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EX-99.2 - EX-99.2 - Oasis Petroleum Inc.h69816a1exv99w2.htm
EX-23.1 - EX-23.1 - Oasis Petroleum Inc.h69816a1exv23w1.htm
EX-23.3 - EX-23.3 - Oasis Petroleum Inc.h69816a1exv23w3.htm
EX-23.2 - EX-23.2 - Oasis Petroleum Inc.h69816a1exv23w2.htm
EX-99.1 - EX-99.1 - Oasis Petroleum Inc.h69816a1exv99w1.htm
Table of Contents

As filed with the Securities and Exchange Commission on April 9, 2010
Registration No. 333-165212
 
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
 
 
 
 
Oasis Petroleum Inc.
(Exact name of registrant as specified in its charter)
 
         
Delaware
  1311   80-0554627
(State or other jurisdiction of
incorporation or organization)
  (Primary Standard Industrial
Classification Code Number)
  (I.R.S. Employer
Identification No.)
 
1001 Fannin Street, Suite 202
Houston, Texas 77002
(713) 574-1770
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
Thomas B. Nusz
Chairman, President and Chief Executive Officer
Oasis Petroleum Inc.
1001 Fannin Street, Suite 202
Houston, Texas 77002
(713) 574-1770
(Name, address, including zip code, and telephone number, including area code, of agent for service)
 
 
 
 
Copies to:
     
T. Mark Kelly
David P. Oelman
Vinson & Elkins L.L.P.
1001 Fannin, Suite 2500
Houston, Texas 77002-6760
(713) 758-2222
  G. Michael O’Leary
David C. Buck
Andrews Kurth LLP
600 Travis Street, Suite 4200
Houston, TX 77002
(713) 220-4200
 
 
 
 
Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this registration statement.
 
If any of the 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 check the following box:  o
 
If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o
 
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.  o
 
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.  o
 
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 o
  Accelerated filer o   Non-accelerated filer þ   Smaller reporting company o
        (Do not check if a 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 of 1933 or until the 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 stockholder 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 stockholder are not soliciting offers to buy these securities in any state where the offer or sale is not permitted.
 
(SUBJECT TO COMPLETION, DATED APRIL 9, 2010)
 
PROSPECTUS
Issued               , 2010
          Shares
 
Oasis Petro LOGO
 
Oasis Petroleum Inc.
 
COMMON STOCK
 
 
Oasis Petroleum Inc. is offering           shares of its common stock and the selling stockholder is offering           shares of common stock. We will not receive any proceeds from the sale of shares by the selling stockholder. This is our initial public offering and no public market currently exists for our shares. We anticipate that the initial public offering price of our common stock will be between $      and $      per share.
 
 
We have applied to list our common stock on the New York Stock Exchange under the symbol “OAS.”
 
 
Investing in our common stock involves risks. See “Risk Factors” beginning on page 13.
 
 
Price $      Per Share
 
 
                                 
        Underwriting
      Proceeds to
    Price to
  Discounts and
  Proceeds to
  Selling
    Public   Commissions   Company   Stockholder
 
Per Share
  $           $           $           $        
Total
  $       $       $       $  
 
The selling stockholder has granted the underwriters the right to purchase up to an additional           shares of common stock to cover over-allotments.
 
The Securities and Exchange Commission and state securities regulators have not approved or disapproved of these securities, or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
 
The underwriters expect to deliver the shares of common stock to purchasers on          , 2010.
 
 
 
 
Joint Book-Running Managers
Morgan Stanley UBS Investment Bank
 
Co-Lead Manager
Simmons & Company International
 
 
Senior Co-Managers
 
J.P. Morgan           Tudor, Pickering, Holt & Co. Wells Fargo Securities
 
 
Co-Managers
BNP PARIBAS  
  Canaccord Adams  
  Johnson Rice & Company L.L.C.  
  Morgan Keegan & Company, Inc.  
  Raymond James  
  RBC Capital Markets  
  Scotia Capital
          , 2010


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Oasis Acreage


 

 
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 EX-23.1
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You should rely only on the information contained in this prospectus and any free writing prospectus prepared by or on behalf of us or to which we have referred you. Neither we nor the selling stockholder has authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We and the selling stockholder are offering to sell shares of common stock and seeking offers to buy shares of common stock, only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the common stock.
 
Until          , 2010, all dealers that buy, sell or trade our common stock, whether or not participating in this offering, may be required to deliver a prospectus. This requirement is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.
 
Industry and Market Data
 
The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Some data is also based on our good faith estimates. Although we believe these third-party sources are reliable and that the information is accurate and complete, we have not independently verified the information.


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PROSPECTUS SUMMARY
 
This summary provides a brief overview of information contained elsewhere in this prospectus. Because it is abbreviated, this summary does not contain all of the information that you should consider before investing in our common stock. You should read the entire prospectus carefully before making an investment decision, including the information presented under the headings “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements and unaudited pro forma financial information and related notes thereto included elsewhere in this prospectus. Unless otherwise indicated, information presented in this prospectus assumes that the underwriters’ option to purchase additional common shares is not exercised. We have provided definitions for certain oil and natural gas terms used in this prospectus in the “Glossary of Oil and Natural Gas Terms” beginning on page A-1 of this prospectus.
 
In this prospectus, unless the context otherwise requires, the terms “we,” “us,” “our,” and the “company” refer to Oasis Petroleum LLC and its subsidiaries before the completion of our corporate reorganization and Oasis Petroleum Inc. and its subsidiaries as of the completion of our corporate reorganization and thereafter.
 
OASIS PETROLEUM INC.
 
Overview
 
We are an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources. We have accumulated approximately 292,000 net leasehold acres in the Williston Basin, approximately 85% of which are undeveloped. We are currently focused on exploiting what we have identified as significant resource potential from the Bakken and Three Forks formations, which are present across a substantial majority of our acreage. A report issued by the United States Geologic Survey, or USGS, in April 2008 classified these formations as the largest continuous oil accumulation ever assessed by it in the contiguous United States. We believe the location, size and concentration of our acreage creates an opportunity for us to achieve cost, recovery and production efficiencies through the large-scale development of our project inventory. Our management team has a proven track record in identifying, acquiring and executing large, repeatable development drilling programs, which we refer to as “resource conversion” opportunities, and has substantial experience in the Williston Basin. We have built our leasehold acreage position in the Williston Basin primarily through acquisitions in our three primary project areas, West Williston, East Nesson and Sanish. For a description of our acquisition activity, please see “—Our Acquisition History” below.
 
DeGolyer and MacNaughton, our independent reserve engineers, estimated our net proved reserves to be 13.3 MMBoe as of December 31, 2009, 42% of which were classified as proved developed and 93% of which were comprised of oil. The following table presents summary data for each of our primary project areas as of December 31, 2009:
 
                                                                         
                      2010 Budget                 Average
 
          Identified Drilling
                Drilling
    Estimated Net
    Daily
 
    Net
    Locations     Gross
    Net
    Capex
    Proved Reserves     Production
 
    Acreage     Gross     Net     Wells     Wells     (In millions)     MMBoe     % Developed     (Boe/d)(1)  
 
Williston Basin
                                                                       
West Williston(2)
    159,491       268       106.5       41       18.8     $ 110       5.0       55 %     1,106  
East Nesson(2)
    124,004       113       57.0       13       7.4       47       3.9       36 %     1,016  
Sanish(3)
    8,747       88       9.6       37       3.8       22       4.3       32 %     792  
                                                                         
Total Williston Basin
    292,242       469       173.1       91       30.0     $ 179       13.2       42 %     2,914  
Other
    879                                     0.1       100 %     159  
                                                                         
Total
    293,121       469       173.1       91       30.0     $ 179       13.3       42 %     3,073  
                                                                         
          
                                                                       
 
 
(1) Represents average daily production for the three months ended December 31, 2009.


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(2) Identified gross and net drilling locations in our West Williston and East Nesson project areas are primarily comprised of Bakken wells based on 1,280-acre spacing and do not include any infill wells targeting the Bakken formation or any primary or infill wells targeting the Three Forks formation.
 
(3) Identified gross and net drilling locations in our Sanish project area include a single Bakken infill well per 1,280-acre or 640-acre spacing unit (excluding spacing units already containing two Bakken producing wells) and include 10 gross (1.6 net) primary wells targeting the Three Forks formation.
 
In our West Williston and East Nesson project areas, we have an inventory of approximately 381 gross primary drilling locations (23 of which are proved undeveloped), substantially all of which are on 1,280-acre spacing targeting the Bakken formation. We plan to aggressively develop these specifically identified drilling locations using horizontal drilling and multi-stage fracture stimulation techniques. In our Sanish project area, we have an additional 88 gross non-operated drilling locations (63 of which are proved undeveloped). A single additional infill well per spacing unit targeting the Bakken formation across all three of our Williston Basin project areas would add over 500 incremental potential drilling locations. We are also evaluating the resource potential in the Three Forks formation across our leasehold position and believe there may be a significant number of additional potential drilling locations targeting this formation.
 
Our total 2010 capital expenditure budget is $220 million, which consists of:
 
  •  $134 million for drilling and completing operated wells;
 
  •  $45 million for drilling and completing non-operated wells;
 
  •  $15 million for maintaining and expanding our leasehold position;
 
  •  $5 million for constructing infrastructure to support production in our core project areas; and
 
  •  $21 million in unallocated funds which are available for additional drilling and leasing costs and activity.
 
While we have budgeted $220 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results as the year progresses. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”
 
Our Acquisition History
 
We built our leasehold position in our West Williston, East Nesson and Sanish project areas through the following acquisitions and development activities:
 
  •  In June 2007, we acquired approximately 175,000 net leasehold acres in the Williston Basin with then-current net production of approximately 1,000 Boe/d. This acreage is the core of our West Williston project area.
 
  •  In May 2008, we entered into a farm-in and purchase arrangement, under which we earned or acquired approximately 48,000 net leasehold acres, establishing our initial position in the East Nesson project area.
 
  •  In June 2009, we acquired approximately 40,000 net leasehold acres with then-current net production of approximately 800 Boe/d, approximately 83% of which was from the Williston Basin. This acquisition consolidated our acreage in the East Nesson project area and established our Sanish project area.
 
  •  In September 2009, we acquired an additional 46,000 net leasehold acres with then-current net production of approximately 300 Boe/d. This acquisition further consolidated our acreage in the East Nesson project area.


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Our Business Strategy
 
Our goal is to increase stockholder value by building reserves, production and cash flows at an attractive return on invested capital. We seek to achieve our goals through the following strategies:
 
  •  Aggressively Develop our Williston Basin Leasehold Position.  We intend to aggressively drill and develop our acreage position to maximize the value of our resource potential. The aggregate 469 gross drilling locations that we have specifically identified in the Bakken formation in our three project areas will be our primary targets in the near term. Our 2010 drilling plan contemplates drilling approximately 35 gross (22.4 net) operated wells in these project areas by using two operated drilling rigs for the full year and adding up to three additional drilling rigs later in the year. Subject to market conditions and rig availability, we expect to operate five drilling rigs in 2011, which could enable us to drill as many as 60 gross operated wells during that year. We believe we have the ability to add additional rigs this year if market conditions and program results warrant.
 
  •  Enhance Returns by Focusing on Operational and Cost Efficiencies.  Our management team is focused on continuous improvement of our operating measures and has significant experience in successfully converting early-stage resource opportunities into cost-efficient development projects. We believe the magnitude and concentration of our acreage within our project areas provides us with the opportunity to capture economies of scale, including the ability to drill multiple wells from a single drilling pad, utilizing centralized production and fluid handling facilities and reducing the time and cost of rig mobilization.
 
  •  Adopt and Employ Leading Drilling and Completion Techniques.  Our team is focused on enhancing our drilling and completion techniques to maximize recovery. We believe these techniques have significantly evolved over the last several years, resulting in increased initial production rates and recoverable hydrocarbons per well through the implementation of techniques such as using longer laterals and more tightly spaced fracturing stimulation stages. We continuously evaluate our internal drilling results and monitor the results of other operators to improve our operating practices, and we expect our drilling and completion techniques will continue to evolve. This continued evolution may significantly enhance our initial production rates, ultimate recovery factors and rate of return on invested capital.
 
  •  Pursue Strategic Acquisitions with Significant Resource Potential.  In the near term, we intend to identify and acquire additional acreage and producing assets in the Williston Basin to supplement our existing operations. Going forward, we expect to selectively target additional domestic basins that would allow us to employ our resource conversion strategy on large undeveloped acreage positions similar to what we have accumulated in the Williston Basin. While we have no current intention to pursue international opportunities, our management team has significant international acquisition and operating expertise. If we identify an international opportunity with appropriate scale, risk and resource conversion potential, our board of directors may approve such an investment should they determine it is in the long-term best interest of our stockholders to do so.
 
Our Competitive Strengths
 
We have a number of competitive strengths that we believe will help us to successfully execute our business strategies:
 
  •  Substantial Leasehold Position in one of North America’s Leading Unconventional Oil-Resource Plays.  Our current leasehold position of approximately 292,000 net leasehold acres in the Williston Basin is highly prospective in the Bakken formation. We believe our acreage is one of the largest concentrated leasehold positions in the basin prospective in the Bakken formation, and much of our acreage is in areas of significant drilling activity by other exploration and production companies. While we are initially targeting the Bakken formation, we are also evaluating what we believe to be significant prospectivity in the Three Forks formation which underlies a large portion of our acreage. We expect


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  that the scale and concentration of our acreage will enable us to continue to improve our drilling and completion costs and operational efficiency.
 
  •  Large, Multi-Year Project Inventory.  We have an inventory of approximately 469 gross drilling locations, primarily targeting the Bakken formation. We plan to drill 35 gross (22.4 net) operated wells across our West Williston and East Nesson project areas in 2010, the completion of which would represent 14% of our 246 gross identified operated drilling locations in these two project areas. We may be able to enhance the total recovery from the Bakken formation by drilling potential infill locations. In addition, our total number of drilling locations may also be substantially increased by pursuing the prospectivity we have identified in the Three Forks formation.
 
  •  Management Team with Proven Acquisition and Operating Skills.   Our senior management team has extensive expertise in the oil and gas industry as previous members of management at Burlington Resources. The senior technical team has an average of more than 25 years of industry experience, including experience in multiple North American resource plays as well as experience in other North American and international basins. We believe our management and technical team is one of our principal competitive strengths relative to our industry peers due to our team’s proven track record in identification, acquisition and execution of resource conversion opportunities. In addition, this team possesses substantial expertise in horizontal drilling techniques and managing and acquiring large development programs, and also has prior experience in the Williston Basin.
 
  •  Incentivized Management Team.  Our management team will own a significant direct ownership interest in us immediately following the completion of this offering. In addition, our management team will own an indirect interest in our controlling stockholder, OAS Holding Company LLC, or OAS Holdco, which will own      shares of our common stock upon completion of this offering. Our management team may significantly increase its sharing percentage in the shares held by OAS Holdco by increasing the return on investment for the other members of OAS Holdco. We believe our management team’s direct ownership interest immediately following the offering as well as their ability to increase their interest over time through OAS Holdco provides significant incentives to grow the value of our business for the benefit of all stockholders. See “Corporate Reorganization — LLC Agreement of OAS Holdco.”
 
  •  Operating Control over the Majority of our Portfolio.  In order to maintain better control over our asset portfolio, we have established a leasehold position comprised primarily of properties that we expect to operate. Controlling operations will allow us to dictate the pace of development as well as the costs, type and timing of exploration and development activities. We believe that maintaining operational control over the majority of our acreage will allow us to better pursue our strategies of enhancing returns through operational and cost efficiencies and maximizing hydrocarbon recovery through continuous improvement of drilling and completion techniques.
 
Recent Developments
 
Drilling Activity.  Since December 31, 2009, we have drilled six operated wells in the Bakken formation. Three of these wells are producing, and three wells are being completed. Additionally, we currently have one operated drilling rig in the West Williston project area and two in the East Nesson project area, each of which is drilling a well targeting the Bakken formation. Of the 16 gross (1.6 net) non-operated wells in progress on December 31, 2009, 13 gross (1.1 net) wells have initiated production and three gross (0.5 net) wells are under completion operations. Subsequent to December 31, 2009, an additional 25 gross (2.1 net) non-operated wells have begun operations with six gross (0.4 net) wells producing and 19 gross (1.7 net) wells being drilled or completed.
 
Amended and Restated Credit Facility.  On February 26, 2010, we entered into an amended and restated revolving credit facility, which will have a borrowing base of $70 million upon completion of this offering. Our revolving credit facility matures on February 26, 2014. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Reserve-based credit facility.” As of April 9, 2010, we had $30.0 million of indebtedness outstanding under our


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revolving credit facility. We anticipate that a portion of the net proceeds from this offering will be used to repay all of our borrowings outstanding as of the closing.
 
Marketing and Transportation
 
The Williston Basin crude oil transportation and refining infrastructure has grown substantially in recent years, largely in response to drilling activity in the Bakken formation. As of February 15, 2010, there was approximately 394,600 barrels per day of crude oil transportation and refining capacity in the Williston Basin, comprised of approximately 276,600 barrels per day of pipeline transportation capacity and approximately 58,000 barrels per day of refining capacity at the Tesoro Corporation Mandan refinery. In addition, approximately 60,000 barrels per day of specifically dedicated railcar transportation capacity has recently been placed into service in the Williston Basin. Based on publicly announced expansion projects, pipeline transportation capacity for Williston Basin oil production could increase by 30,000 to 115,000 barrels per day by 2013, and we believe additional projects are under consideration. We sell a substantial majority of our oil production directly at the wellhead and are not responsible for its transportation. However, the price we receive at the wellhead is impacted by transportation and refining infrastructure constraints. For a discussion of the potential risks to our business that could result from transportation and refining infrastructure constraints in the Williston Basin, please see “Risk Factors — Delays and interruptions of production from our wells due to marketing and transportation constraints in the Williston Basin could cause significant fluctuations in our realized oil and natural gas prices.”
 
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 entitled “Risk Factors” beginning on page 13 for an explanation of these risks before investing in our common stock.
 
Corporate Sponsorship and Structure
 
We were recently incorporated pursuant to the laws of the State of Delaware as Oasis Petroleum Inc. to become a holding company for Oasis Petroleum LLC. Oasis Petroleum LLC was formed as a Delaware limited liability company on February 26, 2007 by certain members of our senior management team and private equity funds managed by EnCap Investments L.P., or EnCap. EnCap, which was formed in 1988, provides private equity to independent oil and gas companies. Since its inception, EnCap has formed fourteen oil and gas investment funds with aggregate capital commitments of approximately $7.0 billion.
 
Pursuant to the terms of a corporate reorganization that will be completed simultaneously with the closing of this offering, all of the interests in Oasis Petroleum LLC will be exchanged for common stock of Oasis Petroleum Inc., a recently formed Delaware corporation. As a result of the reorganization, Oasis Petroleum LLC will become a wholly owned subsidiary of Oasis Petroleum Inc. Upon completion of this offering, EnCap and its affiliates will initially own a     % indirect interest in us through OAS Holdco, the selling stockholder in this offering, based on an assumed initial public offering price of $      per share. In addition, members of our management will initially own an aggregate     % interest in us through direct ownership of our common stock and through their indirect interest in OAS Holdco. For more information on our reorganization and the ownership of our common stock by our principal and selling stockholders, see “Corporate Reorganization” and “Principal and Selling Stockholders.”


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The following diagrams indicate our current ownership structure and our ownership structure after giving effect to our corporate reorganization and this offering based on an assumed initial public offering price of $      per share.
 
[Structure Diagram]
 
Corporate Information
 
Our principal executive offices are located at 1001 Fannin Street, Suite 202, Houston, Texas 77002, and our telephone number at that address is (713) 574-1770. We expect to have an operational website concurrently with the completion of this offering. Information on our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.


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THE OFFERING
 
Common stock offered by Oasis Petroleum Inc.
          shares
 
Common stock offered by the selling stockholder
          shares (          shares if the underwriters’ over-allotment is exercised in full)
 
  Total common stock offered
          shares (          shares if the underwriters’ over allotment is exercised in full)
 
Common stock to be outstanding after the offering
          shares
 
Common stock owned by the selling stockholder after the offering
          shares (           shares if the underwriters’ over-allotment is exercised in full)
 
Over-allotment option
The selling stockholder has granted the underwriters a 30-day option to purchase up to an aggregate of           additional shares of our common stock to cover over-allotments.
 
