taking actions that adversely affect our operations and financial condition.

 

   

Our operations are subject to operational hazards for which we may not be adequately insured.

 

   

Our failure to successfully identify, complete and integrate future acquisitions of properties or businesses could reduce our earnings and slow our growth.

 

   

Our largest stockholder controls a significant percentage of our common stock and its interests may conflict with yours.

For a discussion of other considerations that could negatively affect us, see “Risk Factors” beginning on page 14 and “Cautionary Note Regarding Forward-Looking Statements” on page 41 of this prospectus.

The Contributions

On May 7, 2012, we entered into a contribution agreement with Gulfport in which Gulfport agreed to contribute to us, prior to the closing of this offering, all of its oil and natural gas interests in the Permian Basin in exchange for (i)              shares of our common stock, which will represent 35% of our outstanding

 

 

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common stock immediately prior to the closing of this offering and (ii) approximately $63.6 million in the form of a non-interest bearing promissory note, which we refer to as the Gulfport contribution note, that will be repaid in full upon the closing of this offering with a portion of the net proceeds from this offering. We are the operator of the acreage to be contributed to us by Gulfport. The aggregate consideration payable to Gulfport is subject to a post-closing cash adjustment based on changes in our working capital, long-term debt and certain other items identified in the contribution agreement as of the date of the contribution. Gulfport’s obligation to make this contribution is contingent upon, among other things, the contribution to us of all the outstanding equity interests in Windsor Permian and Gulfport’s satisfaction with the terms of this offering. In connection with this contribution, we will grant Gulfport the right, for so long as Gulfport beneficially owns more than 10% of our outstanding common stock, to designate one individual as a nominee to serve on our board of directors. We will also grant Gulfport certain demand and “piggyback” registration rights obligating us to register with the SEC the shares of our common stock owned by Gulfport. For more information about the Gulfport contribution, see “Management—Our Board of Directors and Committees,” “Related Party Transactions—Gulfport Contribution and Investor Rights Agreement” and “Shares Eligible for Future Sale—Registration Rights” beginning on pages 103, 118 and 128, respectively, of this prospectus.

In addition, our equity sponsor, Wexford, has agreed to cause all of the outstanding equity interests in Windsor UT LLC, or Windsor UT, to be contributed to Windsor Permian before it is contributed to us. Windsor UT was formed in April 2010 and acquired 4,978 gross (2,489 net) acres in the Permian Basin. The other 2,489 net acres are owned by Gulfport and will be contributed to us in the Gulfport contribution. Five wells have been drilled on this acreage as of March 31, 2012, which acreage contains 120 of our identified potential vertical drilling locations based on 40-acre spacing.

We refer to Gulfport’s contribution of properties to us as the Gulfport contribution and we refer to the Gulfport contribution together with the contribution to Windsor Permian of all the equity interests in Windsor UT as the Contributions.

Our Equity Sponsor

We were formed by our equity sponsor, Wexford Capital LP, or Wexford, which is a Greenwich, Connecticut-based SEC-registered investment advisor with over $5.5 billion under management as of December 31, 2011. Wexford has made public and private equity investments in many different sectors and has particular expertise in the energy and natural resources sector. Upon completion of this offering, Wexford will beneficially own approximately     % of our common stock (approximately     % if the underwriters’ option to purchase additional shares is exercised in full). As a result, Wexford will continue to be able to exercise significant control over all matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. Prior to the closing of this offering, we will enter into an advisory services agreement with Wexford under which Wexford will provide us with financial and strategic advisory services related to our business. We are also party to certain other agreements with Wexford and its affiliates. For a description of the advisory services agreement and other agreements with Wexford and its affiliates, see “Related Party Transactions” beginning on page 118. Although our management believes that the terms of these related party agreements are reasonable, it is possible that we could have negotiated more favorable terms for such transactions with unrelated third parties. The existence of these related party agreements may give Wexford the ability to further influence and maintain control over many matters affecting us.

 

 

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Our History

Diamondback Energy, Inc. was incorporated on December 30, 2011 in Delaware as a holding company and will not conduct any material business operations prior to the transaction described below. All of our historical assets, operations and results described in this prospectus are those of Windsor Permian LLC, or Windsor Permian, which is an entity controlled by our equity sponsor, Wexford. Prior to the completion of this offering, Wexford will cause DB Energy Holdings LLC, or DB Holdings, an entity controlled by Wexford, to contribute all of the outstanding equity interests in Windsor Permian to us in exchange for shares of our common stock. Contemporaneously with this contribution, Gulfport will complete the Gulfport contribution. Upon completion of these contributions, Wexford and Gulfport will beneficially own 65% and 35%, respectively, of our outstanding common stock. Upon completion of the offering, Wexford and Gulfport will beneficially own approximately      and     %, respectively, of our common stock (approximately     % and     %, respectively, if the underwriters’ option to purchase additional shares is exercised in full).

As of April 30, 2012, Windsor Permian held a 22% interest in Bison Drilling and Field Services LLC, or Bison, and a 33% interest in Muskie Holdings LLC, or Muskie. Bison owns drilling rigs and various oil and natural gas well servicing equipment and performs drilling and field services for us. Muskie owns certain assets, real estate and rights in a lease for land that is prospective for oil and natural gas fracture grade sand. Windsor Permian’s interests in Bison and Muskie will be distributed to Windsor Permian’s sole member prior to the contribution of Windsor Permian to us so we may focus our activities on our oil and natural gas exploration and development activities. We recorded revenues of $0.8 million and $1.5 million attributable to Bison in our consolidated statements of operations during 2010 and the first quarter of 2011, respectively. Muskie was formed in 2011, and we recorded a loss from equity method investments of $7,107 for 2011. The interests in Bison and Muskie are reflected in “Investments-equity method” on our consolidated balance sheets. For additional information regarding Bison and Muskie, see “Unaudited Pro Forma Condensed Consolidated Financial Statements” and “Related Party Transactions” beginning on pages 48 and 118, respectively, of this prospectus and Note 5 to our consolidated financial statements appearing elsewhere in this prospectus.

Emerging Growth Company

We are an ‘‘emerging growth company’’ within the meaning of the federal securities laws. For as long as we are an emerging growth company, we will not be required to comply with the requirements that are applicable to other public companies that are not “emerging growth companies” including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, the reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements and the exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. We intend to take advantage of these reporting exemptions until we are no longer an emerging growth company. For a description of the qualifications and other requirements applicable to emerging growth companies and certain elections that we have made due to our status as an emerging growth company, see “Risk Factors—Risks Related to this Offering and our Common Stock – We are an ‘emerging growth company’ and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies will make our common stock less attractive to investors” on page 37 of this prospectus.

Our Offices

Our principal executive offices are located at 500 West Texas, Suite 1225, Midland, Texas, and our telephone number at that address is (432) 221-7400. We also lease additional office space in Midland and in Oklahoma City, Oklahoma. Our website address is www.diamondbackenergy.com. Information contained on our website does not constitute part of this prospectus. Except as otherwise indicated or required by the context, all references in this prospectus to “Diamondback,” the “Company,” “we,” “us” or “our” relate to Diamondback Energy, Inc. and its consolidated subsidiaries after giving effect to the contribution to us of all of the outstanding equity interests in Windsor Permian.

 

 

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The Offering

 

Common stock offered by us

             shares (             shares if the underwriters’ option to purchase additional shares is exercised in full)

 

Common stock offered by the selling stockholders

             shares (             shares if the underwriters’ option to purchase additional shares is exercised in full)

 

Common stock to be outstanding immediately after completion of this offering

             shares

 

Option to purchase additional shares

We and the selling stockholders have granted the underwriters a 30-day option to purchase on a pro rata basis up to an aggregate of              additional shares of our common stock.

 

Use of proceeds

We expect to receive approximately $         million of net proceeds from the sale of the common stock offered by us, based upon the assumed initial public offering price of $         per share (the midpoint of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts and estimated offering expenses (or approximately $         million if the underwriters’ option to purchase additional shares is exercised in full). At the closing of this offering, we will use approximately $         million of the net proceeds to repay outstanding borrowings under our revolving credit facility and $63.6 million to repay the Gulfport contribution note. The remaining net proceeds of approximately $         million (or approximately $         million if the underwriters’ option to purchase additional shares is exercised in full), will be used to fund a portion of our exploration and development activities and for general corporate purposes. We will not receive any proceeds from the sale of shares by the selling stockholders. See “Use of Proceeds” on page 42 of this prospectus.

 

Dividend policy

We currently anticipate that we will retain all future earnings, if any, to finance the growth and development of our business. We do not intend to pay cash dividends in the foreseeable future.

 

NASDAQ Global Market symbol

“FANG”

 

Risk Factors

You should carefully read and consider the information beginning on page 14 of this prospectus set forth under the heading “Risk Factors” and all other information set forth in this prospectus before deciding to invest in our common stock.

Except as otherwise indicated, all information contained in this prospectus:

 

   

assumes the underwriters do not exercise their over-allotment option; and

 

   

excludes shares of common stock reserved for issuance under our equity incentive plan.

 

 

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Summary Consolidated Historical and Pro Forma Financial Data

The following table sets forth our summary historical consolidated financial data as of and for each of the periods indicated. The summary consolidated financial data as of December 31, 2011 and 2010 and for the years ended December 31, 2011, 2010 and 2009 are derived from our historical audited consolidated financial statements included elsewhere in this prospectus. The summary consolidated balance sheet data as of December 31, 2009 are derived from our audited consolidated balance sheet as of that date, which is not included in this prospectus. The unaudited pro forma condensed consolidated financial data give effect to (a) the Contributions and (b) the distribution by Windsor Permian to its equity holder of its minority equity interests in Bison and Muskie. The unaudited pro forma condensed consolidated balance sheet data assume that these transactions occurred on December 31, 2011. The unaudited pro forma condensed consolidated statement of operations data for the year ended December 31, 2011 assume that these transactions occurred on January 1, 2011. The unaudited pro forma C Corporation financial data presented give effect to income taxes assuming we operated as a taxable corporation throughout the periods presented. Operating results for the periods ended December 31, 2011, 2010 and 2009 are not necessarily indicative of results that may be expected for any future periods. You should review this information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Selected Historical Consolidated Financial Data” and “Unaudited Pro Forma Condensed Consolidated Financial Statements” beginning on pages 54, 45 and 48, respectively, of this prospectus as well as our consolidated historical financial statements, the historical financial statements of Windsor UT and the statements of revenues and direct operating expenses of certain property interests of Gulfport and their respective related notes included elsewhere in this prospectus.

 

    Pro Forma   Historical  
    Year Ended
December 31,

2011
  Year Ended December 31,  
                2011                2010     2009  

Statement of Operations Data:

   

Oil and natural gas revenues

    $ 47,180,802      $ 26,441,927      $ 12,716,011   

Other income

      1,490,910        811,247        —     

Expenses:

       

Lease operating expense

      10,345,355        4,588,559        2,366,623   

Production taxes

      2,333,853        1,346,879        663,068   

Gathering and transportation

      201,828        105,870        42,091   

Oil and natural gas services

      1,732,892        811,247        —     

Depreciation, depletion and amortization

      15,402,826        8,145,143        3,215,891   

General and administrative

      3,603,479        3,051,627        5,062,618   

Asset retirement obligation accretion expense

      63,259        37,856        27,934   
 

 

 

 

 

   

 

 

   

 

 

 

Total expenses

      33,683,492        18,087,181        11,378,225   
 

 

 

 

 

   

 

 

   

 

 

 

Income from operations

      14,988,220        9,165,993        1,337,786   

Other income (expense):

       

Interest income

      11,197        34,474        35,075   

Interest expense

      (2,528,058     (836,265     (10,938

Loss on derivative contracts

      (13,009,393     (147,983     (4,068,005

Loss from equity investment

      (7,017     —          —     
 

 

 

 

 

   

 

 

   

 

 

 

Total other expense, net

      (15,533,271     (949,774     (4,043,868
 

 

 

 

 

   

 

 

   

 

 

 

Net (loss) income

    $ (545,051   $ 8,216,219      $ (2,706,082
 

 

 

 

 

   

 

 

   

 

 

 

 

 

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    Pro Forma     Historical  
    Year Ended
December 31,

2011
    Year Ended December 31,  
                2011                2010     2009  

Pro Forma C Corporation Data:(1)(2)

       

Historical net income (loss) before income taxes

  $           $ (545,051   $ 8,216,219      $ (2,706,082

Pro forma for income taxes, net of valuation allowance

      —          —          —     
 

 

 

   

 

 

   

 

 

   

 

 

 

Pro forma net income (loss)

  $           $ (545,051   $ 8,216,219      $ (2,706,082
 

 

 

   

 

 

   

 

 

   

 

 

 

Pro forma income (loss) per common share — basic and diluted

    $                    
   

 

 

     

Weighted average pro forma shares outstanding — basic and diluted

       
   

 

 

     

Selected Cash Flow and Other Financial Data:

       

Net income (loss)

    $ (545,051   $ 8,216,219      $ (2,706,082

Depreciation, depletion and amortization

      15,905,315        8,145,143        3,215,891   

Other non-cash items

      13,844,010        344,461        4,108,464   

Change in operating assets and liabilities

      1,179,920        (11,529,999     (1,916,707
   

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

    $ 30,384,194      $ 5,175,824      $ 2,701,566   
   

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

    $ (76,314,042   $ (53,134,641   $ (32,149,617

Net cash provided by financing activities

    $ 48,642,492      $ 49,618,254      $ 23,849,250   
             
    Pro Forma     Historical  
    As of
December 31,

2011
    As of December 31,  
      2011     2010     2009  

Balance sheet data:

       

Cash and cash equivalents

    $ 6,802,389      $ 4,089,745      $ 2,430,308   

Other current assets

      24,130,450        20,947,659        2,263,097   

Oil and gas properties, net — using full cost method of accounting

      206,342,604        135,782,510        89,777,517   

Well equipment to be used in development of oil and gas properties

      —          —          5,413,310   

Other property and equipment, net

      684,015        11,059,220        105,564   

Other assets

      11,524,427        637,562        82,813   
 

 

 

   

 

 

   

 

 

   

 

 

 

Total assets

    $ 249,483,885      $ 172,516,696      $ 100,072,609   
 

 

 

   

 

 

   

 

 

   

 

 

 

Current liabilities

    $ 42,418,305      $ 20,010,276      $ 13,972,080   

Note payable credit facility-long term

      85,000,000        44,766,687        —     

Derivative contracts-long term

      6,138,573        1,373,864        1,416,431   

Asset retirement obligations

      1,079,725        727,826        481,887   

Member’s equity

      114,847,282        105,638,043        84,202,211   
 

 

 

   

 

 

   

 

 

   

 

 

 

Total liabilities and member’s equity

    $ 249,483,885      $ 172,516,696      $ 100,072,609   
 

 

 

   

