S-1 1 a2205401zs-1.htm S-1

Table of Contents

As filed with the Securities and Exchange Commission on August 26, 2011

Registration No. 333-            

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549



FORM S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933



Dynamic Offshore Resources, Inc.
(Exact name of registrant as specified in its charter)

Delaware   1311   45-3034172
(State or other jurisdiction
of incorporation or organization)
  (Primary Standard Industrial
Classification Code Number)
  (I.R.S. Employer
Identification No.)

1301 McKinney, Suite 900
Houston, Texas 77010
(713) 728-7840

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

Thomas R. Lamme
Senior Vice President and General Counsel
1301 McKinney, Suite 900
Houston, Texas 77010
(713) 728-7840

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



Copies to:

T. Mark Kelly
Matthew R. Pacey

Vinson & Elkins L.L.P.
1001 Fannin, Suite 2500
Houston, Texas 77002-6760
(713) 758-2222
  Sean T. Wheeler
Ryan J. Maierson

Latham & Watkins LLP
717 Texas Avenue, Suite 1600
Houston, Texas 77002
(713) 546-5400

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.

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

CALCULATION OF REGISTRATION FEE

       
 
Title of Each Class of
Securities to Be Registered

  Proposed Maximum Aggregate
Offering Price(1)(2)

  Amount of
Registration Fee

 

Common Stock, par value $0.01 per share

  $400,000,000   $46,440

 

(1)
Includes shares of common stock issuable upon exercise of the underwriters' option to purchase additional shares of common stock to cover over-allotments.

(2)
Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933.

         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 this Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.


Table of Contents

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

SUBJECT TO COMPLETION, DATED AUGUST 26, 2011

Prospectus

                        Shares

GRAPHIC

Dynamic Offshore Resources, Inc.

Common Stock



        Dynamic Offshore Resources, Inc. is offering                        shares of its common stock, and the selling stockholders are offering                         shares of common stock. We will not receive any proceeds from the sale of shares by the selling stockholders. 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 intend to apply to list our common stock on the New York Stock Exchange under the symbol "DOR".



        Investing in our common stock involves risks. Please read "Risk Factors" beginning on page 20.

 
  Price to Public   Underwriting
Discounts and
Commissions
  Proceeds to
Company
  Proceeds to
Selling
Stockholders
 

Per Share

  $     $     $     $    

Total

  $     $     $     $    

        The selling stockholders have 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                     , 2011.



Citigroup

                 Credit Suisse

                                          Deutsche Bank Securities

                                                                  Tudor, Pickering, Holt & Co.

                                                                                                         UBS Investment Bank

The date of this prospectus is                     , 2011.


Table of Contents

GRAPHIC


TABLE OF CONTENTS

Prospectus Summary

  1

The Offering

  9

Risk Factors

  20

Cautionary Note Regarding Forward-Looking Statements

  41

Use of Proceeds

  43

Dividend Policy

  43

Capitalization

  44

Dilution

  45

Selected Historical Consolidated and Unaudited Pro Forma Financial Data

  46

Management's Discussion and Analysis of Financial Condition and Results of Operations

  51

Business

  70

Management

  99

Compensation Discussion and Analysis

  104

Executive Compensation

  108

Certain Relationships and Related Party Transactions

  111

Corporate Reorganization

  114

Principal and Selling Stockholders

  115

Description of Capital Stock

  116

Shares Eligible for Future Sale

  120

Material U.S. Federal Income Tax Considerations to Non-U.S. Holders

  122

Underwriters; Conflicts of Interest

  125

Legal Matters

  132

Experts

  132

Where You Can Find More Information

  133

Index to Financial Statements

  F-1

Glossary of Oil and Natural Gas Terms

  A-1

        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 stockholders have authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. 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.

        We and the selling stockholders 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. We have not taken any action to permit a public offering of the shares of common stock outside the United States or to permit the possession or distribution of this prospectus outside the United States. Persons outside the United States who come into possession of this prospectus must inform themselves about and observe any restrictions relating to the offering of the shares of common stock and the distribution of this prospectus outside the United States.

        Until                        , 2011, 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.

        This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read "Risk Factors" and "Cautionary Note Regarding Forward-Looking Statements."

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, we have not independently verified the information and cannot guarantee its accuracy and completeness.

i


Table of Contents


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," "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 the related notes thereto included elsewhere in this prospectus. Unless otherwise indicated, the information presented in this prospectus assumes that the underwriters' option to purchase additional shares of common stock to cover over-allotments 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 Dynamic Offshore Holding, LP and its subsidiaries before the completion of our corporate reorganization and Dynamic Offshore Resources, Inc. and its subsidiaries as of and following the completion of our corporate reorganization.


Dynamic Offshore Resources, Inc.

Overview

        We are an independent exploration and production company focused on the acquisition and development of producing oil and natural gas properties in the Gulf of Mexico. Since we commenced operations in 2008, we have pursued an active growth strategy as an acquirer of producing assets that provide attractive development opportunities. We seek to maximize the value of our reserves through focused operations and exploitation to generate attractive cash returns. Our management team has an average of more than 28 years of energy industry experience, primarily in the Gulf of Mexico, and are experienced in the unique aspects of evaluating, acquiring and developing offshore properties.

        As of March 31, 2011, our estimated net proved reserves were 45,223 MBoe, of which 52% was oil and 84% was proved developed, with an associated PV-10 of approximately $1.2 billion, based on Securities and Exchange Commission ("SEC") pricing of $80.04 per Bbl for oil and $4.10 per MMBtu for natural gas. As of that same date, our estimated net probable reserves were 8,782 MBoe with an associated PV-10 of approximately $237.5 million. Please read "—Summary Reserve Data" for information on our estimated net proved and probable reserves, PV-10 and related pricing. During June 2011, our properties had aggregate average net daily production of 17,634 Boe per day.

        As of March 31, 2011, we had interests in approximately 200 net productive wells and over 200 offshore oil and gas leases in federal and state waters of the Gulf of Mexico, representing approximately 661,000 gross (317,000 net) acres. Importantly, we operate more than 90% of our assets based on the PV-10 of our proved oil and natural gas reserves as of March 31, 2011, allowing us to maintain better control over our asset portfolio. Our properties are predominantly located in water depths of less than 300 feet. In addition, we own a 49% interest in and operate the deepwater Bullwinkle field and associated platform, located in approximately 1,350 feet of water. Similar to our shallow water properties, the Bullwinkle field produces from a fixed-leg platform utilizing surface wellheads and blowout preventers and, consequently, is not subject to recent regulations instituted for deepwater drilling.

Our Acquisition History

        A significant portion of our growth has been achieved through a series of acquisitions. Since we began operations in 2008, we have completed eight material acquisitions, creating significant value relative to the capital employed. Since inception, our principal equity owners have invested

1


Table of Contents


approximately $225 million and have received approximately $83 million in aggregate distributions from cash flows, for a net investment of $142 million. Over this same period, we have incurred a total of $340 million in debt, with $175 million of debt outstanding as of June 30, 2011. As a result of these acquisitions and our operations, the PV-10 of our proved oil and natural gas reserves totaled approximately $1.2 billion as of March 31, 2011.

        We believe that the Gulf of Mexico continues to represent an attractive buyer's market, given the limited number of competitors and the availability of acquisition opportunities, as other oil and natural gas companies divest their Gulf of Mexico properties. For example, we recently entered into an agreement with subsidiaries of Exxon Mobil Corporation ("Exxon") to acquire offshore assets formerly owned by certain subsidiaries of XTO Energy Inc. Please read "—Recent Developments—XTO Acquisition." We will continue to be opportunistic in evaluating potential acquisition targets, which we expect will include both shallow water properties and properties in deeper waters with characteristics similar to the Bullwinkle field.

        The following table presents key metrics related to each of our material acquisitions. For more information, please read "Business—Acquisition History."

 
   
   
  As of Acquisition Date  
Acquisition
  Acquisition
Date
  Major Fields   Net
Proved
Reserves
(MMBoe)
  % Oil   % Proved
Developed
 

SPN Resources(1)

  March 2008     South Pass 60, West Delta 79/80     10.2     57 %   90 %

Northstar

  July 2008     Eugene Island 307, Eugene Island 32     8.7     47 %   75 %

Bayou Bend Petroleum

  May 2009     Marsh Island     0.6     13 %   73 %

Beryl Oil and Gas(1)

  October 2009     Vermilion 362-371     14.3     25 %   85 %

Shell

  January 2010     Bullwinkle     6.2     89 %   68 %

Samson Resources

  July 2010     Vermilion 272, High Island 52     4.9     48 %   92 %

Providence Resources

  March 2011     Ship Shoal 252/253, Main Pass 19     1.4     22 %   82 %

Gryphon Exploration(2)

  May 2011     High Island 52, Ship Shoal 301     2.1     12 %   100 %

XTO

  Pending     South Marsh Island 41,
West Cameron 485/507
    13.5 (3)   39 %(3)   72 %(3)

MOR

  Pending     (4)     3.5 (5)   65 %(5)   92 %(5)

(1)
Includes interests subsequently acquired from Superior in exchange for a 10% equity interest in us.

(2)
The reserve information relating to Gryphon Exploration as of May 1, 2011 is included in Netherland, Sewell & Associates, Inc.'s ("NSAI") March 31, 2011 reserve report for our oil and natural gas properties.

(3)
As of July 31, 2011, based on a reserve report prepared by NSAI and our internally prepared reserve estimates.

(4)
We expect to acquire the remaining 25% working interest in the properties that we acquired from SPN Resources in 2008, including the South Pass 60 and West Delta 79/80 fields.

(5)
As of March 31, 2011, based on a reserve report prepared by NSAI.

        Since our inception, we have acquired 48,509 MBoe of net proved reserves through eight material acquisitions and produced 13,885 MBoe (excluding the XTO Acquisition and the MOR Transaction). At March 31, 2011, our estimated net proved reserves were 45,223 MBoe (excluding the additional reserves that we expect to acquire in the XTO Acquisition and the MOR Transaction).

Our Significant Fields

        All of our oil and natural gas properties are located in federal and state waters in the Gulf of Mexico. In the aggregate, our five largest fields, based on proved reserves, accounted for approximately

2


Table of Contents


64% of the PV-10 of our proved oil and natural gas reserves as of March 31, 2011. Our largest fields include the following:

    Bullwinkle field:  The Bullwinkle field is located in approximately 1,350 feet of water and encompasses all of Green Canyon blocks 65, 108 and 109. Cumulative production from our Bullwinkle field from first production in 1989 through April 2011 totaled approximately 113 MMBbls of oil and 175 Bcf of natural gas. Also, the Bullwinkle platform serves as a major processing hub for deepwater production of third party fields for which we receive significant production handling revenues.

    West Delta 79/80 field:  The West Delta 79/80 field is located in approximately 150 feet of water and encompasses all or portions of West Delta blocks 57, 79 and 80. Cumulative production from our West Delta 79/80 field from first production in 1970 through April 2011 totaled approximately 162 MMBbls of oil and 616 Bcf of natural gas.

    South Pass 60 field:  The South Pass 60 field is located in approximately 250 feet of water and encompasses all or portions of South Pass blocks 6, 17, 59, 60, 61, 66 and 67. Cumulative production from our South Pass 60 field from first production in 1972 through April 2011 totaled approximately 229 MMBbls of oil and 498 Bcf of natural gas.

    Vermilion 362-371 field:  The Vermilion 362-371 field is located in approximately 300 feet of water and encompasses all of Vermilion blocks 362, 363 and 371. Cumulative production from our Vermilion 362-371 field from first production in 1994 through April 2011 totaled approximately 6 MMBbls of oil and 65 Bcf of natural gas.

    Vermilion 272 field:  The Vermilion 272 field is located in approximately 175 feet of water and encompasses all of Vermilion block 272 and all of South Marsh Island blocks 87 and 102. Cumulative production from our Vermilion 272 field from first production in 2003 through April 2011 totaled approximately 6 MMBbls of oil and 14 Bcf of natural gas.

        The following table presents summary data regarding our largest fields as of the date and for the period indicated:

 
   
   
  As of March 31, 2011    
 
Field
  Acquired
From
  Operator   Average
Working
Interest
  % Oil of
Proved
Reserves
  June 2011
Average Net Daily
Production (Boe/d)
 

Bullwinkle

  Shell   Dynamic     49 %   84 %   1,796  

West Delta 79/80

  SPN   Dynamic     75 %(1)   66 %   991  

South Pass 60

  SPN   Dynamic     75 %(1)   84 %   1,308  

Vermilion 362-371

  Beryl   Dynamic     67 %   34 %   1,935  

Vermilion 272

  Samson   Dynamic     100 %   85 %   929  

(1)
We will own a 100% working interest following the completion of the MOR Transaction.

Our Business Strategies

        Our goal is to increase stockholder value by growing reserves, production and cash flows at an attractive return on invested capital. We seek to achieve this goal through the following strategies:

    Continue to pursue strategic acquisitions.  We intend to continue to selectively acquire companies and producing properties based on disciplined valuations of proved reserves. Our acquisition strategy is focused on identifying motivated sellers of operated properties with underworked assets where the total asset retirement obligation is proportionate to the proved reserve value of the assets. We believe these types of assets are candidates for lower-risk production enhancement activities. By applying a disciplined valuation methodology, we reduce the risk of

3


Table of Contents

      underperformance on the acquired properties while maintaining the potential for higher returns on our investment. We believe that opportunities to consolidate interests in our existing properties will continue to be available and that these consolidation transactions can generate attractive returns without the risks associated with acquiring and operating new assets. For example, we recently agreed with Moreno Offshore Resources, LLC to consolidate our interests in the properties we previously acquired from SPN Resources in 2008. Please read "—Recent Developments—MOR Transaction." We also believe that maintaining a strong financial profile through our disciplined financial policy helps position us as a preferred buyer by mitigating sellers' concerns regarding our ability to close transactions and fund future abandonment obligations.

    Enhance returns by focusing on operations and cost efficiencies.  We believe that our focus on lower risk production enhancement activities, such as workovers and recompletions on producing and shut-in wellbores, is one of the most cost-effective ways to maintain and grow production. We are engaged in a continual effort to monitor and reduce operating expenses by finding opportunities to safely increase operational efficiencies related to staffing, transportation and operational procedures. Moreover, our ability to accurately estimate and manage plugging and abandonment ("P&A") costs associated with potential acquisitions increases the likelihood of achieving our target returns on investment.