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. Each $1.00 increase (decrease) in the public offering price would increase (decrease) our net proceeds by approximately $      million. We intend to use a portion of net proceeds from this offering to repay a $      million note payable held by OAS Holdco that was incurred in connection with our corporate reorganization and all outstanding indebtedness under our revolving credit facility, approximately $30.0 million of which was outstanding on April 9, 2010. The remaining proceeds of approximately $      million will be used to fund our exploration and development program. We will not receive any proceeds from the sale of shares by the selling stockholder; however, EnCap, certain of its affiliates, certain of our executive officers and affiliates of certain of the underwriters will indirectly receive proceeds from such sale as a result of a distribution of proceeds by the selling stockholder to its members. Affiliates of certain of the underwriters are lenders under our revolving credit facility and, accordingly, will receive a portion of the proceeds of this offering. See “Use of Proceeds,” “Corporate Reorganization” and “Underwriters.”
 
Dividend policy
We do not anticipate paying any cash dividends on our common stock. In addition, our revolving credit facility prohibits us from paying cash dividends. See “Dividend Policy.”
 
Risk factors
You should carefully read and consider the information beginning on page 13 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.
 
New York Stock Exchange symbol
OAS


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Summary Historical Consolidated and Unaudited Pro Forma Financial Data
 
You should read the following summary financial data in conjunction with “Selected Historical Consolidated and Unaudited Pro Forma Financial Data,” “Corporate Reorganization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical consolidated financial statements and unaudited pro forma financial information and related notes thereto included elsewhere in this prospectus. The financial information included in this prospectus may not be indicative of our future results of operations, financial position and cash flows.
 
Set forth below is our summary historical consolidated financial data for the period from February 26, 2007, the date of inception of Oasis Petroleum LLC, through December 31, 2007, the years ended December 31, 2008 and 2009 and balance sheet data at December 31, 2008 and 2009, all of which have been derived from the audited financial statements of Oasis Petroleum LLC included elsewhere in this prospectus. The balance sheet data at December 31, 2007 has been derived from the audited financial statements of Oasis Petroleum LLC not included elsewhere in this prospectus. The unaudited pro forma financial data for the year ended December 31, 2009, which reflects the effects of the acquisition of interests in certain oil and gas properties from Kerogen Resources, Inc., is derived from the unaudited pro forma financial information included elsewhere in this prospectus. The unaudited pro forma financial information has been prepared as if the acquisition had taken place on January 1, 2009.
 
                                 
    Historical        
    Period from
                Pro Forma Year
 
    February 26, 2007
    Year Ended
    Ended
 
    (Inception) through
    December 31,     December 31,
 
    December 31, 2007     2008     2009     2009  
    (In thousands)  
 
Statement of operations data:
                               
Oil and gas revenues
  $ 13,791     $ 34,736     $ 37,755     $ 41,999  
Expenses:
                               
Lease operating expenses
    2,946       7,073       8,691       10,274  
Production taxes
    1,211       3,001       3,810       4,160  
Depreciation, depletion and amortization
    4,185       8,686       16,670       19,233  
Exploration expenses
    1,164       3,222       1,019       1,019  
Rig termination(1)
                3,000       3,000  
Impairment of oil and gas properties(2)
    1,177       47,117       6,233       6,233  
Gain on sale of properties
                (1,455 )     (1,455 )
General and administrative expenses
    3,181       5,452       9,342       9,342  
                                 
Total expenses
  $ 13,864     $ 74,551     $ 47,310     $ 51,806  
                                 
Operating loss
    (73 )     (39,815 )     (9,555 )     (9,807 )
Other income (expense):
                               
Change in unrealized gain (loss) on derivative instruments
    (10,679 )     14,769       (7,043 )     (7,043 )
Realized gain (loss) on derivative instruments
    (1,062 )     (6,932 )     2,296       2,296  
Interest expense
    (1,776 )     (2,404 )     (912 )     (912 )
Other income (expense)
    40       (9 )     5       5  
                                 
Total other income (expense)
    (13,477 )     5,424       (5,654 )     (5,654 )
                                 
Net loss
  $ (13,550 )   $ (34,391 )   $ (15,209 )   $ (15,461 )
                                 
 
 
(1) For a discussion of our rig termination expenses, see Note 10 to our consolidated financial statements.
 
(2) In 2008, we recognized a $45.5 million non-cash impairment charge on our proved properties to reflect the impact of significantly lower oil prices and a $1.6 million impairment charge on our unproved properties due to expiring leases. See Note 2 to our consolidated financial statements.
 


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        As of
        December 31,
        2009
        As Further
    As of December 31,   Adjusted(1)
    2007   2008   2009   2009
    (In thousands)
 
Balance sheet data:
                               
Cash and cash equivalents
  $ 6,282     $ 1,570     $ 40,562     $    
Net property, plant and equipment
    92,918       114,220       181,573       181,573  
Total assets
    104,145       129,068       239,553          
Long-term debt
    46,500       26,000       35,000          
Total members’ equity
    36,350       82,459       171,850          
 
                         
    Period from
       
    February 26, 2007
       
    (Inception) through
  Year Ended December 31,
    December 31, 2007   2008   2009
    (In thousands)
 
Other financial data:
                       
Net cash provided by operating activities
  $ 2,284     $ 13,766     $ 6,148  
Net cash used in investing activities
    (91,988 )     (78,478 )     (80,756 )
Net cash provided by financing activities
    95,986       60,000       113,600  
Adjusted EBITDA(2)
    5,431       12,269       16,668  
 
 
(1) Includes the effect of our corporate reorganization and the effect of this offering as described in “Corporate Reorganization,” “Capitalization” and “Dilution.”
 
(2) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net loss and net cash provided by operating activities, see “— Non-GAAP Financial Measure” below.
 
Set forth below is historical financial data for the six months ended June 30, 2007 for properties acquired from Bill Barrett Corporation, which constitute the accounting predecessor to Oasis Petroleum LLC. The historical financial data for the six months ended June 30, 2007 have been derived from the audited statement of revenues and direct operating expenses for the properties acquired from Bill Barrett Corporation included elsewhere in this prospectus. Such statement does not reflect depreciation, depletion and amortization, general and administrative expenses, income taxes or interest expense.
 
         
    Predecessor  
    Six Months Ended
 
    June 30, 2007  
    (In thousands)  
 
Statement of operations data:
       
Oil and gas revenues
  $ 10,686  
Direct operating expenses
    3,490  
         
Excess of revenues over direct operating expenses
  $ 7,196  
         
 
Non-GAAP Financial Measure
 
Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.
 
We define Adjusted EBITDA as earnings before interest expense, income taxes, depreciation, depletion and amortization, property impairments, exploration expenses and unrealized derivative gains and losses.

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Adjusted EBITDA is not a measure of net income or cash flows as determined by United States generally accepted accounting principles, or GAAP.
 
Management believes Adjusted EBITDA is useful because it allows them 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 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 or cash flows from operating activities 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 measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.
 
The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measures of net loss and net cash provided by operating activities, respectively.
 
                         
    Period from
             
    February 26, 2007
    Year Ended
 
    (Inception) through
    December 31,  
    December 31, 2007     2008     2009  
    (In thousands)  
 
Adjusted EBITDA reconciliation to Net Loss:
                       
Net loss
  $ (13,550 )   $ (34,391 )   $ (15,209 )
Change in unrealized (gain) loss on derivative instruments
    10,679       (14,769 )     7,043  
Interest expense
    1,776       2,404       912  
Depreciation, depletion and amortization
    4,185       8,686       16,670  
Impairment of oil and gas properties
    1,177       47,117       6,233  
Exploration expenses
    1,164       3,222       1,019  
                         
Adjusted EBITDA
  $ 5,431     $ 12,269     $ 16,668  
                         
 
                         
    Period from
             
    February 26, 2007
    Year Ended
 
    (Inception) through
    December 31,  
    December 31, 2007     2008     2009  
    (In thousands)  
 
Adjusted EBITDA reconciliation to Net Cash Provided by Operating Activities:
                       
Net cash provided by operating activities
  $ 2,284     $ 13,766     $ 6,148  
Realized gain (loss) on derivative instruments
    (1,062 )     (6,932 )     2,296  
Interest expense
    1,776       2,404       912  
Exploration expenses
    1,164       1,942       1,019  
Gain on sale of properties
                1,455  
Debt discount amortization
    (61 )     (107 )     (95 )
Changes in working capital
    1,330       1,196       4,933  
                         
Adjusted EBITDA
  $ 5,431     $ 12,269     $ 16,668  
                         


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Summary Historical Operating and Reserve Data
 
The following table presents summary data with respect to our estimated net proved oil and natural gas reserves as of the dates indicated. For additional information regarding our reserves, as well as the impact of the SEC’s new rules governing the presentation of reserve information, see “Business.” The reserve estimates at December 31, 2007 and 2008 presented in the table below are based on reports prepared by W.D. Von Gonten & Co., independent reserve engineers, and were prepared consistent with the former rules and regulations of the Securities and Exchange Commission, or the SEC, regarding oil and natural gas reserve reporting in effect during such periods. The reserve estimates at December 31, 2009 presented in the table below are based on a report prepared by DeGolyer and MacNaughton, independent reserve engineers, and were prepared consistent with the SEC’s rules regarding oil and natural gas reserve reporting that are currently in effect.
 
                         
    At December 31,  
    2007     2008     2009  
 
Reserve Data(1):
                       
Estimated proved reserves:
                       
Oil (MMBbls)
    4.0       2.2       12.4  
Natural gas (Bcf)
    1.2       0.7       5.3  
Total estimated proved reserves (MMBoe)
    4.3       2.3       13.3  
Estimated proved developed (MMBoe)
    3.4       2.3       5.6  
Percent developed
    81 %     100 %     42 %
Estimated proved undeveloped (MMBoe)
    0.8             7.7  
PV-10 (in millions)(2)
  $ 121.8     $ 17.7     $ 133.5  
Standardized Measure (in millions)(3)
    121.8       17.7       133.5  
 
 
(1) Our estimated proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The index prices were $96.00/Bbl for oil and $7.16/MMBtu for natural gas at December 31, 2007, and $44.60/Bbl for oil and $5.63/MMBtu for natural gas at December 31, 2008, and the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $61.04/Bbl for oil and $3.87/MMBtu for natural gas at December 31, 2009. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
 
(2) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. However, our PV-10 and our Standardized Measure are equivalent because as of December 31, 2009, we were a limited liability company not subject to entity level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income is passed through to our equity holders. However, in connection with the closing of this offering, we will merge into a corporation that will become a holding company for Oasis Petroleum LLC. As a result, we will be treated as a taxable entity for federal income tax purposes and our future income taxes will be dependent upon our future taxable income. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. The PV-10 amounts included in the reports of W.D. Von Gonten & Co. at December 31, 2007 and at December 31, 2008 were $122.9 million and $19.2 million, respectively, because the PV-10 amounts included in such reports do not give effect to additional estimated plugging and abandonment costs.
 
(3) Standardized Measure represents the present value of estimated future net cash inflows from proved oil and natural gas reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses (if applicable), discounted at 10% per annum to reflect timing of future cash flows. In connection with the closing of this offering, we will merge into a corporation that will be treated


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as a taxable entity for federal income tax purposes. Future calculations of Standardized Measure will include the effects of income taxes on future net revenues. For further discussion of income taxes, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
 
The following table sets forth summary data with respect to our production results, average sales prices and production costs on a historical basis for the periods presented:
 
                                   
          Oasis Petroleum LLC
    Predecessor     Period from
       
    January 1, 2007
    February 26, 2007
  Year Ended
    through
    (Inception) through
  December 31,
    June 30, 2007(1)     December 31, 2007(2)   2008   2009
Operating data:
                                 
Net production volumes:
                                 
Oil (MBbls)
    190         159       379       658  
Natural gas (MMcf)
    69         73       123       326  
Oil equivalents (MBoe)
    202         171       400       712  
Average daily production (Boe/d)
              929       1,092       1,950  
Average sales prices:
                                 
Oil, without realized derivatives (per Bbl)
  $ 53.73       $ 83.96     $ 88.07     $ 55.32  
Oil, with realized derivatives(3) (per Bbl)
              77.27       69.79       58.82  
Natural gas (per Mcf)
    6.87         6.25       10.91       4.24  
Costs and expenses (per Boe of production):
                                 
Lease operating expenses
  $ 12.79       $ 17.23     $ 17.70     $ 12.21  
Production taxes
    4.49         7.08       7.51       5.35  
Depreciation, depletion and amortization
              24.47       21.73       23.42  
General and administrative expenses
              18.60       13.64       13.12  
 
 
(1) The historical financial data for the six months ended June 30, 2007 have been derived from the audited statement of revenues and direct operating expenses for the properties acquired from Bill Barrett Corporation included elsewhere in this prospectus. Such statement does not reflect depreciation, depletion and amortization, general and administrative expenses, income taxes or interest expense.
 
(2) For the period from February 26, 2007 through June 30, 2007, we did not engage in oil and gas operating or producing activities. Average daily production includes production from July 1, 2007 through December 31, 2007.
 
(3) Realized prices include realized gains or losses on cash settlements for our commodity derivatives, which do not qualify for hedge accounting. We have not made any estimates of the impact of commodities derivatives on the average sales price for our predecessor.


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RISK FACTORS
 
You should carefully consider the risks described below before making an investment decision. Our business, financial condition or results of operations could be materially adversely affected by any of these risks. The trading price of our common stock could decline due to any of these risks, and you may lose all or part of your investment.
 
Risks Related to the Oil and Natural Gas Industry and Our Business
 
A substantial or extended decline in oil and, to a lesser extent, natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.
 
The price we receive for our oil and, to a lesser extent, natural gas, heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:
 
  •  worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;
 
  •  the actions of the Organization of Petroleum Exporting Countries, or OPEC;
 
  •  the price and quantity of imports of foreign oil and natural gas;
 
  •  political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America and Russia;
 
  •  the level of global oil and natural gas exploration and production;
 
  •  the level of global oil and natural gas inventories;
 
  •  localized supply and demand fundamentals and transportation availability;
 
  •  weather conditions and natural disasters;
 
  •  domestic and foreign governmental regulations;
 
  •  speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;
 
  •  price and availability of competitors’ supplies of oil and natural gas;
 
  •  technological advances affecting energy consumption; and
 
  •  the price and availability of alternative fuels.
 
Substantially all of our production is sold to purchasers under short-term (less than 12-month) contracts at market based prices. Lower oil and natural gas prices will reduce our cash flows, borrowing ability and the present value of our reserves. See also “— Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our oil and natural gas reserves.” Lower oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically and may affect our proved reserves. See also “— The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.”


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Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
 
Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit drilling locations or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “— Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:
 
  •  shortages of or delays in obtaining equipment and qualified personnel;
 
  •  facility or equipment malfunctions;
 
  •  unexpected operational events;
 
  •  pressure or irregularities in geological formations;
 
  •  adverse weather conditions, such as blizzards and ice storms;
 
  •  reductions in oil and natural gas prices;
 
  •  delays imposed by or resulting from compliance with regulatory requirements;
 
  •  proximity to and capacity of transportation facilities;
 
  •  title problems; and
 
  •  limitations in the market for oil and natural gas.
 
Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
 
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this prospectus. See “Business — Our Operations” for information about our estimated oil and natural gas reserves and the PV-10 and Standardized Measure of discounted future net revenues as of December 31, 2009.
 
In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Although the reserve information contained herein is reviewed by independent reserve engineers, estimates of oil and natural gas reserves are inherently imprecise.
 
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this prospectus. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are


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beyond our control. Due to the limited production history of our undeveloped acreage, the estimates of future production associated with such properties may be subject to greater variance to actual production than would be the case with properties having a longer production history.
 
The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.
 
You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. For the years ended December 31, 2007 and 2008, we based the estimated discounted future net revenues from our proved reserves on prices and costs in effect on the day of the estimate in accordance with previous SEC requirements. In accordance with new SEC requirements for the year ended December 31, 2009, we have based the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net revenues from our oil and natural gas properties will be affected by factors such as:
 
  •  actual prices we receive for oil and natural gas;
 
  •  actual cost of development and production expenditures;
 
  •  the amount and timing of actual production; and
 
  •  changes in governmental regulations or taxation.
 
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
 
Actual future prices and costs may differ materially from those used in the present value estimates included in this prospectus. If oil prices decline by $1.00 per Bbl, then our PV-10 as of December 31, 2009 would decrease approximately $4.9 million. If natural gas prices decline by $0.10 per Mcf, then our PV-10 as of December 31, 2009 would decrease approximately $0.3 million.
 
Our business is difficult to evaluate because we have a limited operating history.
 
In considering whether to invest in our common stock, you should consider that there is only limited historical financial and operating information available on which to base your evaluation of our performance. We were formed in February 2007 and, as a result, we have a limited operating history. We face challenges and uncertainties in financial planning as a result of the unavailability of historical data and uncertainties regarding the nature, scope and results of our future activities. New companies must develop successful business relationships, establish operating procedures, hire staff, install management information and other systems, establish facilities and obtain licenses, as well as take other measures necessary to conduct their intended business activities. We may not be successful in implementing our business strategies or in completing the development of the infrastructure necessary to conduct our business as planned. In the event that our development plan is not completed or is delayed, our operating results will be adversely affected and our operations will differ materially from the activities described in this prospectus. As a result of industry factors or factors relating specifically to us, we may have to change our methods of conducting business, which may cause a material adverse effect on our results of operations and financial condition.


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Part of our strategy involves drilling in existing or emerging shale plays using some of the latest available horizontal drilling and completion techniques. 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. As a result, we may incur material write-downs and the value of our undeveloped acreage could decline if drilling results are unsuccessful.
 
Operations in the Bakken and the Three Forks formations involve utilizing the latest drilling and completion techniques as developed by ourselves and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns. 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.
 
Our experience with horizontal drilling utilizing the latest drilling and completion techniques specifically in the Bakken and Three Forks formations is limited. 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 limited takeaway capacity or otherwise, and/or natural gas and oil prices decline, the return on our investment in these areas may not be as attractive as we anticipate and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.
 
Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our oil and natural gas reserves.
 
Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Our cash flows used in investing activities were $47.4 million related to capital and exploration expenditures for the year ended December 31, 2009. Our capital expenditure budget for 2010 is approximately $220 million, with approximately $179 million allocated for drilling and completion operations. To date, our capital expenditures have been financed with capital contributions from EnCap and other private investors, borrowings under our revolving credit facility and net cash provided by operating activities. DeGolyer and MacNaughton projects that we will incur capital costs in excess of $113 million in the next three years to develop the proved undeveloped reserves in the Williston Basin covered by its December 31, 2009 reserve report. Because these costs cover less than 12% of our total potential drilling locations, we will be required to generate or raise multiples of this amount of capital to develop all of our potential drilling locations should we elect to do so. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.
 
A significant improvement in product prices could result in an increase in our capital expenditures. We intend to finance our future capital expenditures primarily through cash flows provided by operating activities, borrowings under our revolving credit facility and net proceeds from this offering; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or additional equity securities or the sale of non-strategic assets. The issuance of additional debt may require that a portion of our cash flows provided by operating activities be used for the payment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of your common stock.


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Our cash flows provided by operating activities and access to capital are subject to a number of variables, including:
 
  •  our proved reserves;
 
  •  the level of oil and natural gas we are able to produce from existing wells;
 
  •  the prices at which our oil and natural gas are sold;
 
  •  the costs of developing and producing our oil and natural gas production;
 
  •  our ability to acquire, locate and produce new reserves;
 
  •  the ability and willingness of our banks to lend; and
 
  •  our ability to access the equity and debt capital markets.
 
If the borrowing base under our revolving credit facility or our revenues decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or cash available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in our oil and natural gas reserves, and could adversely affect our business, financial condition and results of operations.
 
If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties.
 
We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties, which may result in a decrease in the amount available under our revolving credit facility. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our ability to borrow under our revolving credit facility and our results of operations for the periods in which such charges are taken.
 