 

 

   

 

 

   

 

 

 

 

 

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     Pro Forma    Historical  
     Year Ended
December 31,
2011
   As of December 31,  
        2011      2010      2009  

Other financial data:

           

Adjusted EBITDA(3)

      $ 31,505,264       $ 17,383,466       $ 4,616,686   
  

 

  

 

 

    

 

 

    

 

 

 

 

(1) Diamondback Energy, Inc. was incorporated on December 30, 2011 in Delaware as a holding company and will not conduct any material business operations prior to the transaction described below. Our historical consolidated financial statements and other financial information included in this prospectus pertain to assets, liabilities, revenues and expenses of Windsor Permian LLC, which is an entity controlled by our equity sponsor, Wexford. Windsor Permian LLC was treated as a partnership for federal income tax purposes. As a result, essentially all of Windsor Permian LLC’s taxable earnings and losses were passed through to Wexford, and Windsor Permian LLC did not pay federal income taxes at the entity level. Prior to the completion of this offering, Windsor Permian LLC will become our wholly-owned subsidiary and, because we are a subchapter C corporation under the Internal Revenue Code, the earnings at Windsor Permian LLC will become subject to federal income tax. For comparative purposes, we have included pro forma financial data to give effect to income taxes net of valuation allowance assuming the earnings at Windsor Permian LLC had been subject to federal income tax as a subchapter C corporation in all periods presented in the accompanying table. If the earnings at Windsor Permian LLC had been subject to federal income tax as a subchapter C corporation during the periods presented herein, we would have incurred net operating losses in each period presented. We would have been in a net deferred tax asset, or DTA, position as a result of such tax losses and would have recorded a valuation allowance to reduce each period’s DTA balance to zero. A valuation allowance to reduce each period’s DTA would have resulted in an equal and offsetting credit for the respective expenses or an equal and offsetting debit for the respective benefits for income taxes, with the resulting tax expenses for each of the above periods of zero. The unaudited pro forma data is presented for informational purposes only, and does not purport to project our results of operations for any future period or our financial position as of any future date.
(2) Unaudited historical pro forma basic and diluted income (loss) per share will be presented for the latest fiscal year on the basis of the aggregate number of shares to be issued to Gulfport in connection with the Gulfport contribution and to DB Holdings in connection with its contribution to us of all of the outstanding equity interests in Windsor Permian LLC, upon determination of the number of those shares.
(3) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss), see “Selected Historical Consolidated Financial Data” beginning on page 45 of this prospectus.

 

 

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Summary Historical and Pro Forma Reserve Data

The following table sets forth estimates of our net proved oil and natural gas reserves as of December 31, 2011 on a historical basis and on a pro forma basis after giving effect to the Contributions as if they had occurred as of December 31, 2011. Our historical reserves and the historical reserves attributable to the Windsor UT properties and the properties subject to the Gulfport contribution have been prepared in each case as of December 31, 2011 by Ryder Scott, an independent petroleum engineering firm, in accordance with SEC rules and regulations. Copies of these reserve reports are attached to this prospectus as Appendices B, C and D. You should also refer to “Risk Factors,”Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business—Oil and Gas Data—Proved Reserves,” “Business—Oil and Gas Production Prices and Production Costs—Production and Price History” beginning on pages 14, 54, 84 and 88, respectively, of this prospectus, our audited consolidated financial statements and notes thereto and our unaudited pro forma financial statements and notes thereto included in this prospectus in evaluating the material presented below.

 

     Pro Forma     Historical  
     December 31, 2011     December 31, 2011  

Estimated proved developed reserves:

    

Oil (Bbls)

     6,046,099        3,805,291   

Natural gas (Mcf)

     8,335,945        5,186,941   

Natural gas liquids (Bbls)

     1,969,711        1,233,319   

Total (BOE)

     9,405,134        5,903,100   

Estimated proved undeveloped reserves:

    

Oil (Bbls)

     20,140,375        12,911,576   

Natural gas (Mcf)

     24,261,520        14,431,924   

Natural gas liquids (Bbls)

     5,870,850        3,529,955   

Total (BOE)

     30,054,812        18,846,852   

Estimated Net Proved Reserves:

    

Oil (Bbls)

     26,186,474        16,716,867   

Natural gas (Mcf)

     32,597,465        19,618,865   

Natural gas liquids (Bbls)

     7,840,561        4,763,274   

Total (BOE)(1)

     39,459,946        24,749,952   

Percent proved developed

     23.8     23.9

 

(1) Estimates of reserves as of December 31, 2011 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 period ended December 31, 2011, in accordance with revised SEC guidelines applicable to reserves estimates as of the end of 2011. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved 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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RISK FACTORS

An investment in our common stock involves a high degree of risk. You should carefully consider the following risks and all of the other information contained in this prospectus before deciding to invest in our common stock. Our business, financial condition and results of operations could be materially and adversely affected by any of these risks. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider immaterial also may adversely affect us.

Risks Related to the Oil and Natural Gas Industry and Our Business

Our business is difficult to evaluate because we have a limited operating history.

We were incorporated in Delaware on December 30, 2011. All of our historical oil and natural gas assets, operations and results described in this prospectus are currently those of Windsor Permian, which is an entity controlled by our equity sponsor, Wexford. Immediately prior to the closing of this offering, Windsor Permian will become our wholly-owned subsidiary and we will acquire the oil and gas assets of Gulfport located in the Permian Basin in the Gulfport contribution. The oil and natural gas properties of Windsor Permian, Gulfport and Windsor UT described in this prospectus have been acquired by Windsor Permian, Gulfport and Windsor UT since December 2007. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.

We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.

As a recently-formed company, growth in accordance with our business plan, if achieved, could place a significant strain on our financial, technical, operational and management resources. As we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and natural gas industry, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

Approximately 74% of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.

Approximately 74% of our net leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.

Our development and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. In 2011, our total capital expenditures, including expenditures for leasehold interest and property acquisitions, drilling, seismic and infrastructure, were approximately $81.7 million. Our 2012 capital budget for drilling, completion and infrastructure, including investments in water

 

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disposal infrastructure and gathering line projects, is estimated to be approximately $180.0 million. To date, we have financed capital expenditures primarily with funding from our equity sponsor, borrowings under our revolving credit facility and cash generated by operations.

In the near term, we intend to finance our capital expenditures with cash flow from operations, proceeds from this offering and borrowings under our revolving credit facility. Our cash flow from operations and access to capital are subject to a number of variables, including:

 

   

our proved reserves;

 

   

the volume of oil and natural gas we are able to produce from existing wells;

 

   

the prices at which oil and natural gas are sold; and

 

   

our ability to acquire, locate and produce new reserves.

We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2012 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include traditional reserve base borrowings, debt financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.

If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or may be otherwise unable to implement our development plan, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies and related cost savings.

Our success depends on finding, developing or acquiring additional reserves.

Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. We have made and expect to make in the future substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves. We may not have sufficient resources to undertake our exploration, development and production activities or the acquisition of oil and natural gas reserves, our exploratory projects or other replacement activities may not result in significant additional reserves and we may not have success drilling productive wells at low finding and development costs. Furthermore, although our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.

Our project areas, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.

Our project areas are in various stages of development, ranging from project areas with current drilling or production activity to project areas that consist of recently acquired leasehold acreage or that have limited drilling or production history. From inception through March 31, 2012, after giving effect to the Contributions, we drilled a total of 147 gross wells and participated in an additional 11 gross non-operated wells, of which 149 wells were completed as producing wells and nine wells were in various stages of completion. If the wells in the process of being completed do not produce sufficient revenues to return a profit or if we drill dry holes in the future, our business may be materially affected.

 

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Our identified potential drilling locations, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

As of March 31, 2012, after giving effect to the Contributions, we had 977 identified potential vertical drilling locations on our existing acreage based on 40-acre spacing and an additional 1,162 identified potential vertical drilling locations based on 20-acre downspacing. Only 329 of these identified potential vertical drilling locations were attributed to proved reserves. These drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs and drilling results. Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. We cannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable or whether wells drilled on 20-acre downspacing will produce at the same rates as those on 40-acre spacing. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Permian Basin may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. As of March 31, 2012 after giving effect to the Contributions, we had leases representing 250 net acres expiring in 2012, 222 net acres expiring in 2013, 2,041 net acres expiring in 2014 and 13,628 net acres expiring in 2015. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business.

The volatility of oil and natural gas prices due to factors beyond our control greatly affects our profitability.

Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:

 

   

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;

 

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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;

 

   

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.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past five years, the posted price for West Texas intermediate light sweet crude oil, which we refer to as West Texas Intermediate or WTI, has ranged from a low of $30.28 per barrel, or Bbl, in December 2008 to a high of $145.31 per Bbl in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.83 per million British thermal units, or MMBtu, in September 2009 to a high of $15.52 per MMBtu in January 2006. During 2011, prices ranged from $75.67 to $113.93 per Bbl for oil and wellhead natural gas market prices ranged from $2.79 to $4.92 per Mcf. On March 31, 2012, the West Texas Intermediate posted price for crude oil was $103.02 per Bbl and the Henry Hub spot market price of natural gas was $2.02 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development results deteriorate, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties.

We have entered into price swap derivatives and may in the future enter into forward sale contracts or additional price swap derivatives for a portion of our production, which may result in our making cash payments or prevent us from receiving the full benefit of increases in prices for oil and gas.

We use price swap derivatives to reduce price volatility associated with certain of our oil sales. Under these swap contracts, we receive a fixed price per barrel of oil and pay a floating market price per barrel of oil to the counterparty based on New York Mercantile Exchange Light Sweet Crude Oil pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. For the purpose of locking-in the value of a swap, we enter into counter-swaps from time to time. Under the counter-swap, we receive a floating price for the hedged commodity and pay a fixed price to the counterparty. The counter-swap is effective in locking-in the value of a swap since subsequent changes in the market value of the swap are entirely offset by subsequent changes in the market value of the counter-swap.

 

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In December 2007, we placed a swap contract covering 1,680,000 Bbls of crude oil for the period from January 2008 to December 2012 at various fixed prices. In April 2008, we entered into a series of counter-swaps to lock-in the value of certain of these swaps settling 1,188,000 Bbls of crude oil swaps. In June 2009, we entered into an additional series of counter-swaps to lock-in the value of the remaining swaps settling 324,000 Bbls of crude oil swaps. Locking in the value of our swaps with counter-swaps, without entering into new swaps, exposes us to commodity price risks on the originally swapped position. As of December 31, 2010 and 2009, all of our swap contracts were locked-in with counter swaps. In October 2011, we placed a swap contract covering 1,000 Bbls per day of crude oil for the period from January 1, 2012 through December 31, 2013 at a price of $78.50 per barrel in 2012 and $80.55 per barrel in 2013. Such contracts and any future hedging arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.

Our hedging transactions expose us to counterparty credit risk.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract.

The inability of one or more of our customers to meet their obligations may adversely affect our financial results.

In addition to credit risk related to receivables from commodity derivative contracts, our principal exposure to credit risk is through receivables from joint interest owners on properties we operate (approximately $12.7 million at December 31, 2011) and receivables from purchasers of our oil and natural gas production (approximately $5.0 million at December 31, 2011). Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We are generally unable to control which co-owners participate in our wells.

We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the years ended December 31, 2011 and 2010, one purchaser, Windsor Midstream LLC, an entity controlled by Wexford, our equity sponsor, accounted for approximately 78.4% and 81.7% of our revenue, respectively. For the year ended December 31, 2009, two purchasers accounted for more than 10% of our revenue: Windsor Midstream LLC (68.3%) and DCP Midstream, LP (14.8%). No other customer accounted for more than 10% of our revenue during these periods. This concentration of customers may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Current economic circumstances may further increase these risks. We do not require our customers to post collateral. The inability or failure of our significant customers or joint working interest owners to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial results.

Our method of accounting for investments in oil and natural gas properties may result in impairment of asset value.

We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would

 

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significantly change. Income from services provided to working interest owners of properties in which we also own an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves. The average depletion rate per barrel equivalent unit of production was $25.40, $17.78 and $11.21 for the years ended December 31, 2011, 2010 and 2009, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties for the years ended December 31, 2011, 2010 and 2009 was $15.2 million, $7.4 million and $3.2 million, respectively.

The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment exceed the discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. Beginning December 31, 2009, we have used the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date in estimating discounted future net revenues.

No impairment on proved oil and natural gas properties was recorded for the years ended December 31, 2011, 2010 and 2009. We may experience additional ceiling test write downs in the future. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Method of accounting for oil and natural gas properties” beginning of page 71 of this prospectus for a more detailed description of our method of accounting.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may be incorrect. Our historical estimates of proved reserves and related valuations are based on reports prepared by Ryder Scott as of December 31, 2011 and by Pinnacle as of December 31, 2010 and 2009, each an independent petroleum engineering firm. The estimates of proved reserves and related valuations attributable to the Windsor UT properties and the properties subject to the Gulfport contribution are based, in each case, on reports prepared by Ryder Scott as of December 31, 2011. Ryder Scott and Pinnacle, as applicable, conducted a well-by-well review of all our properties for the periods covered by their respective reserve reports using information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. Also, certain assumptions regarding future oil and natural gas prices, production levels and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas we ultimately recover being different from our reserve estimates.

The estimates of reserves as of December 31, 2011, 2010 and 2009 included in this prospectus 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, 2011, 2010 and 2009, respectively, in accordance with the revised SEC guidelines applicable to reserves estimates for such periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage. The reserve estimates represent our net revenue interest in our properties.

 

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The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves.

SEC rules that went into effect for fiscal years ending on or after December 31, 2009 could limit our ability to book additional proved undeveloped reserves in the future.

SEC rules that went into effect for fiscal years ending on or after December 31, 2009 require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.

Approximately 76% of our total estimated proved reserves at December 31, 2011 were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve engineer reports assumes that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.

Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in one major geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.

All of our producing properties are geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of crude oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

In addition to the geographic concentration of our producing properties described above, at December 31, 2011, all of our proved reserves were attributable to the Wolfberry play. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.

 

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We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce.

The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of gas sold in interstate commerce. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. For the years ended December 31, 2011 and 2010, one purchaser, Windsor Midstream LLC, an entity controlled by Wexford, our equity sponsor, accounted for approximately 78.4% and 81.7% of our revenue, respectively. For the year ended December 31, 2009, two purchasers accounted for more than 10% of our revenue: Windsor Midstream LLC (68.3%) and DCP Midstream, LP (14.8%). No other customer accounted for more than 10% of our revenue during these periods. We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production.

The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or personnel may restrict our operations.