    Focus primarily on the shallow waters of the Gulf of Mexico.  Our experience in the Gulf of Mexico has led us to focus our efforts in that particular region, where we are familiar with the regulatory, geological and operational characteristics of this environment. This geographic focus enables us to minimize logistical costs and required staff.

    Maintain a disciplined financial policy.  We intend to continue to pursue a disciplined financial policy by maintaining a prudent capital structure and managing our exposure to interest rate and commodity price risk. We plan to continue maintaining relatively modest leverage and financing our growth with a balanced combination of equity and debt. Maintaining a balanced capital structure allows us to use our available capital to selectively pursue attractive investments or acquisition opportunities.

    Manage our exposure to commodity price risk.  We intend to continue to manage our exposure to commodity price risk in the near term while remaining opportunistic over the long term. We use a variety of hedging instruments to accomplish our risk management objectives and enhance the stability of our cash flows. Our commodity derivative contracts are currently in the form of basic swaps and collars that are designed to provide a fixed price (swaps) or defined range of prices (collars) that we will receive. We have a policy of hedging at least 50% of our forecasted proved developed producing volumes on a two-year rolling basis. We actively monitor our hedge portfolio to support our cash flow objectives.

Our Competitive Strengths

        We have a number of competitive strengths that we believe will help us to successfully execute our business strategies:

    Acquisition execution capabilities.  We have a proven track record of identifying, evaluating and executing the purchase of oil and natural gas assets and companies. Since we began operations in 2008, we have completed eight material acquisitions, creating significant value relative to the capital employed. In addition, we have two acquisitions currently pending. The significant history, experience and familiarity of our executive management team with the Gulf of Mexico leads potential sellers to contact us directly, which reduces potential competition from other buyers. We have an experienced team of professionals dedicated primarily to the technical evaluation of acquisitions and reserve analysis, which allows us to continuously pursue opportunities without compromising the management of our existing assets. Moreover, we

4


Table of Contents

      believe that our expertise related to the legal, financial and regulatory aspects of mergers and acquisitions allows us to quickly and successfully close transactions.

    High-quality asset base with significant production enhancement opportunities.  Our producing asset base is composed of some of the largest fields discovered in the Gulf of Mexico. Given the prolific nature of our assets, we believe that our fields are characterized by lower-risk properties and offer significant additional development and exploration potential. Specifically, our geological and geophysical professionals have identified a multi-year inventory of potential drilling locations in our fields associated with our proved reserves, which we believe represent lower-risk opportunities. In addition, we have identified a substantial inventory of unproven prospects through the technical evaluation of our properties. We have licenses for recent 3-D seismic data utilizing modern processing techniques on more than 450 offshore blocks. Our seismic data covers the vast majority of our acreage holdings, including multiple data sets over several of our more valuable properties. Many of our fields contain several producing zones, providing us increased opportunities for production enhancement activities within each wellbore. Additionally, we own the rights to deep intervals on the vast majority of our 661,000 gross (317,000 net) acres in the Gulf of Mexico, which includes the depths at which ultra-deep exploration is underway on the Gulf of Mexico shelf.

    Operating control over the majority of our portfolio of assets.  We operate more than 90% of our assets based on the PV-10 of our proved oil and natural gas reserves as of March 31, 2011, allowing us to maintain better control over our asset portfolio. We believe that 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 also believe that maintaining operational control over the majority of our assets allows us to better pursue our strategies of enhancing returns through focusing on production enhancement opportunities, operational and cost efficiencies, maximizing hydrocarbon recovery and effectively managing our P&A liabilities.

    Strong financial profile.  We believe that our strong financial profile positions us as a preferred buyer for potential acquisitions. After the completion of this offering, we expect to continue to have strong liquidity and financial flexibility sufficient to fund our anticipated capital needs and future growth opportunities. As of June 30, 2011, after giving effect to the XTO Acquisition and the MOR Transaction and related borrowing base increases and the application of the net proceeds of this offering, we would have had approximately $             million outstanding under our revolving credit facility, with additional availability of approximately $             million. Please read "—Recent Developments—XTO Acquisition," "—MOR Transaction" and "—Borrowing Base Increases." We expect that cash flows from our assets will be sufficient to fund our planned capital expenditure activities, and given our high level of operational control, we should be able to maintain control over the pace of spending.

    Significant oil exposure.  As of March 31, 2011, our estimated net proved reserves were composed of approximately 52% oil. This oil exposure allows us to benefit from the disparity between relative oil and natural gas prices, which has persisted over the last several years and which we expect to continue in the future. Nearly all of our oil is sold at LLS, HLS and EIC prices, which have recently traded at a significant premium to NYMEX WTI benchmark prices. Consequently, our oil production benefits from higher pricing differentials relative to many other North American crude oil producers in other areas. For example, for the three months ended June 30, 2011, the average realized price before the effect of commodity derivative contracts for our oil production was $113.85 per Bbl, compared to an average WTI index price of $102.34 per Bbl for the same period.

    Efficient management of our P&A activities.  We consider the evaluation and execution of P&A activities to be one of our core competencies. We have an experienced internal team with a dedicated focus on managing our P&A activities and estimating P&A costs associated with

5


Table of Contents

      acquisition opportunities. Our ongoing effort to manage our P&A liabilities by proactively removing inactive structures, wellbores and pipelines meaningfully reduces our operating expenses, maintenance expenses, insurance premiums and overall risk exposure.

    Experienced and incentivized management team.  Our management team has an average of more than 28 years of energy industry experience, primarily focused on the Gulf of Mexico. In addition, our executive officers have a meaningful economic interest in us, which is expected to total approximately        % of our common stock following the completion of this offering, thereby aligning management's interests with those of our stockholders.

    Affiliation with Riverstone.  Riverstone Holdings LLC ("Riverstone") has significant energy and financial expertise to complement its investment in us. To date, Riverstone has committed approximately $16.0 billion to 79 investments across the midstream, upstream, power, oilfield service and renewable sectors of the energy industry. Following the completion of this offering, Riverstone and its affiliates will own an approximate        % interest in us. We expect that our relationship with Riverstone will continue to provide us with several significant benefits, including access to potential transactions and financial professionals with a successful track record of investing in energy assets. Please read "Certain Relationships and Related Party Transactions—Riverstone Investments in Dynamic."

    Relationship with Superior.  Superior Energy Services and its affiliates (collectively, "Superior") will continue to own a significant equity interest in us following this offering and is a co-owner in Bullwinkle. We believe this relationship offers several significant benefits, including access to technical expertise related to well intervention and decommissioning and insight into offshore service market conditions. Our complementary areas of expertise and operational capabilities position us favorably in the pursuit of future acquisition opportunities. Please read "Certain Relationships and Related Party Transactions—Transactions with Superior."

Recent Developments

    XTO Acquisition

        On July 29, 2011, we entered into an agreement with XTO Offshore Inc., HHE Energy Company and XH, LLC, each an indirect subsidiary of Exxon, to acquire certain oil and natural gas interests in the Gulf of Mexico for approximately $182.5 million (the "XTO Acquisition"). The properties to be acquired comprise substantially all of the Gulf of Mexico assets that Exxon acquired as part of its acquisition of XTO Energy, Inc. in 2010 (the "XTO Acquisition Properties"). As of July 31, 2011, based on a reserve report prepared by NSAI and our internally prepared reserve estimates these properties contained 13,535 MBoe of proved reserves, of which 39% was oil, and 7,025 MBoe of probable reserves. As of that same date, the PV-10 of the proved oil and natural gas reserves was approximately $329 million, and the PV-10 of the probable oil and natural gas reserves was approximately $87 million, in each case based on SEC pricing of $88.44 per Bbl for oil and $4.19 per MMBtu for natural gas. Please read "—Summary Reserve Data—XTO Reserve Data."

        The XTO Acquisition Properties include approximately 250,000 gross (130,000 net) acres and 135 gross (62 net) producing wells. We expect net production from the XTO Acquisition Properties during August 2011 to exceed 7,000 Boe/d. Additionally, our geological and geophysical professionals have identified an inventory of over 30 potential drilling locations. We will operate over 90% of the XTO Acquisition Properties.

        We expect to complete the XTO Acquisition by August 31, 2011, subject to customary closing conditions. The description of the XTO Acquisition Properties does not give effect to any potential adjustments, including adjustments resulting from the exercise of preferential rights to purchase, which we do not expect to be material. For more information about the XTO Acquisition Properties, please read "Business—XTO Acquisition," "—Our Operations—Estimated Reserves—XTO" and the

6


Table of Contents


statements of revenues and direct operating expenses for the XTO Acquisition Properties included elsewhere in this prospectus.

    MOR Transaction

        On August 25, 2011, we agreed with Moreno Offshore Resources, LLC ("MOR") to pay $68.0 million to acquire the remaining 25% working interest in the properties that we acquired from SPN Resources in 2008 (the "MOR Transaction"). MOR had originally acquired this interest from SPN Resources at the same time as our initial acquisition. As of March 31, 2011, MOR's 25% working interest represented approximately 3,548 MBoe of proved reserves, of which approximately 65% was oil, and 302 MBoe of probable reserves. As of that same date, the PV-10 of the proved oil and natural gas reserves associated with MOR's working interest was approximately $92 million, and the PV-10 of the probable oil and natural gas reserves was approximately $9 million, in each case based on SEC pricing of $80.04 per Bbl for oil and $4.10 per MMBtu for natural gas. Net production attributable to MOR's 25% working interest during June 2011 was approximately 1,369 Boe/d. We currently operate the vast majority of the properties in which we expect to acquire the remaining interest. Please read "—Summary Reserve Data—MOR Reserve Data."

        We expect to complete the MOR Transaction on or about September 15, 2011. For more information about the properties to be acquired in the MOR Transaction, please read "Business—MOR Transaction" and "—Our Operations—Estimated Reserves—MOR."

    Borrowing Base Increases

        In connection with the XTO Acquisition and the MOR Transaction, the lenders under our credit facility approved two independent increases to our borrowing base of $105 million and $25 million, respectively. Each increase is subject to the closing of the related acquisition by September 30, 2011, compliance with the provisions of the credit agreement and our entering into additional commodity derivative contracts.

        Assuming both the XTO Acquisition and the MOR Transaction are closed and we satisfy the other conditions, our borrowing base will increase from the current level of $300 million to $430 million. As of June 30, 2011, after giving effect to the XTO Acquisition and the MOR Transaction and related borrowing base increases and the application of the net proceeds of this offering, we would have had approximately $             million outstanding under our revolving credit facility, with additional availability of approximately $             million.

Risk Factors

        For a discussion of the risks and other considerations that could negatively affect us, including risks related to this offering and our common stock, please read "Risk Factors" beginning on page 20 and "Cautionary Note Regarding Forward-Looking Statements."

Conflicts of Interest

        Affiliates of Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc. and UBS Securities LLC are lenders, and in one case, an agent for the lenders, under our credit facility. A "conflict of interest" under Rule 5121 of the Financial Industry Regulatory Authority, or FINRA, is therefore deemed to exist. Accordingly, this offering is being made in compliance with Rule 5121. Pursuant to Rule 5121, the initial public offering price of the shares of common stock must not be higher than that recommended by a "qualified independent underwriter" meeting certain standards, and the qualified independent underwriter must exercise the usual standards of due diligence with respect to the registration statement of which this prospectus forms a part. Tudor Pickering, Holt & Co. has assumed the responsibilities of acting as the qualified independent underwriter in this offering. Please read "Underwriters—Conflicts of Interest" beginning on page 128.

7


Table of Contents

Corporate Reorganization

        Pursuant to the terms of a corporate reorganization that will be completed immediately prior to the closing of this offering, Dynamic Offshore Holding, LP will merge into its wholly owned subsidiary, Dynamic Offshore Resources, Inc., and all limited partner interests in Dynamic Offshore Holding, LP will be converted into the right to receive common stock of Dynamic Offshore Resources, Inc. For more information regarding our corporate reorganization, please read "Corporate Reorganization."

Corporate Information

        Our principal executive offices are located at 1301 McKinney, Suite 900, Houston, Texas 77010, and our telephone number at that address is (713) 728-7840. Our website is located at www.dynamicosr.com. We expect to make our periodic reports and other information filed with or furnished to the SEC available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

8


Table of Contents


THE OFFERING

Common stock offered by Dynamic Offshore Resources, Inc. 

              shares.

Common stock offered by the selling stockholders

 

            shares (            shares if the underwriters' over-allotment option is exercised in full).

Total common stock offered

 

            shares (            shares if the underwriters' over-allotment option is exercised in full).

Common stock to be outstanding after the offering

 

            shares.

Over-allotment option

 

The selling stockholders have 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 the net proceeds from this offering to repay outstanding borrowings under our revolving credit facility and for general corporate purposes. We will not receive any proceeds from the sale of shares by the selling stockholders, including pursuant to any exercise of the underwriters' over-allotment option to purchase additional shares of our common stock.

 

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. Please read "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 places certain restrictions on our ability to pay cash dividends. Please read "Dividend Policy."

Risk factors

 

You should carefully read and consider the information beginning on page 20 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.

Listing and trading symbol

 

We intend to apply to list our common stock on the New York Stock Exchange under the symbol "DOR".

9


Table of Contents


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 (i) summary historical consolidated financial data for the period from January 1, 2008 through March 13, 2008 of SPN Resources LLC, our accounting predecessor, which has been derived from the audited financial statements of SPN Resources LLC included elsewhere in this prospectus, (ii) our summary historical consolidated financial data for the years ended December 31, 2008, 2009 and 2010, and balance sheet data at December 31, 2009 and 2010, which has been derived from the audited financial statements of Dynamic Offshore Holding, LP included elsewhere in this prospectus, (iii) our summary historical consolidated financial data for the six months ended June 30, 2010 and 2011 and balance sheet data at June 30, 2011, which has been derived from the unaudited financial statements of Dynamic Offshore Holding, LP included elsewhere in this prospectus, and (iv) pro forma consolidated financial data for the year ended December 31, 2010 and the six months ended June 30, 2011 and pro forma balance sheet data at June 30, 2011, which has been derived from the unaudited pro forma financial statements included elsewhere in this prospectus.