We will not be the operator on all of our drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.
 
We expect that we will not be the operator on approximately 48% of our identified gross drilling locations (approximately 18% of our identified net drilling locations). As we carry out our exploration and development programs, we may enter into arrangements with respect to existing or future drilling locations that result in a greater proportion of our locations being operated by others. As a result, we may have limited ability to exercise influence over the operations of the drilling locations operated by our partners. Dependence on the operator could prevent us from realizing our target returns for those locations. The success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:
 
  •  the timing and amount of capital expenditures;
 
  •  the operator’s expertise and financial resources;
 
  •  approval of other participants in drilling wells;
 
  •  selection of technology; and
 
  •  the rate of production of reserves, if any.


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This limited ability to exercise control over the operations of some of our drilling locations may cause a material adverse effect on our results of operations and financial condition.
 
Substantially all of our producing properties and operations are located in the Williston Basin region, making us vulnerable to risks associated with operating in one major geographic area.
 
As of December 31, 2009, approximately 99% of our proved reserves and approximately 96% of our production were located in the Williston Basin in northeastern Montana and northwestern North Dakota. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area. 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.
 
Our business depends on oil and natural gas gathering and transportation facilities, most of which are owned by third parties.
 
The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties. The unavailability of, or lack of, available capacity on these systems and facilities could result in the shut-in of producing wells or the delay, or discontinuance of, development plans for properties. See also “— Delays and interruptions of production from our wells due to marketing and transportation constraints in the Williston Basin could cause significant fluctuations in our realized oil and natural gas prices.” We generally do not purchase firm transportation on third party facilities and, therefore, the transportation of our production can be interrupted by those having firm arrangements. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport our oil and natural gas.
 
The disruption of third-party facilities due to maintenance and/or weather could also negatively impact our ability to market and deliver our products. We have no control over when or if such facilities are restored or what prices will be charged. A total shut-in of production could materially affect us due to a lack of cash flow, and if a substantial portion of the production is hedged at lower than market prices, those financial hedges would have to be paid from borrowings absent sufficient cash flow.
 
Delays and interruptions of production from our wells due to marketing and transportation constraints in the Williston Basin could cause significant fluctuations in our realized oil and natural gas prices.
 
The Williston Basin crude oil marketing and transportation environment has historically been characterized by periods when oil production has surpassed local transportation and refining capacity, resulting in substantial discounts in the price received for crude oil versus prices quoted for West Texas Intermediate (WTI) crude oil. For example, the difference between the WTI crude oil price and the Tesoro North Dakota Sweet oil price as of December, 2008 and 2009 was $14.80 per Bbl and $10.29 per Bbl, respectively. Such fluctuations and discounts could have a material adverse effect on our financial condition and results of operations.


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The development of our proved undeveloped reserves in the Williston Basin and other areas of operation may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.
 
Approximately 58% of our total proved reserves were classified as proved undeveloped as of December 31, 2009. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such 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.
 
Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.
 
Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.
 
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.
 
Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.
 
Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.
 
Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends, in substantial part, on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third-parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of crude oil or natural gas pipelines or gathering system capacity. If our production becomes shut-in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market.
 
We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
 
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and


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natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:
 
  •  environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;
 
  •  abnormally pressured formations;
 
  •  mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
 
  •  personal injuries and death; and
 
  •  natural disasters.
 
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:
 
  •  injury or loss of life;
 
  •  damage to and destruction of property, natural resources and equipment;
 
  •  pollution and other environmental damage;
 
  •  regulatory investigations and penalties;
 
  •  suspension of our operations; and
 
  •  repair and remediation costs.
 
We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
 
Drilling locations that we decide to drill may not yield oil or natural gas in commercially viable quantities.
 
We describe some of our drilling locations and our plans to explore those drilling locations in this prospectus. Our drilling locations are in various stages of evaluation, ranging from a location which is ready to drill to a location that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. 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, 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 Williston Basin may not be indicative of future or long-term production rates. In sum, the cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.
 
We have incurred losses from operations during certain periods since our inception and may continue to do so in the future.
 
We incurred net losses of $15.2 million and $34.4 million for the years ended December 31, 2009 and 2008, respectively, and $13.6 million in the period from February 26, 2007 (inception) through December 31, 2007. 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


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prospectus may impede our ability to economically find, develop, exploit 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.
 
Our potential drilling location inventories are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our potential drilling locations.
 
Our management has identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. As of December 31, 2009, only 86 of our 469 specifically identified potential future gross drilling locations were attributed to proved undeveloped reserves. These potential drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, costs and drilling results. Because of these uncertainties, we do not know if the numerous 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. Pursuant to a new SEC rule and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This new rule and guidance may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program.
 
Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In the highly competitive market for acreage, failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.
 
Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. As of December 31, 2009, we had leases representing 45,640 net acres expiring in 2010, 59,559 net acres expiring in 2011, and 31,642 net acres expiring in 2012. 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. In addition, on certain portions of our acreage, third-party leases become immediately effective if our leases expire. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business.
 
Our operations are subject to environmental and operational safety laws and regulations that may expose us to significant costs and liabilities.
 
Our oil and natural gas exploration and production operations are subject to stringent and complex federal, state and local laws and regulations governing health and safety aspects of our operations, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations including the acquisition of a permit before conducting drilling or underground injection activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of our operations.
 
There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons and wastes, because of air emissions and waste


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water discharges related to our operations, and as a result of historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we could be subject to joint and several, strict liability for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or if the operations were not in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, the risk of accidental spills or releases could expose us to significant liabilities that could have a material adverse effect on our financial condition or results of operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs from insurance.
 
Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that we produce while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.
 
On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Consequently, the EPA proposed two sets of regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and, also, could trigger permit review for greenhouse gas emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. On March 23, 2010, the EPA announced a proposal to expand its final rule on greenhouse gas emissions reporting to include owners and operators of onshore oil and natural gas production. If the proposed rule is finalized in its current form, monitoring those newly covered sources would commence on January 1, 2011. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas we produce.
 
Also, on June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, or ACESA, which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases including carbon dioxide and methane that may contribute to warming of the Earth’s atmosphere and other climatic changes. ACESA would require a 17 percent reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80 percent reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions and President Obama has indicated his support of legislation to reduce greenhouse gas emissions through an emission allowance system. Although it is not possible at this time to predict when the Senate may act on climate change legislation or how any bill passed by the Senate would be reconciled with ACESA, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.


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Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our exploration and production operations. Significant physical effects of climate change could also have an indirect affect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses, or costs that may result from potential physical effects of climate change.
 
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
 
The U.S. Congress is considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing is an important and commonly used process in the completion of unconventional oil and natural gas wells in shale and tight sand formations. This process involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. Sponsors of these bills, which are currently pending in the Energy and Commerce Committee and the Environmental and Public Works Committee of the House of Representatives and Senate, respectively, have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could 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. These bills, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. Moreover, the EPA announced on March 18, 2010 that it has allocated $1.9 million in 2010 and has requested funding in fiscal year 2011 for conducting a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. Consequently, even if these bills are not adopted this year, the performance of the hydraulic fracturing study by the EPA could spur further action at a later date towards federal legislation and regulation of hydraulic fracturing activities.
 
Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.
 
Our ability to acquire additional drilling locations and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing equipment and trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory drilling locations or to identify, evaluate, bid for and purchase a greater number of properties and locations than our financial or personnel resources permit. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful drilling attempts, sustained periods of volatility in financial markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which would adversely affect our competitive position. In addition, companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased over the past few years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.


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The loss of senior management or technical personnel could adversely affect our operations.
 
To a large extent, we depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel, including Thomas B. Nusz, our Chairman, President and Chief Executive Officer, and Taylor L. Reid, our Executive Vice President and Chief Operating Officer, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.
 
Seasonal weather conditions adversely affect our ability to conduct drilling activities in some of the areas where we operate.
 
Oil and natural gas operations in the Williston Basin are adversely affected by seasonal weather conditions. In the Williston Basin, drilling and other oil and natural gas activities cannot be conducted as effectively during the winter months. Severe winter weather conditions limit and may temporarily halt our ability to operate during such conditions. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operating and capital costs.
 
Our derivative activities could result in financial losses or could reduce our income.
 
To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently, and may in the future, enter into derivative arrangements for a portion of our oil and natural gas production, including collars and fixed-price swaps. We have not designated any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.
 
Derivative arrangements also expose us to the risk of financial loss in some circumstances, including when:
 
  •  production is less than the volume covered by the derivative instruments;
 
  •  the counter-party to the derivative instrument defaults on its contract obligations; or
 
  •  there is an increase in the differential between the underlying price in the derivative instrument and actual prices received.
 
In addition, these types of derivative arrangements limit the benefit we would receive from increases in the prices for oil and natural gas and may expose us to cash margin requirements.
 
The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.
 
We enter into derivative contracts in order to hedge a portion of our oil production. Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. ACESA contains provisions that would prohibit private energy commodity derivative and hedging transactions. ACESA would expand the power of the Commodity Futures Trading Commission, or the CFTC, to regulate derivative transactions related to energy commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through registered derivative clearing organizations. Under ACESA, the CFTC’s expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The CFTC is considering whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products. The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants. Separately, two committees of the House of Representatives, the Financial Services and Agriculture Committees, acted on October 15, 2009 and October 21, 2009, respectively, to adopt legislation that would impose comprehensive regulation on the over-the-counter (OTC) derivatives marketplace. This legislation would subject swap dealers and major swap


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participants to substantial supervision and regulation, including capital standards, margin requirements, business conduct standards, and recordkeeping and reporting requirements. It also would require central clearing for transactions entered into between swap dealers or major swap participants, and would provide the CFTC with authority to impose position limits in the OTC derivatives markets. A major swap participant generally would be someone other than a dealer who maintains a “substantial” position in outstanding swaps other than swaps used for commercial hedging, or whose positions create substantial exposure to its counterparties or the system. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any climate change bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.
 
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 acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Recent and 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.
 
Our revolving credit facility contains certain covenants that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions, which could adversely affect our ability to meet our future goals.
 
Our revolving credit facility includes certain covenants that, among other things, restrict:
 
  •  our investments, loans and advances and the payment of dividends and other restricted payments;
 
  •  our incurrence of additional indebtedness;
 
  •  the granting of liens, other than liens created pursuant to the revolving credit facility and certain permitted liens;
 
  •  mergers, consolidations and sales of all or a substantial part of our business or properties;
 
  •  the hedging, forward sale or swap of our production of crude oil or natural gas or other commodities;
 
  •  the sale of assets (other than production sold in the ordinary course of business); and
 
  •  our capital expenditures.
 
Our revolving credit facility requires us to maintain certain financial ratios, such as leverage ratios. All of these restrictive covenants may restrict our ability to expand or pursue our business strategies. Our ability to comply with these and other provisions of our revolving credit facility may be impacted by changes in economic or business conditions, results of operations or events beyond our control. The breach of any of these covenants could result in a default under our revolving credit facility, in which case, depending on the actions taken by the lenders thereunder or their successors or assignees, such lenders could elect to declare all amounts borrowed under our revolving credit facility, together with accrued interest, to be due and payable. If we were unable to repay such borrowings or interest, our lenders could proceed against their collateral. If the indebtedness under our revolving credit facility were to be accelerated, our assets may not be sufficient to repay in full such indebtedness.


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Our level of indebtedness may increase and reduce our financial flexibility.
 
Upon the completion of this offering, we expect to have no indebtedness outstanding and will have a borrowing capacity of $70 million under our revolving credit facility. 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.
 
In addition, our bank borrowing base is subject to periodic redeterminations. We could be forced to repay a portion of our bank borrowings due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.
 
The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results.
 
Our principal exposures to credit risk are through receivables resulting from the sale of our oil and natural gas production ($9.1 million in receivables at December 31, 2009), which we market to energy marketing companies, refineries and affiliates, advances to joint interest parties ($4.6 million at December 31, 2009), joint interest receivables ($1.3 million at December 31, 2009), and commodity derivatives contracts ($0.2 million at December 31, 2009).
 
We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. This concentration of customers may impact our overall credit risk since these entities may be similarly affected by changes in economic and other conditions. For the year ended December 31, 2008, sales to Tesoro Refining and Marketing Company and Texon L.P. accounted for approximately 57% and 14%, respectively, of our total sales. For the year ended December 31, 2009, sales to Tesoro Refining and


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Marketing Company and Texon L.P. accounted for approximately 32% and 30%, respectively, of our total sales. We do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
 
Joint interest receivables arise from billing entities who own a partial interest 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 have limited ability to control participation in our wells. In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties.
 
We may be subject to risks in connection with acquisitions and the integration of significant acquisitions may be difficult.
 
We periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:
 
  •  recoverable reserves;
 
  •  future oil and natural gas prices and their appropriate differentials;
 
  •  development and operating costs; and
 
  •  potential environmental and other liabilities.
 
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.
 
Significant acquisitions and other strategic transactions may involve other risks, including:
 
  •  diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;
 
  •  challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;
 
  •  difficulty associated with coordinating geographically separate organizations; and
 
  •  challenge of attracting and retaining personnel associated with acquired operations.
 
The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.
 
If we fail to realize the anticipated benefits of a significant acquisition, our results of operations may be lower than we expect.
 
The success of a significant acquisition will depend, in part, on our ability to realize anticipated growth opportunities from combining the acquired assets or operations with those of ours. Even if a combination is successful, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices, or in oil and natural gas industry conditions, or by


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risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties. If we fail to realize the benefits we anticipate from an acquisition, our results of operations may be adversely affected.
 
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 adversely impact our ability in the future to increase production and reserves. There is no assurance that we will not suffer a monetary loss from title defects or title failure. 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.
 
Risks Relating to the Offering and our Common Stock
 
The initial public offering price of our common stock may not be indicative of the market price of our common stock after this offering. In addition, an active liquid trading market for our common stock may not develop and our stock price may be volatile.
 
Prior to this offering, our common stock was not traded on any market. An active and liquid trading market for our common stock may not develop or be maintained after this offering. Liquid and active trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. The initial public offering price will be negotiated between us, the selling stockholder and representatives of the underwriters, based on numerous factors which we discuss in the “Underwriters” section of this prospectus, and may not be indicative of the market price of our common stock after this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in the offering.
 
The following factors could affect our stock price:
 
  •  our operating and financial performance and drilling locations, including reserve estimates;
 
  •  quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;
 
  •  changes in revenue or earnings estimates or publication of reports by equity research analysts;
 
  •  speculation in the press or investment community;
 
  •  sales of our common stock by us, the selling stockholder or other stockholders, or the perception that such sales may occur;
 
  •  general market conditions, including fluctuations in commodity prices; and
 
  •  domestic and international economic, legal and regulatory factors unrelated to our performance.
 
The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock.


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Purchasers of common stock in this offering will experience immediate and substantial dilution of $      per share.
 
Based on an assumed initial public offering price of $      per share, purchasers of our common stock in this offering will experience an immediate and substantial dilution of $      per share in the pro forma as adjusted net tangible book value per share of common stock from the initial public offering price, and our pro forma as adjusted net tangible book value as of December 31, 2009 after giving effect to this offering would be $      per share. See “Dilution” for a complete description of the calculation of net tangible book value.
 
Because we are a relatively small company, the requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management; and we may be unable to comply with these requirements in a timely or cost-effective manner.
 
As a public company with listed equity securities, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the New York Stock Exchange, or the NYSE, with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to:
 
  •  institute a more comprehensive compliance function;
 
  •  design, establish, evaluate and maintain a system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;
 
  •  comply with rules promulgated by the NYSE;
 
  •  prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;
 
  •  establish new internal policies, such as those relating to disclosure controls and procedures and insider trading;
 
  •  involve and retain to a greater degree outside counsel and accountants in the above activities; and
 
  •  establish an investor relations function.
 
In addition, we also expect that being a public company subject to these rules and regulations will require us to accept less director and officer liability insurance coverage than we desire or to incur substantial costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our audit committee, and qualified executive officers.
 
In connection with past audits of our financial statements, our independent registered public accounting firm identified and reported audit adjustments to management. Certain audit adjustments were deemed to be the result of internal control deficiencies that constitute material weaknesses in our internal control over financial reporting. If one or more material weaknesses persist or if we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.
 
Prior to the completion of this offering, we have been a private company with limited accounting personnel to adequately execute our accounting processes and other supervisory resources with which to address our internal control over financial reporting. As such, we have not maintained an effective control environment in that the design and execution of our controls has not consistently resulted in effective review and supervision by individuals with financial reporting oversight roles. The lack of adequate staffing levels resulted in insufficient time spent on review and approval of certain information used to prepare our financial statements. We have concluded that these control deficiencies constitute a material weakness in our control


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environment. A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. The control deficiencies described above, at varying degrees of severity, contributed to the material weaknesses in the control environment as further described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations -Internal Controls and Procedures.”
 
In response, we have begun the process of evaluating our internal control over financial reporting, although we are in the early phases of our review and will not complete our review until well after this offering is completed. We cannot predict the outcome of our review at this time. During the course of the review, we may identify additional control deficiencies, which could give rise to significant deficiencies and other material weaknesses in addition to the material weaknesses previously identified. Although remediation efforts are still in progress, management has taken steps to address the causes of our audit adjustments and to improve our internal control over financial reporting, including the implementation of new accounting processes and control procedures and the identification of gaps in our skills base and expertise of the staff required to meet the financial reporting requirements of a public company.
 
We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes-Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a public company, we will need to upgrade our systems, including information technology, implement additional financial and management controls, reporting systems and procedures and hire additional accounting, finance and legal staff.
 
Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future and comply with the certification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act. Further, our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future. Any failure to remediate deficiencies and to develop or maintain effective controls, or any difficulties encountered in our implementation or improvement of our internal controls over financial reporting could result in material misstatements that are not prevented or detected on a timely basis, which could potentially subject us to sanctions or investigations by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information.
 
We do not intend to pay, and we are currently prohibited from paying, dividends on our common stock and, consequently, your only opportunity to achieve a return on your investment is if the price of our stock appreciates.
 
We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, we are currently prohibited from making any cash dividends pursuant to the terms of our revolving credit facility. Consequently, your only opportunity to achieve a return on your investment in us will be if the market price of our common stock appreciates, which may not occur, and you sell your shares at a profit. There is no guarantee that the price of our common stock that will prevail in the market after this offering will ever exceed the price that you pay.
 
Future sales of our common stock in the public market could lower our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.
 
We may sell additional shares of common stock in subsequent public offerings. We may also issue additional shares of common stock or convertible securities. After the completion of this offering, we will


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have            outstanding shares of common stock. This number includes           shares that we and the selling stockholder are selling in this offering (assuming no exercise of the underwriters’ over-allotment option), which may be resold immediately in the public market. Following the completion of this offering, the selling stockholder will own           shares, or     % of our total outstanding shares, and certain of our affiliates will own           shares,     % of our outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements between such parties and the underwriters described in “Underwriters,” but may be sold into the market in the future. We expect that the selling stockholder will be a party to a registration rights agreement with us which will require us to effect the registration of its shares in certain circumstances no earlier than 180 days after the date of this prospectus. The holders of the remaining           shares, or     % of our outstanding shares, are not subject to lock-up agreements and, subject to compliance with Rule 144 under the Securities Act, may sell such shares into the public market.
 
As soon as practicable after this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of           shares of our common stock issued or reserved for issuance under our stock incentive plan. Subject to the satisfaction of vesting conditions and the expiration of lock-up agreements, shares registered under this registration statement on Form S-8 will be available for resale immediately in the public market without restriction.
 
We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.
 
Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
 
Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:
 
  •  a classified board of directors, so that only approximately one-third of our directors are elected each year;
 
  •  limitations on the removal of directors; and
 
  •  limitations on the ability of our stockholders to call special meetings and establish advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders.
 
Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our board of directors.
 
The concentration of our capital stock ownership among our largest stockholders and their affiliates will limit your ability to influence corporate matters.
 