The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. In accordance with customary industry practice, we rely on independent third party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. In addition, we do not have long-term contracts securing the use of our existing rigs, and the operator of those rigs may choose to cease providing services to us. In addition, we intend to increase the number of rigs we have operating in 2012 and 2013. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. According to the Lower Colorado River Authority, during 2011, Texas experienced the lowest inflows of water of any year in recorded history. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European debt crisis, the United States mortgage market and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil, natural gas and natural gas liquids, declining

 

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business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad continues to deteriorate, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our oil, natural gas and natural gas liquids, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.

We have incurred losses from operations during certain periods since our inception and may do so in the future.

We incurred a net loss of $0.5 million for the year ended December 31, 2011. Our development of and participation in an increasingly larger number of drilling locations has required and will continue to require substantial capital expenditures. The uncertainty and risks described in this prospectus may impede our ability to economically find, develop and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows provided by operating activities in the future.

Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques; therefore, the results of our planned exploratory drilling in these plays are subject to drilling and completion technique risks and drilling results may not meet our expectations for reserves or production.

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and consequently we are less able to predict future drilling results in these areas.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or natural gas and oil prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and gas properties and the value of our undeveloped acreage could decline in the future.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

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The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. When these facilities are unavailable, our operations can be interrupted and our revenues reduced.

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our oil production is transported from the wellhead to our tank batteries by our gathering system. Our purchasers then transport the oil by truck to a pipeline for transportation. Our gas production is generally transported by our gathering lines from the wellhead to an interconnection point with the purchaser. We do not control these trucks and other third party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced, would adversely affect our financial condition and results of operations.

Our operations are subject to various governmental regulations which require compliance that can be burdensome and expensive.

Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operations. Moreover, these laws and regulations have continually imposed increasingly strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. We believe the trend of more expansive and stricter environmental legislation and regulations will continue. See “Business—Regulation—Environmental Matters and Regulation” and “Business—Regulation—Other Regulation of the Oil and Natural Gas Industry” beginning on pages 92 and 96, respectively, of this prospectus for a description of the laws and regulations that affect us.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. The EPA, however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. At the same time, the Environmental Protection Agency, or EPA, has commenced a study of the potential environmental impacts of

 

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hydraulic fracturing activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. As part of these studies, both the EPA and the House committee have requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.

Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the Safe Drinking Water Act.

On April 17, 2012, EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds , or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule includes a 95 percent reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules will require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts, the results of which are expected between later in 2012 and 2014.

These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities.

Several states, including Texas, have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Railroad Commission recently adopted rules and regulations requiring that the well operator disclose the list of chemical ingredients subject to the requirements of federal Occupational Safety and Health Act (OSHA) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. We plan to use hydraulic fracturing extensively in connection with the development and production of certain of our oil and natural gas properties and any increased federal, state, local, foreign or international regulation of hydraulic fracturing could reduce the volumes of oil and gas that we can economically recover, which could materially and adversely affect our revenues and results of operations.

There has been increasing public controversy regarding hydraulic fracturing with regard to use of fracturing fluids, impacts on drinking water supplies, use of waters and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict

 

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hydraulic fracturing, such as the FRAC Act, are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.

We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to our exploration, development and production activities. These laws and regulations may require us to obtain a variety of permits or other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, production and transporting product pipelines or other operations; regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or impose substantial liabilities for spills, pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations.

Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. In addition, the risk of accidental spills or releases from our operations could expose us to significant liabilities under environmental laws. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the

 

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resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.

The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. The U.S. Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The new legislation was signed into law by the President on July 21, 2010, and requires the Commodities Futures Trading Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking under the new legislation, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. Although the CFTC has promulgated numerous final rules based on its proposals, it is not possible at this time to predict when the CFTC will finalize its proposed regulations or the effect of such regulations on our business. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our existing or future derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our derivative contracts in existence at that time, and increase our exposure to less creditworthy counterparties. If we reduce or change the way we use derivative instruments as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations or cash flows.

Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations and cash flows.

The U.S. President’s Fiscal Year 2013 Budget Proposal includes provisions that would, if enacted, make significant changes to U.S. tax laws. These changes include, but are not limited to, (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) eliminating the deduction from income for domestic production activities relating to oil and natural gas exploration and development, (iii) the repeal of the of the percentage depletion allowance for oil and gas properties, (iv) an extension of the amortization period for certain geological and geophysical expenditures and (iv) implementing certain international tax reforms. These proposed changes in the U.S. tax laws, if adopted, or other similar changes that reduce or eliminate deductions currently available with respect to oil and natural gas exploration and development, could adversely affect our business, financial condition, results of operations and cash flows.

 

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The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.

Many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas, and refined petroleum products, are “greenhouse gases,” or GHGs, regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol at this time, several states or geographic regions have adopted legislation and regulations to reduce emissions of greenhouse gases. Additionally, on April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts, et al. v. EPA, that the EPA has the authority to regulate carbon dioxide emissions from automobiles as “air pollutant” under the federal Clean Air Act. Thereafter, in December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Subsequently, the EPA adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective January 2011, although it does not require immediate reductions in GHG emissions. The EPA adopted the stationary source rule, also known as the “Tailoring Rule,” in May 2010, and it also became effective January 2011, although it remains subject of several pending lawsuits filed by industry groups. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. In addition, the EPA has continued to adopt GHG regulations of other industries, such as the March 2012 proposed GHG rule restricting future development of coal-fired power plants. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly.

Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry. Currently, while we are subject to certain federal GHG monitoring and reporting requirements, our operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some

 

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studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the Natural Gas Act of 1938, or the NGA, exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission, or FERC. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish whether a pipeline performs a gathering function and therefore is exempt from FERC’s jurisdiction under the NGA. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is a fact-based determination. The classification of facilities as unregulated gathering is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress, which could cause our revenues to decline and operating expenses to increase and may materially adversely affect our business, financial condition or results of operations. In addition, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, which could have a material adverse effect on our business, financial condition or results of operations.

We rely on a few key employees whose absence or loss could adversely affect our business.

Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our new executive team, including our Chief Executive Officer, Travis D. Stice, could disrupt our operations. We have employment agreements with these executives which contain restrictions on competition with us in the event they cease to be employed by us. However, as a practical matter, such employment agreements may not assure the retention of our employees. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

A significant reduction by Wexford of its ownership interest in us could adversely affect us.

Prior to the Gulfport contribution, Wexford will beneficially own 100% of our equity interests. Upon completion of this offering, Wexford will beneficially own approximately     % of our common stock, or     % if the underwriters exercise in full their option to purchase additional shares. See “Principal and Selling Stockholders” beginning on page 122 of this prospectus. Further, we anticipate that several individuals who will serve as our directors upon completion of this offering will be affiliates of Wexford. We believe that Wexford’s substantial ownership interest in us provides Wexford with an economic incentive to assist us to be successful. Upon the expiration of the lock-up restrictions on transfers or sales of our securities by or on behalf of DB Holdings following the completion of this offering, Wexford will not be subject to any obligation to maintain its ownership interest in us and may elect at any time thereafter to sell all or a substantial portion of or otherwise reduce its ownership interest in us. If Wexford sells all or a substantial portion of its ownership interest in us, Wexford may have less incentive to assist in our success and its affiliate(s) that are expected to serve as members of our board of directors may resign. Such actions could adversely affect our ability to successfully implement our business strategies which could adversely affect our cash flows or results of operations. We also receive certain services, including drilling services from entities controlled by Wexford. These service contracts may generally be terminated on 30-days notice. In the event Wexford ceases to own a significant ownership interest in us, such services may not be available to us on terms acceptable to us, if at all.

 

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Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may result in a total loss of investment and adversely affect our business, financial condition or results of operations.

Our drilling activities are subject to many risks. For example, we cannot assure you that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such wells. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics of a project. Further, our drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

 

   

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.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.

Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.

Historically, we have acquired significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.

Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.

Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical

 

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additives. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of operations and repairs to resume operations.

We endeavor to contractually allocate potential liabilities and risks between us and the parties that provide us with services and goods, which include pressure pumping and hydraulic fracturing, drilling and cementing services and tubular goods for surface, intermediate and production casing. Under our agreements with our vendors, to the extent responsibility for environmental liability is allocated between the parties, (i) our vendors generally assume all responsibility for control and removal of pollution or contamination which originates above the surface of the land and is directly associated with such vendors’ equipment while in their control and (ii) we generally assume the responsibility for control and removal of all other pollution or contamination which may occur during our operations, including pre-existing pollution and pollution which may result from fire, blowout, cratering, seepage or any other uncontrolled flow of oil, gas or other substances, as well as the use or disposition of all drilling fluids. In addition, we generally agree to indemnify our vendors for loss or destruction of vendor-owned property that occurs in the well hole (except for damage that occurs when a vendor is performing work on a footage, rather than day work, basis) or as a result of the use of equipment, certain corrosive fluids, additives, chemicals or proppants. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into contractual arrangements with the terms that vary from the above allocations of risk. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operation.

In accordance with what we believe to be customary industry practice, we historically have maintained insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flow. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.

Since hydraulic fracturing activities are part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have no coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

Our failure to successfully identify, complete and integrate future acquisitions of properties or businesses could reduce our earnings and slow our growth.

There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently operate, which could result in unforeseen operating difficulties and difficulties in coordinating geographically

 

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dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Completed acquisitions could require us to invest further in operational, financial and management information systems and to attract, retain, motivate and effectively manage additional employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.

Acquiring oil and gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

We may incur losses as a result of title defects in the properties in which we invest.

It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.

Prior to the drilling of an oil or gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

Competition in the oil and natural gas industry is intense, which may adversely affect our ability to succeed.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to

 

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discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

We will be subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our profitability, stock price and results of operations and financial condition could be materially adversely affected.

We will be required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002 as early as December 31, 2013. Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls upon becoming a large accelerated filer, as defined in the SEC rules, or otherwise ceasing to qualify for an exemption from the requirement to provide auditors’ attestation on internal controls afforded to emerging growth companies under the “Jumpstart Our Business Startups Act” enacted by the U.S. Congress in April 2012. We are currently evaluating our existing controls against the standards adopted by the Committee of Sponsoring Organizations of the Treadway Commission. During the course of our ongoing evaluation and integration of the internal control over financial reporting, we may identify areas requiring improvement, and we may have to design enhanced processes and controls to address issues identified through this review. For example, we anticipate the need to hire additional administrative and accounting personnel to conduct our financial reporting.

We believe that the out-of-pocket costs, the diversion of management’s attention from running the day-to-day operations and operational changes caused by the need to comply with the requirements of Section 404 of the Sarbanes-Oxley Act could be significant. If the time and costs associated with such compliance exceed our current expectations, our results of operations could be adversely affected.

We cannot be certain at this time that we will be able to successfully complete the procedures, certification and attestation requirements of Section 404 or that we or our auditors will not identify material weaknesses in internal control over financial reporting. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report such material weaknesses, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.

Increased costs of capital could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue

 

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acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

We recorded compensation expense in 2011 and we may incur substantial additional compensation expense related to our future grants of stock compensation which may have a material negative impact on our operating results for the foreseeable future.

As a result of outstanding stock-based compensation awards, we recorded $0.5 million of compensation expense in 2011. In addition, our compensation expenses may increase in the future as compared to our historical expenses because of the costs associated with our existing and anticipated stock-based incentive plans. These additional expenses will adversely affect our net income. We cannot determine the actual amount of these new stock-related compensation and benefit expenses at this time because applicable accounting practices generally require that they be based on the fair market value of the options or shares of common stock at the date of the grant; however, they may be significant. We will recognize expenses for restricted stock awards and stock options generally over the vesting period of awards made to recipients.

Our level of indebtedness may increase and reduce our financial flexibility.

In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties.

Our level of indebtedness could affect our operations in several ways, including the following:

 

   

a significant portion of our cash flows could be used to service our indebtedness;

 

   

a high level of debt would increase our vulnerability to general adverse economic and industry conditions;

 

   

the covenants contained in the agreements governing our outstanding indebtedness will 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.

A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

 

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Our revolving credit facility contains restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.

Our revolving credit facility contains restrictive covenants that limit our ability to, among other things:

 

   

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.

In addition, our revolving credit facility requires us to maintain certain financial ratios and tests. The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.

If we are unable to comply with the restrictions and covenants in our revolving credit facility, there could be an event of default under the terms of our revolving credit facility, which could result in an acceleration of repayment.

If we are unable to comply with the restrictions and covenants in our revolving credit facility, there could be an event of default under the terms of this facility. Our ability to comply with these restrictions and covenants, including meeting the financial ratios and tests under our revolving credit facility, may be affected by events beyond our control. As a result, we cannot assure that we will be able to comply with these restrictions and covenants or meet such financial ratios and tests. In the event of a default under our revolving credit facility, the lenders could terminate their commitments to lend or accelerate the loans and declare all amounts borrowed due and payable. If any of these events occur, our assets might not be sufficient to repay in full all of our outstanding indebtedness and we may be unable to find alternative financing. Even if we could obtain alternative financing, it might not be on terms that are favorable or acceptable to us. Additionally, we may not be able to amend our revolving credit facility or obtain needed waivers on satisfactory terms.

Our borrowings under our revolving credit facility expose us to interest rate risk.

Our earnings are exposed to interest rate risk associated with borrowings under our revolving credit facility, which bear interest at a rate elected by us that is based on the prime, LIBOR or federal funds rate plus margins ranging from 1.25% to 3.50% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. As of December 31, 2011, the weighted average interest rate on outstanding borrowings under our revolving credit facility was 3.3%. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.

Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Under our revolving credit facility, which currently provides for a $100.0 million borrowing base, we are subject to semi-annual and other elective collateral borrowing base redeterminations based on our oil and natural gas reserves. Our revolving credit facility currently provides that the borrowing base will remain at $100.0 million through October 15, 2012, at which time the borrowing base will be reduced to $85.0 million, subject to the periodic and elective borrowing base redeterminations discussed above, and without consideration of the impact of the Gulfport contribution and the Windsor UT properties. Any significant reduction in our borrowing

 

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base as a result of such borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial position, results of operation and cash flow.

Loss of our information and computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Risks Related to this Offering and Our Common Stock

Our two largest stockholders control a significant percentage of our common stock, and their interests may conflict with those of our other stockholders.

Upon completion of this offering, Wexford and Gulfport will beneficially own approximately     % and     %, respectively, of our common stock, or     % and     %, respectively, if the underwriters exercise their option to purchase additional shares in full. See “Principal and Selling Stockholders” beginning on page 122 of this prospectus. In addition, individuals affiliated with Wexford and Gulfport serve on our Board of Directors, and Gulfport has the right to designate one individual as a nominee for election to our Board of Directors so long as it continues to beneficially own more than 10% of our outstanding common stock. As a result, Wexford and Gulfport, together, will be able to control, and Wexford alone will continue to be able to exercise significant influence over, matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our common stock will be able to affect the way we are managed or the direction of our business. The interests of Wexford and Gulfport with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders. This continued concentrated ownership will make it impossible for another company to acquire us and for you to receive any related takeover premium for your shares unless Wexford approves the acquisition.