        The unaudited pro forma financial data for the year ended December 31, 2010, which reflects our acquisition of certain oil and natural gas properties from Samson Resources on July 8, 2010 (the "Samson Acquisition Properties"), our pending XTO Acquisition, our corporate reorganization and the effects of this offering and the application of the net proceeds, was derived from the unaudited pro forma financial information included elsewhere in this prospectus. The unaudited pro forma financial information for the year ended December 31, 2010 and the six months ended June 30, 2011 was prepared as if each of these transactions occurred on January 1, 2010. The unaudited pro forma financial information as of June 30, 2011 was prepared as if our pending XTO Acquisition, our corporate reorganization and this offering and the application of the net proceeds had occurred on June 30, 2011. The unaudited pro forma financial information does not give effect to our pending MOR Transaction.

10


Table of Contents

 
  Historical   Pro Forma  
 
  Predecessor   Dynamic Offshore Holding, LP  
 
  January 1,
2008
Through
March 13,
2008
  Year Ended
December 31,
  Six Months Ended
June 30,
   
  Six
Months
Ended
June 30,
2011
 
 
  Year Ended
December 31,
2010
 
 
  2008   2009   2010   2010   2011  
 
  (In thousands)
 

Statement of operations data:

                                                 

Oil and gas revenues

  $ 56,179   $ 163,649   $ 155,596   $ 317,584   $ 149,210   $ 201,864   $ 512,688   $ 268,549  

Other operating revenues

    741     1,173     1,557     12,552     3,266     7,866     12,552     7,866  
                                   

    56,920     164,822     157,153     330,136     152,476     209,730   $ 525,240   $ 276,415  

Operating expenses:

                                                 
 

Lease operating expense

    8,791     30,192     52,181     81,055     36,649     43,739     119,684     56,718  
 

Exploration expense

        67     8,908     2,093     994     5,147     2,093     5,147  
 

Depreciation, depletion and amortization

    13,414     41,230     82,507     184,324     55,291     62,479     285,494     89,860  
 

General and administrative expense

    2,275     15,591     22,841     22,687     12,324     11,920     22,687     11,920  
 

Other operating expense(1)

    4,786     23,971     43,347     66,411     31,384     27,963     76,884     32,011  
                                   

    29,266     111,051     209,784     356,570     136,642     151,248     506,842     195,656  
                                   

Income (loss) from operations

    27,654     53,771     (52,631 )   (26,434 )   15,834     58,482     18,398     80,759  

Other income (expense):

                                                 
 

Interest expense, net

    (34 )   (3,667 )   (8,328 )   (14,661 )   (7,483 )   (4,950 )   (13,544 )   (3,565 )
 

Commodity derivative income (expense)

        159,939     (21,887 )   6,990     30,252     (9,884 )   6,990     (9,884 )
 

Bargain purchase gain

            161,351     4,024             4,024      
 

Other

                (1,080 )       1,166     (1,080 )   1,166  
                                   

Income (loss) before income taxes

    27,620     210,043     78,505     (31,161 )   38,603     44,814     14,788     68,476  

Income tax benefit (expense)

        (14,738 )   20,387     14,814     2,669     503     (5,870 )   (23,967 )
                                   

Net income (loss)

    27,620     195,305     98,892     (16,347 )   41,272     45,317     8,918     44,509  

Less: Net income (loss) attributable to noncontrolling interests

        34,648     57,663     (4,070 )   6,809     460     (2,645 )   299  
                                   

Net income (loss) attributable to Dynamic Offshore Holding, LP

  $ 27,620   $ 160,657   $ 41,229   $ (12,277 ) $ 34,463   $ 44,857   $ 11,563   $ 44,210  
                                   

Income (loss) per share

  $     $     $     $     $     $     $     $    

Diluted income (loss) per share

  $     $     $     $     $     $     $     $    

Adjusted EBITDA(2)

  $ 41,953   $ 119,763   $ 124,490   $ 222,671   $ 102,563   $ 124,459   $ 372,645   $ 175,971  

(1)
Includes insurance expense, workover expense, accretion expense, casualty loss (gain), loss on abandonments, loss (gain) on sale of assets and other.

(2)
Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, please read "—Non-GAAP Financial Measure."

 
  As of December 31,    
   
 
 
  As of
June 30, 2011
  Pro Forma As of
June 30, 2011
 
 
  2009   2010  
 
  (In thousands)
 

Balance sheet data:

                         

Cash and cash equivalents

  $ 88,457   $ 75,162   $ 28,872   $ 28,227  

Net property, plant and equipment

    798,255     809,035     841,255     1,096,046  

Total assets

    1,056,285     987,918     984,254     1,249,400  

Long-term debt

    243,000     203,205     175,000     79,500  

Total owners'/stockholders' equity

    482,175     431,714     458,168     735,786  

11


Table of Contents


 
  Predecessor   Dynamic Offshore Holding, LP  
 
  January 1,
2008
Through
March 13,
2008
  Years Ended
December 31,
  Six Months
Ended June 30,
 
 
  2008   2009   2010   2010   2011  
 
  (In thousands)
 

Other financial data:

                                     

Net cash provided by operating activities

  $ 22,836   $ 124,835   $ 30,432   $ 151,814   $ 79,619   $ 93,372  

Net cash provided by (used in) investing activities

    (3,627 )   (362,317 )   69,439     (91,200 )   (2,080 )   (89,362 )

Net cash provided by (used in) financing activities

    —-     289,512     (63,589 )   (73,909 )   (73,157 )   (50,300 )

Non-GAAP Financial Measure

    Adjusted EBITDA

        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, to compare our performance across reporting periods on a consistent basis by excluding items that we do not believe are indicative of our core operating performance.

        We define Adjusted EBITDA as revenues, including commodity derivative settlements, less lease operating expense, workover expense, insurance expense and general and administrative expense. Adjusted EBITDA is not a measure of net income or cash flows as determined by United States generally accepted accounting principles ("GAAP").

        Our senior management reviews Adjusted EBITDA monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results. Adjusted EBITDA provides useful information to investors because it is a supplemental financial measure used by us and by external users of our financial statements, including investors, commercial banks and others, to assess:

    the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

    our operating performance and return on capital as compared to other companies in our industry, without regard to financing or capital structure; and

    the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

        Adjusted EBITDA has limitations as an analytical tool and should not be considered as an alternative to, or more meaningful than, performance measures calculated in accordance with GAAP. Some of these limitations are:

    certain items excluded from Adjusted EBITDA are significant components in understanding a company's financial performance, such as a company's cost of capital and tax structure;

    Adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;

    Adjusted EBITDA does not reflect changes in, or cash requirements for, our working capital needs;

12


Table of Contents

    Adjusted EBITDA does not consider the potentially dilutive impact of share-based compensation;

    although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and Adjusted EBITDA does not reflect any cash requirements for such replacements; and

    our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

        Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating that understanding into its decision-making processes.

        The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities.

 
  Historical   Pro Forma  
 
  Predecessor   Dynamic Offshore Holding, LP  
 
  January 1,
2008
Through
March 13,
2008
  Year Ended
December 31,
  Six Months Ended
June 30,
   
  Six
Months
Ended
June 30,
2011
 
 
  Year Ended
December 31,
2010
 
 
  2008   2009   2010   2010   2011  
 
  (In thousands)
 

Reconciliation of net income (loss) to Adjusted EBITDA:

                                                 

Net income (loss)

  $ 27,620   $ 195,305   $ 98,892   $ (16,347 ) $ 41,272   $ 45,317   $ 8,918   $ 44,509  

Interest expense, net

    34     3,667     8,328     14,661     7,483     4,950     13,544     3,565  

Income tax expense (benefit)

        14,738     (20,387 )   (14,814 )   (2,669 )   (503 )   5,870     23,967  

Depreciation, depletion and amortization

    13,414     41,230     82,507     184,324     55,291     62,479     285,494     89,860  

Unrealized gain (loss) on commodity derivatives

        (146,671 )   97,975     36,181     (2,259 )   2,441     36,181     2,441  

Other operating expense

    885     11,494     18,526     21,610     3,445     10,941     25,582     12,795  

Bargain purchase gain

            (161,351 )   (4,024 )           (4,024 )    

Other

                1,080         (1,166 )   1,080     (1,166 )
                                   

Adjusted EBITDA

  $ 41,953   $ 119,763   $ 124,490   $ 222,671   $ 102,563   $ 124,459   $ 372,645   $ 175,971  
                                   

Reconciliation of net cash provided by operating activities to Adjusted EBITDA:

                                                 

Net cash provided by operating activities

  $ 22,836   $ 124,835   $ 30,432   $ 151,814   $ 79,619   $ 93,372              

Derivative settlements

        13,268     76,088     43,171     27,993     (7,443 )            

Interest expense, net

    34     3,667     8,328     14,661     7,483     4,950              

Exploration expense

        67     8,908     2,093     994     5,147              

Amortization in interest expense

        (750 )   (971 )   (1,407 )   (870 )   (784 )            

Current income tax expense

            (2,188 )                        

Changes in operating assets and liabilities

    18,978     (30,061 )   (829 )   10,733     (9,015 )   29,415              

Other

    105     8,737     4,722     1,606     (3,641 )   (198 )            
                                       

Adjusted EBITDA

  $ 41,953   $ 119,763   $ 124,490   $ 222,671   $ 102,563   $ 124,459              
                                       

13


Table of Contents


Summary Historical Operating and Reserve Data

Summary Reserve Data

    Dynamic Reserve Data

        The following table presents summary data with respect to our estimated net proved and probable oil and natural gas reserves as of the dates indicated. The reserve estimates at March 31, 2011 presented in the tables below are based on reports prepared by Netherland, Sewell & Associates, Inc. ("NSAI"), independent reserve engineers, in accordance with the rules and regulations of the SEC regarding oil and natural gas reserve reporting. The reserve estimates at December 31, 2010 presented in the table below are based on estimates prepared by our internal engineers, in accordance with the rules and regulations regarding oil and natural gas reserve reporting. For more information about our summary reserve data, please read "Business—Our Operations" and NSAI's reports, which have been filed as exhibits to the registration statement containing this prospectus.

        Proved reserves are reserves 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 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. Probable reserves are reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves which may potentially be recoverable through additional drilling or recovery techniques are by nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by us.

 
  At December 31,
2010(1)
  At March 31,
2011
 

Reserve Data(2):

             

Estimated proved reserves:

             
 

Oil (MMBbls)

    18.5     23.3  
 

Natural gas (Bcf)

    91.3     131.3  
   

Total estimated proved reserves (MMBoe)

    33.7     45.2  
 

Proved developed (MMBoe)

    28.5     37.9  
 

Percent proved developed

    85 %   84 %
 

Proved undeveloped (MMBoe)

    5.2     7.3  

PV-10 of proved reserves (in millions)(3)

  $ 947.7   $ 1,162.3  

Standardized Measure (in millions)(4)

  $ 1,093.1        

Estimated probable reserves:

             
 

Oil (MMBbls)

    4.6     4.6  
 

Natural gas (Bcf)

    48.7     25.1  
   

Total estimated probable reserves (MMBoe)

    12.7     8.8  

PV-10 of probable reserves (in millions)

  $ 285.1   $ 237.5  

(1)
Includes reserves net to our equity interests in our consolidated subsidiaries in which we owned less than 100% of the outstanding equity as of December 31, 2010.

(2)
Our estimated proved and probable reserves and related future net revenues, PV-10 and Standardized Measure at December 31, 2010 and at March 31, 2011 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 $79.40/Bbl for oil and $4.38/MMBtu for natural gas at December 31, 2010 and $80.04/Bbl for oil and $4.10/MMBtu for natural gas at March 31, 2011. These prices were adjusted by lease for quality, transportation fees, historical geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

14


Table of Contents

(3)
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. Until the completion of our corporate reorganization in connection with the closing of this offering, we will be a limited partnership not subject to entity-level taxation. Other than with respect to our corporate subsidiary, we have not provided for federal or state corporate income taxes, because taxable income is passed through to our equity holders. Because Standardized Measure as of December 31, 2010 includes a portion attributable to noncontrolling interests in our consolidated subsidiaries, PV-10 of $947.7 million as of December 31, 2010 is reconciled to Standardized Measure of $1,093.1 million at that date by adding noncontrolling interests of $170.2 million and subtracting discounted future net income taxes of $24.8 million. Because Standardized Measure is only calculated as of year-end, there is no GAAP measure comparable to our PV-10 as of March 31, 2011. In connection with the closing of this offering, we will be converted into a corporation. As a result, we will be treated as a taxable entity for federal income tax purposes. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas reserves. 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.
(4)
Standardized Measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows. Standardized Measure as of December 31, 2010 includes $170.2 million attributable to noncontrolling interests in our consolidated subsidiaries. In connection with the closing of this offering, we will be converted into a corporation that will be treated 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, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations."

        The following table illustrates the sensitivity of our estimated proved and probable oil and natural gas reserves and related PV-10 to changes in product price levels. The reserve quantities and PV-10 shown below were prepared on the same basis as in the table above, except for the use of market pricing based on closing forward prices on the NYMEX for oil and natural gas on March 31, 2011 rather than average first-day-of-the-month prices for the prior 12 months as specified by the SEC. Based on SEC pricing, the PV-10 of our proved oil and natural gas reserves was approximately $1.2 billion while, based on NYMEX forward pricing at March 31, 2011, as set forth below, the PV-10 of our proved oil and natural gas reserves was approximately $1.7 billion. Please read "Business—Our Operations—Estimated Reserves—Dynamic" for further discussion of why we believe the presentation of oil and natural gas reserves using forward pricing is useful for investors.

 
  At March 31,
2011
 

Reserve Data(1):

       

Estimated proved reserves:

       
 

Oil (MMBbls)

    23.9  
 

Natural gas (Bcf)

    135.0  
   

Total estimated proved reserves (MMBoe)

    46.4  

PV-10 of proved reserves (in millions)

  $ 1,657.7  

Estimated probable reserves:

       
 

Oil (MMBbls)

    4.6  
 

Natural gas (Bcf)

    26.8  
   

Total estimated probable reserves (MMBoe)

    9.1  

PV-10 of probable reserves (in millions)

  $ 329.3  

(1)
Our estimated proved reserves and related future net revenues and PV-10 at March 31, 2011 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. At March 31, 2011, the

15


Table of Contents

    forward prices were: $109.26/Bbl for oil and $4.59/MMBtu for natural gas for the period ending December 31, 2011; $107.44/Bbl for oil and $5.08/MMBtu for natural gas for the year ending December 31, 2012; $104.02/Bbl for oil and $5.47/MMBtu for natural gas for the year ending December 31, 2013; and $102.23/Bbl for oil and $5.83/MMBtu for natural gas thereafter. These prices were adjusted by lease for quality, transportation fees, historical geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

    XTO Reserve Data

        The following table presents summary data with respect to the estimated net proved and probable oil and natural gas reserves to be acquired in the XTO Acquisition as of the date indicated. The reserve estimates at July 31, 2011 presented in the tables below are based, in part, on reports prepared by NSAI covering 75% of the total net proved reserves (85% of the total net proved developed reserves and 85% of the present value of the total proved reserves) in accordance with the rules and regulations of the SEC regarding oil and natural gas reserve reporting. The remaining 25% of the total net proved reserves (15% of the total net proved developed reserves and 15% of the present value of the total proved reserves) and all of the total probable reserves are based on estimates prepared by our internal engineers. For more information about the summary reserve data for the XTO Acquisition Properties, please read "Business—XTO Acquisition" and NSAI's reports, which have been filed as exhibits to the registration statement containing this prospectus.