Upon completion of this offering (assuming no exercise of the underwriters’ over-allotment option), we anticipate that OAS Holdco, the selling stockholder, will own approximately     % of our outstanding common stock and EnCap and its affiliates will own     % of the selling stockholder (based on an assumed initial public offering price of $     per share). Consequently, EnCap and its affiliates will continue to have significant influence over all matters that require approval by our stockholders, including the election of


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directors and approval of significant corporate transactions. This concentration of ownership will limit your ability to influence corporate matters, and as a result, actions may be taken that you may not view as beneficial.
 
Furthermore, conflicts of interest could arise in the future between us, on the one hand, and EnCap and its affiliates, including its portfolio companies, on the other hand, concerning among other things, potential competitive business activities or business opportunities. EnCap is a private equity firm in the business of making investments in entities primarily in the U.S. oil and gas industry. As a result, EnCap’s existing and future portfolio companies which it controls may compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor.
 
We will be a “controlled company” within the meaning of the NYSE rules and, as a result, will qualify for and will rely on exemptions from certain corporate governance requirements.
 
Because OAS Holdco will own a majority of our outstanding common stock following the completion of this offering, we will be a “controlled company” as that term is set forth in Section 303A of the NYSE Listed Company Manual. Under the NYSE rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a “controlled company” and may elect not to comply with certain NYSE corporate governance requirements, including:
 
  •  the requirement that a majority of our board of directors consist of independent directors;
 
  •  the requirement that our nominating and corporate governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and
 
  •  the requirement that our compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.
 
These requirements will not apply to us as long as we remain a “controlled company.” Following this offering, we may utilize some or all of these exemptions. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE. EnCap’s significant ownership interest could adversely affect investors’ perceptions of our corporate governance.
 
Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.
 
On February 1, 2010, the White House released President Obama’s budget proposal for the fiscal year 2011, or the Budget Proposal. Among the changes recommended in the Budget Proposal is the elimination of certain key U.S. federal income tax preferences currently available to coal, oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for United States production activities, and (iv) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for, or development of, oil or gas within the United States.
 
It is unclear whether any such changes will actually be enacted or, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of the Budget Proposal or any other similar change in U.S. federal income tax law could affect certain tax deductions that are currently available with respect to oil and gas exploration and production and could negatively impact the value of an investment in our shares.


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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
 
This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
 
Forward-looking statements may include statements about our:
 
  •  business strategy;
 
  •  reserves;
 
  •  technology;
 
  •  cash flows and liquidity;
 
  •  financial strategy, budget, projections and operating results;
 
  •  oil and natural gas realized prices;
 
  •  timing and amount of future production of oil and natural gas;
 
  •  availability of drilling and production equipment;
 
  •  availability of oil field labor;
 
  •  the amount, nature and timing of capital expenditures, including future development costs;
 
  •  availability and terms of capital;
 
  •  drilling of wells;
 
  •  competition and government regulations;
 
  •  marketing of oil and natural gas;
 
  •  exploitation or property acquisitions;
 
  •  costs of exploiting and developing our properties and conducting other operations;
 
  •  general economic conditions;
 
  •  competition in the oil and natural gas industry;
 
  •  effectiveness of our risk management activities;
 
  •  environmental liabilities;
 
  •  counterparty credit risk;
 
  •  governmental regulation and taxation of the oil and natural gas industry;
 
  •  developments in oil-producing and natural gas-producing countries;
 
  •  uncertainty regarding our future operating results;
 
  •  estimated future net reserves and present value thereof; and
 
  •  plans, objectives, expectations and intentions contained in this prospectus that are not historical.
 
All forward-looking statements speak only as of the date of this prospectus. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this prospectus are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this prospectus. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.


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USE OF PROCEEDS
 
We will receive net proceeds of approximately $      million from the sale of the common stock offered by us, assuming an initial public offering price of $      per share (the midpoint of the price range set forth on the cover page of this prospectus) and after deducting estimated expenses and underwriting discounts and commissions of approximately $      million. We will not receive any of the proceeds from the sale of shares of our common stock by the selling stockholder.
 
We intend to use the net proceeds from this offering to:
 
  •  repay a $        million note payable held by OAS Holdco that was incurred as partial consideration for the assets being contributed to us in connection with our corporate reorganization;
 
  •  repay all outstanding indebtedness under our revolving credit facility; and
 
  •  fund our exploration and development program.
 
The note payable matures in           and bears interest at a rate of     % per annum. Our revolving credit facility matures in February 2014 and bears interest at a variable rate, which was approximately 4.0% per annum on a weighted-average basis as of April 9, 2010. Our outstanding borrowings under our revolving credit facility were incurred to fund exploration, development and other capital expenditures. Affiliates of certain of the underwriters are lenders under our revolving credit facility and, accordingly, will receive a portion of the proceeds from this offering.
 
We estimate that the selling stockholder will receive net proceeds of approximately $      million from the sale of           common shares in this offering based upon the assumed initial offering price of $      per share, after deducting underwriting discounts. If the underwriters’ over-allotment option is exercised in full, we estimate that the selling stockholder’s net proceeds will be approximately $      million. We will pay all expenses related to this offering, other than underwriting discounts and commissions related to the shares sold by the selling stockholder.
 
An increase or decrease in the initial public offering price of $1.00 per share of common stock would cause the net proceeds that we will receive from the offering, after deducting estimated expenses and underwriting discounts and commissions, to increase or decrease by approximately $      million.
 
EnCap and certain of its affiliates, certain of our executive officers and affiliates of certain of the underwriters will indirectly receive proceeds from the sale of common stock by the selling stockholder as a result of a distribution of proceeds by the selling stockholder to its members.
 
DIVIDEND POLICY
 
We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our results of operations, financial condition, capital requirements and investment opportunities. In addition, our revolving credit facility prohibits us from paying cash dividends.


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CAPITALIZATION
 
The following table sets forth the capitalization of Oasis Petroleum LLC and Oasis Petroleum Inc., as applicable, as of December 31, 2009,
 
  •  on an actual basis;
 
  •  on an as adjusted basis to give effect to the transactions described under “Corporate Reorganization” that will occur simultaneously with the closing of this offering; and
 
  •  on an as further adjusted basis to give effect to this offering and the application of the net proceeds as set forth under “Use of Proceeds.”
 
You should read the following table in conjunction with “Use of Proceeds,” “Selected Historical Consolidated and Unaudited Pro Forma Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical consolidated financial statements and unaudited pro forma financial information and related notes thereto appearing elsewhere in this prospectus.
 
                         
    As of December 31, 2009  
                As Further
 
    Actual     As Adjusted     Adjusted  
    (In thousands)  
 
Cash and cash equivalents(1)
  $ 40,562     $ 40,562     $  
                         
                         
Long-term debt, including current maturities:
                       
Revolving credit facility(2)
  $ 35,000     $ 35,000     $  
Note payable(3)
                   
                         
Total long-term debt
    35,000                
                         
Members’ / stockholders’ equity:
                       
Capital contributions
    235,000              
Common stock, $0.001 par value; no shares authorized, issued and outstanding (actual);           shares authorized (as adjusted and as further adjusted); shares issued and outstanding (as adjusted);           shares issued and outstanding (as further adjusted)
                   
Preferred stock, $0.001 par value; no shares authorized (actual); shares authorized (as adjusted and as further adjusted); no shares issued and outstanding
                 
Additional paid-in capital
          235,000          
Retained earnings (accumulated loss)(4)
    (63,150 )     (71,150 )        
                         
Total members’/stockholders’ equity
    171,850       163,850          
                         
Total capitalization
  $ 206,850     $ 198,850     $        
                         
 
(1) As of April 9, 2010, our cash and cash equivalents were $4.6 million.
 
(2) On February 26, 2010, we entered into an amended and restated revolving credit facility, which will have a borrowing base of $70 million upon the completion of this offering. Prior to amending and restating our revolving credit facility, we repaid substantially all outstanding indebtedness under our revolving credit facility with cash on hand. As of April 9, 2010, we had $30.0 million of indebtedness outstanding under our revolving credit facility. We intend to repay in full all amounts outstanding under our revolving credit facility with a portion of the net proceeds from this offering.
 
(3) Represents a $      million note payable held by OAS Holdco that was incurred in connection with our corporate reorganization. See “Corporate Reorganization.” We will repay in full all amounts outstanding under the note payable held by OAS Holdco with a portion of the net proceeds from this offering.
 
(4) In connection with our corporate reorganization, an estimated net deferred tax liability of approximately $8.0 million will be established for differences between the book and tax basis of our assets and liabilities and a corresponding expense will be recorded to net income from continuing operations.


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DILUTION
 
Purchasers of the common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. Our net tangible book value as of December 31, 2009, after giving pro forma effect to the transactions described under “Corporate Reorganization,” was approximately $      million, or $      per share of common stock. Pro forma net tangible book value per share is determined by dividing our pro forma tangible net worth (tangible assets less total liabilities) by the total number of outstanding shares of common stock that will be outstanding immediately prior to the closing of this offering. After giving effect to our corporate reorganization and the sale of the shares in this offering and assuming the receipt of the estimated net proceeds (after deducting estimated discounts and expenses of this offering), our adjusted pro forma net tangible book value as of December 31, 2009 would have been approximately $      million, or $      per share. This represents an immediate increase in the net tangible book value of $      per share to our existing stockholders and an immediate dilution (i.e., the difference between the offering price and the adjusted pro forma net tangible book value after this offering) to new investors purchasing shares in this offering of $      per share. The following table illustrates the per share dilution to new investors purchasing shares in this offering:
 
         
Assumed initial public offering price per share
  $        
Pro forma net tangible book value per share as of December 31, 2009 (after giving effect to our corporate reorganization)
       
Increase per share attributable to new investors in this offering
       
As adjusted pro forma net tangible book value per share after giving effect to our corporate reorganization and this offering
       
Dilution in pro forma net tangible book value per share to new investors in this offering
  $  
 
The following table summarizes, on an adjusted pro forma basis as of December 31, 2009, the total number of shares of common stock owned by existing stockholders and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing stockholders and to be paid by new investors in this offering at $           , the midpoint of the range of the initial public offering prices set forth on the cover page of this prospectus, calculated before deduction of estimated underwriting discounts and commissions:
 
                                         
    Shares Acquired   Total Consideration   Average Price
    Number   Percent   Amount   Percent   per Share
 
Existing stockholders(1)
            %   $         %   $    
New investors(2)
                               
Total
            %   $         %   $  
 
 
(1) The number of shares disclosed for the existing stockholders includes           shares being sold by the selling stockholder in this offering. The total consideration and average price per share represents the consideration paid net of the note payable in connection with our corporate reorganization. See “Corporate Reorganization.”
 
(2) The number of shares disclosed for the new investors does not include the           shares being purchased by the new investors from the selling stockholder in this offering.


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SELECTED HISTORICAL CONSOLIDATED AND UNAUDITED PRO FORMA FINANCIAL DATA
 
You should read the following selected financial data in conjunction with “Corporate Reorganization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical consolidated financial statements and unaudited pro forma financial information and related notes thereto included elsewhere in this prospectus. We believe that the assumptions underlying the preparation of our historical consolidated financial statements and unaudited pro forma financial data are reasonable. The financial information included in this prospectus may not be indicative of our future results of operations, financial position and cash flows.
 
Set forth below is our selected historical consolidated financial data for the period from February 26, 2007, the date of inception of Oasis Petroleum LLC, through December 31, 2007, the years ended December 31, 2008 and 2009 and balance sheet data at December 31, 2008 and 2009, all of which have been derived from the audited financial statements of Oasis Petroleum LLC included elsewhere in this prospectus. The balance sheet data at December 31, 2007 has been derived from the audited financial statements of Oasis Petroleum LLC not included elsewhere in this prospectus. The unaudited pro forma financial data for the year ended December 31, 2009, which reflects the effects of the acquisition of interests in certain oil and gas properties from Kerogen Resources, Inc., is derived from the unaudited pro forma financial information included elsewhere in this prospectus. The unaudited pro forma financial information has been prepared as if the acquisition had taken place on January 1, 2009.
 
                                 
    Historical        
    Period from
                Pro Forma Year
 
    February 26, 2007
    Year Ended
    Ended
 
    (Inception) through
    December 31,     December 31,
 
    December 31, 2007     2008     2009     2009  
    (In thousands)  
 
Statement of operations data:
                               
Oil and gas revenues
  $ 13,791     $ 34,736     $ 37,755     $ 41,999  
Expenses:
                               
Lease operating expenses
    2,946       7,073       8,691       10,274  
Production taxes
    1,211       3,001       3,810       4,160  
Depreciation, depletion and amortization
    4,185       8,686       16,670       19,233  
Exploration expenses
    1,164       3,222       1,019       1,019  
Rig termination(1)
                3,000       3,000  
Impairment of oil and gas properties(2)
    1,177       47,117       6,233       6,233  
Gain on sale of properties
                (1,455 )     (1,455 )
General and administrative expenses
    3,181       5,452       9,342       9,342  
                                 
Total expenses
    13,864       74,551       47,310       51,806  
                                 
Operating loss
    (73 )     (39,815 )     (9,555 )     (9,807 )
Other income (expense):
                               
Change in unrealized gain (loss) on derivative instruments
    (10,679 )     14,769       (7,043 )     (7,043 )
Realized gain (loss) on derivative instruments
    (1,062 )     (6,932 )     2,296       2,296  
Interest expense
    (1,776 )     (2,404 )     (912 )     (912 )
Other income (expense)
    40       (9 )     5       5  
                                 
Total other income (expense)
    (13,477 )     5,424       (5,654 )     (5,654 )
                                 
Net loss
  $ (13,550 )   $ (34,391 )   $ (15,209 )   $ (15,461 )
                                 
 
 
(1) For a discussion of our rig termination expenses, see Note 10 to our consolidated financial statements.
 
(2) In 2008, we recognized a $45.5 million non-cash impairment charge on our proved properties to reflect the impact of significantly lower oil prices and a $1.6 million impairment charge on our unproved properties due to expiring leases. See Note 2 to our consolidated financial statements.


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    As of December 31,
    2007   2008   2009
    (In thousands)
 
Balance sheet data:
                       
Cash and cash equivalents
  $ 6,282     $ 1,570     $ 40,562  
Net property, plant and equipment
    92,918       114,220       181,573  
Total assets
    104,145       129,068       239,553  
Long-term debt
    46,500       26,000       35,000  
Total members’ equity
    36,350       82,459       171,850  
 
                         
    Period from
       
    February 26, 2007
       
    (Inception) through
  Year Ended December 31,
    December 31, 2007   2008   2009
    (In thousands)
 
Other financial data:
                       
Net cash provided by operating activities
  $ 2,284     $ 13,766     $ 6,148  
Net cash used in investing activities
    (91,988 )     (78,478 )     (80,756 )
Net cash provided by financing activities
    95,986       60,000       113,600  
Adjusted EBITDA(1)
    5,431       12,269       16,668  
 
 
(1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net loss and net cash provided by operating activities, see “Summary Historical Consolidated and Unaudited Pro Forma Financial Data — Non-GAAP Financial Measure.”
 
Set forth below is historical financial data for the years ended December 31, 2005 and 2006 and the six months ended June 30, 2007 for properties acquired from Bill Barrett Corporation, which constitute the accounting predecessor to Oasis Petroleum LLC. The historical financial data for the years ended December 31, 2005 and 2006 was derived from the historical accounting records of Bill Barrett Corporation. The historical financial data for the six months ended June 30, 2007 have been derived from the audited statement of revenues and direct operating expenses for the properties acquired from Bill Barrett Corporation included elsewhere in this prospectus. Such statement does not reflect depreciation, depletion and amortization, general and administrative expenses, income taxes or interest expense.
 
                         
    Predecessor  
    Year Ended December 31,     Six Months Ended
 
    2005     2006     June 30, 2007  
    (In thousands)  
 
Statement of operations data:
                       
Oil and gas revenues
  $ 20,494     $ 25,207     $ 10,686  
Direct operating expenses
    4,283       5,872       3,490  
                         
Excess of revenues over direct operating expenses
  $ 16,211     $ 19,335     $ 7,196  
                         


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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this prospectus. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in oil and natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in the prospectus, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.”
 
Overview
 
We are an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources primarily in the Williston Basin. Since our inception, we have emphasized the acquisition of properties that provided current production and significant upside potential through further development. Our drilling activity is primarily directed toward projects that we believe can provide us with repeatable successes in the Bakken formation.
 
Our use of capital for acquisitions and development allows us to direct our capital resources to what we believe to be the most attractive opportunities as market conditions evolve. We have historically acquired properties that we believe will meet or exceed our rate of return criteria. For acquisitions of properties with additional development, exploitation and exploration potential, we have focused on acquiring properties that we expect to operate so that we can control the timing and implementation of capital spending. In some instances, we have acquired non-operated property interests at what we believe to be attractive rates of return either because they provided a foothold in a new area of interest or complemented our existing operations. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives. In addition, our willingness to acquire non-operated properties in new areas provides us with geophysical and geologic data that may lead to further acquisitions in the same area, whether on an operated or non-operated basis.
 
Our company was formed in February 2007. We began active oil and natural gas operations in July 2007 following the acquisition of properties in the Williston Basin consisting of approximately 175,000 net leasehold acres and approximately 1,000 Boe/d of then-current net production, substantially forming our core leasehold position in the West Williston project area. In May 2008, we entered into a farm-in and purchase arrangement under which we earned or acquired approximately 48,000 net leasehold acres, establishing our initial position in the East Nesson project area. In June 2009, we acquired approximately 40,000 net leasehold acres with then-current net production of approximately 800 Boe/d, approximately 83% of which was from the Williston Basin. This acquisition consolidated our acreage in the East Nesson project area and established our Sanish project area. In September 2009, we acquired an additional 46,000 net leasehold acres with then-current production of approximately 300 Boe/d. This acquisition further consolidated our acreage in the East Nesson project area. Our acquisitions were financed with a combination of borrowings under our revolving credit


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facility, cash flows provided by operating activities and capital contributions made by EnCap and other private investors.
 
                             
        Adjusted
    Production at
       
    Closing Date of
  Purchase Price(1)
    Acquisition
    Net Acreage at
 
Project Areas of Acquired Properties
 
Acquisition
  (In millions)     (Boe/d)     Acquisition  
 
West Williston(2)
  June 22, 2007   $ 83       1,000       175,000  
East Nesson(3)
  May 16, 2008     16             48,000  
East Nesson/Sanish
  June 15, 2009     27       800       40,000  
East Nesson
  September 30, 2009     11       300       46,000  
 
 
(1) Represents initial purchase price plus closing adjustments.
 
(2) For accounting purposes, results from our West Williston acquisition are included in our results of operations effective July 1, 2007.
 
(3) Our farm-in and purchase arrangement required an initial payment of $15.6 million and obligated us to spend $15.1 million of drilling costs on behalf of the other parties.
 
Because of our substantial recent acquisition activity, our discussion and analysis of our historical financial condition and results of operations for the periods discussed below may not necessarily be comparable with or applicable to our future results of operations. Our initial acquisition of properties in the Williston Basin was completed in June 2007 from Bill Barrett Corporation, which constitutes our accounting predecessor. Our historical results include the results from our recent acquisitions beginning on the closing dates indicated in the table above. See our unaudited pro forma financial information and related notes included elsewhere in this prospectus for more information about how our historical results of operations would have been affected had our June 2009 acquisition been completed on January 1, 2009.
 
Our 2009 activities included development and exploration drilling in each of our primary project areas. Our current activities are focused on evaluating and developing our asset base, optimizing our acreage positions and evaluating potential acquisitions. At December 31, 2009, based on the reserve report prepared by our independent reserve engineers, we had 13.3 MMBoe of estimated net proved reserves with a PV-10 of $133.5 million and a Standardized Measure of $133.5 million. At December 31, 2008, we had 2.3 MMBoe of estimated net proved reserves with a PV-10 of $17.7 million and a Standardized Measure of $17.7 million. Our estimated proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $61.04/Bbl for oil and $3.87/MMBtu for natural gas at December 31, 2009, and the index prices were $44.60/Bbl for oil and $5.63/MMBtu for natural gas at December 31, 2008. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
 
Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.
 
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 gas activities, commodity prices have experienced significant fluctuations. Our quarterly average net realized oil prices are shown in the table below.
 