Since we are a “controlled company” for purposes of The NASDAQ Global Market’s corporate governance requirements, our stockholders will not have, and may never have, the protections that these corporate governance requirements are intended to provide.

Since we are a “controlled company” for purposes of The NASDAQ Global Market’s corporate governance requirements, we are not required to comply with the provisions requiring that a majority of our directors be independent, the compensation of our executives be determined by independent directors or nominees for election to our board of directors be selected by independent directors. If we choose to take advantage of any or all of these exemptions, our stockholders may not have the protections that these rules are intended to provide.

 

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The corporate opportunity provisions in our certificate of incorporation could enable Wexford, our equity sponsor, or other affiliates of ours to benefit from corporate opportunities that might otherwise be available to us.

Subject to the limitations of applicable law, our certificate of incorporation, among other things:

 

   

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.

These provisions create the possibility that a corporate opportunity that would otherwise be available to us may be used for the benefit of one of our affiliates.

We have engaged in transactions with our affiliates and expect to do so in the future. The terms of such transactions and the resolution of any conflicts that may arise may not always be in our or our stockholders’ best interests.

We have engaged in transactions and expect to continue to engage in transactions with affiliated companies. As described under the caption “Related Party Transactions” beginning on page 118 of this prospectus, these include, among others, drilling services provided to us to Bison Drilling and Field Services, LLC, real property leased by us from Fasken Midland, LLC and certain administrative services provided to us by Everest Operations Management LLC. Each of these entites is either controlled by or affiliated with Wexford, and the resolution of any conflicts that may arise in connection with such related party transactions, including pricing, duration or other terms of service, may not always be in our or our stockholders’ best interests because Wexford may have the ability to influence the outcome of these conflicts. For a discussion of potential conflicts, see “—Risks Related to this Offering and our Common Stock – Our two largest stockholders control a significant percentage of our common stock, and their interests may conflict with those of our other stockholders” on page 35 of this prospectus.

We will incur increased costs as a result of being a public company, which may significantly affect our financial condition.

As a public company, we will incur significant legal, accounting and other expenses that we did not incur as a private company. We will incur costs associated with our public company reporting requirements. We also anticipate that we will incur costs associated with corporate governance requirements, including requirements under the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the Financial Industry Regulatory Authority. We expect these rules and regulations to increase our legal and financial compliance costs and to make some activities more time-consuming and costly, particularly after we are no longer an “emerging growth company.” We also expect these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

However, for as long as we remain an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012, we intend to take advantage of certain exemptions from various reporting

 

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requirements that are applicable to other public companies that are not “emerging growth companies” including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. We intend to take advantage of these reporting exemptions until we are no longer an “emerging growth company.”

We will remain an “emerging growth company” for up to five years, although if the market value of our common stock that is held by non-affiliates exceeds $700 million as of any June 30 before that time, we would cease to be an “emerging growth company” as of the following December 31.

After we are no longer an “emerging growth company,” we expect to incur significant additional expenses and devote substantial management effort toward ensuring compliance with those requirements applicable to companies that are not “emerging growth companies,” including Section 404 of the Sarbanes-Oxley Act. See “—Risks Related to the Oil and Natural Gas Industry and Our Business—We will be subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our profitability, stock price and results of operations and financial condition could be materially adversely affected” on page 32 of this prospectus.

We are an “emerging growth company” and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies will make our common stock less attractive to investors.

We are an “emerging growth company,” as defined in the Jumpstart our Business Startups Act of 2012, and we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies, including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. We cannot predict if investors will find our common stock less attractive because we will rely on these exemptions. If some investors find our common stock less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.

There has been no public market for our common stock and if the price of our common stock fluctuates significantly, your investment could lose value.

Prior to this offering, there has been no public market for our common stock. Although we have applied to have our common stock listed on The NASDAQ Global Market, we cannot assure you that an active public market will develop for our common stock or that our common stock will trade in the public market subsequent to this offering at or above the initial public offering price. If an active public market for our common stock does not develop, the trading price and liquidity of our common stock will be materially and adversely affected. If there is a thin trading market or “float” for our stock, the market price for our common stock may fluctuate significantly more than the stock market as a whole. Without a large float, our common stock is less liquid than the stock of companies with broader public ownership and, as a result, the trading prices of our common stock may be more volatile. In addition, in the absence of an active public trading market, investors may be unable to liquidate their investment in us. The initial offering price, which will be negotiated between us and the underwriters, may not be indicative of the trading price for our common stock after this offering. In addition, the stock market is subject to significant price and volume fluctuations, and the price of our common stock could fluctuate widely in response to several factors, including:

 

   

our quarterly or annual operating results;

 

   

changes in our earnings estimates;

 

   

investment recommendations by securities analysts following our business or our industry;

 

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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 change.

The stock market has experienced extreme price and volume fluctuations in recent years that have significantly affected the quoted prices of the securities of many companies, including companies in our industry. The changes often appear to occur without regard to specific operating performance. The price of our common stock could fluctuate based upon factors that have little or nothing to do with our company and these fluctuations could materially reduce our stock price.

Future sales of our common stock, or the perception that such future sales may occur, may cause our stock price to decline.

Sales of substantial amounts of our common stock in the public market after this offering, or the perception that these sales may occur, could cause the market price of our common stock to decline. See “Shares Eligible for Future Saleon page 127 of this prospectus. In addition, the sale of these shares could impair our ability to raise capital through the sale of additional common or preferred stock. After this offering, we will have              shares of common stock outstanding, excluding stock options. All of the shares sold in this offering, except for any shares purchased by our affiliates, will be freely tradable.

DB Holdings, Gulfport and our directors and executive officers will be subject to agreements that limit their ability to sell our common stock held by them. These holders cannot sell or otherwise dispose of any shares of our common stock for a period of at least 180 days after the date of this prospectus, which period may be extended under limited circumstances, without the prior written approval of Credit Suisse Securities (USA) LLC. However, these lock-up agreements are subject to certain specific exceptions, including transfers of common stock as a bona fide gift or by will or intestate succession and transfers to such person’s immediate family or to a trust or to an entity controlled by such holder, provided that the recipient of the shares agrees to be bound by the same restrictions on sales. In the event that one or more of our stockholders sells a substantial amount of our common stock in the public market, or the market perceives that such sales may occur, the price of our stock could decline.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our stock or if our operating results do not meet their expectations, our stock price could decline.

The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our stock or if our operating results do not meet their expectations, our stock price could decline.

Purchasers in this offering will experience immediate dilution and will experience further dilution with the future exercise of stock options granted to certain of our executive officers under their respective employment agreements.

The initial public offering price is substantially higher than the pro forma net tangible book value per share of our outstanding common stock. As a result, you will experience immediate and substantial dilution of

 

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approximately $         per share, representing the difference between our net tangible book value per share as of          after giving effect to this offering and an assumed initial public offering price of $         (which is the midpoint of the range set forth on the cover of the prospectus). A $1.00 increase (decrease) in the assumed initial public offering price of $         per share (which is the midpoint of the range set forth on the cover page of this prospectus) would increase (decrease) our net tangible book value per share after giving effect to this offering by $        , and increase (decrease) the dilution to new investors by $        , assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offered expenses payable by us. If the options granted to certain of our executive officers under their respective employment agreements are exercised in full, the investors in this offering will experience further dilution. See “Dilution” beginning on page 44 of this prospectus for a description of dilution.

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.

Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of the company, which could adversely affect the price of our common stock.

The existence of some provisions in our certificate of incorporation and bylaws and Delaware corporate law could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult, including:

 

   

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.

These provisions also could discourage proxy contests and make it more difficult for you and other stockholders to elect directors and take other corporate actions. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price that investors are willing to pay in the future for shares of our common stock.

 

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We do not intend to pay cash dividends on our common stock in the foreseeable future, and therefore only appreciation of the price of our common stock will provide a return to our stockholders.

We currently anticipate that we will retain all future earnings, if any, to finance the growth and development of our business. We do not intend to pay cash dividends in the foreseeable future. Any future determination as to the declaration and payment of cash dividends will be at the discretion of our board of directors and will depend upon our financial condition, results of operations, contractual restrictions capital requirements, business prospects and other factors deemed relevant by our board of directors. In addition, the terms of our credit facilities prohibit us from paying dividends and making other distributions. As a result, only appreciation of the price of our common stock, which may not occur, will provide a return to our stockholders.

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

 

   

business strategy;

 

   

exploration and development drilling prospects, inventories, projects and programs;

 

   

oil and natural gas reserves;

 

   

identified drilling locations;

 

   

ability to obtain permits and governmental approvals;

 

   

technology;

 

   

financial strategy;

 

   

realized oil and natural gas prices;

 

   

production;

 

   

lease operating expenses, general and administrative costs and finding and development costs;

 

   

future operating results; and

 

   

plans, objectives, expectations and intentions.

All of these types of statements, other than statements of historical fact included in this prospectus, are forward-looking statements. These forward-looking statements may be found in the “Prospectus Summary,” “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business” beginning on pages 1, 14, 54 and 77, respectively, and other sections of this prospectus. In some cases, you can identify forward-looking statements by terminology such as “may,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “seek,” “objective” or “continue,” the negative of such terms or other comparable terminology.

The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, our management’s assumptions about future events may prove to be inaccurate. Our management cautions all readers that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the many factors including those described in the “Risk Factors” section and elsewhere in this prospectus. All forward-looking statements speak only as of the date of this prospectus. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

 

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USE OF PROCEEDS

Our net proceeds from the sale of              shares of common stock in this offering, assuming a public offering price of $         per share (which is the midpoint of the range set forth on the cover of this prospectus), are estimated to be $         million, after deducting underwriting discounts and commissions and estimated offering expenses. The net proceeds would be $         million if the underwriters’ option to purchase additional shares is exercised in full. At the closing of this offering, we intend to use approximately $         million of the net proceeds to repay outstanding borrowings under our revolving credit facility and $63.6 million to repay the Gulfport contribution note and, thereafter, we intend to use the balance of the proceeds from this offering to fund a portion of our exploration and development activities and for general corporate purposes, which may include leasehold interest and property acquisitions, working capital and the settlement of crude oil swaps. Upon repayment of the outstanding borrowings under our revolving credit facility, we will have $         million of borrowing capacity under that facility to further fund our exploration and development activities and for general corporate purposes.

All borrowings under our revolving credit facility are due and payable on October 14, 2014. As of April 30, 2012, $100.0 million was outstanding under our revolving credit facility and bore interest at a weighted average rate of 3.3% per annum. The amounts initially borrowed under our revolving credit facility were used to repay in full the outstanding indebtedness under our prior credit facility and for general corporate purposes. The Gulfport contribution note, which will be issued immediately prior to the closing of this offering in connection with the Gulfport contribution, does not bear interest and is due upon completion of this offering.

We will not receive any proceeds from the sale of shares by the selling stockholders, including any sale the selling stockholders may make upon exercise of the underwriters’ option to purchase additional shares.

An increase or decrease in the initial public offering price of $1.00 per share would cause the net proceeds that we will receive in this offering to increase or decrease by approximately $             million. If our net proceeds are reduced, we will have less proceeds to fund our exploration and development activities and may not have sufficient funds to repay our revolving credit facility in full. Any reduction in net proceeds may cause us to need to borrow additional funds under our revolving credit facility to fund our operations, which would increase our interest expense and decrease our net income.

DIVIDEND POLICY

We have never declared or paid any cash dividends on our capital stock. We currently intend to retain all available funds and any future earnings for use in the operation and expansion of our business and do not anticipate declaring or paying any cash dividends in the foreseeable future. Any future determination as to the declaration and payment of dividends will be at the discretion of our board of directors and will depend on then-existing conditions, including our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors that our board of directors considers relevant. In addition, the terms of our revolving credit facility restrict the payment of dividends to the holders of our common stock and any other equity holders.

 

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of December 31, 2011:

 

   

on an actual basis;

 

   

on a pro forma basis to give effect to the issuance of (a)              shares of our common stock to an affiliate of Wexford in exchange for its contribution to us of all the outstanding equity interests in Windsor Permian, (b)              shares of our common stock and the Gulfport contribution note to Gulfport in connection with the Gulfport contribution and (c) the distribution by Windsor Permian to its equity holders of its minority equity interests in Bison and Muskie; and

 

   

on a pro forma basis described above as adjusted to give effect to the sale of shares of our common stock in this offering at an assumed initial public offering price of $         per share (which is the midpoint of the range set forth on the cover of this prospectus), our receipt of an estimated $ million of net proceeds from this offering after deducting underwriting discounts and commissions and estimated offering expenses and the use of a portion of those proceeds to repay outstanding borrowings as described under the caption “Use of Proceedson page 42 of this prospectus.

You should read the following table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 54 and our consolidated financial statements and related notes appearing elsewhere in this prospectus.

 

     As of December 31, 2011  
     Actual(1)      Pro Forma      Pro Forma
As  Adjusted(2)
 
     (in thousands)  

Cash and cash equivalents

   $ 6,802       $               $           
  

 

 

    

 

 

    

 

 

 

Long term debt (including current maturities)(3)

   $ 85,000       $        $    

Member’s equity

     114,847         —           —     

Stockholders’ equity:

        

Common stock, par value $0.01; 100 shares authorized and              shares issued and outstanding actual;              shares authorized and              shares issued and outstanding as adjusted for the offering

     —           

Additional paid-in capital

     —           

Accumulated deficit(4)

     —           
  

 

 

    

 

 

    

 

 

 

Total stockholders’ equity

        
  

 

 

    

 

 

    

 

 

 

Total capitalization

   $ 199,847       $        $    
  

 

 

    

 

 

    

 

 

 

 

(1) Diamondback Energy, Inc. was incorporated on December 30, 2011 in Delaware as a holding company and will not conduct any material business operations prior to the completion of the offering. The data in this table has been derived from the historical consolidated financial statements and other financial information included in this prospectus which pertain to the assets, liabilities, revenues and expenses of Windsor Permian LLC. Immediately prior to the completion of this offering, Windsor Permian LLC will become our wholly-owned subsidiary.
(2) A $1.00 increase (decrease) in the assumed initial public offering price of $         per share (which is the midpoint of the range set forth on the cover of this prospectus) would increase (decrease) each of cash and cash equivalents, additional paid-in-capital and total capitalization by $        , assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.
(3) At April 30, 2012, long term debt was $100.0 million.
(4) Upon completion of this offering, we will recognize deferred tax liabilities and assets for temporary differences between the historical cost basis and tax basis of these assets and liabilities. Based on estimates of those temporary differences as of December 31, 2011, a net deferred tax liability of approximately $26.2 million will be recognized with a corresponding charge to earnings.