 
  At July 31,
2011
 

Reserve Data(1):

       

Estimated proved reserves:

       
 

Oil (MMBbls)

    5.2  
 

Natural gas (Bcf)

    49.8  
   

Total estimated proved reserves (MMBoe)

    13.5  
 

Proved developed (MMBoe)

    9.8  
 

Percent proved developed

    72 %
 

Proved undeveloped (MMBoe)

    3.8  

PV-10 of proved reserves (in millions)

  $ 328.5  

Estimated probable reserves:

       
 

Oil (MMBbls)

    1.5  
 

Natural gas (Bcf)

    33.3  
   

Total estimated probable reserves (MMBoe)

    7.0  

PV-10 of probable reserves (in millions)

  $ 87.4  

(1)
The estimated proved and probable reserves and related future net revenues and PV-10 at July 31, 2011 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 $88.44/Bbl for oil and $4.19/MMBtu for natural gas at July 31, 2011. These prices were adjusted by lease for quality, transportation fees, historical geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

        The following table illustrates the sensitivity of the XTO Acquisition Properties' estimated proved and probable oil and natural gas reserves and related PV-10 to changes in product price levels. The reserve quantities and PV-10 shown below were prepared on the same basis as in the table above, except (i) that NSAI's report covers 84% of the present value of the total proved reserves and (ii) for the use of market pricing based on closing forward prices on the NYMEX for oil and natural gas on July 31, 2011 rather than average first-day-of-the-month prices for the prior 12 months as specified by the SEC. Please read "Business—Our Operations—Estimated Reserves—XTO" for further discussion

16


Table of Contents


of why we believe the presentation of oil and natural gas reserves using forward pricing is useful for investors.

 
  At July 31,
2011
 

Reserve Data(1):

       

Estimated proved reserves:

       
 

Oil (MMBbls)

    5.3  
 

Natural gas (Bcf)

    50.4  
   

Total estimated proved reserves (MMBoe)

    13.7  

PV-10 of proved reserves (in millions)

  $ 413.7  

Estimated probable reserves:

       
 

Oil (MMBbls)

    1.5  
 

Natural gas (Bcf)

    37.4  
   

Total estimated probable reserves (MMBoe)

    7.7  

PV-10 of probable reserves (in millions)

  $ 127.2  

(1)
The estimated proved reserves and related future net revenues and PV-10 at July 31, 2011 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. At July 31, 2011, the forward prices were: $100.14/Bbl for oil and $4.46/MMBtu for natural gas for the period ending December 31, 2011; $102.61/Bbl for oil and $4.79/MMBtu for natural gas for the year ending December 31, 2012; $103.75/Bbl for oil and $5.19/MMBtu for natural gas for the year ending December 31, 2013; and $103.53/Bbl for oil and $5.40/MMBtu for natural gas thereafter. These prices were adjusted by lease for quality, transportation fees, historical geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

    MOR Reserve Data

        The following table presents summary data with respect to the estimated net proved and probable oil and natural gas reserves to be acquired in the MOR Transaction as of the date indicated. The reserve estimates at March 31, 2011 presented in the tables below are based on reports prepared by NSAI in accordance with the rules and regulations of the SEC regarding oil and natural gas reserve reporting. For more information about the summary reserve data for the MOR Transaction, please read

17


Table of Contents

"Business—MOR Transaction" and NSAI's reports, which have been filed as exhibits to the registration statement containing this prospectus.

 
  At March 31,
2011
 

Reserve Data(1):

       

Estimated proved reserves:

       
 

Oil (MMBbls)

    2.3  
 

Natural gas (Bcf)

    7.4  
   

Total estimated proved reserves (MMBoe)

    3.5  
 

Proved developed (MMBoe)

    3.3  
 

Percent proved developed

    92%  
 

Proved undeveloped (MMBoe)

    0.3  

PV-10 of proved reserves (in millions)

  $ 92.5  

Estimated probable reserves:

       
 

Oil (MMBbls)

    0.2  
 

Natural gas (Bcf)

    0.7  
   

Total estimated probable reserves (MMBoe)

    0.3  

PV-10 of probable reserves (in millions)

  $ 9.1  

(1)
The estimated proved and probable reserves and related future net revenues and PV-10 at March 31, 2011 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 $80.04/Bbl for oil and $4.10/MMBtu for natural gas at March 31, 2011. These prices were adjusted by lease for quality, transportation fees, historical geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

        The following table illustrates the sensitivity of the MOR Transaction properties' estimated proved and probable oil and natural gas reserves and related PV-10 to changes in product price levels. The reserve quantities and PV-10 shown below were prepared on the same basis as in the table above, except for the use of market pricing based on closing forward prices on the NYMEX for oil and natural gas on March 31, 2011 rather than average first-day-of-the-month prices for the prior 12 months as specified by the SEC. Please read "Business—Our Operations—Estimated Reserves—MOR" for further discussion of why we believe the presentation of oil and natural gas reserves using forward pricing is useful for investors.

 
  At March 31,
2011
 

Reserve Data(1):

       

Estimated proved reserves:

       
 

Oil (MMBbls)

    2.4  
 

Natural gas (Bcf)

    7.6  
   

Total estimated proved reserves (MMBoe)

    3.7  

PV-10 of proved reserves (in millions)

  $ 132.1  

Estimated probable reserves:

       
 

Oil (MMBbls)

    0.2  
 

Natural gas (Bcf)

    0.9  
   

Total estimated probable reserves (MMBoe)

    0.3  

PV-10 of probable reserves (in millions)

  $ 12.7  

(1)
The estimated proved reserves and related future net revenues and PV-10 at March 31, 2011 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. At March 31, 2011, the forward prices were: $109.26/Bbl for oil and $4.59/MMBtu for natural gas for the period ending

18


Table of Contents

    December 31, 2011; $107.44/Bbl for oil and $5.08/MMBtu for natural gas for the year ending December 31, 2012; $104.02/Bbl for oil and $5.47/MMBtu for natural gas for the year ending December 31, 2013; and $102.23/Bbl for oil and $5.83/MMBtu for natural gas thereafter. These prices were adjusted by lease for quality, transportation fees, historical geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

Summary Operating Data

        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. This summary data is presented on a basis consistent with our consolidated financial statements. The unaudited pro forma information was prepared as if our acquisition of oil and natural gas properties from Samson Resources and our XTO Acquisition had each occurred on January 1, 2010, but it does not give effect to our pending MOR Transaction.

 
  Historical   Pro Forma  
 
  Predecessor   Dynamic Offshore Holding, LP  
 
  January 1,
2008
Through
March 13,
2008
  Year Ended
December 31,
  Six Months Ended
June 30,
   
  Six
Months
Ended
June 30,
2011
 
 
  Year Ended
December 31,
2010
 
 
  2008   2009   2010   2010   2011  

Operating data:

                                                 

Net sales volumes:

                                                 
 

Oil (MBbls)

    364     1,055     1,820     2,986     1,371     1,499     4,514     1,938  
 

Natural gas (MMcf)

    2,575     5,369     9,648     17,615     8,813     8,612     33,006     12,152  
                                   
 

Total (MBoe)

    793     1,950     3,428     5,922     2,840     2,934     10,015     3,963  
                                   
 

Average net daily production (Boe/d)

    10,859     5,328     9,392     16,225     15,691     16,210     27,438     21,895  
                                   

Average sales prices:

                                                 
 

Oil, without realized derivatives ($/Bbl)

    96.72     104.20     63.00     78.54     76.67     106.83     78.34     107.23  
 

Natural gas, without realized derivatives ($/Mcf)

    8.16     10.00     4.24     4.72     5.00     4.85     4.54     4.76  
 

Oil, with realized derivatives ($/Bbl)(1)

    96.72     116.93     95.19     87.03     90.81     96.69     83.96     99.39 (2)
 

Natural gas, with realized derivatives ($/Mcf)(1)

    8.16     9.98     6.06     5.73     5.98     5.75     5.08     5.40  
 

Oil, WTI benchmark ($/Bbl)

    96.25     99.75     62.09     79.61     78.46     98.50     79.61     98.50 (2)
 

Natural gas, Henry Hub benchmark ($/MMBtu)

    8.58     8.90     4.16     4.38     4.66     4.29     4.38     4.29  

Costs and expenses ($/Boe):

                                                 
 

Lease operating expense

    11.09     15.48     15.22     13.69     12.71     14.91     11.95     14.31  
 

Depreciation, depletion and amortization

    16.92     21.14     24.07     31.13     19.47     21.29     28.51     22.67  
 

General and administrative expense

    2.87     8.00     6.66     3.83     4.34     4.06     2.27     3.01  

(1)
Realized prices include realized gains or losses on cash settlements for our commodity derivative contracts, which have not been designated for hedge accounting. We have not made any estimates of the impact of commodities derivatives on the average sales price for our predecessor.

(2)
For the three months ended June 30, 2011, the average realized price before the effect of commodity derivative contracts for our oil production was $113.85 per Bbl, compared to an average WTI index price of $102.34 per Bbl for the same period.

19


Table of Contents


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 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 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. We expect that these markets will 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;

    weather conditions and natural disasters;

    the actions of the Organization of Petroleum Exporting Countries;

    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;

    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 at market-based prices. Lower oil and natural gas prices will reduce our cash flows, borrowing ability and the present value of our reserves. If oil and natural gas prices materially deteriorate, we anticipate that the revised borrowing base under our revolving credit facility may be reduced. For more information, please read "—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."

        In addition, 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. For more information, please

20


Table of Contents


read "—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."

Our offshore operations will involve special risks that could affect operations adversely.

        Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions, or result in loss of equipment and properties. In particular, we are not intending to put in place business interruption insurance due to its high cost. We therefore may not be able to rely on insurance coverage in the event of such natural phenomena.

The geographic concentration of our properties in the Gulf of Mexico subjects us to an increased risk of loss of revenues or curtailment of production from factors affecting the Gulf of Mexico specifically.

        The geographic concentration of our properties along the U.S. Gulf Coast and adjacent waters on the Outer Continental Shelf means that some or all of our properties could be affected by the same event should the Gulf of Mexico experience:

    severe weather, including hurricanes and tropical storms;

    delays or decreases in production, the availability of equipment, facilities or services;

    changes in the status of pipelines that we depend on for transportation of our production to the marketplace;

    delays or decreases in the availability of capacity to transport, gather or process production; or

    changes in the regulatory environment.

        Because all our properties could experience the same condition at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other operators who have properties over a wider geographic area. For example, following Hurricane Ike in 2008, all of our properties were shut-in for varying lengths of time, as were those of other operators in the Gulf of Mexico.

Relatively short production periods or reserve lives for Gulf of Mexico properties subject us to higher reserve replacement needs.

        High production rates generally result in recovery of a relatively higher percentage of reserves from properties in the Gulf of Mexico during the initial few years when compared to other regions in the United States. Due to high initial production rates, production of reserves from reservoirs in the Gulf of Mexico generally decline more rapidly than from other producing reservoirs. All of our existing operations are in the Gulf of Mexico. As a result, our reserve replacement needs from new prospects may be greater than those of other oil and gas companies with longer-life reserves in other producing areas. Also, our expected revenues and return on capital will depend on prices prevailing during these relatively short production periods.

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,

21


Table of Contents


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, please read "—Our estimated proved and probable 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 hurricanes and tropical storms, which are common in the Gulf of Mexico during certain times of the year;

    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 and probable 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. Please read "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 March 31, 2011.

        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 was prepared by our 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. Moreover, the variability is likely to be higher for probable reserves 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,

22


Table of Contents


results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

The Macondo well explosion and ensuing oil spill could have broad adverse consequences affecting our operations in the Gulf of Mexico, some of which may be unforeseeable.

        In April 2010, there was a fire and explosion aboard the rig drilling the Macondo well operated by another company in ultra deep water in the U.S. Gulf of Mexico. As a result of the explosion and ensuing fire, the rig sank, causing loss of life, and created a major oil spill that produced economic, environmental and natural resource damage in the U.S. Gulf Coast region. In response to the explosion and spill, there have been many proposals by governmental and private constituencies to address the direct impact of the disaster and to prevent similar disasters in the future. Beginning in May 2010, the federal Bureau of Ocean Energy Management, Regulation and Enforcement, (the "BOEMRE") of the U.S. Department of the Interior issued a series of "Notices to Lessees and Operators" ("NTLs"), imposing a variety of new safety measures and permitting requirements, and implementing a moratorium on deepwater drilling activities in the U.S. Gulf of Mexico that effectively shut down deepwater drilling activities until the moratorium was lifted by Secretary of the Interior Ken Salazar in October 2010. Despite the fact that the drilling moratorium was lifted, this spill and its aftermath have led to delays in obtaining drilling permits. Legislation was introduced in the U.S. Congress to expedite the process for offshore permits including limitations on the timeframe for environmental and judicial review, but there is no guarantee that this or similar legislation will pass.