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                    Year
                  Year
                    Ended
                  Ended
    2008   December 31,
  2009   December 31,
    Q1   Q2   Q3   Q4   2008   Q1   Q2   Q3   Q4   2009
 
Average Realized Oil Prices($/bbl)(1)
  $ 88.65     $ 114.30     $ 108.73     $ 44.99     $ 69.79     $ 30.68     $ 52.47     $ 57.00     $ 65.09     $ 58.82  
Average Price Differential(2)
    9%       8%       8%       23%       11%       29%       13%       17%       14%       17%  
 
 
(1) Realized oil prices do not include the effect of realized derivative contract settlements.
 
(2) Price differential compares realized oil prices to West Texas Intermediate crude index prices.
 
The effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas such as the Williston Basin. In general, higher commodity prices and higher production rates from the application of new technology caused drilling activity in the Williston Basin to increase over the course of 2007 and 2008 before peaking in the fourth quarter of 2008 with over 90 active drilling rigs in the Williston Basin. This level of drilling activity resulted in record levels of oil production by early 2009 and the aggregate Williston Basin oil production temporarily exceeded the takeaway capacity that transports the oil to refining markets both inside and outside of the basin. As a result, the price differential, or Williston Basin discount, between our realized prices as compared to the West Texas Intermediate crude oil index price averaged approximately 23% and 29% in the fourth quarter of 2008 and the first quarter of 2009, respectively. By comparison, our Williston Basin discount averaged approximately 11% and 17% for the year ended December 31, 2008 and the year ended December 31, 2009, respectively.
 
The global and national financial crisis of late 2008 and 2009 reduced overall commodity demand. The combination of reduced oil demand and oil oversupply in the Williston Basin caused a significant decline in our realized crude oil prices during the fourth quarter of 2008 and the first quarter of 2009. Due to the decline in commodity prices and the large increases in realized price differentials, drilling rig activity declined to approximately 30 active rigs in the Williston Basin by the second quarter of 2009.
 
Changes in commodity prices may also significantly affect the economic viability of drilling projects as well as the economic valuation and economic recovery of oil and gas reserves. From December 31, 2007 to December 31, 2008, our standardized measure of discounted future net cash flows attributable to proved oil and natural gas reserves declined from $121.8 million to $17.7 million primarily due to net decreases of both value and reserve quantities from the decline in oil and gas commodity prices described above.
 
During the fourth quarter of 2008, we also recorded a $45.5 million charge to recognize an impairment to the carrying value of our proved oil and gas properties as a result of the decline in oil and gas commodity prices. In response to the commodity pricing environment in the fourth quarter of 2008, we reduced our planned 2009 capital expenditure program and also initiated discussions for early termination of two of our drilling rig contracts. In addition, although we drilled ten wells in the second half of 2008, we elected to delay the completion of five of the wells until mid 2009, as a result of lower commodity prices without a corresponding decrease in completion costs available from our vendors. We subsequently completed these wells in mid 2009 when completion costs were significantly lower.
 
While we experienced reduced cash flows from operations during this period due to lower oil and gas commodity prices, we had access to $69.6 million of remaining private equity funding capacity and $3.5 million of unused borrowing base capacity at December 31, 2008 under our previous revolving credit facility. Our financial position allowed us to pursue the preservation of our leasehold acreage positions by extending leases and purchasing leases instead of drilling. In addition, we maintained the financial capacity to endure the downturn in the commodity and financial markets as well as to position ourselves for acquisitions in 2009.

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Oil and gas prices for 2009 increased significantly from the fourth quarter of 2008. The higher commodity prices, as well as continued successes in the application of completion technologies in the Bakken formation, caused the active drilling rig count in the Williston Basin to exceed 100 rigs at March 31, 2010. Although additional Williston Basin transportation takeaway capacity was added in 2009, we believe that the expected production increases from the elevated 2010 drilling activity may cause price differentials to exceed the historical average range of approximately 10% to 15% of the West Texas Intermediate crude oil index price.
 
Sources of our revenue
 
Our revenues are derived from the sale of oil and natural gas production and do not include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.
 
The following table summarizes our revenues and production data for the periods indicated.
 
                                   
    Predecessor       Oasis Petroleum LLC  
            Period from
             
    January 1, 2007
      February 26, 2007
    Year Ended
 
    through
      (Inception) through
    December 31,  
    June 30, 2007(1)       December 31, 2007(2)     2008     2009  
Operating results (in thousands):
                                 
Revenues
                                 
Oil
  $ 10,211       $ 13,335     $ 33,396     $ 36,376  
Natural gas
    475         456       1,340       1,379  
                                   
Total oil and gas revenues
  $ 10,686       $ 13,791     $ 34,736     $ 37,755  
Production data:
                                 
Oil (MBbls)
    190         159       379       658  
Natural gas (MMcf)
    69         73       123       326  
Oil equivalents (MBoe)
    202         171       400       712  
Average daily production (Boe/d)
              929       1,092       1,950  
Average sales prices:
                                 
Oil, without realized derivatives (per Bbl)
  $ 53.73       $ 83.96     $ 88.07     $ 55.32  
Oil, with realized derivatives (3) (per Bbl)
              77.27       69.79       58.82  
Natural gas (per Mcf)
    6.87         6.25       10.91       4.24  
 
 
(1) The historical financial data for the six months ended June 30, 2007 have been derived from the audited statement of revenues and direct operating expenses for the properties acquired from Bill Barrett Corporation included elsewhere in this prospectus.
 
(2) For the period from February 26, 2007 through June 30, 2007, we did not engage in oil and gas operating or producing activities. Average daily production includes production from July 1, 2007 through December 31, 2007.
 
(3) Realized prices include realized gains or losses on cash settlements for commodity derivatives, which do not qualify for hedge accounting. We have not made any estimates of the impact of commodities derivatives on the average sales price for our predecessor.
 
Year ended December 31, 2009 as compared to year ended December 31, 2008
 
Oil and Natural Gas Revenues.  Our oil and natural gas sales revenues increased $3.0 million, or 9%, to $37.8 million during the year ended December 31, 2009 as compared to the year ended December 31, 2008.


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Our revenues are a function of oil and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 858 Boe per day or 79% to 1,950 Boe per day during the year ended December 31, 2009 as compared to the year ended December 31, 2008. The increase in average daily production sold was primarily due to the Sanish and East Nesson acquisitions completed in 2009, which contributed approximately 380 Boe per day, and well completions in our Sanish and East Nesson project areas, which contributed 168 Boe per day and 213 Boe per day, respectively. This $16.2 million revenue increase attributable to higher production sold was almost entirely offset by a $13.2 million revenue reduction attributable to lower oil sales prices during the year ended December 31, 2009. Average oil sales prices, without realized derivatives, declined by $32.75 per barrel or 37% to an average of $55.32 per barrel for the year ended December 31, 2009 as compared to the year ended December 31, 2008.
 
Year ended December 31, 2008 as compared to period from February 26, 2007 (Inception) through December 31, 2007
 
Oil and Natural Gas Revenues.  Our oil and natural gas sales revenues increased $20.9 million, or 152%, to $34.7 million for the year ended December 31, 2008 compared to the period from February 26, 2007 (inception) through December 31, 2007. This increase was primarily a result of production from properties acquired in our West Williston project area, which we owned for all of 2008 as compared to only the last six months in 2007. Average oil sales prices, without realized derivatives, increased by $4.11 per barrel or 5% to an average of $88.07 per barrel for the year ended December 31, 2008 as compared to the period ended December 31, 2007.
 
When comparing our revenue for the period from February 26, 2007 (inception) through December 31, 2007 to our predecessor’s revenues for the period from January 1 through June 30, 2007, our revenues increased by $3.1 million or 29% to $13.8 million. The revenue increase is primarily due to average oil sales prices, without realized derivatives, that increased by $30.23 per barrel or 56% to an average of $83.96 per barrel.
 
Expenses
 
  •  Lease operating expenses.  Lease operating expenses 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 field personnel compensation, utilities, 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 market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities. We take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues.
 
  •  Depreciation, depletion and amortization.  Depreciation, depletion and amortization includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas. As a successful efforts company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, and allocate these costs to each unit of production using the units-of-production method.
 
  •  Exploration expenses.  Exploration expenses consist of exploratory dry hole expenses and costs incurred in evaluating areas that are considered to have prospective oil and natural gas reserves, including costs for topographical, geological and geophysical studies, rights of access to properties and costs of carrying and retaining undeveloped properties, such as delay rentals.
 
  •  Impairment of unproved and proved properties.  These costs include unproved property impairment and costs associated with lease expirations. We could also record impairment charges for proved properties if the carrying value exceeds estimated future cash flows. See “— Impairment of proved properties.”


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  •  General and administrative expenses.  General and administrative expenses include 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 professional fees and legal compliance.
 
Other Income (Expense)
 
  •  Change in unrealized gain (loss) on derivative instruments.  We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the price of crude oil and natural gas. This account activity represents the recognition of gains and losses associated with our open derivative contracts as commodity prices and commodity derivative contracts change.
 
  •  Realized gain (loss) on derivative instruments, net.  We utilize commodity derivative instruments to reduce our exposure to fluctuations in the price of crude oil and natural gas. The account activity represents our realized gains and losses on the settlement of these commodity derivative instruments.
 
  •  Interest expense.  We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our revolving credit facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to the lenders under our revolving credit facility in interest expense. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees as interest expense.
 
  •  Income tax expense.  As of December 31, 2009, we were a limited liability company not subject to entity level income tax. Accordingly, no provision for federal or state corporate income taxes has been provided for the year ended December 31, 2009 or prior years because taxable income is allocated directly to our equity holders. In connection with the closing of this offering, we will merge into a corporation that will be subject to federal and state entity-level taxation. In connection with our corporate reorganization, a net deferred tax liability will be established for differences between the tax and book basis of our assets and liabilities and a corresponding “first day” tax expense will be recorded to net income from continuing operations. We estimate the net deferred tax liability to be approximately $8.0 million. We do not expect to report any income tax benefit or expense for 2010. Based on our history of losses since inception and deductions primarily related to intangible drilling costs, or IDCs, that are expected to exceed 2010 earnings, we expect to generate net tax benefits in our income statement and record tax assets on our balance sheet. However, due to uncertainty about our ability to ultimately realize our tax benefits, we will record a full valuation allowance against the tax assets which offsets the net tax benefits. We may report and pay state income or franchise taxes in periods where our IDC deductions do not exceed our taxable income or where state income or franchise taxes are determined on another basis.


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The following table summarizes our operating expenses for the periods indicated.
 
                                   
            Oasis Petroleum LLC  
    Predecessor       Period from
             
    January 1, 2007
      February 26, 2007
    Year Ended
 
    through
      (Inception) through
    December 31,  
    June 30, 2007(1)       December 31, 2007(2)     2008     2009  
    (In thousands, except production cost and expense (per Boe of production))  
Expenses:
                                 
Lease operating expenses
  $ 2,583       $ 2,946     $ 7,073     $ 8,691  
Production taxes
    907         1,211       3,001       3,810  
Depreciation, depletion and amortization
              4,185       8,686       16,670  
Exploration expenses
              1,164       3,222       1,019  
Rig termination
                          3,000  
Impairment of oil and gas properties
              1,177       47,117       6,233  
Gain on sale of properties
                          (1,455 )
General and administrative expenses
              3,181       5,452       9,342  
                                   
Total expenses
            $ 13,864     $ 74,551     $ 47,310  
                                   
Operating loss
              (73 )     (39,815 )     (9,555 )
Other income (expense):
                                 
Change in unrealized gain (loss) on derivative instruments
              (10,679 )     14,769       (7,043 )
Realized gain (loss) on derivative instruments, net
              (1,062 )     (6,932 )     2,296  
Interest expense
              (1,776 )     (2,404 )     (912 )
Other income (expense)
              40       (9 )     5  
                                   
Total other income (expense)
              (13,477 )     5,424       (5,654 )
                                   
Net loss
            $ (13,550 )   $ (34,391 )   $ (15,209 )
                                   
Cost and expense (per Boe of production):
                                 
Lease operating expenses
  $ 12.79       $ 17.23     $ 17.70     $ 12.21  
Production taxes
    4.49         7.08       7.51       5.35  
Depreciation, depletion and amortization
              24.47       21.73       23.42  
General and administrative expenses
              18.60       13.64       13.12  
 
 
(1) The historical financial data for the six months ended June 30, 2007 have been derived from the audited statement of revenues and direct operating expenses for the properties acquired from Bill Barrett Corporation included elsewhere in this prospectus. Such statement does not reflect depreciation, depletion and amortization, general and administrative expenses, income taxes or interest expense.
 
(2) For the period from February 26, 2007 through June 30, 2007, we did not engage in oil and gas operating or producing activities. Average daily production includes production from July 1, 2007 through December 31, 2007.
 
Year ended December 31, 2009 compared to year ended December 31, 2008
 
Lease Operating Expenses.  Lease operating expenses increased $1.6 million to $7.1 million for the year ended December 31, 2009 compared to the year ended December 31, 2008. This increase was primarily due to the higher number of productive wells from our Sanish and East Nesson acquisitions that were completed in 2009. The 73% increase in oil volumes from 2008 to 2009 resulted in a 31% decrease in unit operating costs to $12.21 per Boe. The lease operating expenses for 2008 were also higher on a per barrel basis due to increased equipment repair and salt water disposal costs for the properties in our West Williston project area. Equipment repair costs were higher in 2008 due to the replacement and upgrading of equipment that had been deferred by the previous owner of the properties we acquired in 2007. Salt water disposal costs were higher in 2008 from the use of higher volume pumps resulting in increases of produced salt water volumes and the use


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of third-party salt water disposal facilities while we developed our own salt water disposal wells and centralized our salt water disposal facilities. As compared to the properties in our West Williston project area that produce primarily from the Madison formation, the properties we acquired in the Sanish acquisition produce primarily from the Bakken formation and have higher production volumes per well and lower per Boe operating costs than our Madison wells. The 2009 lease operating costs per Boe decreased in the West Williston project area due to our previously mentioned 2008 construction and centralization of our salt water disposal facilities.
 
Production Taxes.  Our production taxes for the years ended December 31, 2009 and 2008 were 10.1% and 8.6%, respectively, as a percentage of oil and natural gas sales. The 2009 production tax rate was higher than the 2008 production tax rate due to the increased weighting of revenues in North Dakota which imposes an 11.5% production tax rate. The 2008 production taxes were primarily for oil and natural gas sales revenue associated with the properties in our West Williston project area acquired in 2007. A portion of the properties in our West Williston project area generate revenues that are subject to lower Montana production tax rates and certain North Dakota exemptions.
 
Depreciation, Depletion and Amortization (DD&A).  Depreciation, depletion and amortization expense increased $8.0 million for the year ended December 31, 2009 compared to the year ended December 31, 2008. The 2009 expense increase is primarily due to a 73% production increase from the 2009 East Nesson and Sanish acquisitions. The 2009 DD&A rate was $23.42 per Boe compared to $21.73 per Boe in 2008. The increase from 2008 to 2009 was due to higher acquisition, leasehold, drilling and completion costs in the East Nesson and Sanish project areas.
 
Exploration Expenses.  Exploration expenses of $1.0 million in the year ended December 31, 2009 were primarily composed of exploratory geological and geophysical costs. The comparable period in 2008 contained exploratory dry hole costs of $1.3 million and higher expenditures for exploratory geological and geophysical costs.
 
Rig Termination.  During 2008, we entered into drilling rig contracts with two drilling contractors. In the fourth quarter of 2008, we reduced our planned 2009 capital expenditure program and entered into discussions regarding early termination of these contracts. In the first quarter of 2009, we paid a total of $3.0 million in rig termination expenses in connection with the termination of our remaining commitment under one drilling rig contract and the extension of the other drilling rig contract until June 2010.
 
In November 2009, we entered into a new six-month drilling rig contract which replaced the contract we had previously extended. In the event of an early termination under this new drilling rig contract, we are obligated to pay a daily shortfall rate of $9,000 per day for the days remaining between the date of termination and May 15, 2010, the end of the primary contract term.
 
Impairment of Oil and Gas Properties.  During the years ended December 31, 2009 and 2008, we recorded $0.8 million and $45.5 million, respectively, in non-cash impairment charges on our proved oil and gas properties. The 2008 charges reflected the impact of significantly lower oil prices reflected in our 2008 reserve report.
 
During the years ended December 31, 2009 and 2008, we recorded non-cash impairment charges of $5.4 million and $1.6 million, respectively, for unproved property leases that expired during the period. In determining the amount of the non-cash impairment charges for such periods, we considered the application of the factors described under “Critical accounting policies and estimates — Impairment of unproved properties,” including our 45,640 net leasehold acres that may expire in 2010 unless production is established from such acreage. As of December 31, 2009, we did not record an impairment charge with respect to any acreage expiring in 2010 based primarily on our ability to actively manage and prioritize our capital expenditures to drill leases and to make payments to extend leases that would otherwise expire. Depending on the results of those activities, we may ultimately recognize in our 2010 financial statements impairment charges with respect to a portion of the $11.9 million carrying value associated with such acreage. In general, we would recognize $1.2 million of impairment expense for every 5,000 net leasehold acres that actually expire.


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Gain on Sale of Properties.  In December 2009, we sold our interests in non-core oil and natural gas producing properties located in the Barnett shale in Texas for $1.5 million. We recognized a gain of $1.4 million from the sale of these divested properties.
 
General and Administrative.  Our general and administrative expenses increased to $9.3 million for the year ended December 31, 2009 from $5.5 million for the year ended December 31, 2008. This increase was primarily due to higher costs related to employee bonus compensation, additional employees and higher advisory, audit, legal and tax fees related to our initial public offering. As of December 31, 2009, we had 27 full-time employees compared to 20 employees as of December 31, 2008. On a per unit basis, general and administrative expenses were $13.12 per Boe compared to $13.64 per Boe for the years ended December 31, 2009 and 2008, respectively.
 
Derivatives.  As a result of our derivative activities, we incurred cash settlement gains of $2.3 million for the year ended December 31, 2009 and cash settlement losses of $6.9 million for the year ended December 31, 2008. In addition, as a result of forward oil price changes, we recognized $7.0 million of unrealized mark-to-market non-cash derivative losses in 2009 and $14.8 million of unrealized mark-to-market non-cash derivative gains during 2008.
 
Interest Expense.  Interest expense decreased $1.5 million, or 62%, for the year ended December 31, 2009 compared to the year ended December 31, 2008, due to a lower weighted average outstanding debt balance and a lower weighted average interest rate during 2009. Our weighted average debt balance decreased to $22.8 million for the year ended December 31, 2009 compared to $37.7 million for the year ended December 31, 2008. The weighted average interest rate on our revolving credit facility borrowings was 3.5% for the year ended December 31, 2009 compared to 6.3% for the same period in 2008. At December 31, 2009 our outstanding debt balance under our revolving credit facility was $35.0 million with a weighted average interest rate of 2.95%.
 
Year ended December 31, 2008 compared to period from February 26, 2007 (Inception) through December 31, 2007
 
Lease Operating Expenses.  Lease operating expenses increased $4.1 million for the year ended December 31, 2008 compared to the period from February 26, 2007 to December 31, 2007. The West Williston oil and natural gas producing properties were purchased in June 2007 and are reflected in only six months of our 2007 operating results as compared to a full twelve months in 2008. Lease operating expenses were $17.70 and $17.23 per Boe for the year ended December 31, 2008 and for the period from February 26, 2007 (inception) through December 31, 2007, respectively. The unit operating costs for the year ended December 31, 2008 were higher on a Boe unit basis due to increased equipment repair and salt water disposal costs for our West Williston properties. Equipment repair costs were higher in 2008 due to the replacement and upgrading of equipment that had been deferred by the previous owner of the properties we acquired in 2007. Salt water disposal costs were higher in 2008 from the use of higher volume pumps resulting in increases of produced salt water volumes and the use of third-party salt water disposal facilities while we developed our own salt water disposal wells and centralized our salt water disposal facilities. When comparing our lease operating expenses for the period from February 26, 2007 (inception) through December 31, 2007 to our predecessor’s lease operating expenses from January 1 through June 30, 2007, our lease operating expenses increased by $0.4 million or 14% to $2.9 million. The lease operating expense increase is primarily due to the increase in oil and gas operating and producing activities.
 