 

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DILUTION

Our reported net tangible book value as of December 31, 2011 was $         million, or $         per share, based upon shares outstanding as of that date after giving pro forma effect to (a) the contribution to us of all of the outstanding equity interests in Windsor Permian, (b) the Gulfport contribution and (c) the distribution by Windsor Permian to its equity holders of its minority equity interests in Bison and Muskie. Net tangible book value per share is determined by dividing such number of outstanding shares of common stock into our net tangible book value, which is our total tangible assets less total liabilities. Assuming the sale by us of              shares of common stock offered in this offering at an estimated initial public offering price of $         per share (which is the midpoint of the range set forth on the cover of this prospectus) and after deducting the underwriting discounts and commissions and estimated offering expenses payable by us, our net tangible book value as of December 31, 2011 would have been approximately $         million, or $         per share, after giving pro forma effect to (a) the contribution to us of all of the outstanding equity interests in Windsor Permian, (b) to the Gulfport contribution and (c) the distribution by Windsor Permian to its equity holders of its minority equity interests in Bison and Muskie. This represents an immediate increase in net tangible book value of $         per share to our existing stockholders and an immediate dilution of $         per share to new investors purchasing shares at the initial public offering price.

The following table illustrates the per share dilution:

 

Assumed initial public offering price per share

      $                

Pro forma net tangible book value per share as of December 31, 2011

   $                   

Increase per share attributable to new investors

   $        
  

 

 

    

As adjusted net tangible book value per share after the offering

      $     
     

 

 

 

Dilution per share to new investors

      $     
     

 

 

 

A $1.00 increase (decrease) in the assumed initial public offering price of $         per share (which is the midpoint of the range set forth in the cover of this prospectus) would increase (decrease) our net tangible book value after the offering by $        , and increase (decrease) the dilution to new investors by $        , assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

The following table sets forth, as of December 31, 2011, after giving pro forma effect to the contribution to us by DB Holdings of all of the outstanding equity interests in Windsor Permian and to the Contributions, the number of shares of common stock to be issued by us to DB Holdings and Gulfport, which will be our existing stockholders immediately prior to this offering, and by the new investors at the assumed initial public offering price of $         per share, together with the total consideration paid and average price per share paid by each of these groups, before deducting underwriting discounts and commissions and estimated offering expenses.

 

     Shares Purchased     Total Consideration     Average Price  
      Number    Percent     Amount      Percent     Per Share  

Existing stockholders

               $                             $                

New investors

                          
  

 

  

 

 

   

 

 

    

 

 

   

 

 

 

Total

        100.0   $                      100.0   $     
  

 

  

 

 

   

 

 

    

 

 

   

 

 

 

If the underwriters’ option to purchase additional shares is exercised in full, the number of shares held by new investors will be increased to             , or approximately     % of the total number of shares of common stock.

The data in the table excludes              shares of common stock reserved for issuance under our equity incentive plan.

 

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

The following selected historical consolidated financial data as of December 31, 2011 and 2010 and for each of the years in the three-year period ended December 31, 2011 are derived from our audited consolidated financial statements included elsewhere in this prospectus. The selected consolidated balance sheet data as of December 31, 2009 and 2008 and the selected historical consolidated financial data for 2008 and the period from inception on October 23, 2007 to December 31, 2007 are derived from our audited financial statements not included in this prospectus. The balance sheet data as of December 31, 2007 is derived from our unaudited financial statements not included in this prospectus. The unaudited pro forma data presented gives effect to income taxes assuming that the Company operated as a taxable corporation throughout the periods presented. Operating results for the periods ended December 31, 2011, 2010, 2009, 2008 and 2007 are not necessarily indicative of results that may be expected for any future periods. You should review this information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 54 and our historical consolidated financial statements and related notes included elsewhere in this prospectus.

 

    Year Ended December 31,     Period from
Inception
(October 23,
2007) to
December 31,
2007
 
    2011     2010     2009     2008    

Statement of Operations Data:

       

Oil and natural gas revenues

  $ 47,180,802      $ 26,441,927      $ 12,716,011      $ 18,238,692      $ 578,336   

Other income

    1,490,910        811,247        —          —          —     

Expenses:

         

Lease operating expense

    10,345,355        4,588,559        2,366,623        3,375,419        25,684   

Production taxes

    2,333,853        1,346,879        663,068        1,008,991        136,077   

Gathering and transportation

    201,828        105,870        42,091        53,407        2,637   

Oil and natural gas services

    1,732,892        811,247        —          —          —     

Depreciation, depletion and amortization

    15,402,826        8,145,143        3,215,891        10,199,581        138,066   

Impairment of oil and gas properties

    —          —          —          83,164,230        —     

General and administrative

    3,603,479        3,051,627        5,062,618        5,459,874        6,609   

Asset retirement obligation accretion expense

    63,259        37,856        27,934        23,569        514   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses

    33,683,492        18,087,181        11,378,225        103,285,071        309,587   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from operations

    14,988,220        9,165,993        1,337,786        (85,046,379     268,749   

Other income (expense):

         

Interest income

    11,197        34,474        35,075        625,086        23,581   

Interest expense

    (2,528,058     (836,265     (10,938     —          —     

Loss on derivative contracts

    (13,009,393     (147,983     (4,068,005     (9,528,220     (4,791,587

Loss from equity investment

    (7,017     —          —          —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other expense, net

    (15,533,271     (949,774     (4,043,868     (8,903,134     (4,768,006
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

  $ (545,051   $ 8,216,219      $ (2,706,082   $ (93,949,513   $ (4,499,257
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Pro Forma C Corporation Data:(1)(2)

         

Historical net income (loss) before income taxes

  $ (545,051   $ 8,216,219      $ (2,706,082   $ (93,949,513   $ (4,499,257

Pro forma for income taxes, net of valuation allowance

    —          —          —          —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Pro forma net income (loss)

  $ (545,051   $ 8,216,219      $ (2,706,082   $ (93,949,513   $ (4,499,257
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Pro forma income (loss) per common share — basic and diluted

  $             
 

 

 

         

Weighted average pro forma shares outstanding — basic and diluted

         
 

 

 

         

 

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Table of Contents
   
Year Ended December 31,
    Period from
Inception
(October 23,
2007) to
December 31,
2007
 
    2011     2010     2009     2008    

Selected Cash Flow and Other Financial Data:

         

Net income (loss)

  $ (545,051   $ 8,216,219      $ (2,706,082   $ (93,949,513   $ (4,499,257

Depreciation, depletion and amortization

    15,905,315        8,145,143        3,215,891        10,199,581        138,066   

Other non-cash items

    13,844,010        344,461        4,108,464        92,716,019        4,792,101   

Change in operating assets and liabilities

    1,179,920        (11,529,999     (1,916,707     3,076,317        (2,448,557
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) operating activities

  $ 30,384,194      $ 5,175,824      $ 2,701,566      $ 12,042,404      $ (2,017,647
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

  $ (76,314,042   $ (53,134,641   $ (32,149,617   $ (84,196,562   $ (86,863,149

Net cash provided by financing activities

  $ 48,642,492      $ 49,618,254      $ 23,849,250      $ 80,182,600      $ 88,881,463   
    As of December 31,  
    2011     2010     2009     2008     2007  

Balance sheet data:

         

Cash and cash equivalents

  $ 6,802,389      $ 4,089,745      $ 2,430,308      $ 8,029,109      $ 667   

Other current assets

    24,130,450        20,947,659        2,263,097        1,389,810        2,489,231   

Oil and gas properties, net — using full cost method of accounting

    206,342,604        135,782,510        89,777,517        73,786,284        83,375,502   

Well equipment to be used in development of oil and gas properties

    —          —          5,413,310        8,503,178        —     

Other property and equipment, net

    684,015        11,059,220        105,564        161,103        —     

Other assets

    11,524,427        637,562        82,813        —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total assets

  $ 249,483,885      $ 172,516,696      $ 100,072,609      $ 91,869,484      $ 85,865,400   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Current liabilities

  $ 42,418,305      $ 20,010,276      $ 13,972,080      $ 18,011,452      $ 126,757   

Note payable credit facility-long term

    85,000,000        44,766,687        —          —          —     

Derivative contracts-long term

    6,138,573        1,373,864        1,416,431        2,868,452        1,141,587   

Asset retirement obligations

    1,079,725        727,826        481,887        374,287        214,850   

Members’ equity

    114,847,282        105,638,043        84,202,211        70,615,293        84,382,206   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total liabilities and members’ equity

  $ 249,483,885      $ 172,516,696      $ 100,072,609      $ 91,869,484      $ 85,865,400   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    Year Ended December 31,     Period from
Inception
(October 23,
2007) to
December 31,

2007
 
    2011     2010     2009     2008    

Other financial data:

         

Adjusted EBITDA(3)

  $ 31,505,264      $ 17,383,466      $ 4,616,686      $ 8,966,087      $ 430,910   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)

Diamondback Energy, Inc. was incorporated on December 30, 2011 in Delaware as a holding company and will not conduct any material business operations prior to the transaction described below. Our historical consolidated financial statements and other financial information included in this prospectus pertain to assets, liabilities, revenues and expenses of Windsor Permian LLC, which is an entity controlled by our equity sponsor, Wexford. Windsor Permian LLC was treated as a partnership for federal income tax purposes. As a result, essentially all of Windsor Permian LLC’s taxable earnings and losses were passed through to Wexford, and Windsor Permian LLC did not pay federal income taxes at the entity level. Prior to the completion of this offering, Windsor Permian LLC will become our wholly-owned subsidiary and, because we are a subchapter C corporation under the Internal Revenue Code, the earnings at Windsor Permian LLC will become subject to federal income tax. For comparative purposes, we have included pro forma financial data to give effect to income taxes net of valuation allowance assuming the earnings of Windsor Permian LLC had been subject to federal income tax as a subchapter C corporation in all periods presented in the accompanying table. If the earnings of Windsor Permian LLC had been subject to federal income tax as a subchapter C corporation during the periods presented herein, we would have incurred net operating losses in each period presented. We would have been in a net deferred tax asset, or DTA, position as a result of such tax losses and would have recorded a valuation allowance to reduce each period’s DTA balance to zero. A

 

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Table of Contents
  valuation allowance to reduce each period’s DTA would have resulted in an equal and offsetting credit for the respective expenses or an equal and offsetting debit for the respective benefits for income taxes, with the resulting tax expenses for each of the above periods of zero. The unaudited pro forma data is presented for informational purposes only, and does not purport to project our results of operations for any future period or our financial position as of any future date.
(2) Unaudited pro forma basic and diluted income (loss) per share will be presented for the latest fiscal year on the basis of the aggregate number of shares to be issued to Gulfport in connection with the Gulfport contribution and to DB Holdings in connection with its contribution to us of all of the outstanding equity interests in Windsor Permian LLC to us, upon determination of the number of those shares.
(3) Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as net income (loss) before loss on derivative contracts, interest expense, depreciation, depletion and amortization, impairment of oil and gas properties, non-cash equity based compensation and asset retirement obligation accretion expense. Adjusted EBITDA is not a measure of net income (loss) as determined by United States’ generally accepted accounting principles, or GAAP. Management believes Adjusted EBITDA is useful because it allows it to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measure of other companies or to such measure in our credit facility.

The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income (loss).

 

    Year Ended December 31,     Period from
Inception
(October 23,
2007) to
December 31,

2007
 
    2011     2010     2009     2008    

Reconciliation of Adjusted EBITDA to net income (loss):

         

Net income (loss)

  $ (545,051   $ 8,216,219      $ (2,706,082   $ (93,949,513   $ (4,499,257

Loss on derivative contracts

    13,009,393        147,983        4,068,005        9,528,220        4,791,587   

Interest expense

    2,528,058        836,265        10,938        —          —     

Depreciation, depletion and amortization

    15,905,315        8,145,143        3,215,891        10,199,581        138,066   

Impairment of oil and gas properties

    —          —          —          83,164,230        —     

Equity-based compensation expense

    544,290        —          —          —          —     

Asset retirement obligation accretion expense

    63,259        37,856        27,934        23,569        514   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $ 31,505,264      $ 17,383,466      $ 4,616,686      $ 8,966,087      $ 430,910   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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Table of Contents

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Diamondback Energy, Inc.

Unaudited Pro Forma Condensed Consolidated Financial Statements

Introduction

The following unaudited pro forma condensed consolidated financial statements and related notes of the Company have been prepared to show the effect of the Contributions and the distribution by Windsor Permian to its equity holders of its minority equity interests in Bison and Muskie. The unaudited pro forma condensed consolidated financial statements should be read together with the historical financial statements of Windsor Permian and Windsor UT and the historical Statements of Revenues and Direct Operating Expenses of certain property interests of Gulfport Energy Corporation included in this prospectus. The accompanying unaudited pro forma condensed consolidated financial statements are based on assumptions and include adjustments as explained in the accompanying notes. The acquisition of certain property interests of Gulfport Energy Corporation (the Gulfport properties) will be treated as a business combination accounted for under the acquisition method of accounting with the identifiable assets recognized at fair value on the date of transfer. The Windsor UT contribution is treated as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in the accounts of the transferring entity at the date of transfer. The pro forma data presented reflect events directly attributable to the Contributions and other described transactions and certain assumptions the Company believes are reasonable. The pro forma data are not necessarily indicative of financial results that would have been attained had the described transactions occurred on the dates indicated below. The pro forma data also necessarily exclude various operation expenses related to the Gulfport properties and the financial statements should not be viewed as indicative of operations in future periods.

The unaudited pro forma condensed consolidated balance sheet assumes that the Contributions and other described transactions occurred on December 31, 2011. The unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 2011 assumes that the Contributions and other described transactions occurred on January 1, 2011.

 

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Diamondback Energy, Inc.

Unaudited Pro Forma Condensed Consolidated Balance Sheets

December 31, 2011

 

     Windsor
Permian

Historical
     Windsor
UT

Historical
     Pro Forma
Adjustments
    Pro Forma  
Assets                           

Cash and cash equivalents

   $ 6,802,389       $ 156,733       $                   $                

Other current assets

     24,130,450         214,633        
  

 

 

    

 

 

    

 

 

   

 

 

 

Total current assets

     30,932,839         371,366        

Oil and natural gas properties, net using full cost method of accounting

     206,342,604         14,122,632              (a)   

Other property and equipment

     684,015         —          

Other assets

     11,524,427         —                (b)   
  

 

 

    

 

 

    

 

 

   

 

 

 

Total assets

   $ 249,483,885       $ 14,493,998        
  

 

 

    

 

 

    

 

 

   

 

 

 
Liabilities and Members’ Equity                           

Current liabilities

   $ 42,418,305       $ 280,383              (a)   

Note payable credit facility-long term

     85,000,000         —          

Derivative contracts-long term

     6,138,573         —          

Asset retirement obligations

     1,079,725         24,267              (c)   

Members’ equity

     114,847,282         14,189,348              (a)(c)   
  

 

 

    

 

 

    

 

 

   

 

 

 

Total liabilities and members’ equity

   $ 249,483,885       $ 14,493,998       $        $     
  

 

 

    

 

 

    

 

 

   

 

 

 

 

The accompanying notes are an integral part of these unaudited pro forma condensed consolidated financial statements.