        In addition to the drilling restrictions, new safety measures and permitting requirements already issued by the BOEMRE, there have been numerous additional proposed changes in laws, regulations, guidance and policy in response to the Macondo well explosion and oil spill that could affect our operations and cause us to incur substantial losses or expenditures. Implementation of any one or more of the various proposed responses to the disaster could materially adversely affect operations in the U.S. Gulf of Mexico by raising operating costs, increasing insurance premiums, delaying drilling operations and increasing regulatory costs, and, further, could lead to a wide variety of other unforeseeable consequences that make operations in the U.S. Gulf of Mexico more difficult, more time consuming, and more costly. For example, during the previous session of Congress, a variety of amendments to the Oil Pollution Act of 1990, (the "OPA"), were proposed in response to the Macondo well incident. The OPA and regulations adopted pursuant to the OPA impose a variety of requirements related to the prevention of and response to oil spills into waters of the United States, including the Outer Continental Shelf, which includes the U.S. Gulf of Mexico where we have substantial offshore operations. The OPA subjects operators of offshore leases and owners and operators of oil handling facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. The OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. The OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the Outer Continental Shelf, although the Secretary of Interior may increase this amount up to $150 million in certain situations. Legislation was proposed in the previous session of Congress to amend the OPA to increase the minimum level of financial responsibility to $300 million or more and there exists the possibility that similar legislation could be introduced and adopted during the current session of Congress. If the OPA is amended during the current session of Congress to increase the minimum level of financial responsibility to $300 million, we may experience difficulty in providing financial assurances sufficient to comply with this requirement. If we are unable to provide the level of financial assurance required by the OPA, we may be forced to sell our properties or operations located on the Outer Continental Shelf or enter into partnerships with other companies that can meet the increased financial responsibility requirement, and any such developments

23


Table of Contents


could have an adverse effect on the value of our offshore assets and the results of our operations. We cannot predict at this time whether the OPA will be amended or whether the level of financial responsibility required for companies operating on the Outer Continental Shelf will be increased.

Regulatory requirements imposed by the BOEMRE could significantly delay our ability to obtain permits to drill new wells in offshore waters.

        Subsequent to the Macondo well incident in the U.S. Gulf of Mexico, the BOEMRE issued a series of NTLs and other regulatory requirements imposing new standards and permitting procedures for new wells to be drilled in federal waters of the Outer Continental Shelf. These requirements include the following:

    The Environmental NTL, which imposes new and more stringent requirements for documenting the environmental impacts potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements.

    The Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well design, construction and flow intervention processes, and also requires certifications of compliance from senior corporate officers.

    The Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling fluids to maintain wellbore integrity, and stiffens oversight requirements relating to blowout preventers and their components, including shear and pipe rams.

    The Workplace Safety Rule, which requires operators to have a comprehensive safety and environmental management system in order to reduce human and organizational errors as root causes of work-related accidents and offshore spills.

        As a result of the issuance of these new regulatory requirements, the BOEMRE has been taking much longer than in the past to review and approve permits for drilling operations. Moreover, as the new standards and procedures are being integrated into the existing framework of offshore regulatory programs, we anticipate that there may be increased costs associated with regulatory compliance and delays in obtaining permits for other operations such as recompletions, workovers and abandonment activities.

        We are unsure what long-term effect, if any, the BOEMRE's additional regulatory requirements and permitting procedures will have on our offshore operations. Consequently, we may be subject to a variety of unforeseen adverse consequences arising directly or indirectly from the Macondo well incident.

Regulatory requirements imposed by the BOEMRE could significantly impact our estimates of future asset retirement obligations from period to period.

        We are responsible for plugging and abandoning wellbores and decommissioning associated platforms, pipelines and facilitates on our oil and natural gas properties. In addition to the NTLs discussed previously, the BOEMRE issued NTL No. 2010-G05, effective October 15, 2010, which establishes a more stringent regimen for the timely decommissioning of what is known as "idle iron"—wells, platforms and pipelines that are no longer producing or serving exploration or support functions related to an operator's lease—in the U.S. Gulf of Mexico. This NTL sets forth more stringent standards for decommissioning timing requirements by applying the requirement that any well that has not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities must be permanently plugged or temporarily abandoned within three years. Plugging or abandonment of wells may be delayed by two years if all of the well's hydrocarbon and sulphur zones are appropriately isolated. Similarly, platforms or other facilities that

24


Table of Contents


are no longer useful for operations must be removed within five years of the cessation of operations. The triggering of these plugging, abandonment and removal activities under what may be viewed as an accelerated schedule in comparison to the industry's historical decommissioning efforts may serve to increase, perhaps materially, our future plugging, abandonment and removal costs, which may translate into a need to increase our estimate of future asset retirement obligations ("AROs") required to meet such increased costs. For additional details relating to our AROs, please read Note 7 to our audited consolidated financial statements included elsewhere in this prospectus.

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. 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 in light of recent market volatilities. If oil prices decline by $1.00 per Bbl, then our PV-10 as of March 31, 2011 would decrease approximately $17 million. If natural gas prices decline by $0.10 per Mcf, then our PV-10 as of March 31, 2011 would decrease approximately $11 million.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute exploration and exploitation plans on a timely basis and within budget, and consequently could adversely affect our anticipated cash flows.

        We utilize third-party services to maximize the efficiency of our organization. The cost of oil field services may increase or decrease depending on the demand for services by other oil and gas companies. While we currently have excellent relationships with oil field service companies, there is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our exploitation and exploration operations, which could have a material adverse effect on our business, financial condition or results of operations.

25


Table of Contents


Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms.

        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 $54.3 million and $41.8 million related to capital and exploration expenditures for the year ended December 31, 2010 and the six months ended June 30, 2011. Our total capital expenditure budget for 2011 drilling, completion and recompletion activities is approximately $100 million. 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. To date, our capital expenditures (other than for acquisitions) have been financed with net cash provided by operating activities. We may be required to raise additional capital in the future to develop all of our potential drilling locations should we elect to do so.

        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.

We may be unable to make attractive acquisitions or successfully integrate acquired companies, and any inability to do so may disrupt our business and hinder our ability to grow.

        One aspect of our business strategy calls for acquisitions of businesses or assets that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive candidates, we may not be able to complete the acquisition of them or do so on commercially acceptable terms.

        In addition, our revolving credit facility imposes certain limitations on our ability to enter into mergers or combination transactions. Our revolving credit facility also limits our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses or assets. If we desire to engage in an acquisition that is otherwise prohibited by our revolving credit facility, we will be required to seek the consent of our lenders in accordance with the requirements of the facility, which consent may be withheld by the lenders under our revolving credit facility in their sole discretion. In addition, we may incur additional debt or issue additional equity to pay for any future acquisitions, subject to the limitations described above.

        If we acquire another business or assets, we could have difficulty integrating its operations, systems, management and other personnel and technology with our own. These difficulties could disrupt our ongoing business, distract our management and employees, increase our expenses and adversely affect our results of operations.

26


Table of Contents


Our acquisitions may prove to be worth less than what we paid and could expose us to potentially significant liabilities, including our P&A liabilities.

        We obtained the majority of our current reserve base through acquisitions of producing properties. We expect that acquisitions will continue to contribute to our future growth. In connection with these and potential future acquisitions, we are often only able to perform limited due diligence.

        Successful acquisitions of oil and natural gas properties require an assessment of a number of factors, including estimates of recoverable reserves, the timing of recovering reserves, exploration potential, future oil and natural gas prices, operating costs and potential environmental, regulatory and other liabilities, including our P&A liabilities. Such assessments are inexact, and we cannot make these assessments with a high degree of accuracy. In connection with our assessments, we perform a review of the acquired properties. However, such a review will not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities.

        There may be threatened, contemplated, asserted or other claims against the acquired assets related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations. We are sometimes able to obtain contractual indemnification for preclosing liabilities, including environmental liabilities, but we generally acquire interests in properties on an "as is" basis with limited remedies for breaches of representations and warranties. In addition, even when we are able to obtain such indemnification from the sellers, these indemnification obligations usually expire over time and expose us to potential unindemnified liabilities, which could materially adversely affect our production, revenues 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. 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.

If third-party pipelines connected to our facilities become partially or fully unavailable to transport our natural gas or oil, our revenues could be adversely affected.

        We depend upon third-party pipelines that provide delivery options from our facilities. Because we do not own or operate these pipelines, their continued operation is not within our control. If any one of these third-party pipelines becomes partially or fully unavailable to transport natural gas and oil, or if the gas quality specification for the natural gas pipelines changes so as to restrict our ability to transport natural gas on those pipelines, our revenues could be adversely affected. For example, following Hurricane Ike in 2008, all of our properties were shut-in for varying lengths of time, as were those of other operators in the Gulf of Mexico.

Our estimates of future asset retirement obligations may vary significantly from period to period and are especially significant because our operations are exclusively in the Gulf of Mexico.

        We are required to record a liability for the present value of our AROs to plug and abandon inactive, non-producing wells, to remove inactive or damaged platforms, facilities and equipment, and

27


Table of Contents


to restore the land or seabed at the end of oil and natural gas production operations. These costs are typically considerably more expensive for offshore operations as compared to most land-based operations, due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths. Estimating future restoration and removal costs in the Gulf of Mexico is especially difficult because most of the removal obligations may be many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and asset removal technologies are constantly evolving, which may result in additional or increased costs. As a result, we may make significant increases or decreases to our estimated AROs in future periods. For example, because we operate in the Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes. The estimated cost to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled rather than structurally intact. Accordingly, our estimate of future AROs could differ dramatically from what we may ultimately incur as a result of damage from a hurricane.

        As described above in the risk factor titled "Regulatory requirements imposed by the BOEMRE could significantly impact our estimates of future asset retirement obligations from period to period," the BOEMRE's NTL No. 2010-G05 increased our liability for AROs by accelerating the time frame for plugging, abandonment and removal for some of our platforms. In addition, the potential increase in decommissioning activity in the Gulf of Mexico over the next several years as a result of the NTL could likely result in increased demand for salvage contractors and equipment, resulting in increased estimates of plugging, abandonment and removal costs and increases in related AROs.

Our insurance may not protect us against business and operating risks.

        We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. Due to market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance policies are economically unavailable or available only for reduced amounts of coverage. Although we will maintain insurance at levels we believe are appropriate and consistent with industry practice, we will not be fully insured against all risks, including high-cost business interruption insurance and drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition and results of operations.

        Due to a number of recent catastrophic events, like the terrorist attacks on September 11, 2001, Hurricanes Ivan, Katrina, Rita, Gustav and Ike, the April 20, 2010 Macondo well incident and the Japanese tsunami in 2011, insurance underwriters increased insurance premiums for many of the coverages historically maintained and issued general notices of cancellation and significant changes for a wide variety of insurance coverages. The oil and natural gas industry suffered extensive damage from Hurricanes Ivan, Katrina, Rita, Gustav and Ike. As a result, insurance costs have increased significantly from the costs that similarly situated participants in this industry have historically incurred. Insurers are requiring higher retention levels and limit the amount of insurance proceeds that are available after a major windstorm in the event that damages are incurred. If storm activity in the future is as severe as it was in 2005 or 2008, insurance underwriters may no longer insure Gulf of Mexico assets against weather-related damage. In addition, we do not have in place, and do not intend to put in place, business interruption insurance due to its high cost. If an accident or other event resulting in damage to our operations, including severe weather, terrorist acts, war, civil disturbances, pollution or environmental damage, occurs and is not fully covered by insurance or a recoverable indemnity from a vendor, it could adversely affect our financial condition and results of operations. Moreover, we may

28


Table of Contents


not be able to maintain adequate insurance in the future at rates we consider reasonable or be able to obtain insurance against certain risks.

Prospects that we decide to drill may not yield oil or natural gas in commercial quantities or quantities sufficient to meet our targeted rate of return.

        A prospect is a property in which we own an interest or have operating rights and have what our geoscientists believe, based on available seismic and geological information, to be indications of economic accumulation of oil or natural gas. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to be drilled to a prospect that will require substantial seismic data processing and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling and completion costs or to be economically viable. The use of seismic data and other 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 commercial quantities. We cannot assure you that the analysis we perform using data from other wells, more fully explored prospects and/or producing fields will accurately predict the characteristics and potential reserves associated with our drilling prospects. To the extent we drill additional wells in the deepwater or on the deep shelf, our drilling activities could become more expensive and successful drilling could become less certain. As a result, there can be no assurance that we will find commercial quantities of oil and natural gas and, therefore, there can be no assurance that we will achieve positive rates of return on our investments.

The development of our proved undeveloped reserves in our 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 16% of our total proved reserves were classified as proved undeveloped as of March 31, 2011. 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 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.

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.

29


Table of Contents

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 commenced operations in 2008 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.

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 contracts for a portion of our oil and natural gas production, including collars and fixed-price swaps. We have not designated any of our commodity derivative contracts as hedges for accounting purposes and record all commodity derivative contracts on our balance sheet at fair value. Changes in the fair value of our commodity derivative contracts are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our commodity derivative contracts.

        Derivative contracts also expose us to the risk of financial loss in some circumstances, including when:

    production is less than the volume covered by the derivative contracts;

    the counterparty to the derivative contract defaults on its obligations; or

    there is a change in the differential between the underlying price in the derivative contract and actual prices received.

        In addition, these types of derivative contracts limit the benefit we would receive from increases in the prices for oil and natural gas. In the event of nonperformance by the counterparty to the derivative contract, we could be subject to significant credit risk.

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. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

30


Table of Contents


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; and

    the sale of assets (other than production sold in the ordinary course of business).

        Our revolving credit facility requires us to maintain certain financial ratios, such as leverage and interest coverage 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.

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

        Upon the completion of this offering, after giving effect to the XTO Acquisition, the MOR Transaction and the borrowing base increases described in "Recent Developments—XTO Acquisitions," "—MOR Transaction" and "—Borrowing Base Increases," we expect to have $            in outstanding indebtedness and will have available borrowing capacity of $             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;

31


Table of Contents

    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.

The borrowing base under our revolving credit facility could be reduced upon the next re-determination date, and may be further reduced in the future if commodity prices decline, which will limit our available funding for exploration and development.

        As of June 30, 2011, after giving effect to the XTO Acquisition and the MOR Transaction the borrowing base increases described in "Recent Developments—XTO Acquisition," "—MOR Transaction" and "—Borrowing Base Increases," total outstanding borrowings under our revolving credit facility would have been $         million, and our borrowing base would have been $430 million. Our borrowing base is re-determined semi-annually by our lenders in their sole discretion. The lenders will re-determine the borrowing base based on an engineering report with respect to our natural gas and oil reserves, which will take into account the prevailing natural gas and oil prices at such time. In the future, we may not be able to access adequate funding under our revolving credit facility as a result of (i) a decrease in our borrowing base due to the outcome of a subsequent borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. If oil and natural gas commodity prices materially deteriorate, we anticipate that the revised borrowing base under our revolving credit facility may be reduced. As a result, we may be unable to obtain adequate funding under our revolving credit facility or even be required to pay down amounts outstanding under our revolving credit facility to reduce our level of borrowing. If funding is not available when needed, or is available only on unfavorable terms, it could adversely affect our exploration and development plans as currently anticipated and our ability to make new acquisitions, each of which could have a material adverse effect on our production, revenues and results of operations.