Production Taxes.  Our production taxes for the year ended December 31, 2008, the period from February 26, 2007 (inception) through December 31, 2007 and our predecessor’s production taxes for the period from January 1 through June 30, 2007 were 8.6%, 8.8% and 8.5% respectively, of oil and natural gas sales for our West Williston oil and gas producing properties.
 
Depreciation, Depletion and Amortization.  Depreciation, depletion and amortization expense increased $4.5 million for the year ended December 31, 2008 compared to the period from February 26, 2007 to December 31, 2007. The West Williston oil and gas producing properties were purchased in June 2007 and are reflected in only six months of our 2007 operating results as compared to a full twelve months in 2008. The depreciation, depletion and amortization rate was $21.73 per Boe for the year ended December 31, 2008 as compared to $24.47 per Boe in the period from February 26, 2007 (inception) through December 31, 2007.


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The decrease in the per Boe rate from 2007 to 2008 was primarily due to the $45.5 million impairment charge that we recorded on our proved oil and gas properties as a result of lower crude oil prices at December 31, 2008. The decrease in the per Boe rate from the reduction in carrying value of our proved oil and gas properties was partially offset by the corresponding decrease in our proved reserve quantities as a result of lower crude oil prices at December 31, 2008.
 
Exploration Expenses.  Exploration expenses of $3.2 million in the year ended December 31, 2008 included $1.3 million of dry hole costs with the remaining geological and geophysical costs comparable to those incurred from February 26, 2007 to December 31, 2007. For the period ended December 31, 2007, we did not incur any dry hole costs.
 
Impairment of Oil and Gas Properties.  During the year ended December 31, 2008, we recorded a non-cash impairment charge of $45.5 million on our proved oil and gas properties as a result of lower crude oil prices at December 31, 2008, without a comparable charge for the period ended December 31, 2007. During the year ended December 31, 2008 and the period from February 26, 2007 to December 31, 2007, we recorded non-cash impairment charges of $1.6 million and $1.2 million, respectively, for unproved property leases that expired during the period.
 
General and Administrative.  General and administrative expenses increased to $5.5 million for the year ended December 31, 2008 from $3.2 million during the period from February 26, 2007 through December 31, 2007. This increase was due both to a full 12 months of operations in 2008 as well as to the start-up nature of our activities in the 2007 period. General and administrative expenses were $13.64 per Boe for the year ended December 31, 2008 compared to $18.60 per Boe for the period ended 2007. The improvement was due to a full year of production volumes in the 2008 period versus only six months of volumes in the 2007 period.
 
Derivatives.  In connection with the West Williston acquisition in June 2007, we entered into fixed-price swap and collar contracts. As a result, only five contract settlement periods occurred during the period from February 26, 2007 through December 31, 2007 as compared to twelve contract settlement periods for the year ended December 31, 2008. We incurred cash settlement losses of $6.9 million and $1.1 million during the year ended December 31, 2008 and the period from February 26, 2007 to December 31, 2007, respectively, on contract settlements of our crude oil derivative transactions. In addition, we recognized $14.8 million of unrealized mark-to-market non-cash derivative gains during the year ended December 31, 2008 as compared to $10.7 million of unrealized mark-to-market non-cash derivative losses during the period from February 26, 2007 through December 31, 2007 due to increases in forward oil prices during the 2008 period.
 
Interest Expense.  Interest expense increased $0.6 million, or 35%, for the year ended December 31, 2008 compared to the period from February 26 through December 31, 2007, primarily due to our revolving credit facility borrowings being outstanding for a full 12 months in the 2008 period. The weighted average outstanding debt balance and weighted average interest rates were $37.7 million and 6.3% during for the year ended December 31, 2008. The weighted average outstanding debt balance and weighted average interest rates were $22.8 million and 7.81% during the period from February 26 through December 31, 2007.
 
Liquidity and Capital Resources
 
Our primary sources of liquidity to date have been capital contributions from EnCap and other private investors, borrowings under our revolving 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 continually monitor potential capital sources, including equity and debt financings, in order 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.
 
Our total 2010 capital expenditure budget is $220 million, which consists of:
 
  •  $134 million for drilling and completing operated wells;
 
  •  $45 million for drilling and completing non-operated wells;
 
  •  $15 million for maintaining and expanding our leasehold position;


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  •  $5 million for constructing infrastructure to support production in our core project areas; and
 
  •  $21 million in unallocated funds which are available for additional drilling and leasing costs and activity.
 
While we have budgeted $220 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results as the year progresses. To date, our 2010 capital budget has been funded from a $35 million capital contribution from our equity investors in December 2009 and borrowings under our revolving credit facility. We believe the net proceeds from this offering together with cash flows from operations and additional borrowings under our revolving credit facility should be more than sufficient to fund the remainder of our 2010 and a portion of our 2011 capital expenditure budget. However, because the operated wells funded by our 2010 drilling plan represent only a small percentage of our gross identified operated drilling locations, we will be required to generate or raise multiples of this amount of capital to develop our entire inventory of identified drilling locations should we elect to do so.
 
On February 26, 2010, we entered into an amended and restated revolving credit facility, which will have a borrowing base of $70 million upon the completion of this offering. As of April 9, 2010 we had $30.0 million of indebtedness outstanding and $40.0 million of borrowing capacity available under the conforming borrowing base commitment of our revolving credit facility. For more information regarding our revolving credit facility, see “— Reserve-based credit facility.”
 
 
We expect that in the future our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas. Please see “— Quantitative and Qualitative Disclosures About Market Risk.”
 
We actively review acquisition opportunities on an ongoing basis. Our ability to make significant additional acquisitions for cash would require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all.
 
Our cash flows for the period from February 26, 2007 through December 31, 2007 and the years ended December 31, 2008 and 2009, respectively, are presented below (in thousands):
 
                         
    Period from
             
    February 26, 2007
             
    (Inception) through
    Year Ended December 31,  
    December 31, 2007     2008     2009  
 
Net cash provided by operating activities
  $ 2,284     $ 13,766     $ 6,148  
Net cash used in investing activities
    (91,988 )     (78,478 )     (80,756 )
Net cash provided by financing activities
    95,986       60,000       113,600  
                         
Net change in cash
  $ 6,282     $ (4,712 )   $ 38,992  
                         
 
Cash flows provided by operating activities
 
Net cash provided by operating activities was $2.3 million for the period from February 26, 2007 through December 31, 2007, and $13.8 million and $6.1 million for the years ended December 31, 2008 and 2009, respectively. The increase in cash flows from operations for the year ended December 31, 2008 compared to period ended December 31, 2007 was primarily the result of an increase in oil and natural gas production. Cash flows from operations during the year ended December 31, 2009 decreased compared to 2008 primarily as a result of a $3.0 million rig termination payment and $3.9 million increase in general and administration expenses related to the initial public offering.
 
Our operating cash flows are sensitive to a number of variables, the most significant of which is the volatility of oil and gas prices. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of these commodities. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “— Quantitative and Qualitative Disclosures About Market Risk” below.


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Cash flows used in investing activities
 
We had cash flows used in investing activities of $92.0 million during the period from February 26, 2007 through December 31, 2007 and we had $78.5 million and $80.8 million during the years ended December 31, 2008 and 2009, respectively, as a result of our capital expenditures for drilling, development and acquisition costs. The decrease in cash flows used in investing activities during the year ended December 31, 2008 compared to the period ended December 31, 2007 was attributable to the completion of the acquisition of the West Williston assets in 2007. The increase in cash used in investing activities for the year ended December 31, 2009 compared to 2008 of $2.3 million was attributable to our acquisitions of properties in the East Nesson and Sanish project areas, as well as increased levels of expenditures for the development of our properties.
 
Our capital expenditures for drilling, development and acquisition costs for the period from February 26, 2007 to December 31, 2007 and the years ended December 31, 2008 and 2009 are summarized in the following table (in thousands):
 
                         
    Period from
             
    February 26, 2007
    Year Ended
 
    (Inception) through
    December 31,  
    December 31, 2007     2008     2009  
 
Project Area:
                       
West Williston
  $ 95,109     $ 12,703     $ 15,521  
East Nesson
          66,513       40,208  
Sanish
                32,952  
Other(1)
                582  
                         
Total(2)
  $ 95,109     $ 79,216     $ 89,263  
                         
 
 
(1) Represents data relating to our properties in the Barnett shale.
 
(2) Consolidated capital expenditures reflected in the table above differ from the amounts shown in the statement of cash flows in our financial statements because amounts reflected in the table include changes in accounts payable from the previous reporting period for capital expenditures, while the amounts presented in the statement of cash flows are presented on a cash basis.
 
Our board of directors has approved a total capital expenditure budget of $220 million for 2010, which is a 147% increase over the $89 million invested during 2009. Our capital budget may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil and natural gas prices decline or costs increase significantly, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control.
 
Expenditures for exploration and development of oil and natural gas properties are the primary use of our capital resources. We anticipate investing $220 million for capital and exploration expenditures in 2010 as follows (in millions):
 
         
    Amount  
 
Exploration and development drilling
  $ 179  
Land costs
    15  
Infrastructure
    5  
Unallocated funds available for additional drilling and leasing costs and activity.
    21  
         
    $ 220  
         


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Cash flows provided by financing activities
 
Net cash provided by financing activities was $96.0 million for period from February 26, 2007 through December 31, 2007, and $60.0 million and $113.6 million for the years ended December 31, 2008 and 2009, respectively. For the period from February 26, 2007 through December 31, 2007 and the years ended December 31, 2008 and 2009, cash sourced through financing activities was primarily provided by capital contributions from EnCap and other private investors and borrowings under our revolving credit facility. Our long-term debt, including the current portion, was $46.5 million, $26.0 million and $35.0 million at December 31, 2007, 2008 and 2009, respectively.
 
In March 2007, we entered into a limited liability company agreement that provided for an aggregate of $100 million in capital contribution commitments from EnCap, its affiliates and other investors, including certain members of management and other employees through Oasis Petroleum Management LLC. The original capital contribution commitment period extended from March 2007 until March 2010. In November 2007, the agreement was amended to increase the aggregate capital contribution commitment from $100 million to $200 million and to add additional members. In December 2009, the agreement was further amended to extend the commitment period to December 31, 2011 and increase the aggregate capital contribution commitment to $275 million. As of December 31, 2009, we had $40 million of remaining capital commitment capacity. This commitment will terminate upon the consummation of this offering.
 
Reserve-based credit facility
 
On February 26, 2010, we entered into an amended and restated reserve-based revolving credit facility under which our initial borrowing base was set at $85 million. Following the completion of this offering, our borrowing base will be $70 million with a maturity of February 26, 2014. At the earlier of the closing of this offering and October 1, 2010, the $15 million non-conforming portion of the borrowing base will terminate. The borrowing base under our revolving credit facility will be subject to redetermination on a semi-annual basis, effective April 1 and October 1, beginning October 1, 2010, and at up to one additional time per year, as may be requested by either us or the administrative agent, acting at the direction of the majority of the lenders. The borrowing base will be determined by the administrative agent in its sole discretion and consistent with its normal oil and gas lending criteria in existence at that particular time. Our revolving credit facility is available for our general corporate purposes, including, without limitation, working capital for exploration and production operations. Our obligations under our revolving credit facility are secured by substantially all of our assets. Our revolving credit facility is filed as an exhibit to the registration statement of which this prospectus is a part.
 
As of April 9, 2010, we had $30.0 million outstanding under our revolving credit facility, the substantial majority of which was used to fund our drilling and acquisition activities. We anticipate that a portion of the net proceeds from this offering will be used to repay all of our borrowings outstanding as of the closing.
 
At our election, interest is generally determined by reference to:
 
  •  the London interbank offered rate, or LIBOR, plus an applicable margin between 2.25% and 4.00% per annum; or
 
  •  a domestic bank prime rate plus an applicable margin between 0.75% and 2.50% per annum.
 
Interest is generally payable quarterly for domestic bank rate loans and on the last day of the applicable interest period for LIBOR loans, but not less frequently than quarterly.
 
Our revolving credit facility contains various covenants that limit our ability to:
 
  •  incur indebtedness;
 
  •  grant certain liens;
 
  •  make certain loans, advances and investments;
 
  •  make dividends, distributions or redemptions;
 
  •  merge or consolidate;


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  •  engage in certain asset dispositions, including a sale of all or substantially all of our assets;
 
  •  enter into certain transactions with affiliates;
 
  •  grant negative pledges or agree to restrict dividends or distributions from subsidiaries;
 
  •  allow gas imbalances, take-or-pay or other prepayments with respect to oil and gas properties that would require us from delivering hydrocarbons in the future in excess of an aggregate of 75,000 Mcfe; or
 
  •  enter into certain swap agreements.
 
Our revolving credit facility also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:
 
  •  a current ratio, consisting of consolidated current assets, including the unused amount of the total commitments, to consolidated current liabilities of not less than 1.0 to 1.0, excluding non-cash derivative assets and liabilities, as of the last day of any fiscal quarter; and
 
  •  a debt coverage ratio, consisting of consolidated debt (excluding non-cash obligations, accounts payable and other certain accrued liabilities) to consolidated net income plus interest expense, income taxes, depreciation, depletion, amortization, exploration expenses and other similar non-cash charges, minus all non-cash income added to consolidated net income, of not more than 4.0 to 1.0 for the four quarters ended on the last day of each fiscal quarter.
 
We believe that we are in compliance with the terms of our revolving credit facility. If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. Each of the following will be an event of default:
 
  •  failure to pay any principal or any reimbursement obligation under any letter of credit when due or any interest, fees or other amount within certain grace periods;
 
  •  a representation or warranty is proven to be incorrect in any material respect when made;
 
  •  failure to perform or otherwise comply with the covenants in the credit agreement or other loan documents, subject, in certain instances, to certain grace periods;
 
  •  default by us on the payment of any other indebtedness in excess of $2.5 million, or any event occurs that permits or causes the acceleration of the indebtedness;
 
  •  bankruptcy or insolvency events involving us or our subsidiaries;
 
  •  the entry of, and failure to pay, one or more adverse judgments in excess of $2.0 million or one or more non-monetary judgments that could reasonably be expected to have a material adverse effect and for which enforcement proceedings are brought or that are not stayed pending appeal; and
 
  •  a change of control, as defined in the credit agreement.
 
Obligations and Commitments
 
We have the following contractual obligations and commitments as of December 31, 2009 (in thousands):
 
                                         
    Payments Due by Period  
          Less Than
                More Than
 
Contractual Obligations
  Total     1 Year     1 - 3 Years     3 - 5 Years     5 Years  
 
Revolving credit facility(1)
  $ 35,000     $     $ 35,000     $   —     $  
Operating leases(2)
    969       451       518              
Drilling rig commitments(2)
    2,575       2,575                    
Asset retirement obligations(3)
    6,511       282       1,872       74       4,283  
                                         
Total contractual cash obligations
  $ 45,055     $ 3,308     $ 37,390     $ 74     $ 4,283  
                                         


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(1) Amount excludes interest on our revolving credit facility as both the amount borrowed and applicable interest rate is variable. On February 26, 2010, we entered into an amended and restated revolving credit facility, which matures on February 26, 2014. See Notes 7 and 11 to our consolidated financial statements.
 
(2) See Note 10 to our consolidated financial statements for a description of lease obligations and drilling contract commitments.
 
(3) Amounts represent our estimate of future asset retirement obligations on an undiscounted basis. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 8 to our consolidated financial statements.
 
Critical accounting policies and estimates
 
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. See Note 2 to our consolidated financial statements for a discussion of additional accounting policies and estimates made by management.
 
Method of accounting for oil and natural gas properties
 
Oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. All capitalized well costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and proved reserves, respectively.
 
Costs of retired, sold or abandoned properties that constitute a part of an amortization base (partial field) are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate for an entire field, in which case a gain or loss is recognized currently. Gains or losses from the disposal of properties are recognized currently.
 
Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.
 
Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Unproved lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we expense the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is recorded as impairment expense in the statement of


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operations in our consolidated financial statements. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.
 
For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.
 
Oil and natural gas reserve quantities and standardized measure of future net revenue
 
Our independent engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the SEC has recently adopted rules which allow us to disclose proved, probable and possible reserves, we have elected to present only proved reserves in this prospectus. The SEC’s revised rules define proved reserves as the quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Our independent engineers and technical staff must make a number of subjective assumptions based on their professional judgment in developing reserve estimates. Reserve estimates are updated annually and consider recent production levels and other technical information about each field. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil and natural gas prices, cost changes, technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.
 
Revenue recognition
 
Revenue from our interests in producing wells is recognized when the product is delivered, at which time the customer has taken title and assumed the risks and rewards of ownership, and collectability is reasonably assured. Substantially all of our production is sold to purchasers under short-term (less than 12 month) contracts at market based prices. The sales prices for oil and natural gas are adjusted for transportation and other related deductions. These deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these revenue deductions are adjusted to reflect actual charges based on third-party documents. Since there is a ready market for oil and natural gas, we sell the majority of production soon after it is produced at various locations. As a result, we maintain a minimum amount of product inventory in storage.
 
Impairment of proved properties
 
We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future cash flows of our oil and natural gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development


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costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved properties will be recorded.
 
Impairment of unproved properties
 
We assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage and records impairment expense for any decline in value.
 
We have historically recognized impairment expense for unproved properties at the time when the lease term has expired or sooner if, in management’s judgment, the unproved properties have lost some or all of their carrying value. We consider the following factors in our assessment of the impairment of unproved properties:
 
  •  the remaining amount of unexpired term under our leases;
 
  •  our ability to actively manage and prioritize our capital expenditures to drill leases and to make payments to extend leases that may be closer to expiration;
 
  •  our ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;
 
  •  our ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and
 
  •  our evaluation of the continuing successful results from the application of completion technology in the Bakken formation by us or by other operators in areas adjacent to or near our unproved properties.
 
The assessment of unproved properties to determine any possible impairment requires managerial judgment.
 
Asset retirement obligations
 
In accordance with the Financial Accounting Standard Board’s (FASB) authoritative guidance on asset retirement obligations, or ARO, we record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount we will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period and the capitalized cost is depreciated on the unit-of-production method. The accretion expense is recorded as a component of depreciation, depletion and amortization in our consolidated statement of operations.
 
We determine the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.


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Derivatives
 
We record all derivative instruments on the balance sheet as either assets or liabilities measured at their estimated fair value. We have not designated any derivative instruments as hedges for accounting purposes and we do not enter into such instruments for speculative trading purposes. Realized gains and realized losses from the settlement of commodity derivative instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled commodity derivative instruments are reported under Other Income (Expense) in our consolidated statement of operations.
 
Recent accounting pronouncements
 
Fair Value.  In February 2010, the FASB enhanced existing authoritative guidance on certain disclosure requirements and added two new disclosure requirements related to fair value measurements. The guidance requires a gross presentation of activities within the Level 3 roll forward and adds a new requirement to disclose details of significant transfers in and out of Level 1 and 2 measurements and the reasons for the transfers. The new disclosures are required for all companies that are required to provide disclosures about recurring and nonrecurring fair value measurements, and is effective the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward information, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. We do not expect the adoption of this new guidance to have a significant impact on our financial position, cash flows or results of operations.
 
Oil and Gas Reporting Requirements.  In December 2008, the SEC released the final rule, “Modernization of Oil and Gas Reporting,” which adopts revisions to the SEC’s oil and gas reporting disclosure requirements. The disclosure requirements under this final rule require reporting of oil and gas reserves using the unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months rather than year-end prices, and the use of new technologies to determine proved reserves if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Companies are allowed, but not required, to disclose probable and possible reserves in SEC filings. In addition, companies are required to report the independence and qualifications of their reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit. In January 2010, the FASB issued authoritative guidance on oil and gas reserve estimation and disclosure, aligning their requirements with the SEC’s final rule. We have presented and applied this new guidance for the year ended December 31, 2009 herein.
 