 

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Table of Contents

Diamondback Energy, Inc.

Unaudited Pro Forma Condensed Consolidated Statement of Operations

Year ended December 31, 2011

 

     Windsor
Permian

Historical
    Gulfport
Contribution

Historical
     Windsor UT
Historical
     Pro Forma
Adjustments
    Pro Forma  

Revenues:

            

Oil and natural gas revenues

   $ 47,180,802      $ 23,052,000       $ 694,666       $        $                

Oil and natural gas services

     1,490,910        —           —           (b )   
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Total revenues

     48,671,712        23,052,000         694,666        

Costs and expenses:

            

Lease operating expenses

     10,345,355        5,484,000         251,824        

Production taxes

     2,333,853        1,276,000         32,016        

Gathering and transportation

     201,828        —           —          

Oil and natural gas services

     1,732,892        —           —                (b)   

Depreciation, depletion and amortization

     15,402,826        —           198,712              (d)   

General and administrative expenses

     3,603,479        —           37,044        

Asset retirement obligation accretion expense

     63,259        —           1,255              (c)   
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Total costs and expenses

     33,683,492        6,760,000         520,851        
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Income from operations

     14,988,220        16,292,000         173,815        

Other income (expense)

            

Interest income

     11,197        —           —          

Interest expense

     (2,528,058     —           —          

Loss on derivative contracts

     (13,009,393     —           —          

Loss from equity investment

     (7,017     —           —          
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Total other expense, net

     (15,533,271     —           —          
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Net income (loss)

   $ (545,051   $ 16,292,000       $ 173,815       $                   $            
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

 

The accompanying notes are an integral part of these unaudited pro forma condensed consolidated financial statements.

 

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Table of Contents

Diamondback Energy, Inc

Notes to Unaudited Pro Forma Condensed Consolidated

Financial Statements

1. Basis of Presentation

The historical financial information is derived from the historical financial statements of Windsor Permian and Windsor UT and the historical statements of revenues and direct operating expenses of certain property interests of Gulfport. The unaudited pro forma condensed consolidated balance sheet as of December 31, 2011 has been prepared as if the Contributions and other described transactions had taken place on December 31, 2011. The unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 2011 assumes that the Contributions and other described transactions had occurred on January 1, 2011.

2. Pro Forma Assumptions and Adjustments

We made the following adjustments in the preparation of the unaudited pro forma condensed consolidated financial statements.

 

(a) To record the contribution of the Gulfport properties at fair value for              shares of our common stock, which will represent 35% of our outstanding common stock immediately prior to the closing of this offering, and $63,590,050 in the form of a non-interest bearing promissory note that will be repaid in full upon the closing of this offering. The allocation of the purchase price to the assets acquired is preliminary and, therefore, subject to change.

 

(b) To record the distribution of minority equity interests in Bison and Muskie to Windsor Permian’s sole member prior to the contribution of Windsor Permian to us.

 

(c) To record incremental accretion of discount on asset retirement obligation associated with the Contributions.

 

(d) To record incremental depletion, depreciation, and amortization of oil and natural gas properties associated with the Contributions, amortized on a unit-of-production basis over the remaining life of total proved reserves, as applicable.

3. Oil and Natural Gas Producing Activities

The following table presents estimated unaudited pro forma volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2011 and changes in proved reserves during the year, assuming continuation of economic conditions prevailing at the end of the year. The weighted average prices at December 31, 2011 used for reserve report purposes are $93.09 per Bbl of oil, $56.62 per Bbl of natural gas liquids and $3.96 per Mcf of natural gas, respectively.

The Company emphasizes that the volumes of reserves shown below are estimates which, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data.

 

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Table of Contents
    Year Ended December 31, 2011  
    Windsor
Permian
Historical
    Gulfport
Contribution
Historical
    Windsor UT
Historical
    Total
Pro Forma
 
    Oil
(MBbls)
    Natural
Gas
Liquids
(MBbls)
    Natural
Gas
(MMcf)
    Oil
(MBbls)
    Natural
Gas
Liquids
(MBbls)
    Natural
Gas
(MMcf)
    Oil
(MBbls)
    Natural
Gas
Liquids
(MBbls)
    Natural
Gas
(MMcf)
    Oil
(MBbls)
    Natural
Gas
Liquids
(MBbls)
    Natural
Gas
(MMcf)
 

Proved Developed and Undeveloped Reserves:

                       

As of January 1, 2011

    18,819        5,564        21,662        9,358        3,107        11,926        811        269        1,033        28,988        8,940        34,621   

Extensions, discoveries and other additions

    1,706        448        1,824        764        217        992        94        18        60        2,564        683        2,876   

Revisions of prior reserve estimates

    (3,366     (1,162     (3,454     (1,828     (474     (599     487        (1     (160     (4,707     (1,637     (4,213

Production

    (442     (87     (413     (208     (59     (273     (8     —          —          (658     (146     (686
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

As of December 31, 2011

    16,717        4,763        19,619        8,086        2,791        12,046        1,384        286        933        26,187        7,840        32,598   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved Developed Reserves:

                       

January 1, 2011

    3,308        1,105        4,255        1,840        794        3,048        64        21        82        5,212        1,920        7,385   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2011

    3,805        1,233        5,187        2,097        706        3,050        144        30        99        6,046        1,969        8,336   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved Undeveloped Reserves:

                       

January 1, 2011

    15,511        4,459        17,407        7,518        2,313        8,878        747        248        951        23,776        7,020        27,236   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2011

    12,912        3,530        14,432        5,989        2,085        8,996        1,240        256        834        20,141        5,871        24,262   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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Table of Contents

Diamondback Energy, Inc

Notes to Unaudited Pro Forma Condensed Consolidated

Financial Statements

The following pro forma standardized measure of discounted estimated future net cash flows and changes therein relating to the combined proved oil and natural gas reserves of Windsor Permian and the Contributions as of and for the year ended December 31, 2011 were made in accordance with the provisions of the FASB ASU 2010-03, “Extractive Activities—Oil and Gas (Topic 932).”

 

     Year Ended December 31, 2011  
     Windsor
Permian
Historical
    Gulfport
Contribution
Historical
    Windsor UT
Historical
    Total
Pro Forma
 

Future cash flows

   $ 1,901,127,669      $ 960,918,000      $ 148,561,297      $ 3,010,606,966   

Future development costs

     (373,750,257     (236,336,000     (36,600,000     (646,686,257

Future production costs

     (458,939,218     (166,899,000     (38,872,203     (664,710,421

Future production taxes

     (97,457,261     (50,235,000     (7,410,909     (155,103,170
  

 

 

   

 

 

   

 

 

   

 

 

 

Future net cash flows

     970,980,933        507,448,000        65,678,185        1,544,107,118   

10% discount to reflect timing of cash flows

     (627,533,692     (305,160,000     (47,669,824     (980,363,516
  

 

 

   

 

 

   

 

 

   

 

 

 

Standardized measure of discounted future net cash flows

   $ 343,447,241      $ 202,288,000      $ 18,008,361      $ 563,743,602   
  

 

 

   

 

 

   

 

 

   

 

 

 

The primary changes in the pro forma standardized measure of discounted estimated future net cash flows were as follows for 2011:

 

     Year Ended December 31, 2011  
     Windsor
Permian
Historical
    Gulfport
Contribution
Historical
    Windsor UT
Historical
    Total
Pro Forma
 

Sales and transfers of oil and gas produced, net of production costs

   $ (34,299,766   $ (16,292,000   $ (410,826   $ (51,002,592

Net changes in prices and production costs and development costs

     86,655,407        48,089,000        383,765        135,128,172   

Extension and discoveries

     69,375,680        29,432,000        4,195,434        103,003,114   

Revisions of previous quantity estimates, less related production costs

     (100,433,225     (71,088,000     1,899,993        (169,621,232

Accretion of discount

     33,035,782        16,211,000        864,314        50,111,096   

Change in production rates and other

     (41,244,457     33,830,000        2,432,541        (4,981,916
  

 

 

   

 

 

   

 

 

   

 

 

 

Total change in standardized measure of discounted future net cash flows

   $ 13,089,421      $ 40,182,000      $ 9,365,221      $ 62,636,642   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the “Selected Historical Consolidated Financial Data” and the combined financial statements and related notes included elsewhere in this prospectus. This discussion contains forward-looking statements reflecting our current expectations and estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” appearing elsewhere in this prospectus.

Overview

We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, long-life, onshore oil and natural gas reserves in the Permian Basin in West Texas. We intend to grow our reserves and production through development drilling, exploitation and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves.

We intend to increase stockholder value by profitably growing reserves and production, primarily through drilling operations. We seek high quality exploration and development projects with potential for providing long-term drilling inventories that generate high returns. Substantially all of our revenues are generated through the sale of oil, natural gas liquids and natural gas production. For the year ended December 31, 2011, our production was approximately 74% oil, 15% natural gas liquids and 11% natural gas.

We began operations in December 2007 with our acquisition of certain strategic oil and gas properties located in the Permian Basin of West Texas from ExL Petroleum, LP, Ambrose Energy I, Ltd. and certain other sellers for approximately $85.0 million. Through this transaction, we acquired 4,174 net acres with production at the time of acquisition of approximately 800 net barrels of oil equivalent, or BOE/d, from 33 gross (16.5 net) wells. Subsequently, we acquired approximately 25,851 additional net acres, which brought our total net acreage position in the Permian Basin to approximately 30,025 net acres at March 31, 2012 and, after giving effect to the Contributions, we had 49,703 net acres in the Permian Basin. Since our initial acquisition in the Permian Basin through March 31, 2012, we drilled or participated in the drilling of 152 gross (81 net) wells (or 158 gross (141 net) wells after giving effect to the Contributions) on our acreage in this area, primarily targeting the Wolfberry play. We are the operator of approximately 99% of our Permian Basin acreage.

We have increased our initial leasehold position through the following acquisitions in the Wolfberry play for an aggregate net cost of $41.2 million.

 

   

In 2008, we acquired 6,247 net acres at the Spanish Trail and Munn prospects in Midland County, Texas through 11 leases and one mineral deed, with 5,146 net acres attributable to one lease;

 

   

Commencing in 2008 and ending in 2010, we acquired leases at the Barron prospect in Midland County, Texas covering 225 net acres;

 

   

Commencing in 2008 and ending in 2011, we acquired leases at the Gist prospect in Ector County, Texas covering 1,404 net acres;

 

   

In 2008, 2009 and 2011, we acquired 35 leases at the UL prospect in Andrews and Upton Counties, Texas covering a total of 9,966 net acres;

 

   

Beginning in 2008, we acquired 17 leases at the Hurt/WHL prospect in Ector County, Texas covering 2,779 net acres;

 

   

In 2009, we acquired one lease at the Cumberland prospect located in Midland County, Texas covering 207 net acres;

 

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In 2010, we acquired leases at the North Howard prospect located in Howard County, Texas that currently cover 176 net acres;

 

   

In 2010, we acquired 912 net acres at the Sabo prospect in Upton County, Texas;

 

   

In 2010 and 2011, we acquired 150 leases at the Big Max prospect located in Andrews County, Texas covering 825 net acres; and

 

   

In 2011, we acquired three leases in the Clete prospect in Crockett County, Texas covering 3,110 net acres.

Diamondback Energy, Inc. was incorporated in Delaware on December 30, 2011 as a holding company and will not conduct any material business operations prior to the transaction described below. Our historical financial information included in this prospectus pertains to assets, liabilities, revenues and expenses of Windsor Permian LLC, which is an entity controlled by our equity sponsor, Wexford. Prior to the closing of this offering, Wexford will cause DB Holdings, an entity controlled by Wexford, to contribute all of the outstanding equity interests in Windsor Permian LLC to us in exchange for shares of our common stock, and Windsor Permian LLC will become our wholly-owned subsidiary. In addition, Wexford has agreed to cause all the outstanding equity interests in Windsor UT to be contributed to Windsor Permian prior to the time Windsor Permian is contributed to us. Contemporaneously with the contribution of Windsor Permian to us, Gulfport will complete the Gulfport contribution in exchange for shares of our common stock.

Prior to Windsor Permian being contributed to us, Windsor Permian will distribute to its sole member its minority equity interests in Bison Drilling and Field Services LLC, or Bison, and Muskie Holdings LLC, or Muskie. Bison was formed in November 2010 as a wholly-owned subsidiary of Windsor Permian. Between March 2011 and April 2012, Gulfport and various entities controlled by Wexford acquired interests in Bison, which reduced Windsor Permian’s interest to approximately 22%. Bison owns and operates four drilling rigs and various oil and natural gas well servicing equipment and has performed drilling and field services for us. Muskie was formed in October 2011 when Windsor Permian contributed certain assets, real estate and rights in a lease covering land in Wisconsin to Muskie in exchange for a 48.6% equity interest. The contributed lease is prospective for oil and natural gas fracture grade sand. At the time of the contribution, the remaining interests in Muskie were held by Gulfport and entities controlled by Wexford. Through additional contributions from the Wexford-controlled entities, Windsor Permian’s equity interest in Muskie decreased to approximately 33%. Windsor Permian’s interests in Bison and Muskie will be distributed to Windsor Permian’s sole member prior to the contribution of Windsor Permian to us so we may focus our activities on our oil and natural gas exploration and development activities. We recorded revenues attributable to Bison in our consolidated statements of operations of $0.8 million during 2010 and $1.5 million during the first quarter of 2011, at which time Bison was deconsolidated for financial reporting purposes. Muskie was formed in 2011, and we recorded a loss from equity method investments of $7,107 million for 2011. The interests in Bison and Muskie are reflected in “Investments-equity method” on our consolidated balance sheets. For additional information regarding Bison and Muskie, see “Unaudited Pro Forma Condensed Consolidated Financial Statements” and “Related Party Transactions” beginning on pages 48 and 118, respectively, of this prospectus and Note 5 to our consolidated financial statements appearing elsewhere in this prospectus.

Since we began operations, we have increased our drilling activity, evaluated potential acquisitions and added to our acreage portfolio. Because of our growth through acquisitions and development of our properties, our historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful or indicative of future results.

Like all oil and natural gas exploration and production companies, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well naturally decreases. Thus, an oil and natural gas exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend on our

 

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ability to continue to add reserves in excess of production. We will maintain our focus on managing costs associated with drilling and the development and production of reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. We expect the permitting and approval process to become more difficult with increased activism from environmental and other groups which may extend the time it takes us to receive permits. Because of our relatively small size and concentrated property base, we can be disproportionately disadvantaged by delays in obtaining or failing to obtain drilling approvals compared to companies with larger or more dispersed property bases. As a result, we are less able to shift drilling activities to areas where permitting may be easier and we have fewer properties over which to spread the costs related to complying with these regulations and the costs or foregone opportunities resulting from delays.