        The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our revolving credit facility. Any increase in the borrowing base requires the consent of all the lenders. Outstanding borrowings in excess of the borrowing base must be repaid in six equal monthly installments. 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 joint interest partners or purchasers to meet their obligations to us may adversely affect our financial results.

        Our principal exposures to credit risk are through joint interest receivables ($9.3 million at June 30, 2011), receivables resulting from the sale of our oil and natural gas production ($45.8 million at June 30, 2011), which we market to energy marketing companies, and advances to joint interest

32


Table of Contents


parties ($1.2 million at June 30, 2011). In addition, from time to time we may have credit risk related to our counterparties under our commodity derivative contracts.

        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. Also, we could be responsible for plugging and abandonment and other liabilities in excess of our proportionate interest in the property if others are unwilling or unable, due to insolvency or otherwise, to contribute their portions to pay for such liabilities.

        We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant purchasers. This concentration of purchasers may impact our overall credit risk since these entities may be similarly affected by changes in economic and other conditions. We generally do not require our purchasers to post collateral. The inability or failure of our significant purchasers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

We are not the operator for all of our operations, 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 may acquire additional assets in the future where we would not serve as operator. As a result, we may have limited ability to exercise influence over the operations of the drilling locations operated by our partners. If we are not willing and able to fund required capital expenditures relating to a project when required by the majority owner or operator, our interests in the project may be reduced or forfeited. 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.

        This limited ability to exercise control over some of our operations may cause a material adverse effect on our results of operations and financial condition.

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 who have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and natural gas production, and developing and executing acquisition, financing and hedging strategies. Our ability to hire and retain our officers and key employees is important to our continued success and growth. The loss of the services of our senior management or technical personnel, including our President and Chief Executive 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.

33


Table of Contents


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

        The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The new legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the "CFTC") and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In June 2011, this deadline was extended to December 31, 2011. The CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and to establish minimum capital requirements, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the Dodd-Frank Act. The Dodd-Frank Act may also require compliance with margin requirements and with certain clearing and trade-execution requirements in connection with certain derivative activities, although the application of those provisions is uncertain at this time. The legislation may also require the counterparties to our commodity derivative contracts to spinoff some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty, or cause the entity to comply with the capital requirements, which could result in increased costs to counterparties such as us.

        The new legislation and any new regulations could significantly increase the cost of some commodity derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of some commodity derivative contracts, reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing commodity derivative contracts and potentially increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the new legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. If the new legislation and regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations.

Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, and additional state taxes on natural gas extraction may be imposed, as a result of future legislation.

        Legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain U.S. federal income tax benefits currently available to oil and gas exploration and production companies. Such proposed 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 certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or, if enacted, how soon such changes would be effective.

        The passage of this legislation or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to natural gas and oil exploration and development, and any such change, as well as any changes to or the imposition of

34


Table of Contents


new state or local taxes (including the imposition of, or increase in, production, severance or similar taxes), could negatively affect our financial condition and results of operations.

Our operations may incur substantial costs and liabilities to comply with environmental laws and regulations.

        Our oil and natural gas operations are subject to stringent federal, regional, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things, require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities, limit or prohibit exploration or drilling activities on certain environmentally sensitive protected areas that may affect certain species, including marine mammals, and impose substantial liabilities for pollution resulting from our operations. We may be required to make significant capital and operating expenditures or perform other corrective actions at our wells and properties to comply with the requirements of these environmental laws and regulations or the terms or conditions of permits issued pursuant to such requirements. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, loss of our leases, incurrence of investigatory or remedial obligations and the imposition of injunctive relief.

        There is risk of incurring significant environmental costs and liabilities in the performance of our operations as a result of our handling of petroleum hydrocarbons and wastes, air emissions and wastewater discharges related our operations, and historical operations and waste disposal practices. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and regardless of whether our operations met previous standards in the industry at the time they were conducted. In addition, claims for damages to persons, property or natural resources may result from environmental and other impacts of our operations. Changes in environmental laws and regulations occur frequently and any changes that result in more stringent or costly drilling, construction, completion, water management or 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 industry in general and 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 legislation or regulations restricting emissions of "greenhouse gases" could result in increased operating costs and reduced demand for the oil and natural gas that we produce.

        In December 2009, the U.S. Environmental Protection Agency (the "EPA") determined that emissions of carbon dioxide, methane and other "greenhouse gases" present an endangerment to public 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. Based on its findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the Clean Air Act (the "CAA"). The EPA has adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore and offshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.

35


Table of Contents

        In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. 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, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

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 stockholders 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 stockholders 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.

36


Table of Contents

        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.

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 as adjusted net tangible book value per share of common stock from the initial public offering price, and our as adjusted net tangible book value as of June 30, 2011 after giving effect to this offering would be $            per share. Please read "Dilution" for a complete description of the calculation of net tangible book value.

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 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.

        Compliance with these requirements 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.

We do not intend to pay, and we are currently subject to restrictions on paying, dividends on our common stock and, consequently, your only opportunity to achieve a return on your investment is if the price of our common stock appreciates.

        We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, our revolving credit facility places certain restrictions on our ability to pay cash dividends. Consequently, your only opportunity to achieve a return on your investment in us will be if the market

37


Table of Contents


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 have                        outstanding shares of common stock. This number includes                        shares that we and the selling stockholders 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 stockholders will own                        shares, or approximately        % of our total outstanding shares, and certain of our affiliates will own                         shares, or approximately        % of our total 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 stockholders 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 the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering. The holders of the remaining                        shares and a small portion of shares owned by our affiliates which will be distributed to non-officer employees and other non-affiliates totaling up to approximately                        shares, or approximately        % of our total 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;

38


Table of Contents

    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.

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 Riverstone will initially own up to approximately        % of our outstanding common stock. Consequently, Riverstone and its affiliates will continue to have significant influence over all matters that require approval by our stockholders, including the election of 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 Riverstone and its affiliates, including its portfolio companies, on the other hand, concerning among other things, potential competitive business activities or business opportunities. Riverstone is a private equity firm that regularly makes investments in entities in the U.S. oil and natural gas industry. As a result, Riverstone's existing and future portfolio companies may compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor.

        We have also renounced our interest in certain business opportunities. Please read "—Our amended and restated certificate of incorporation contains a provision renouncing our interest and expectancy in certain corporate opportunities, which could adversely affect our business or prospects."

Our amended and restated certificate of incorporation contains a provision renouncing our interest and expectancy in certain corporate opportunities, which could adversely affect our business or prospects.

        Our amended and restated certificate of incorporation provides that, to the fullest extent permitted by applicable law, we renounce any interest or expectancy in, or in being offered an opportunity to participate in, any business opportunity that may be from time to time presented to Riverstone or its affiliates or any of their respective officers, directors, agents, shareholders, members, partners, affiliates and subsidiaries (other than us and our subsidiaries) or business opportunities that such parties participate in or desire to participate in, even if the opportunity is one that we might reasonably have pursued or had the ability or desire to pursue if granted the opportunity to do so, and no such person shall be liable to us for breach of any fiduciary or other duty, as a director or officer or controlling stockholder or otherwise, by reason of the fact that such person pursues or acquires any such business opportunity, directs any such business opportunity to another person or fails to present any such business opportunity, or information regarding any such business opportunity, to us unless, in the case of any such person who is our director or officer, any such business opportunity is expressly offered to such director or officer solely in his or her capacity as our director or officer. We will also enter into a business opportunity agreement with Riverstone that contains similar contractual provisions.

        As a result, Riverstone or its affiliates may become aware, from time to time, of certain business opportunities, such as acquisition opportunities, and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to Riverstone and its affiliates could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours. Please read "Description of Capital Stock."

39


Table of Contents


We expect to be a "controlled company" within the meaning of the NYSE rules and, if applicable, would qualify for and will rely on exemptions from certain corporate governance requirements.

        Because Riverstone will own a majority of our outstanding common stock following the completion of this offering, we expect to 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 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. Riverstone's significant ownership interest could adversely affect investors' perceptions of our corporate governance.

40


Table of Contents


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;

    estimated future reserves and the present value thereof;

    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;

    amount, nature and timing of capital expenditures, including future development costs;

    availability and terms of capital;

    competition;

    marketing of oil and natural gas;

    exploitation or property acquisitions;

    costs of exploiting and developing our properties and conducting other operations;

    general economic conditions;

    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; 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 when anticipated or at all. 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

41


Table of Contents


Financial Condition and Results of Operations" and elsewhere in this prospectus. These factors include risks related to:

    variations in the market demand for, and prices of, oil and natural gas;

    uncertainties about our estimated quantities of oil and natural gas reserves;

    the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity under our revolving credit facility;

    general economic and business conditions;

    failure to realize expected value creation from property acquisitions;

    uncertainties about our ability to replace reserves and economically develop our current reserves;

    risks related to the concentration of our operations offshore in the Gulf of Mexico;

    drilling results;

    potential financial losses or earnings reductions from our commodity price risk management programs;

    potential adoption of new governmental regulations (including any enhanced regulatory oversight attributable to the governmental response to the Macondo well incident); and

    our ability to satisfy future cash obligations and environmental costs.

        These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

        Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by our reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered.

42


Table of Contents


USE OF PROCEEDS

        We expect to 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. 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.

        We intend to use the net proceeds from this offering to repay borrowings outstanding under our revolving credit facility, of which $           million was outstanding as of                         , 2011, and for general corporate purposes. Our revolving credit facility matures on June 20, 2015 and bears interest at a variable rate, which was 2.75% as of June 30, 2011. The borrowings to be repaid were incurred primarily to fund our pending XTO Acquisition and our pending MOR Transaction. Amounts repaid under the revolving credit facility may be reborrowed at any time.

        We will not receive any of the proceeds from the sale of shares of our common stock by the selling stockholders. We will pay all expenses related to this offering, other than underwriting discounts and commissions related to the shares sold by the selling stockholders.

        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. Please read "Underwriters."


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 places certain restrictions on our ability to pay cash distributions.

43


Table of Contents


CAPITALIZATION

        The following table sets forth the capitalization of Dynamic Offshore Holding, LP and Dynamic Offshore Resources, Inc., as applicable, as of June 30, 2011:

    on an actual basis;

    on an as adjusted basis to give effect to our pending XTO Acquisition, as described under "Prospectus Summary—Recent Developments—XTO Acquisition"; and

    on an as further adjusted basis to give effect to this offering, the transactions described under "Corporate Reorganization" which will occur simultaneously with the closing of 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 June 30, 2011  
 
  Actual   As Adjusted(1)   As Further
Adjusted(1)
 
 
  (In thousands)
 

Cash and cash equivalents

  $ 28,872   $     $    
               

Long-term debt, including current maturities:

                   
 

Revolving credit facility(2)

    175,000              
               
 

Total long-term debt

    175,000              
               

Owners'/stockholders' equity:

                   
 

Partners' capital

    458,168            
 

Common stock, $0.01 par value;         shares authorized (as further adjusted) ;         shares issued and outstanding (as further adjusted)

               
 

Preferred stock, $0.01 par value;          shares authorized (as further adjusted); no shares issued and outstanding (as further adjusted)

             
 

Additional paid-in capital

               
 

Retained earnings (accumulated loss)(3)

               
               
 

Total owners'/stockholders' equity

    458,168              
               
 

Total capitalization

  $ 633,168   $     $    
               

(1)
Does not give effect to our pending MOR Transaction. Please read "Prospectus Summary—Recent Developments—MOR Transaction."

(2)
As of                    , 2011, $             million was outstanding under our revolving credit facility, leaving $             million available for borrowing.

(3)
In connection with our corporate reorganization, an estimated net deferred tax liability of approximately $78.0 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.

44


Table of Contents


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 June 30, 2011, 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 including giving effect to our corporate reorganization. After giving effect to the sale of the shares in this offering and further 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 June 30, 2011 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 to new investors purchasing shares in this offering of $            per share, resulting from the difference between the offering price and the adjusted pro forma net tangible book value after this offering. 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 June 30, 2011 (after giving effect to our corporate reorganization)

  $          

Increase per share attributable to new investors in this offering

             
             

Pro forma as adjusted 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 a pro forma basis as adjusted as of June 30, 2011, 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
Per Share
 
 
  Number   Percent   Amount   Percent  

Existing stockholders(1)

            % $         % $    

New investors(2)

            %           %    
                       
 

Total

            % $         % $    
                       

(1)
The number of shares disclosed for the existing stockholders includes                        shares being sold by the selling stockholders in this offering. The number of shares disclosed for the new investors does not include the                        shares being purchased by the new investors from the selling stockholders in this offering.

(2)
The number of shares disclosed for the new investors does not include the                        shares being purchased by the new investors from the selling stockholders in this offering.

45


Table of Contents


SELECTED HISTORICAL CONSOLIDATED AND UNAUDITED PRO FORMA FINANCIAL DATA

        Set forth below is (i) summary historical consolidated financial data for the period from January 1, 2008 through March 13, 2008 of SPN Resources LLC, our accounting predecessor, which has been derived from the audited financial statements of SPN Resources LLC included elsewhere in this prospectus, (ii) our summary historical consolidated financial data for the years ended December 31, 2008, 2009 and 2010, and balance sheet data at December 31, 2009 and 2010, which has been derived from the audited financial statements of Dynamic Offshore Holding, LP included elsewhere in this prospectus, (iii) our summary historical consolidated financial data for the six months ended June 30, 2010 and 2011 and balance sheet data at June 30, 2011, which has been derived from the unaudited financial statements of Dynamic Offshore Holding, LP included elsewhere in this prospectus, and (iv) pro forma consolidated financial data for the year ended December 31, 2010 and the six months ended June 30, 2011 and pro forma balance sheet data at June 30, 2011, which has been derived from the unaudited pro forma financial statements included elsewhere in this prospectus.