Disclosures about Derivative Instruments and Hedging Activities.  In March 2008, the FASB issued authoritative guidance related to disclosures about derivative instruments and hedging activities. Disclosures previously required only for the annual financial statements are now required in interim financial statements. This guidance is intended to improve financial reporting about derivative instruments and hedging activities by requiring companies to enhance disclosure about how these instruments and activities affect their financial position, performance and cash flows and to improve the transparency of the location and amounts of derivative instruments in a company’s financial statements and how they are accounted for. This guidance was effective for us beginning January 1, 2009. The adoption of this guidance did not have a significant impact on our consolidated financial position, results of operations or cash flows.
 
Business Combinations.  In December 2007, the FASB revised the authoritative guidance for business combinations, extending its applicability to all transactions and other events in which one entity obtains control over one or more other businesses. The revised guidance broadens the fair value measurement and recognition of assets acquired, liabilities assumed and interests transferred as a result of business combinations and requires that acquisition-related costs incurred prior to the acquisition be expensed. The revised guidance also expands the definition of what qualifies as a business, and this expanded definition could include prospective oil and gas purchases. Additionally, this guidance expands the required disclosures to improve the financial statement users’ abilities to evaluate the nature and financial effects of business combinations. The guidance is effective for business combinations for which the acquisition date is on or after January 1, 2009.


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Internal Controls and Procedures
 
Prior to the completion of this offering, we have been a private company with limited accounting personnel to adequately execute our accounting processes and other supervisory resources with which to address our internal control over financial reporting. As such, we have not maintained an effective control environment in that the design and execution of our controls has not consistently resulted in effective review and supervision by individuals with financial reporting oversight roles. The lack of adequate staffing levels resulted in insufficient time spent on review and approval of certain information used to prepare our financial statements. We have concluded that these control deficiencies constitute a material weakness in our control environment. A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. The control deficiencies described above, at varying degrees of severity, contributed to the material weaknesses in the control environment, as described below.
 
In 2007, we did not maintain effective controls to ensure that correct working interests were used in our calculations of asset retirement obligations and depreciation, depletion and amortization expense. In 2008, the lack of effective controls over the accuracy of working interests and the accurate clearing of asset retirement obligations resulted in the misstatement of our proved property impairment expense. In 2009, we did not maintain effective controls over the accuracy of key spreadsheets used in our computations of unproved property impairment expense. For each of those years, effective controls were not adequately designed or consistently operating to ensure that key computations were properly reviewed before the amounts were recorded in our accounting records. The above identified control deficiencies resulted in audit adjustments to our consolidated financial statements during 2007, 2008 and 2009.
 
Although remediation efforts are still in progress, management has taken steps to address the causes of the 2007 and 2008 audit adjustments by putting into place new accounting processes and control procedures. Management created a centralized source for working interests and implemented controls to ensure that working interests used in reserve report information and accounting computations are reconciled to the centralized source of working interests. Management also implemented an account reconciliation and analysis process to ensure the correct recording of asset retirement obligations. In addition, management is in the process of evaluating the remediation steps needed to address the cause of the 2009 audit adjustment.
 
In January 2010, we hired a financial reporting manager and an operations accountant to allow for additional preparation and review time during our monthly accounting close process. During 2010, we expect to implement a comprehensive review of our internal controls, including our overall control environment, and to formalize our review and approval processes.
 
While we have begun the process of evaluating our internal control over financial reporting, we are in the early phases of our review and will not complete our review until well after this offering is completed. We cannot predict the outcome of our review at this time. During the course of the review, we may identify additional control deficiencies, which could give rise to significant deficiencies and other material weaknesses, in addition to the material weaknesses previously identified. Management has taken steps to improve our internal control over financial reporting, including the implementation of new accounting processes and control procedures and the identification of gaps in our skills base and expertise of the staff required to meet the financial reporting requirements of a public company.
 
We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a public company, we will need to upgrade our systems, including information technology, implement


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additional financial and management controls, reporting systems and procedures and hire additional accounting, finance and legal staff.
 
Further, our independent registered public accounting firm is not yet required to formally attest to the effectiveness of our internal controls over financial reporting until the year following our first annual report required to be filed with the SEC. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future.
 
Inflation
 
Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the period from February 26, 2007 through December 31, 2007 and the years ended 2008 and 2009. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations.
 
Quantitative and Qualitative Disclosures About Market Risk
 
We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative instruments.
 
Commodity price exposure.  We are exposed to market risk as the prices of oil and natural gas fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative instruments in the past and expect to enter into derivative instruments in the future to cover a significant portion of our future production.
 
We utilize derivative financial instruments (primarily swaps and zero-cost collars) to manage risks related to changes in oil prices. As of December 31, 2009, we utilized fixed-price swap agreements and zero-cost collar options, or Derivative Contracts, to reduce the volatility of oil prices on a significant portion of our future expected oil production.
 
For derivative instruments recorded at fair value, the credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on the balance sheet.
 
The following is a summary of our Derivative Contracts as of December 31, 2009:
 
                                             
        Total Notional
    Average
    Average
             
    Derivative
  Amount of Oil
    Floor
    Ceiling
          Fair
 
Settlement Period
 
Instrument
  (Barrels)     Price     Price     Fixed Price     Market Value  
                                (In thousands)  
 
2010
  NYMEX Swap     11,163                     $ 72.25     $ (26 )
2010
  NYMEX Collar     401,814     $ 67.48     $ 90.19               (841 )
2011
  NYMEX Collar     186,764       61.49       82.23               (1,912 )
2012
  NYMEX Collar     13,618       60.00       80.25               (174 )
                                             
                                        $ (2,953 )
                                             
 
Interest rate risk.  At December 31, 2009, we had indebtedness outstanding under our prior revolving credit facility of $35.0 million, which bore interest at floating rates. The weighted average annual interest rate incurred on this indebtedness for the years ended December 31, 2009 and 2008 and the period ended December 31, 2007 was approximately 3.5%, 6.3% and 7.8%, respectively. A 1.0% increase in each of the average LIBOR and federal funds rate for the year ended December 31, 2009 would have resulted in an estimated $0.2 million increase in interest expense for the year ended December 31, 2009.


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We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.
 
Counterparty and customer credit risk.  Joint interest receivables arise from billing entities which own partial interest 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 have limited ability to control participation in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers. See “Business — Marketing and Major Customers” for further detail about our significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties.
 
While we do not require our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers for oil and gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate under the circumstances. This evaluation may include reviewing a counterparty’s latest financial information and, in the case of a customer with which we have receivables, their historical payment record, the financial ability of the customer’s parent company to make payment if the customer cannot and undertaking the due diligence necessary to determine credit terms and credit limits. The counterparties on our derivative instruments currently in place are lenders under our revolving credit facility and we are likely to enter into any future derivative instruments with these or other lenders under our revolving credit facility.
 
Off-Balance Sheet Arrangements
 
Currently, we do not have any off-balance sheet arrangements.


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BUSINESS
 
Overview
 
We are an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources. We have accumulated approximately 292,000 net leasehold acres in the Williston Basin, approximately 85% of which are undeveloped. We are currently focused on exploiting what we have identified as significant resource potential from the Bakken and Three Forks formations, which are present across a substantial majority of our acreage. A report issued by the USGS in April 2008 classified these formations as the largest continuous oil accumulation ever assessed by it in the contiguous United States. We believe the location, size and concentration of our acreage creates an opportunity for us to achieve cost, recovery and production efficiencies through the large-scale development of our project inventory. Our management team has a proven track record in identifying, acquiring and executing large, repeatable development drilling programs, which we refer to as “resource conversion” opportunities, and has substantial experience in the Williston Basin. We have built our leasehold acreage position in the Williston Basin primarily through acquisitions in our three primary project areas, West Williston, East Nesson and Sanish. For a description of our acquisition activity, please see “—Our Acquisition History” below.
 
DeGolyer and MacNaughton, our independent reserve engineers, estimated our net proved reserves to be 13.3 MMBoe as of December 31, 2009, 42% of which were classified as proved developed and 93% of which were comprised of oil. The following table presents summary data for each of our primary project areas as of December 31, 2009:
 
                                                                         
                      2010 Budget                 Average
 
          Identified Drilling
                Drilling
    Estimated Net
    Daily
 
    Net
    Locations     Gross
    Net
    Capex
    Proved Reserves     Production
 
    Acreage     Gross     Net     Wells     Wells     (In millions)     MMBoe     % Developed     (Boe/d)(1)  
 
Williston Basin
                                                                       
West Williston(2)
    159,491       268       106.5       41       18.8     $ 110       5.0       55 %     1,106  
East Nesson(2)
    124,004       113       57.0       13       7.4       47       3.9       36 %     1,016  
Sanish(3)
    8,747       88       9.6       37       3.8       22       4.3       32 %     792  
                                                                         
Total Williston Basin
    292,242       469       173.1       91       30.0     $ 179       13.2       42 %     2,914  
Other
    879                                     0.1       100 %     159  
                                                                         
Total
    293,121       469       173.1       91       30.0     $ 179       13.3       42 %     3,073  
                                                                         
 
 
(1) Represents average daily production for the three months ended December 31, 2009.
 
(2) Identified gross and net drilling locations in our West Williston and East Nesson project areas are primarily comprised of Bakken wells based on 1,280-acre spacing and do not include any infill wells targeting the Bakken formation or any primary or infill wells targeting the Three Forks formation.
 
(3) Identified gross and net drilling locations in our Sanish project area include a single Bakken infill well per 1,280-acre or 640-acre spacing unit (excluding spacing units already containing two Bakken producing wells) and include 10 gross (1.6 net) primary wells targeting the Three Forks formation.
 
In our West Williston and East Nesson project areas, we have an inventory of approximately 381 gross primary drilling locations (23 of which are proved undeveloped), substantially all of which are on 1,280-acre spacing targeting the Bakken formation. We plan to aggressively develop these specifically identified drilling locations using horizontal drilling and multi-stage fracture stimulation techniques. In our Sanish project area, we have an additional 88 gross non-operated drilling locations (63 of which are proved undeveloped). A single additional infill well per spacing unit targeting the Bakken formation across all three of our Williston Basin project areas would add over 500 incremental potential drilling locations. We are also evaluating the resource potential in the Three Forks formation across our leasehold position and believe there may be a significant number of additional potential drilling locations targeting this formation.


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Our total 2010 capital expenditure budget is $220 million, which consists of:
 
  •  $134 million for drilling and completing operated wells;
 
  •  $45 million for drilling and completing non-operated wells;
 
  •  $15 million for maintaining and expanding our leasehold position;
 
  •  $5 million for constructing infrastructure to support production in our core project areas; and
 
  •  $21 million in unallocated funds which are available for additional drilling and leasing costs and activity.
 
While we have budgeted $220 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results as the year progresses. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”
 
Our Acquisition History
 
We built our leasehold position in our West Williston, East Nesson and Sanish project areas through the following acquisitions and development activities:
 
  •  In June 2007, we acquired approximately 175,000 net leasehold acres in the Williston Basin with then-current net production of approximately 1,000 Boe/d. This acreage is the core of our West Williston project area.
 
  •  In May 2008, we entered into a farm-in and purchase arrangement, under which we earned or acquired approximately 48,000 net leasehold acres, establishing our initial position in the East Nesson project area.
 
  •  In June 2009, we acquired approximately 40,000 net leasehold acres with then-current net production of approximately 800 Boe/d, approximately 83% of which was from the Williston Basin. This acquisition consolidated our acreage in the East Nesson project area and established our Sanish project area.
 
  •  In September 2009, we acquired an additional 46,000 net leasehold acres with then-current net production of approximately 300 Boe/d. This acquisition further consolidated our acreage in the East Nesson project area.
 
Our Business Strategy
 
Our goal is to increase stockholder value by building reserves, production and cash flows at an attractive return on invested capital. We seek to achieve our goals through the following strategies:
 
  •  Aggressively Develop our Williston Basin Leasehold Position.  We intend to aggressively drill and develop our acreage position to maximize the value of our resource potential. The aggregate 469 gross drilling locations that we have specifically identified in the Bakken formation in our three project areas will be our primary targets in the near term. Our 2010 drilling plan contemplates drilling approximately 35 gross (22.4 net) operated wells in these project areas by using two operated drilling rigs for the full year and adding up to three additional drilling rigs later in the year. Subject to market conditions and rig availability, we expect to operate five drilling rigs in 2011, which could enable us to drill as many as 60 gross operated wells during that year. We believe we have the ability to add additional rigs this year if market conditions and program results warrant.
 
  •  Enhance Returns by Focusing on Operational and Cost Efficiencies.  Our management team is focused on continuous improvement of our operating measures and has significant experience in successfully converting early-stage resource opportunities into cost-efficient development projects. We believe the magnitude and concentration of our acreage within our project areas provides us with the opportunity to capture economies of scale, including the ability to drill multiple wells from a single drilling pad, utilizing centralized production and fluid handling facilities and reducing the time and cost of rig mobilization.


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  •  Adopt and Employ Leading Drilling and Completion Techniques.  Our team is focused on enhancing our drilling and completion techniques to maximize recovery. We believe these techniques have significantly evolved over the last several years, resulting in increased initial production rates and recoverable hydrocarbons per well through the implementation of techniques such as using longer laterals and more tightly spaced fracturing stimulation stages. We continuously evaluate our internal drilling results and monitor the results of other operators to improve our operating practices, and we expect our drilling and completion techniques will continue to evolve. This continued evolution may significantly enhance our initial production rates, ultimate recovery factors and rate of return on invested capital.
 
  •  Pursue Strategic Acquisitions with Significant Resource Potential.  In the near term, we intend to identify and acquire additional acreage and producing assets in the Williston Basin to supplement our existing operations. Going forward, we expect to selectively target additional domestic basins that would allow us to employ our resource conversion strategy on large undeveloped acreage positions similar to what we have accumulated in the Williston Basin. While we have no current intention to pursue international opportunities, our management team has significant international acquisition and operating expertise. If we identify an international opportunity with appropriate scale, risk and resource conversion potential, our board of directors may approve such an investment should they determine it is in the long-term best interest of our stockholders to do so.
 
Our Competitive Strengths
 
We have a number of competitive strengths that we believe will help us to successfully execute our business strategies:
 
  •  Substantial Leasehold Position in one of North America’s Leading Unconventional Oil-Resource Plays.  Our current leasehold position of approximately 292,000 net leasehold acres in the Williston Basin is highly prospective in the Bakken formation. We believe our acreage is one of the largest concentrated leasehold positions in the basin prospective in the Bakken formation, and much of our acreage is in areas of significant drilling activity by other exploration and production companies. While we are initially targeting the Bakken formation, we are also evaluating what we believe to be significant prospectivity in the Three Forks formation which underlies a large portion of our acreage. We expect that the scale and concentration of our acreage will enable us to continue to improve our drilling and completion costs and operational efficiency.
 
  •  Large, Multi-Year Project Inventory.  We have an inventory of approximately 469 gross drilling locations, primarily targeting the Bakken formation. We plan to drill 35 gross (22.4 net) operated wells across our West Williston and East Nesson project areas in 2010, the completion of which would represent 14% of our 246 gross identified operated drilling locations in these two project areas. We may be able to enhance the total recovery from the Bakken formation by drilling potential infill locations. In addition, our total number of drilling locations may also be substantially increased by pursuing the prospectivity we have identified in the Three Forks formation.
 
  •  Management Team with Proven Acquisition and Operating Skills.  Our senior management team has extensive expertise in the oil and gas industry as previous members of management at Burlington Resources. The senior technical team has an average of more than 25 years of industry experience, including experience in multiple North American resource plays as well as experience in other North American and international basins. We believe our management and technical team is one of our principal competitive strengths relative to our industry peers due to our team’s proven track record in identification, acquisition and execution of resource conversion opportunities. In addition, this team possesses substantial expertise in horizontal drilling techniques and managing and acquiring large development programs, and also has prior experience in the Williston Basin.
 
  •  Incentivized Management Team.  Our management team will own a significant direct ownership interest in us immediately following the completion of this offering. In addition, our management team will own an indirect interest in OAS Holdco, which will own      shares of our common stock upon


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  completion of this offering. Our management team may significantly increase its sharing percentage in the shares held by OAS Holdco by increasing the return on investment for the other members of OAS Holdco. We believe our management team’s direct ownership interest immediately following the offering as well as their ability to increase their interest over time through OAS Holdco provides significant incentives to grow the value of our business for the benefit of all stockholders. See “Corporate Reorganization — LLC Agreement of OAS Holdco.”
 
  •  Operating Control over the Majority of our Portfolio.  In order to maintain better control over our asset portfolio, we have established a leasehold position comprised primarily of properties that we expect to operate. Controlling operations will allow us to dictate the pace of development as well as the costs, type and timing of exploration and development activities. We believe that maintaining operational control over the majority of our acreage will allow us to better pursue our strategies of enhancing returns through operational and cost efficiencies and maximizing hydrocarbon recovery through continuous improvement of drilling and completion techniques.
 
Recent Developments
 
Drilling Activity.  Since December 31, 2009, we have drilled six operated wells in the Bakken formation. Three of these wells are producing and three wells are being completed. Additionally, we currently have one operated drilling rig in the West Williston project area and two in the East Nesson project area, each of which is drilling a well targeting the Bakken formation. Of the 16 gross (1.6 net) non-operated wells in progress on December 31, 2009, 13 gross (1.1 net) wells have initiated production and three gross (0.5 net) wells are under completion operations. Subsequent to December 31, 2009, an additional 25 gross (2.1 net) non-operated wells have begun operations with six gross (0.4 net) wells producing and 19 gross (1.7 net) wells being drilled or completed.
 
Amended and Restated Credit Facility.  On February 26, 2010, we entered into an amended and restated revolving credit facility, which will have a borrowing base of $70 million upon completion of this offering. Our revolving credit facility matures on February 26, 2014. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Reserve-based credit facility.” As of April 9, 2010, we had $30.0 million of indebtedness outstanding under our revolving credit facility. We anticipate that a portion of the net proceeds from this offering will be used to repay all of our borrowings outstanding as of the closing.
 
Marketing and Transportation
 
The Williston Basin crude oil transportation and refining infrastructure has grown substantially in recent years, largely in response to drilling activity in the Bakken formation. As of February 15, 2010, there was approximately 394,600 barrels per day of crude oil transportation and refining capacity in the Williston Basin, comprised of approximately 276,600 barrels per day of pipeline transportation capacity and approximately 58,000 barrels per day of refining capacity at the Tesoro Corporation Mandan refinery. In addition, approximately 60,000 barrels per day of specifically dedicated railcar transportation capacity has recently been placed into service in the Williston Basin. Based on publicly announced expansion projects, pipeline transportation capacity for Williston Basin oil production could increase by 30,000 to 115,000 barrels per day by 2013, and we believe additional projects are under consideration. We sell a substantial majority of our oil production directly at the wellhead and are not responsible for its transportation. However, the price we receive at the wellhead is impacted by transportation and refining infrastructure constraints. For a discussion of the potential risks to our business that could result from transportation and refining infrastructure constraints in the Williston Basin, please see “Risk Factors — Delays and interruptions of production from our wells due to marketing and transportation constraints in the Williston Basin could cause significant fluctuations in our realized oil and natural gas prices.”


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Our Operations
 
Estimated proved reserves
 
Unless otherwise specifically identified in this prospectus, the summary data with respect to our estimated proved reserves presented below has been prepared by our independent reserve engineering firms in accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities. As discussed below, the SEC has adopted new rules relating to disclosures of estimated reserves that are effective for fiscal years ending on or after December 31, 2009. In this prospectus, proved reserve estimates do not include any value for probable or possible reserves which may exist, categories which the new SEC rules would for the first time permit us to disclose in public reports. Our estimated proved reserves under the SEC rules in effect for the years ended December 31, 2007 and 2008 were determined using constant prices and unescalated costs based on the prices received and costs incurred on a field-by-field basis as of the year end. For the year ended December 31, 2009 and for future periods, our estimated proved reserves are determined using the preceding twelve months’ unweighted arithmetic average of the first-day-of-the-month prices, rather than year-end prices. For a definition of proved reserves under the SEC rules for both the fiscal years ending on or after December 31, 2009 and the fiscal years ending prior to December 31, 2009, see the “Glossary of Oil and Natural Gas Terms” beginning on page A-1 of this prospectus. For more information regarding our independent reserve engineers, please see “— Independent petroleum engineers” below.
 