Reserves and pricing

In December 2008, the SEC released the final rule for Modernization of Oil and Gas Reporting. Among other changes, the final rule requires us to report oil and natural gas reserves and calculate the full cost ceiling value using the unweighted arithmetic average first-day-of-the-month oil and natural gas prices during the 12-month period ending in the reporting period. The prior SEC rule required using prices at period end. The requirements of this standard became effective for the year ended December 31, 2009. These revisions and requirements affect the comparability between reporting periods prior to and after the year ended December 31, 2009 for reserve volume and value estimates, full cost pool write-down calculations and the calculations of depletion of oil and gas assets.

In the table below, Ryder Scott estimated all of our proved reserves at December 31, 2011 and Pinnacle estimated all of our proved reserves at December 31, 2010 and 2009. The prices used to estimate proved reserves for all periods did not give effect to derivative transactions, were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

 

     2011      2010      2009  

Estimated Net Proved Reserves:

        

Oil (Bbls)

     16,716,867         18,819,050         29,230,940   

Natural gas (Mcf)

     19,618,865         21,662,720         27,481,820   

Natural gas liquids (Bbls)

     4,763,274         5,563,978         7,522,225   

Total (BOE)

     24,749,952         27,993,481         41,333,468   

 

     2011      2010      2009  
     Unweighted Arithmetic Average First-Day-of-the-Month Prices  

Oil (Bbls)

   $ 93.09       $ 77.61       $ 58.84   

Natural gas (Mcf)

   $ 3.91       $ 4.14       $ 3.64   

Natural gas liquids (Bbls)

   $ 56.33       $ 40.74       $ 29.37   

Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities, commodity prices have experienced significant fluctuations, and additional changes in commodity prices may significantly affect the economic viability of drilling projects, as well as the economic valuation and economic recovery of oil and gas reserves.

Sources of our revenue

Our revenues are derived from the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from our natural gas during processing. Our oil and natural gas revenues do not include the effects of derivatives. For the year ended December 31, 2011, our revenues were derived 84% from oil sales,

 

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10% from natural gas liquids sales, 3% from natural gas sales and 3% from oil and natural gas services. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Oil, natural gas liquids and natural gas prices have historically been volatile. For example, during the past five years, the West Texas Intermediate posted price for crude oil has ranged from a low of $30.28 per Bbl in December 2008 to a high of $145.31 per Bbl in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.83 per MMBtu in September 2009 to a high of $15.52 per MMBtu in January 2006. During 2011, West Texas Intermediate prices ranged from $75.67 to $113.93 per Bbl for oil and wellhead natural gas market prices ranged from $2.79 to $4.92 per Mcf. On March 31, 2012, the West Texas Intermediate posted price for crude oil was $103.02 per Bbl and the Henry Hub spot market price of natural gas was $2.02 per MMBtu.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from time-to-time we enter into derivative arrangements for our crude oil and natural gas production. We utilize commodity derivatives to reduce our exposure to fluctuations in NYMEX WTI benchmark prices. While these derivative contracts stabilize our cash flows when market prices are below our contract prices, they also prevent us from realizing increases in our cash flow when market prices are higher than our contract prices. We will sustain realized and unrealized losses to the extent our derivatives contract prices are lower than market prices and, conversely, we will sustain realized and unrealized gains to the extent our derivatives contract prices are higher than market prices. Our derivatives contracts are not designated as accounting hedges and, as a result, gains or losses on derivatives contracts are recorded as other income (expense) in our statements of operations.

Principal components of our cost structure

Lease operating and natural gas transportation and treating expenses. These are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workover expenses related to our oil and natural gas properties.

Production taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and gas properties.

General and administrative. These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other fees for professional services and legal compliance.

Depreciation, depletion and amortization. Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unproved properties and major development projects for which proved reserves cannot yet be assigned, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values. We calculate depreciation on the cost of fixed assets related to other fixed assets.

Impairment expense. This is the cost to reduce proved oil and gas properties to the calculated full cost ceiling value.

Other income (expense)

Interest income. This represents the interest received on our cash and cash equivalents.

 

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Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our credit facility. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense.

Loss on derivative contracts. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the price of crude oil. This amount represents (i) the recognition of unrealized gains and losses associated with our open derivative contracts as commodity prices change and commodity derivative contracts expire or new ones are entered into, and (ii) our realized gains and losses on the settlement of these commodity derivative instruments.

Loss from equity investment. This line item represents our proportionate share of the earnings and losses from our investment in the membership interests of Muskie, an equity method investment.

Income tax expense. As of December 31, 2011, we were a limited liability company treated as a disregarded entity for federal income tax purposes. Accordingly, no provision for federal or state corporate income taxes has been provided for the year ended December 31, 2011 or prior fiscal years because taxable income is allocated directly to our equity holders. Prior to the completion of this offering, Windsor Permian will become our wholly-owned subsidiary and, because we are a subchapter C corporation under the Internal Revenue Code, the earnings at Windsor Permian will become subject to federal and state entity-level taxation. We will establish a net deferred tax liability for differences between the tax and book basis of our assets and liabilities, and we will record a corresponding “first day” tax expense to net income from continuing operations. On a pro forma basis, at December 31, 2011 the amount of this charge would have been $26.2 million. It is anticipated that the company will be subject to a future, total combined federal and state income tax rate of 34% to 36%.

 

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Results of Operations

The following table sets forth selected historical operating data for the periods indicated.

 

    Year Ended December 31,  
    2011     2010     2009  

Operating Results:

     

Revenues

     

Oil and natural gas revenues

  $ 47,180,802      $ 26,441,927      $ 12,716,011   

Other income

    1,490,910        811,247        —     

Operating expenses

     

Lease operating expense

    10,345,355        4,588,559        2,366,623   

Production taxes

    2,333,853        1,346,879        663,068   

Gathering and transportation expense

    201,828        105,870        42,091   

Oil and natural gas services

    1,732,892        811,247        —     

Depreciation, depletion and amortization

    15,402,826        8,145,143        3,215,891   

General and administrative

    3,603,479        3,051,627        5,062,618   

Asset retirement obligation accretion expense

    63,259        37,856        27,934   
 

 

 

   

 

 

   

 

 

 

Total expenses

    33,683,492        18,087,181        11,378,225   
 

 

 

   

 

 

   

 

 

 

Income from operations

    14,988,220        9,165,993        1,337,786   

Net interest income (expense)

    (2,516,861     (801,791     24,137   

Loss on derivative contracts

    (13,009,393     (147,983     (4,068,005

Loss from equity investment

    (7,017     —          —     
 

 

 

   

 

 

   

 

 

 

Net income (loss)

  $ (545,051   $ 8,216,219      $ (2,706,082
 

 

 

   

 

 

   

 

 

 

Production Data:

     

Oil (Bbls)

    441,822        280,721        168,741   

Natural gas (Mcf)

    413,640        323,847        253,321   

Natural gas liquids (Bbl)

    86,815        79,978        70,384   

Combined volumes (BOE)

    597,577        414,674        281,345   

Daily combined volumes
(BOE/d)

    1,637        1,136        771   

Average Prices(1):

     

Oil (per Bbl)

  $ 92.26      $ 76.51      $ 58.01   

Natural gas (per Mcf)

    3.98        4.32        3.64   

Natural gas liquids (per Bbl)

    54.98        44.56        28.49   

Combined (per BOE)

    78.95        63.77        45.20   

Average Costs (per BOE):

     

Lease operating expense

  $ 17.31      $ 11.07      $ 8.41   

Gathering and transportation expense

    0.34        0.26        0.15   

Production taxes

    3.91        3.25        2.36   

Production taxes as a % of sales

    4.9     5.1     5.2

Depreciation, depletion and amortization

    25.78        19.64        11.43   

General and administrative

    6.03        7.36        17.99   

 

(1) After giving effect to our hedging arrangements in effect during 2009, the average prices per Bbl of oil and per BOE (on a combined basis), were $41.59 and $35.35, respectively, during that year. Average prices for our hydrocarbons were not impacted by our hedging arrangements during 2011 or 2010.

 

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Year ended December 31, 2011 Compared to Year ended December 31, 2010

Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $20.8 million, or 78%, to $47.2 million for the year ended December 31, 2011 from $26.4 million for the year ended December 31, 2010. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 501 BOE/d during the year ended December 31, 2011 as compared to the same period in 2010. The total increase in revenue of approximately $20.8 million is largely attributable to higher oil, natural gas liquids and natural gas production volumes and an increase in the prices of oil and natural gas liquids realized for the year ended December 31, 2011 as compared to the year ended December 31, 2010. Production increased by 161,101 Bbls of oil, 6,837 Bbls of natural gas liquids and 89,793 Mcf of natural gas for the year ended 2011 as compared to the year ended 2010. The net dollar effect of the increase in prices of approximately $7.7 million (calculated as the change in year-to-year average prices times current year production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the increase in production of approximately $13.0 million (calculated as the increase in year-to-year volumes for oil, natural gas liquids and natural gas times the prior year average prices) are shown below.

 

     Change in
prices
    Production volumes
at December 31, 2011(1)
     Total net dollar effect
of change
(in thousands)
 

Effect of changes in price:

       

Oil

   $ 15.75        441,822       $ 6,959   

Natural gas liquids

   $ 10.42        86,815       $ 905   

Natural gas

   $ (0.34     413,640       $ (141
       

 

 

 

Total revenues due to change in price

        $ 7,723   
     Change in
production
volumes(1)
    Prices at
December 31, 2010(2)
     Total net dollar effect
of change
(in thousands)
 

Effect of changes in volumes:

       

Oil

     161,101      $ 76.51       $ 12,326   

Natural gas liquids

     6,837      $ 44.56       $ 305   

Natural gas

     89,793      $ 4.32       $ 388   
       

 

 

 

Total revenues due to change in volumes

        $ 13,019   
       

 

 

 

Total change in revenues

        $ 20,742   

 

(1) Production volumes are presented in Bbls for oil and natural gas liquids and in Mcf for natural gas.
(2) Prices represent the unweighted arithmetic average first-day-of-the-month oil and natural gas prices during the 12-month period ended December 31, 2010.

Lease Operating Expense. Lease operating expense was $10.3 million ($17.31 per BOE) for the year ended December 31, 2011, an increase of $5.7 million, or 125%, from $4.6 million ($11.07 per BOE) for the year ended December 31, 2010. The increase is due to increased drilling activity, which resulted in additional producing wells for the year ended December 31, 2011 as compared to the year ended December 31, 2010. On a per-BOE basis, the increase is due to cost increases in services and supplies (primarily as a result of higher demand for such services and supplies in the Permian Basin and higher commodity prices), the cost of repairing and replacing downhole equipment due to rod and tubing configurations and pumping practices that resulted in a higher rate of well failures during 2011 and the associated downtime and loss of production as these failures were remediated. Our lease operating expense for the year ended December 31, 2011 was also adversely impacted by the cost of processing and treating non-hydrocarbon gases from certain of our wells that came on line in 2011. The processing cost of approximately $200,000 per month has been necessary to meet pipeline specifications.

 

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During the second quarter of 2012, we intend to complete both oil and water gathering systems that will transport this gas stream to a sour gas pipeline, thereby eliminating the monthly processing and treating expense, and reduce water trucking, respectively. We believe that our reduced well failure rate and the completion of the gathering systems will help reduce our lease operating expense on a per-BOE basis in future periods.

Production Tax Expense. Production taxes as a percentage of oil and natural gas sales were 4.9% for the year ended December 31, 2011 as compared to 5.1% for the year ended December 31, 2010. Production taxes are primarily based on the market value of our production at the wellhead and vary across the different counties in which we operate. Total production taxes increased $1.0 million, or 73.3%, from $1.3 million during the year ended December 31, 2010 to $2.3 million during the year ended December 31, 2011 as a result of higher production and an increase in the market value of our production.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $7.3 million, or 89.1%, from $8.1 million for the year ended December 31, 2010 to $15.4 million for the year ended December 31, 2011. The weighted average depletion rate was $25.40 per BOE for the year ended December 31, 2011 and $17.78 per BOE for the year ended December 31, 2010. The depletion rate increase was due primarily to an increase in costs and a decrease in proved reserves at December 31, 2011 for the reasons described in “Business—Oil and Gas Data beginning on page 84 of this prospectus.

General and Administrative Expense. General and administrative expense increased $0.5 million from $3.1 million for the year ended December 31, 2010 to $3.6 million for the year ended December 31, 2011. A $1.9 million increase primarily attributable to salary and equity based compensation expense for our new executive team was partially offset by the capitalization of $0.9 million of such expense and a $0.5 million increase in COPAS overhead payments due to increased drilling activity.

Interest Expense. Interest expense for the year ended December 31, 2011 was $2.5 million, as compared to $0.8 million for the year ended December 31, 2010, an increase of $1.7 million. Our weighted average outstanding principal under our credit agreement was $69.0 million for the year ended December 31, 2011 as compared to $23.0 million for 2010 due to our increased drilling activity.

Hedging Activities. We have used price swap derivatives to reduce price volatility associated with certain of our oil sales. In these swaps, we received the fixed price per the contract and paid a floating market price to the counterparty based on New York Mercantile Exchange Light Sweet Crude Oil pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. The counterparties to our derivative contracts as of December 31, 2011 are Hess Corporation, or Hess, and BNP Paribas, or BNP, which we believe are acceptable credit risks.

All derivative financial instruments are recorded on our consolidated balance sheets at fair value. The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity.

On October 4, 2011, in an effort to lock-in prices on our anticipated base level of production, while at the same time providing downside protection for our borrowing base, we entered into West Texas Intermediate light sweet crude oil swaps on the NYMEX with BNP for the calendar years 2012 and 2013 of 1,000 barrels per day priced at $78.50 and $80.55, respectively.

 

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Set forth below are the summarized amounts, terms and fair values of outstanding instruments held as of December 31, 2011. As of December 31, 2011, we had unrealized losses under all of our crude oil swaps. We may seek to settle some or all of these swaps after the closing of this offering with a portion of the net proceeds depending upon our assessment of market conditions.

 

Description and Production Period

   Volume
(Bbls)
     Original
Strike
Price
(per Bbl)
     December 31,
2011
 
         Fair Value
Liability
 
Crude Oil Swaps:         

January — November 2012

     335,000       $ 78.50       $ 6,833,265   

December 2012

     31,000         78.50         594,223   

January — December 2013

     365,000         80.55         5,544,350   

We enter into counter-swaps from time to time for the purpose of locking-in the value of a swap. Under the counter-swap, we receive a floating price for the hedged commodity and pay a fixed price to the counterparty. The counter-swap is effective in locking-in the value of a swap since subsequent changes in the market value of the swap are entirely offset by subsequent changes in the market value of the counter-swap.