        The unaudited pro forma financial data for the year ended December 31, 2010, which reflects our acquisition of the Samson Acquisition Properties on July 8, 2010, our pending XTO Acquisition, our corporate reorganization and the effects of this offering and the application of the net proceeds, was derived from the unaudited pro forma financial information included elsewhere in this prospectus. The unaudited pro forma financial information for the year ended December 31, 2010 and the six months ended June 30, 2011 was prepared as if each of these transactions occurred on January 1, 2010. The unaudited pro forma financial information as of June 30, 2011 was prepared as if our pending XTO Acquisition, our corporate reorganization and this offering and the application of the net proceeds had occurred on June 30, 2011. The unaudited pro forma financial information does not give effect to our pending MOR Transaction.

        You should read the following summary 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. The financial information included in this prospectus may not be indicative of our future results of operations, financial position and cash flows. As a result of our numerous acquisitions and because we have grown significantly since we began operations, our historical results of operations may not be comparable from period to period. For more information on the comparability of our results, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Factors that Significantly Affect Our Results."

46


Table of Contents

 
  Historical   Pro Forma  
 
  Predecessor   Dynamic Offshore Holding, LP  
 
  January 1,
2008
Through
March 13,
2008
  Year Ended
December 31,
  Six Months Ended
June 30,
   
   
 
 
   
  Six Months
Ended
June 30,
2011
 
 
  Year Ended
December 31,
2010
 
 
  2008   2009   2010   2010   2011  
 
  (In thousands)
 

Statement of operations data:

                                                 

Oil and gas revenues

  $ 56,179   $ 163,649   $ 155,596   $ 317,584   $ 149,210   $ 201,864   $ 512,688   $ 268,549  

Other operating revenues

    741     1,173     1,557     12,552     3,266     7,866     12,552     7,866  
                                   

    56,920     164,822     157,153     330,136     152,476     209,730     525,240     276,415  

Operating expenses:

                                                 
 

Lease operating expense

    8,791     30,192     52,181     81,055     36,649     43,739     119,684     56,718  
 

Exploration expense

        67     8,908     2,093     994     5,147     2,093     5,147  
 

Depreciation, depletion and amortization

    13,414     41,230     82,507     184,324     55,291     62,479     285,494     89,860  
 

General and administrative expense

    2,275     15,591     22,841     22,687     12,324     11,920     22,687     11,920  
 

Other operating expense(1)

    4,786     23,971     43,347     66,411     31,384     27,963     76,884     32,011  
                                   

    29,266     111,051     209,784     356,570     136,642     151,248     506,842     195,656  
                                   

Income (loss) from operations

    27,654     53,771     (52,631 )   (26,434 )   15,834     58,482     18,398     80,759  

Other income (expense):

                                                 
 

Interest expense, net

    (34 )   (3,667 )   (8,328 )   (14,661 )   (7,483 )   (4,950 )   (13,544 )   (3,565 )
 

Commodity derivative income (expense)

        159,939     (21,887 )   6,990     30,252     (9,884 )   6,990     (9,884 )
 

Bargain purchase gain

            161,351     4,024             4,024      
 

Other

                (1,080 )       1,166     (1,080 )   1,166  
                                   

Income (loss) before income taxes

    27,620     210,043     78,505     (31,161 )   38,603     44,814     14,788     68,476  

Income tax benefit (expense)

        (14,738 )   20,387     14,814     2,669     503     (5,870 )   (23,967 )
                                   

Net income (loss)

    27,620     195,305     98,892     (16,347 )   41,272     45,317     8,918     44,509  

Less: Net income (loss) attributable to noncontrolling interests

        34,648     57,663     (4,070 )   6,809     460     (2,645 )   299  
                                   

Net income (loss) attributable to Dynamic Offshore Holding, LP

  $ 27,620   $ 160,657   $ 41,229   $ (12,277 ) $ 34,463   $ 44,857   $ 11,563   $ 44,210  
                                   

Income (loss) per share

  $     $     $     $     $     $     $     $    

Diluted income (loss) per share

  $     $     $     $     $     $     $     $    

Adjusted EBITDA(2)

  $ 41,953   $ 119,763   $ 124,490   $ 222,671   $ 102,563   $ 124,459   $ 372,645   $ 175,971  

(1)
Includes insurance expense, workover expense, accretion expense, casualty loss (gain), loss on abandonments, loss (gain) on sale of assets and other.

(2)
Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, please read "—Non-GAAP Financial Measure."

47


Table of Contents

 
  As of December 31,    
   
 
 
  As of
June 30, 2011
  Pro Forma As of
June 30, 2011
 
 
  2009   2010  
 
  (In thousands)
 

Balance sheet data:

                         

Cash and cash equivalents

  $ 88,457   $ 75,162   $ 28,872   $ 28,227  

Net property, plant and equipment

    798,255     809,035     841,255     1,096,046  

Total assets

    1,056,285     987,918     984,254     1,249,400  

Long-term debt

    243,000     203,205     175,000     79,500  

Total owners'/stockholders' equity

    482,175     431,714     458,168     735,786  

 

 
   
  Dynamic Offshore Holding, LP  
 
  Predecessor  
 
  Years Ended
December 31,
  Six Months
Ended June 30,
 
 
  January 1,
2008 Through
March 13,
2008
 
 
  2008   2009   2010   2010   2011  
 
  (In thousands)
 

Other financial data:

                                     

Net cash provided by operating activities

  $ 22,836   $ 124,835   $ 30,432   $ 151,814   $ 79,619   $ 93,372  

Net cash provided by (used in) investing activities

    (3,627 )   (362,317 )   69,439     (91,200 )   (2,080 )   (89,362 )

Net cash provided by (used in) financing activities

    —-     289,512     (63,589 )   (73,909 )   (73,157 )   (50,300 )

        Set forth below is unaudited financial data regarding our predecessor's revenues and direct operating expenses. The financial data regarding revenues and direct operating expenses is not indicative of the financial condition or results of operations of SPN Resources, LLC due to the omission of various operating expenses. Prior to our acquisition, Superior did not account for SPN Resources, LLC as a separate business unit. As such, certain costs, such as depreciation, depletion and amortization, accretion of asset retirement obligations, general and administrative expense and interest expense were not allocated to SPN Resources, LLC.

 
  Years Ended December 31,  
 
  2006   2007  
 
  (In thousands)
 

Oil and gas revenues

  $ 139,729   $ 196,629  

Other operating revenues

    2,482     3,449  
           

    142,211     200,078  

Direct operating expenses

    46,809     44,353  
           

Excess of revenues over direct operating expenses

  $ 95,402   $ 155,725  
           

Non-GAAP Financial Measure

    Adjusted EBITDA

        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, to compare our performance across reporting periods on a consistent basis by excluding items that we do not believe are indicative of our core operating performance.

48


Table of Contents

        We define Adjusted EBITDA as revenues, including commodity derivative settlements, less lease operating expense, workover expense, insurance expense and general and administrative expense. Adjusted EBITDA is not a measure of net income or cash flows as determined by GAAP.

        Our senior management reviews Adjusted EBITDA monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results. Adjusted EBITDA provides useful information to investors because it is a supplemental financial measure used by us and by external users of our financial statements, including investors, commercial banks and others, to assess:

    the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

    our operating performance and return on capital as compared to other companies in our industry, without regard to financing or capital structure; and

    the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

        Adjusted EBITDA has limitations as an analytical tool and should not be considered as an alternative to, or more meaningful than, performance measures calculated in accordance with GAAP. Some of these limitations are:

    certain items excluded from Adjusted EBITDA are significant components in understanding a company's financial performance, such as a company's cost of capital and tax structure;

    Adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;

    Adjusted EBITDA does not reflect changes in, or cash requirements for, our working capital needs;

    Adjusted EBITDA does not consider the potentially dilutive impact of share-based compensation;

    although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and Adjusted EBITDA does not reflect any cash requirements for such replacements; and

    our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

        Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating that understanding into its decision-making processes.

49


Table of Contents

        The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities.

 
  Historical   Pro Forma  
 
  Predecessor   Dynamic Offshore Holding, LP  
 
  January 1,
2008
Through
March 13,
2008
  Year Ended
December 31,
  Six Months Ended
June 30,
   
   
 
 
   
  Six Months
Ended
June 30,
2011
 
 
  Year Ended
December 31,
2010
 
 
  2008   2009   2010   2010   2011  
 
  (In thousands)
 

Reconciliation of net income (loss) to Adjusted EBITDA:

                                                 

Net income (loss)

  $ 27,620   $ 195,305   $ 98,892   $ (16,347 ) $ 41,272   $ 45,317   $ 8,918   $ 44,509  

Interest expense, net

    34     3,667     8,328     14,661     7,483     4,950     13,544     3,565  

Income tax expense (benefit)

        14,738     (20,387 )   (14,814 )   (2,669 )   (503 )   5,870     23,967  

Depreciation, depletion and amortization

    13,414     41,230     82,507     184,324     55,291     62,479     285,494     89,860  

Unrealized gain (loss) on commodity derivatives

        (146,671 )   97,975     36,181     (2,259 )   2,441     36,181     2,441  

Other operating expense

    885     11,494     18,526     21,610     3,445     10,941     25,582     12,795  

Bargain purchase gain

            (161,351 )   (4,024 )           (4,024 )    

Other

                1,080         (1,166 )   1,080     (1,166 )
                                   

Adjusted EBITDA

  $ 41,953   $ 119,763   $ 124,490   $ 222,671   $ 102,563   $ 124,459   $ 372,645   $ 175,971  
                                   

Reconciliation of net cash provided by operating activities to Adjusted EBITDA:

                                                 

Net cash provided by operating activities

  $ 22,836   $ 124,835   $ 30,432   $ 151,814   $ 79,619   $ 93,372              

Derivative settlements

        13,268     76,088     43,171     27,993     (7,443 )            

Interest expense, net

    34     3,667     8,328     14,661     7,483     4,950              

Exploration expense

        67     8,908     2,093     994     5,147              

Amortization in interest expense

        (750 )   (971 )   (1,407 )   (870 )   (784 )            

Current income tax expense

            (2,188 )                        

Changes in operating assets and liabilities

    18,978     (30,061 )   (829 )   10,733     (9,015 )   29,415              

Other

    105     8,737     4,722     1,606     (3,641 )   (198 )            
                                       

Adjusted EBITDA

  $ 41,953   $ 119,763   $ 124,490   $ 222,671   $ 102,563   $ 124,459              
                                       

50


Table of Contents


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 variations in the market demand for, and prices of, oil and natural gas; uncertainties about our estimated quantities of oil and natural gas reserves; the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity under our revolving credit facility; access to capital and general economic and business conditions; failure to realize expected value creation from property acquisitions; uncertainties about our ability to replace reserves and economically develop our current reserves; risks related to the concentration of our operations offshore in the Gulf of Mexico; drilling results; potential financial losses or earnings reductions from our commodity price risk management programs; potential adoption of new governmental regulations (including any enhanced regulatory oversight attributable to the governmental response to the Macondo well incident); our ability to satisfy future cash obligations and environmental costs; 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. Please read "Risk Factors" and "Cautionary Note Regarding Forward-Looking Statements."

Overview

        We are an independent exploration and production company focused on the acquisition and development of producing oil and natural gas properties in the Gulf of Mexico. As of March 31, 2011, our estimated net proved reserves were 45,223 MBoe, of which 52% was oil and 84% was proved developed, with an associated PV-10 of approximately $1.2 billion, based on SEC pricing of $80.04 per Bbl for oil and $4.10 per MMBtu for natural gas. As of that same date, our estimated net probable reserves were 8,782 MBoe with an associated PV-10 of approximately $237.5 million. Please read "Prospectus Summary—Summary Reserve Data" for information on our estimated net proved and probable reserves, PV-10 and related pricing. During June 2011, our properties had aggregate average net daily production of 17,634 Boe per day.

        A significant portion of our growth has been achieved through a series of acquisitions. Since we began operations in 2008, we have completed eight material acquisitions. In addition, we recently entered into an agreement with subsidiaries of Exxon to acquire offshore assets formerly owned by certain subsidiaries of XTO Energy Inc. and agreed with MOR to acquire the remaining 25% working interest in the properties that we acquired from SPN Resources in 2008. As a result of these acquisitions and because we have grown significantly over that time, our historical results of operations may not be comparable from year-to-year.

51


Table of Contents

        The following table presents key metrics related to each of our material acquisitions. For additional details regarding our material acquisitions, please read "Business—Our Acquisition History," "—XTO Acquisition" and "—MOR Transaction."

Acquisition
  Acquisition
Date
  Major Fields   Net Proved Reserves
(MMBoe)
As of Acquisition Date
 

SPN Resources(1)

  March 2008   South Pass 60, West Delta 79/80     10.2  

Northstar

  July 2008   Eugene Island 307, Eugene Island 32     8.7  

Bayou Bend Petroleum

  May 2009   Marsh Island     0.6  

Beryl Oil and Gas(1)

  October 2009   Vermilion 362-371     14.3  

Shell

  January 2010   Bullwinkle     6.2  

Samson Resources

  July 2010   Vermilion 272, High Island 52     4.9  

Providence Resources

  March 2011   Ship Shoal 252/253, Main Pass 19     1.4  

Gryphon Exploration(2)

  May 2011   High Island 52, Ship Shoal 301     2.1  

XTO

  Pending   South Marsh Island 41,
West Cameron 485/507
    13.5 (3)

MOR

  Pending   (4)                 3.5 (5)

(1)
Includes interests subsequently acquired from Superior in exchange for an additional 10% equity interest in us.

(2)
The reserve information relating to Gryphon Exploration as of May 1, 2011 is included in NSAI's March 31, 2011 reserve report for our oil and natural gas properties.

(3)
As of July 31, 2011, based on a reserve report prepared by NSAI and our internally prepared reserve estimates.

(4)
We expect to acquire the remaining 25% interest in the properties that we acquired from SPN Resources in 2008, including the South Pass 60 and West Delta 79/80 fields.

(5)
As of March 31, 2011, based on a reserve report prepared by NSAI.

Factors that Significantly Affect Our Results

    Acquisitions

        As described above, acquisitions and the resulting changes to our company have been our defining features since we began operations in 2008. In addition to the increases in magnitude in our operations as a result of the acquisitions, the Bullwinkle acquisition in January 2010 also changed the scope of our operations by adding operation of the associated platform, which resulted in our generating fees from production handling agreements ("PHA fees"). Before we acquired Bullwinkle, we did not generate significant amounts of PHA fees.