The table below summarizes our estimated proved reserves and related PV-10 at December 31, 2008 for each of our core operating areas as prepared consistent with the SEC’s rules regarding natural gas and oil reserve reporting in effect for fiscal years ending prior to December 31, 2009. The table also summarizes our estimated proved reserves and related PV-10 at December 31, 2009 for each of our project areas as prepared consistent with our and our independent reserve engineers’ interpretation of the SEC’s new rules. The SEC’s new rules relating to disclosures of estimated oil and natural gas reserves are effective for fiscal years ending on or after December 31, 2009. These new rules require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on 12-month historical unweighted first-day-of-the-month average prices.
 
The reserve estimates at December 31, 2009 presented in the table below are based on a report prepared by DeGolyer and MacNaughton, independent reserve engineers. In preparing its report, DeGolyer and MacNaughton evaluated properties representing all of our PV-10 at December 31, 2009 under the new SEC rules. The reserve estimates at December 31, 2008 presented in the table below are based on a report prepared by W.D. Von Gonten & Co., independent reserve engineers. In preparing its report, W.D. Von Gonten & Co. evaluated properties representing all of our PV-10 at December 31, 2008 using the SEC rules in effect at the time of the report. For more information regarding our independent reserve engineers, please see “— Independent petroleum engineers” below. The information in the following table does not give any effect to or reflect our commodity hedges.
 
                                         
    At December 31, 2008     At December 31, 2009        
    Proved Reserves
    PV-10(1)
    Proved Reserves
    PV-10
       
Project Area
  (MMBoe)     (in millions)     (MMBoe)     (in millions)        
 
Williston Basin
                                       
West Williston
    2.2     $ 16.4       5.0     $ 50.7          
East Nesson
    0.1       1.3       3.9       31.6          
Sanish
                4.3       50.6          
                                         
Total Williston Basin
    2.3     $ 17.7       13.2     $ 132.9          
Other(2)
                0.1       0.6          
                                         
Total
    2.3     $ 17.7       13.3     $ 133.5          
                                         
 
 
(1) The PV-10 amount included in the report of W.D. Von Gonten & Co. at December 31, 2008 was $19.2 million because such amount does not give effect to additional estimated plugging and abandonment costs.


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(2) Represents data relating to our properties in the Barnett shale.
 
Estimated proved reserves at December 31, 2009 were 13.3 MMBoe, with a PV-10 of $133.5 million. Our estimated proved reserves at December 31, 2009 increased 11.0 MMBoe and PV-10 increased $115.8 million over our estimated proved reserves and PV-10 at December 31, 2008 due to the results of our drilling program, acquisitions and a higher oil price assumption at December 31, 2009.
 
The following table sets forth more information regarding our estimated proved reserves at December 31, 2007, 2008 and 2009:
 
                         
    At December 31,  
    2007     2008     2009  
 
Reserve Data(1):
                       
Estimated proved reserves:
                       
Oil (MMBbls)
    4.0       2.2       12.4  
Natural gas (Bcf)
    1.2       0.7       5.3  
Total estimated proved reserves (MMBoe)
    4.3       2.3       13.3  
Estimated proved developed reserves:
                       
Oil (MMBbls)
    3.3       2.2       5.2  
Natural gas (Bcf)
    1.1       0.7       2.3  
Total estimated proved developed reserves (MMBoe)
    3.4       2.3       5.6  
Percent developed
    81 %     100 %     42 %
Estimated proved undeveloped reserves:
                       
Oil (MMBbls)
    0.8             7.2  
Natural gas (Bcf)
    0.2             3.0  
Total estimated proved undeveloped reserves (MMBoe)
    0.8             7.7  
PV-10 (in millions)(2)
  $ 121.8     $ 17.7     $ 133.5  
Standardized Measure (in millions)(3)
    121.8       17.7       133.5  
 
 
(1) Our estimated proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The index prices were $96.00/Bbl for oil and $7.16/MMBtu for natural gas at December 31, 2007, and $44.60/Bbl for oil and $5.63/MMBtu for natural gas at December 31, 2008, and the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $61.04/Bbl for oil and $3.87/MMBtu for natural gas at December 31, 2009. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
 
(2) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. However, our PV-10 and our Standardized Measure are equivalent because as of December 31, 2009, we were a limited liability company not subject to entity level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income is passed through to our equity holders. However, in connection with the closing of this offering, we will merge into a corporation that will become a holding company for Oasis Petroleum LLC. As a result, we will be treated as a taxable entity for federal income tax purposes and our future income taxes will be dependent upon our future taxable income. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. The PV-10 amounts included in the reports of W.D. Von Gonten & Co. at December 31, 2007 and at December 31, 2008 were $122.9 million and $19.2 million, respectively, because the PV-10 amounts included in such reports do not give effect to additional estimated plugging and abandonment costs.


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(3) Standardized Measure represents the present value of estimated future net cash inflows from proved oil and natural gas reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses (if applicable), discounted at 10% per annum to reflect timing of future cash flows. In connection with the closing of this offering, we will merge into a corporation that will be treated as a taxable entity for federal income tax purposes. Future calculation of Standardized Measure will include the effects of income taxes on future net revenues. For further discussion of income taxes, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
 
Estimated proved reserves at December 31, 2009 were 13.3 MMBoe, a 477% increase from reserves of 2.3 MMBoe at December 31, 2008. Our 2009 estimated proved reserves increased 11.0 MMBoe over our 2008 estimated reserves due to acquisitions, our drilling program and higher oil price assumptions at December 31, 2009. Our commodity price assumption for oil increased $16.44 per Bbl to $61.04 per Bbl for the year ended December 31, 2009 from $44.60 per Bbl for the year ended December 31, 2008. Our proved developed producing reserves increased 3.3 MMBoe or 144% to 5.6 MMBoe for the year ended December 31, 2009 from 2.3 MMBoe for the year ended December 31, 2008 due to acquisitions and our drilling program. Our proved undeveloped reserves increased to 7.7 MMBoe for the year ended December 31, 2009 from 0.0 MMBoe for the year ended December 31, 2008 due to significant regional drilling activity, higher commodity price assumptions and higher overall estimated ultimate recoveries using recent drilling and completion techniques.
 
Estimated proved reserves at December 31, 2008 were 2.3 MMBoe, a 47% decrease from reserves of 4.3 MMBoe at December 31, 2007. Our estimated proved reserves decreased 2.0 MMBoe for the year ended December 31, 2008 from December 31, 2007 due primarily to lower commodity price assumptions. Our commodity price assumption for oil decreased $51.40 per Bbl to $44.60 per Bbl at December 31, 2008 from $96.00 per Bbl at December 31, 2007. Our proved developed producing reserves decreased 0.9 MMBoe or 28% to 2.3 MMBoe at December 31, 2008 from 3.2 MMBoe at December 31, 2007 due to commodity price assumption and production. Our proved undeveloped reserves decreased from 0.8 MMBoe at December 31, 2007 to no proved undeveloped reserves at December 31, 2008 due to the effect of lower commodity price assumptions and drilling results in conventional reservoirs.
 
The PV-10 of our estimated proved reserves at December 31, 2009 was $133.5 million, a 653% increase from PV-10 of $17.7 million at December 31, 2008. Our PV-10 of estimated proved reserves increased $115.8 million over the 2008 PV-10 due to an increase in reserves and higher oil price assumptions.
 
The following table sets forth the estimated future net revenues, excluding derivatives contracts, from proved reserves, the present value of those net revenues (PV-10), and the expected benchmark prices used in projecting net revenues at December 31, 2007, 2008 and 2009 (in millions):
 
                         
    At December 31,
    2007   2008   2009
 
Future net revenues
  $ 227.8     $ 27.1     $ 286.1  
Present value of future net revenues:
                       
Before income tax (PV-10)
    121.8       17.7       133.5  
After income tax (Standardized Measure)
    121.8       17.7       133.5  
Benchmark oil price(1)($/Bbl)
  $ 96.00     $ 44.60     $ 61.04  
 
 
(1) Our estimated proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The index prices were $96.00/Bbl for oil and $7.16/MMBtu for natural gas at December 31, 2007, and $44.60/Bbl for oil and $5.63/MMBtu for natural gas at December 31, 2008, and the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $61.04/Bbl for oil and $3.87/MMBtu for natural gas at December 31, 2009. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. The PV-10 amounts included in the reports of W.D. Von Gonten & Co. at December 31, 2007 and at December 31, 2008 were $122.9


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million and $19.2 million, respectively, because the PV-10 amounts included in such reports do not give effect to additional estimated plugging and abandonment costs.
 
Future net revenues represent projected revenues from the sale of proved reserves net of production and development costs (including operating expenses and production taxes). Such calculations at December 31, 2007 and 2008 are based on costs and prices in effect at December 31 of each year, without giving effect to derivative transactions, and are held constant throughout the life of the properties. Such calculations at December 31, 2009 are based on costs in effect at December 31, 2009 and the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January 2009 through December 2009, without giving effect to derivative transactions, and are held constant throughout the life of the properties. There can be no assurance that the proved reserves will be produced within the periods indicated or that prices and costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information and different reservoir engineers often arrive at different estimates for the same properties.
 
Independent petroleum engineers
 
Our estimated reserves and related future net revenues and PV-10 at December 31, 2009 are based on a report prepared by DeGolyer and MacNaughton, our independent reserve engineers, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and current guidelines established by the SEC. A copy of this report has been filed as an exhibit to the registration statement containing this prospectus. DeGolyer and MacNaughton is a Delaware corporation with offices in Dallas, Houston, Calgary and Moscow. The firm’s more than 100 professionals include engineers, geologists, geophysicists, petrophysicists, and economists engaged in the appraisal of oil and gas properties, evaluation of hydrocarbon and other mineral prospects, basin evaluations, comprehensive field studies, and equity studies related to the domestic and international energy industry. The Senior Vice President at DeGolyer and MacNaughton primarily responsible for overseeing the preparation of the reserve estimates is a Registered Petroleum Engineer in the State of Texas with more than 35 years of experience in oil and gas reservoir studies and reserve evaluations. He graduated with a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1974 and he is a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists. These services have been provided for over 70 years. DeGolyer and MacNaughton restricts its activities exclusively to consultation; it does not accept contingency fees, nor does it own operating interests in any oil, gas, or mineral properties, or securities or notes of clients. The firm subscribes to a code of professional conduct, and its employees actively support their related technical and professional societies. The firm is a Texas Registered Engineering Firm.
 
Our estimated reserves and related future net revenues and PV-10 at December 31, 2007 and 2008 are based on reports prepared by W.D. Von Gonten & Co., our independent reserve engineers at such dates, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC in effect at such time. A copy of these reports have been filed as exhibits to the registration statement containing this prospectus. W.D. Von Gonten & Co. was formed in 1995 and is located in Houston, Texas. The firm has a professional staff consisting of thirteen petroleum engineers and three geophysicists and geologists, as well as a financial analyst and additional technical support. W.D. Von Gonten & Co. provides a variety of services to the oil and gas industry, including field studies, oil and gas reserve estimations, appraisals of oil and gas properties and reserve reports for both public and private companies. W.D. Von Gonten & Co. is a Texas Registered Engineering Firm.
 
Technology used to establish proved reserves
 
Under the new SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes


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reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
 
In order to establish reasonable certainty with respect to our estimated proved reserves, DeGolyer and MacNaughton employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques. For wells and locations targeting the Bakken formation, the evaluation included an assessment of the beneficial impact of the use of multi-stage hydraulic fracture stimulation treatments on estimated recoverable reserves. In addition to assessing reservoir continuity, geologic data from well logs, core analyses and seismic data related to the Bakken formation were used to estimate original oil in place. In portions of our Sanish project area where estimated proved reserves were attributed to more than one well per spacing unit, the estimated original oil in place was used to calculate reasonable estimated recovery factors based on experience with similar reservoirs where similar drilling and completion techniques have been employed.
 
Internal controls over reserves estimation process
 
We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserves estimation process. Our Senior Vice President Asset Management is the technical person within the company primarily responsible for overseeing the preparation of our reserves estimates. Our Senior Vice President Asset Management has over 20 years of industry experience with positions of increasing responsibility in engineering and evaluations and holds both a Bachelor of Science degree and Master of Science degree in petroleum engineering. Our Senior Vice President Asset Management reports directly to our Chief Operating Officer.
 
Throughout each fiscal year, our technical team meets with representatives of our independent reserve engineers to review properties and discuss methods and assumptions used in preparation of the proved reserves estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a preliminary copy of the reserve report is reviewed by our Chief Operating Officer with representatives of our independent reserve engineers and internal technical staff. Following the consummation of this offering, we anticipate that our audit committee will conduct a similar review on an annual basis.
 
Production, revenues and price history
 
Oil and natural gas are commodities. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand for oil and natural gas in the United States has increased dramatically during this decade. However, the current economic slowdown reduced this demand during the second half of 2008 and through 2009. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or natural gas can result in substantial price volatility. Historically, commodity prices have been volatile and we expect that volatility to continue in the future. A substantial or extended decline in oil or natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access capital markets.
 
The following table sets forth information regarding oil and natural gas production, revenues and realized prices and production costs for the period from February 26, 2007 through December 31, 2007 and for the


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years ended December 31, 2008 and 2009. For additional information on price calculations, see information set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operation.”
 
                         
    Period from
       
    February 26, 2007
  Year Ended
    (Inception) through
  December 31,
    December 31, 2007(1)   2008   2009
 
Operating data:
                       
Net production volumes:
                       
Oil (MBbls)
    159       379       658  
Natural gas (MMcf)
    73       123       326  
Oil equivalents (MBoe)
    171       400       712  
Average daily production (Boe/d)
    929       1,092       1,950  
Average sales prices:
                       
Oil, without realized derivatives (per Bbl)
  $ 83.96     $ 88.07     $ 55.32  
Oil, with realized derivatives(2) (per Bbl)
    77.27       69.79       58.82  
Natural gas (per Mcf)
    6.25       10.91       4.24  
Costs and expenses (per Boe):
                       
Lease operating expenses
  $ 17.23     $ 17.70     $ 12.21  
Production taxes
    7.08       7.51       5.35  
Depreciation, depletion and amortization
    24.47       21.73       23.42  
General and administrative expenses
    18.60       13.64       13.12  
 
 
(1) For the period from February 26, 2007 through June 30, 2007, we did not engage in oil and gas operating or producing activities. Average daily production includes production from July 1, 2007 through December 31, 2007.
 
(2) Realized prices include realized gains or losses on cash settlements for our commodity derivatives, which do not qualify for hedge accounting.
 
Net production volumes for the year ended December 31, 2009 were 712 MBoe, a 78% increase from net production of 400 MBoe for 2008. Our net production volumes increased 312 MBoe over 2008 net production volumes due to acquisitions and a successful operated and non-operated drilling and completion program. Our average oil sales prices, without the effect of realized derivatives, decreased $32.75 per Bbl to $55.32 per Bbl for the year ended December 31, 2009 from $88.07 per Bbl for the year ended December 31, 2008. Giving effect to our derivative transactions in both periods, our oil prices decreased only $10.97 per Bbl to $58.82 per Bbl for the year ended December 31, 2009 from $69.79 per Bbl for the year ended December 31, 2008. Our lease operating expenses decreased $5.49 per Boe, or 31%, to $12.21 per Boe for the year ended December 31, 2009 from $17.70 per Boe for the year ended December 31, 2008 due to acquisitions and our drilling program. The Bakken formation generally has a lower per unit lease operating cost than our conventional producing horizons.
 
Net production volumes for the year ended December 31, 2008 were 400 MBoe, a 134% increase from net production of 171 MBoe for the period from February 26, 2007 through December 31, 2007. Our 2008 net production volumes increased 229 MBoe over the 2007 net production volumes due to the initiation of our production activities on July 1, 2007. Our average oil sales prices, without the effect of realized derivatives, increased $4.11 per Bbl to $88.07 per Bbl for the year ended December 31, 2008 from $83.96 per Bbl for the period from February 26, 2007 through December 31, 2007. Giving effect to our derivative transactions in both periods, our oil prices decreased $7.48 per Bbl to $69.79 per Bbl for the year ended December 31, 2008 from $77.27 per Bbl for the period from February 26, 2007 through December 31, 2007. Our lease operating expenses increased $0.47 per Boe or 3% to $17.70 per Boe for the year ended December 31, 2008 from $17.23 per Boe for the period from February 26, 2007 through December 31, 2007 due to limited drilling program activities, rising operating costs and decreasing production per well.


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The following table sets forth information regarding our average daily production during the three months ended December 31, 2009:
 
                         
    Average Daily Production for the
 
    Three Months Ended December 31, 2009  
    Bbls     Mcf     Boe  
 
Williston Basin:
                       
West Williston
    1,036       420       1,106  
East Nesson
    1,005       65       1,016  
Sanish
    751       249       792  
                         
Total Williston Basin
    2,792       734       2,914  
Other
    16       857       159  
                         
Total
    2,808       1,591       3,073  
                         
 
Productive wells
 
The following table presents the total gross and net productive wells by project area and by oil or gas completion as of December 31, 2009:
 
                                                 
    Oil Wells     Natural Gas Wells     Total Wells  
    Gross     Net     Gross     Net     Gross     Net  
 
Williston Basin:
                                               
West Williston
    130       45.5                   130       45.5  
East Nesson
    43       19.0                   43       19.0  
Sanish
    62       5.1                   62       5.1  
                                                 
Total Williston Basin
    235       69.6                   235       69.6  
Other
                25       3.2       25       3.2  
                                                 
Total
    235       69.6       25       3.2       260       72.8  
                                                 
 
Gross wells are the number of wells in which a working interest is owned and net wells are the total of our fractional working interests owned in gross wells.
 
Acreage
 
The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2009 for each of our project areas. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.
 
                                                 
    Developed Acres     Undeveloped Acres     Total Acres  
    Gross     Net     Gross     Net     Gross     Net  
 
Williston Basin
                                               
West Williston
    31,305       19,482       214,417       140,009       245,722       159,491  
East Nesson
    26,361       16,969       176,430       107,035       202,791       124,004  
Sanish
    38,598       7,862       5,433       885       44,031       8,747  
                                                 
Total Williston Basin
    96,264       44,313       396,280       247,929       492,544       292,242  
Other
    5,917       879                   5,917       879  
                                                 
Total
    102,181       45,192       396,280       247,929       498,461       293,121  
                                                 


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Table of Contents

Undeveloped acreage expirations
 
The following table sets forth the number of gross and net undeveloped acres as of December 31, 2009 that will expire over the next three years by project area unless production is established within the spacing units covering the acreage prior to the expiration dates:
 
                                                 
    Expiring 2010     Expiring 2011     Expiring 2012  
    Gross     Net     Gross     Net     Gross     Net  
 
Williston Basin
                                               
West Williston
    38,276       11,228       92,191       48,222       51,575       21,254  
East Nesson
    68,874       34,302       33,372       11,272       25,693       10,367  
Sanish
    1,038       110       1,154       65       120       21  
                                                 
Total Williston Basin
    108,188       45,640       126,717       59,559       77,388       31,642  
Other
                                   
                                                 
Total
    108,188       45,640       126,717       59,559       77,388       31,642  
                                                 
 
Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities. While we may attempt to secure a new lease upon the expiration of certain of our acreage, there are some third-party leases that may become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date. We have options to extend some of our leases through payment of additional lease bonus payments prior to the expiration of the primary term of the leases. Our leases are mainly fee leases with three to five years of primary term. We believe that our leases are similar to our competitors’ fee lease terms as they relate to primary term and reserve royalty interests.
 
Drilling activity
 
The following table summarizes our drilling activity for the period from February 26, 2007 through December 31, 2007 and the years ended December 31, 2008 and 2009. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells.
 
                                                 
    2007     2008     2009  
    Gross     Net     Gross     Net     Gross     Net  
 
Development wells:
                                               
Oil
    4       1.2       7       1.3       31       2.3  
Gas
                                   
Dry(1)
    2       1.5       1       1.0              
                                                 
Total development wells
    6       2.7       8       2.3       31       2.3  
                                                 
Exploratory wells:
                                               
Oil
                26       3.8       12       5.0  
Gas
                                   
Dry(1)
                1       0.3              
                                                 
Total exploratory wells
                27       4.1