In December 2007, we entered into a swap contract covering 1,680,000 Bbls of oil for the period from January 2008 through December 2012 at various fixed prices. In April 2008, we entered into a series of counter-swaps to lock-in the value of certain of these swaps settling 1,188,000 Bbls of oil swaps. In June 2009, we entered into an additional series of counter-swaps to lock-in the value of the remaining swaps settling 324,000 Bbls of oil swaps.

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the April 2008 settlements as of December 31, 2011 and December 31, 2010.

 

     Volume
(Bbls)
     Original
Strike

Price
(per Bbl)
     Lock-in
Price
(per Bbl)
     December 31,  

Description and Production Period

            2011      2010  
Oil Swaps:             Fair Value
Liability
     Fair Value
Liability
 

December 2010

     22,000       $ 82.80       $ 99.45-103.20       $ —         $ 392,462   

January — November 2011

     180,000         82.90         98.50–102.20         —           4,159,695   

December 2011

     90,000         82.90         98.50–102.20         378,750         377,314   

January — December 2012

     270,000         85.07         98.25–101.80         3,876,959         3,844,101   

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the June 2009 settlements as of December 31, 2011 and December 31, 2010.

 

     Volume
(Bbls)
     Original
Strike

Price
(per Bbl)
     Lock-in
Price
(per Bbl)
     December 31,  

Description and Production Period

            2011      2010  
Oil Swaps:             Fair Value
Asset
     Fair Value
Asset
 

December 2010

     8,000       $ 82.80         75.00       $ —         $ 62,400   

January — November 2011

     82,500         82.90         78.42         —           369,205   

December 2011

     7,500         82.90         78.42         33,600         33,503   

January — December 2012

     90,000         85.07         80.52         409,380         406,489   

 

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None of our derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following table summarizes the loss on derivative contracts included in our consolidated statements of operations:

 

      Years Ended December 31,  
     2011      2010      2009  

Unrealized loss on open non-hedge derivative instruments

   $ 12,971,838       $ —         $ —     

Unrealized loss on locked-in non-hedge derivative instruments

     —           —           1,297,979   

Loss on settlement of non-hedge derivative instruments

     37,555         147,983         2,770,026   
  

 

 

    

 

 

    

 

 

 

Loss on derivative contracts

   $ 13,009,393       $ 147,983       $ 4,068,005   
  

 

 

    

 

 

    

 

 

 

We are required to provide margin deposits whenever our unrealized losses with Hess exceed predetermined credit limits. We had a margin deposit held by Hess of $2.3 million and $6.5 million as of December 31, 2011 and 2010, respectively, which earns interest that is remitted to us. Under our master netting agreement with Hess, we have offset this margin deposit against its derivative positions.

Year ended December 31, 2010 Compared to Year ended December 31, 2009

Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $13.7 million, or 108%, to $26.4 million during the year ended December 31, 2010 from $12.7 million for the year ended December 31, 2009. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 365 BOE/d during the year ended December 31, 2010 as compared to the year ended December 31, 2009. The total increase in revenue of approximately $13.7 million is largely attributable to higher oil, natural gas liquid and natural gas production volumes as well as an increase in oil, natural gas liquid and natural gas prices realized for the year ended December 31, 2010 as compared to year ended December 31, 2009. Production increased by 111,980 Bbls of oil, 9,594 Bbls of natural gas liquids and 70,526 Mcf of natural gas during 2010 as compared to 2009. The net dollar effect of the increase in prices of approximately $6.7 million (calculated as the change in year-to-year average prices times current year production volumes for oil, natural gas liquids and natural gas) and the net dollar effect of the change in production of approximately $7.0 million (calculated as the increase in year-to-year volumes for oil, natural gas liquids and natural gas times the prior year average prices) are shown below.

 

     Change in
prices
     Production volumes at
December 31, 2010(1)
     Total net dollar effect
of change
(in thousands)
 

Effect of changes in price:

        

Oil

   $ 18.50         280,721       $ 5,193   

Natural gas liquids

   $ 16.07         79,978       $ 1,285   

Natural gas

   $ 0.68         323,847       $ 220   
        

 

 

 

Total revenues due to change in price

         $ 6,698   
     Change in
production
volumes(1)
     Prices at December 31,
2009
     Total net dollar effect
of change

(in thousands)
 

Effect of changes in volumes:

        

Oil

     111,980       $ 58.01       $ 6,496   

Natural gas liquids

     9,594       $ 28.49       $ 273   

Natural gas

     70,526       $ 3.64       $ 257   
        

 

 

 

Total revenues due to change in volumes

         $ 7,026   
        

 

 

 

Total change in revenues

         $ 13,724   

 

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

 

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Lease Operating Expense. Lease operating expense was $4.6 million ($11.07 per BOE) for the year ended December 31, 2010, an increase of $2.2 million, or 92%, from $2.4 million ($8.41 per BOE) for the year ended December 31, 2009. The increase is due to increased drilling activity, which resulted in additional producing wells in 2010 as compared to 2009. On a per-BOE basis, the increase is due to cost increases in services and supplies, primarily as a result of the increased demand for such services and supplies in the Permian Basin, and increased commodity prices as well as additional well failure repairs coupled with downtime associated with the failures impacting production.

Production Tax Expense. Production taxes as a percentage of oil and natural gas sales were 5.1% for the year ended December 31, 2010 as compared to 5.2% for the year ended December 31, 2009. Production taxes are primarily based on the market value of our production at the wellhead and vary across the different counties in which we operate. Total production taxes increased $0.6 million, or 86%, from $0.7 million for the year ended December 31, 2009 to $1.3 million for the year ended December 31, 2010 as a result of higher production and an increase in the market value of our production.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $4.9 million, or 153%, from $3.2 million for the year ended December 31, 2009 to $8.1 million for the year ended December 31, 2010. The weighted average depletion rate was $11.21 per BOE in 2009 and $17.78 per BOE in 2010. The higher depletion rate in 2010 was due primarily to downward reserve revisions due to undeveloped locations being scheduled for development beyond five years and thus being excluded from proved reserves.

On December 31, 2009, we adopted the new SEC rules related to disclosures of oil and natural gas reserves. As a result of these new SEC rules, we recorded additional proved reserves and utilized the additional proved reserves in our depletion computation for 2009. Our 2009 depletion expense rate was $11.21 per BOE, which is lower in part due to these additional proved reserves.

General and Administrative Expense. General and administrative expense decreased $2.0 million, or 39%, from $5.1 million for the year ended December 31, 2009 to $3.1 million for the year ended December 31, 2010. This decrease was primarily due to a reduction in our labor force. As our capital expenditure programs result in increased production levels, we expect that general and administrative expense per unit of production will continue to decrease.

Interest Expense. Interest expense for 2010 was $0.8 million as compared to an interest expense of $0.01 million for 2009. During the year ended December 31, 2010, $0.2 million of our interest was capitalized and our weighted average outstanding principal under our credit agreement was $23.0 million, which was used primarily to fund our increased drilling program. During the year ended December 31, 2009, most of the interest was capitalized and our weighted average outstanding principal was $6.7 million.

Hedging Activities. We have used price swap derivatives to reduce price volatility associated with certain of our oil sales. In these swaps, we received the fixed price per the contract and paid a floating market price to the counterparty based on New York Mercantile Exchange Light Sweet Crude Oil pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. The counterparty to all of our derivative contracts is Hess, which we believe is an acceptable credit risk.

All derivative financial instruments are recorded on our consolidated balance sheets at fair value. The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity.

We enter into counter-swaps from time to time for the purpose of locking-in the value of a swap. Under the counter-swap, we receive a floating price for the hedged commodity and pay a fixed price to the counterparty. The counter-swap is effective in locking-in the value of a swap since subsequent changes in the market value of the swap are entirely offset by subsequent changes in the market value of the counter-swap.

 

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In December 2007, we entered into a swap contract covering 1,680,000 Bbls of oil for the period from January 2008 through December 2012 at various fixed prices. In April 2008, we entered into a series of counter-swaps to lock-in the value of certain of these swaps settling 1,188,000 Bbls of oil swaps. In June 2009, we entered into an additional series of counter-swaps to lock-in the value of the remaining swaps settling 324,000 Bbls of oil swaps. We have not entered into any new swap contracts since the initial contract in December 2007. As of December 31, 2010 and 2009, all swap contracts were locked-in with counter swaps.

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the April 2008 settlements as of December 31, 2010 and 2009.

 

     Volume (Bbls)      Original Strike
Price (per Bbl)
     Lock-in Price
(per Bbl)
     December 31,  
              2010      2009  

Description and Production Period

            Fair Value
Liability
     Fair Value
Liability
 

Oil Swaps:

              

December 2009

     22,000       $ 83.75       $ 102.25 – 105.90       $ —         $ 432,550   

January — November 2010

     242,000         82.80           99.45 – 103.20         —           4,312,111   

December 2010

     22,000         82.80           99.45 – 103.20         392,462         390,714   

January — December 2011

     270,000         82.90           98.50 – 102.20         4,537,009         4,485,047   

January — December 2012

     270,000         85.07           98.25 – 101.80         3,844,101         3,737,855   

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the June 2009 settlements as of December 31, 2010 and 2009.

 

     Volume (Bbls)      Original Strike
Price (per Bbl)
     Lock-in Price
(per Bbl)
     December 31,  
              2010      2009  

Description and Production Period

            Fair Value Asset      Fair Value Asset  

Oil Swaps:

              

December 2009

     8,000       $ 83.75       $ 71.03       $ —         $ 101,757   

January — November 2010

     88,000         82.80         75.00         —           685,405   

December 2010

     8,000         82.80         75.00         62,400         62,108   

January — December 2011

     90,000         82.90         78.42         402,708         397,880   

January — December 2012

     90,000         85.07         80.52         406,489         394,696   

None of our derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following summarizes the loss on derivative contracts included in the consolidated statements of operations as follows:

 

     Years ended December 31,  
     2010      2009  

Unrealized loss on locked-in non-hedge derivative instruments

   $ —         $ 1,297,979   

Loss on settlement of non-hedge derivative instruments

     147,983         2,770,026   
  

 

 

    

 

 

 

Loss on derivative contracts

   $ 147,983       $ 4,068,005   
  

 

 

    

 

 

 

We are required to provide margin deposits whenever our unrealized losses with Hess exceed predetermined credit limits. We had a margin deposit held by Hess of $6.5 million and $10.3 million as of December 31, 2010 and 2009, respectively. Interest earned on the deposit is remitted to us. As we have a master netting agreement with Hess, we have offset this margin deposit against derivative positions.

 

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Liquidity and Capital Resources

Our primary sources of liquidity to date have been capital contributions from our equity holder, borrowings under our credit facility and cash flows from operations. Our primary use of capital has been for the acquisition, development and exploration of oil and natural gas properties. We regularly evaluate potential capital sources, including equity and debt financings, in an effort to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.

Liquidity and cash flow

Our cash flows for the years ended December 31, 2011, 2010 and 2009 are presented below:

 

     Year Ended December 31,  
     2011     2010     2009  

Net cash provided by operating activities

   $ 30,384,194      $ 5,175,824      $ 2,701,566   

Net cash used in investing activities

     (76,314,042     (53,134,641     (32,149,617

Net cash provided by financing activities

     48,642,492        49,618,254        23,849,250   
  

 

 

   

 

 

   

 

 

 

Net change in cash

   $ 2,712,644      $ 1,659,437      $ (5,598,801
  

 

 

   

 

 

   

 

 

 

Operating Activities

Net cash provided by operating activities was $30.4 million for the year ended December 31, 2011 as compared to $5.2 million for the year ended December 31, 2010. The increase in operating cash flows is due to an overall increase in production revenues, partially offset by increased expenses, as discussed above in “—Results of Operations” on page 59. The increase in production is largely a result of our increased drilling activities throughout 2011.

Net cash provided by operating activities was $5.2 million for the year ended December 31, 2010 as compared to $2.7 million for the year ended December 31, 2009. The increase in operating cash flows is due to an overall increase in production revenues, partially offset by increased expenses, as discussed above in “—Results of Operations” on page 59. The increase in production volumes is largely a result of our increased drilling program in 2010. The increase in operating activities was partially offset by changes in our working capital components in 2010 which consisted primarily of the purchase of inventory of tubular goods for our drilling program and increased accounts receivables due to the increase in our drilling activities in 2010.

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas we produce. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict.

Investing Activities

The purchase and development of oil and natural gas properties accounted for the majority of our cash outlays for investing activities. We used cash for investing activities of $76.3 million, $53.1 million and $32.1 million during the years ended December 31, 2011, 2010 and 2009, respectively.

During 2011, we spent $72.2 million on capital expenditures in conjunction with our drilling program in which we participated in the drilling of 54 gross (31 net) wells. We spent an additional $3.2 million on leasehold costs, $4.1 million for the purchase of certain assets, real estate and leasehold interests which were subsequently

 

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contributed to Muskie and $2.9 million for the purchase of drilling rigs and other equipment which were subsequently contributed to Bison. These amounts were partially offset by proceeds of $6.0 million from a partial sale of our equity investment, $0.05 million from the sale of property and equipment and $0.08 million from the settlement of non-hedge derivative investments and margin deposits.

During 2010, we spent $39.0 million on capital expenditures in conjunction with our drilling program in which we participated in the drilling of 40 gross (25 net) wells. We spent an additional $3.5 million for the purchase and development of leasehold interests, $11.7 million for the purchase of drilling rigs, well servicing equipment and other equipment which were subsequently contributed to Bison and $0.2 million for the settlement of non-hedge derivative instruments and margin deposits. These amounts were partially offset by the $1.3 million we received from the sale of approximately 10,946 net acres of non producing acreage in the Permian Basin.

During 2009, we spent $24.0 million on capital expenditures in conjunction with our drilling program in which we participated in the drilling of 12 gross (nine net) wells. We spent an additional $2.7 million for the purchase and development of leasehold interests in the Permian Basin and $5.5 million for the net amount of the settlement of non-hedge derivative instruments and margin deposits.

Our investment activities for the years ended December 31, 2011, 2010 and 2009 are summarized in the following table:

 

     Year Ended December 31,  
     2011     2010     2009  

Drilling and completion of wells

   $ (72,165,677   $ (38,979,629   $ (23,955,667

Proceeds from leasehold acquisitions

     (3,213,932     (3,493,464     (2,667,068

Purchase of other property and equipment

     (7,064,972     (11,741,073     (8,856

Proceeds from sale of property and equipment

     54,909        1,270,075        2,000   

Settlement of non-hedge derivative instruments

     (4,126,800     (3,962,440     (2,770,026

Receipt (payment) on derivative margins

     4,202,467        3,771,890        (2,750,000

Proceeds from equity investment, net

     5,999,963        —