        We intend to continue to selectively acquire companies and producing properties based on disciplined valuations of proved reserves. In addition, we believe that the Gulf of Mexico continues to represent an attractive buyer's market, which should facilitate this acquisition strategy. As with our historical acquisitions, any future acquisitions could make year-to-year comparisons of our results of operations difficult. We may also incur substantial debt or issue additional equity securities to fund future acquisitions.

    Commodity Prices

        Our results of operations are heavily influenced by commodity prices, which are subject to wide fluctuations in response to relatively wide changes in supply and demand. For a description of factors

52


Table of Contents

that may impact future commodity prices, please read "Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business—A substantial or extended decline in oil and 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."

        Oil and natural gas prices have been subject to significant fluctuations during the past several years. In general, oil prices were significantly higher during 2010 when measured against 2009 while natural gas prices were moderately higher. The NYMEX oil price and NYMEX natural gas price reached high and low daily settlement prices of $99.87 and $79.30 per Bbl and $4.55 and $3.94 per MMBtu during the period from July 1, 2011 to August 15, 2011. At August 15, 2011, the NYMEX oil price and NYMEX natural gas price were $87.88 per Bbl and $4.02 per MMBtu.

        The table below sets forth the prices we receive per unit of volume for our oil and natural gas production, both including and excluding the effects of our commodity derivative contracts, and also includes the benchmark price for each product.

 
  Year Ended
December 31,
  Six Months Ended
June 30,
 
 
  2008   2009   2010   2010   2011  

Average sales prices:

                               
 

Oil, without realized derivatives ($/Bbl)

    104.20     63.00     78.54     76.67     106.83  
 

Natural gas, without realized derivatives ($/Mcf)(1)

    10.00     4.24     4.72     5.00     4.85  
 

Oil, with realized derivatives ($/Bbl)

    116.93     95.19     87.03     90.81     96.69  
 

Natural gas, with realized derivatives ($/Mcf)(1)

    9.98     6.06     5.73     5.98     5.75  
 

Oil, WTI benchmark ($/Bbl)

    99.75     62.09     79.61     78.46     98.50  
 

Natural gas, Henry Hub benchmark ($/MMBtu)

    8.90     4.16     4.38     4.66     4.29  

(1)
Realized prices include realized gains or losses on cash settlements for our commodity derivative contracts, which have not been designated for hedge accounting. We have not made any estimates of the impact of commodities derivatives on the average sales price for our predecessor.

        Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of the production. We intend to continue to manage our exposure to commodity price risk in the near term while remaining opportunistic over the long term. We use a variety of hedging instruments to accomplish our risk management objectives and enhance the stability of our cash flows. Our commodity derivative contracts are currently in the form of basic swaps and collars that are designed to provide a fixed price (swaps) or defined range of prices (collars) that we will receive. We have a policy of hedging at least 50% of our forecasted proved developed producing volumes on a two-year rolling basis. We actively monitor our hedge portfolio to support our cash flow objectives. For a description of our commodity hedge position, please read "Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk."

        Nearly all of our oil is sold at LLS, HLS and EIC prices, which have recently traded at a significant premium to NYMEX WTI benchmark prices. In general, differentials are adjustments to the benchmark price for crude oil based on grade, sulfur content and location of the sales point. Our oil production benefits from higher pricing differentials relative to many other North American crude oil producers in other areas. Moreover, these pricing differentials have been increasing in recent months. For example, for the three months ended June 30, 2011, the average realized price before the effect of commodity derivative contracts for our oil production was $113.85 per Bbl, compared to an average WTI forward index price of $102.34 per Bbl for the same period.

53


Table of Contents

    Production Volumes

        The volumes of oil and natural gas that we produce are driven by several factors, including:

    our acquisitions of oil and natural gas properties;

    the amount of capital we invest in the development of our oil and natural gas properties, including the drilling of new wells, which may be exploratory wells, and the recompletion of existing wells;

    facility or equipment malfunctions;

    adverse weather conditions, such as hurricanes and tropical storms, which are common in the Gulf of Mexico during certain times of the year;

    delays imposed by or resulting from compliance with regulatory requirements; and

    the rate at which production volumes on our wells naturally decline.

        The following table sets forth summary data with respect to our production volumes for the periods presented.

 
  Year Ended
December 31,
  Six Months Ended
June 30,
 
 
  2008   2009   2010   2010   2011  

Net sales volumes:

                               
 

Oil (MBbls)

    1,055     1,820     2,986     1,371     1,499  
 

Natural gas (MMcf)

    5,369     9,648     17,615     8,813     8,612  
                       
 

Total (MBoe)

    1,950     3,428     5,922     2,840     2,934  
                       
 

Average net daily production (Boe/d)

    5,328     9,392     16,225     15,691     16,210  
                       

How We Evaluate Our Operations

        Our profitability is a function of the difference between the revenues we receive from our operations, including revenues from the crude oil and natural gas we sell, and the costs associated with conducting our operations, including operating and general and administrative costs and the impact of our commodity hedging activities.

        Our management uses a variety of financial and operational measurements to analyze our performance. The most important of these measurements include: (1) Adjusted EBITDA, (2) production volumes and (3) operating expenses.

    Adjusted EBITDA

        Our senior management reviews Adjusted EBITDA monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results. Adjusted EBITDA provides useful information to investors because it is a supplemental financial measure used by us and by external users of our financial statements, including investors, commercial banks and others, to assess:

    the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

    our operating performance and return on capital as compared to other companies in our industry, without regard to financing or capital structure; and

54


Table of Contents

    the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

        Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating that understanding into its decision-making processes. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, please read "Prospectus Summary—Summary Historical Consolidated and Unaudited Pro Forma Financial Data—Non-GAAP Financial Measure."

    Production Volumes

        Our expected production volumes for any given period form an important part of our outlook and planning for that period. As a result, our senior management reviews actual production volumes in relation to our expected production volumes for the period on a regular basis. We identify the causes for the variance, and, based on the results of that analysis, adjust our operations accordingly, which may include increasing expenditures.

        Certain factors affecting our production volumes are outside of our control. To the extent possible, based on disciplined estimates of these factors and our experience, we include these factors in estimating our future production volumes. For a description of the factors affecting our production volumes, please read "Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business—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."

    Operating Expenses

        Operating expenses are costs associated with conducting our operations. Lease operating expense and depreciation, depletion and amortization comprise the most significant portion of our operating expenses. For a description of our primary operating expenses, please read "—Basis of Presentation—Our Expenses."

        The table below sets forth the operating expenses per unit of volume for our production.

 
  Year Ended
December 31,
  Six Months Ended
June 30,
 
 
  2008   2009   2010   2010   2011  

Costs and expenses ($/Boe):

                               
 

Lease operating expense

    15.48     15.22     13.69     12.71     14.91  
 

Depreciation, depletion and amortization

    21.14     24.07     31.13     19.47     21.29  
 

General and administrative expense

    8.00     6.66     3.83     4.34     4.06  

Basis of Presentation

    Sources of Our Revenues

        Oil and natural gas revenues.    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.

        Other operating revenues.    Other operating revenues consist primarily of PHA fees. Prior to our acquisition of Bullwinkle in January 2010, we did not generate significant amounts of PHA fees.

55


Table of Contents

    Our Expenses

        Lease operating expense.    Lease operating expense is the daily costs incurred to bring crude 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, and repair expenses related to our oil and natural gas properties.

        Workover expense.    Workover expense is major remedial operation on a completed well to restore, maintain, or improve the well's production. Because the amount of workover expense is closely correlated to the levels of workover activity, which is not regularly scheduled, workover expense is not necessarily comparable from period-to-period.

        Exploration expense.    Costs related to exploratory wells that do not find proved reserves are charged as exploration expense. These costs include costs for topographical, geological and geophysical studies, including seismic data, rights of access to properties and costs of carrying and retaining undeveloped properties, such as delay rentals. As with workover expense, the amount of exploration expense is non-recurring, and may not necessarily be comparable from period-to-period.

        Depreciation, depletion and amortization.    Depreciation, depletion and amortization ("DD&A") is the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas. As a company that utilizes the successful efforts method of accounting, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, and allocate these costs to each equivalent barrel produced using the units-of-production method. We also include unproved property impairment and costs associated with lease expirations. Impairment charges are recorded for proved properties if the carrying value exceeds estimated fair value.

        General and administrative expense.    General and administrative expense includes 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.

        Insurance expense.    Insurance expense includes workers' compensation, casualty insurance, pollution liability including oil spill financial responsibility, property insurance (including windstorm) and management liability.

        Loss on abandonments.    Loss on abandonments is the difference between the actual settlement cost of our property abandonments and the recorded amount.

        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.

        Commodity derivative income (expense).    We utilize commodity derivative contracts to reduce our exposure to fluctuations in the price of crude oil and natural gas. We recognize unrealized gains and losses associated with our open commodity derivative contracts as commodity prices and commodity derivative contracts change. The commodity derivative contracts we have in place are not classified as hedges for accounting purposes. Consequently, these commodity derivative contracts are marked-to-market each quarter with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market commodity derivative contracts in our income statement. Cash flow is only impacted to the extent the actual settlements under the contracts result in making or receiving a payment from the counterparty.

56


Table of Contents

        Bargain purchase gain.    A bargain purchase gain is recognized on an acquisition if our estimate of the fair value of the net assets acquired exceeds the fair value of the total consideration paid.

        Income tax benefit (expense).    Our provision for income taxes is solely applicable to federal tax obligations of Dynamic Offshore Resources NS Parent, Inc. ("DOR NS"), our indirect wholly-owned subsidiary. Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of DOR NS for financial reporting and tax purposes. A valuation allowance for deferred tax assets is recorded when it is more-likely-than-not that the benefit from the deferred tax assets will not be realized. Our profits and losses other than within DOR NS are reported directly to the taxing authorities by our partners. Accordingly, no provision for income taxes has been included for those profits and losses, except as they relate to DOR NS.

    Corporate Reorganization

        In connection with the closing of this offering, we will merge into a newly formed corporation that will be subject to federal and state entity-level taxation. As a result, a net deferred tax liability will be established for differences between the tax and book basis of our assets and liabilities and a corresponding expense will be recorded to net income. We estimate the net deferred tax liability to be approximately $78.0 million.

57


Table of Contents

Results of Operations

        The following table summarizes the key components of our results of operations for the periods indicated:

 
  Year Ended
December 31,
  Six Months Ended
June 30,
 
 
  2008(1)   2009   2010   2010   2011  
 
   
   
   
  (unaudited)
 
 
  (In thousands)
 

Oil and gas revenues

  $ 163,649   $ 155,596   $ 317,584   $ 149,210   $ 201,864  

Other operating revenues

    1,173     1,557     12,552     3,266     7,866  
                       

    164,822     157,153     330,136     152,476     209,730  

Operating expenses:

                               
 

Lease operating expense

    30,192     52,181     81,055     36,649     43,739  
 

Exploration expense

    67     8,908     2,093     994     5,147  
 

Depreciation, depletion and amortization

    41,230     82,507     184,324     55,291     62,479  
 

General and administrative expense

    15,591     22,841     22,687     12,324     11,920  
 

Insurance expense

    11,563     27,650     32,754     19,328     16,940  
 

Workover expense

    981     6,079     14,140     9,605     5,229  
 

Accretion expense, net

    2,690     5,036     11,069     5,519     4,826  
 

Casualty loss (gain), net

    8,750         (2,099 )   (2,676 )   (184 )
 

Loss (gain) on abandonments

        4,722     2,408     (102 )   1,152  
 

Loss (gain) on sale of assets

        (140 )   8,139     (290 )    
 

Other

    (13 )                
                       

    111,051     209,784     356,570     136,642     151,248  
                       

Income (loss) from operations

    53,771     (52,631 )   (26,434 )   15,834     58,482  

Other income (expense):

                               
 

Interest expense, net

    (3,667 )   (8,328 )   (14,661 )   (7,483 )   (4,950 )
 

Commodity derivative income (expense)

    159,939     (21,887 )   6,990     30,252     (9,884 )
 

Bargain purchase gain

        161,351     4,024          
 

Other

            (1,080 )       1,166  
                       

Income (loss) before income taxes

    210,043     78,505     (31,161 )   38,603     44,814  

Income tax benefit (expense)

    (14,738 )   20,387     14,814     2,669     503  
                       

Net income (loss)

    195,305     98,892     (16,347 )   41,272     45,317  

Less: Net income (loss) attributable to noncontrolling interests

    34,648     57,663     (4,070 )   6,809     460  
                       

Net income (loss) attributable to Dynamic Offshore Holding, LP

  $ 160,657   $ 41,229   $ (12,277 ) $ 34,463   $ 44,857  
                       

Adjusted EBITDA(2)

  $ 119,763   $ 124,490   $ 222,671   $ 102,563   $ 124,459  

(1)
Does not include the results of operations for our predecessor for the period from January 1, 2008 through March 13, 2008. For more information about our predecessor's results of operations, please read "Selected Historical Consolidated and Unaudited Pro Forma Financial Data."

(2)
Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, please read "Prospectus Summary—Summary Historical Consolidated and Unaudited Pro Forma Financial Data—Non-GAAP Financial Measure."

58


Table of Contents

    Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

        Oil and gas revenues.    Oil and gas revenues increased $52.7 million, or 35%, to $201.9 million for the six months ended June 30, 2011 as compared to the same period in 2010. Higher realized commodity prices in 2011 accounted for $43.9 million of this increase. Average daily production volumes increased 519 Boe per day to 16,210 Boe per day, an increase of 3%, accounting for $8.8 million of the increased revenues. The increase in average daily production was primarily due to our acquisitions subsequent to June 30, 2010 and the resumption of operations at fields affected by hurricanes, offset by normal declines.

        Other operating revenues.    Other operating revenues increased $4.6 million, or 141%, to $7.9 million for the six months ended June 30, 2011 as compared to the same period in 2010. The increase primarily resulted from additional PHA fees due to increased third-party production processed on our Bullwinkle platform.

        Lease operating expense.    Lease operating expense increased $7.1 million, or 19%, to $43.7 million for the six months ended June 30, 2011 as compared to the same period in 2010. Higher costs primarily for transportation, fuel and chemicals increased lease operating expense by $5.9 million. Incremental production from our acquisitions resulted in a $1.2 million increase in lease operating expense. On a per unit basis, lease operating costs increased to $14.91 per Boe for the six months ended June 30, 2011 versus $12.71 per Boe for the six months ended June 30, 2010.

        Exploration expense.    Exploration expense increased by $4.2 million to $5.1 million for the six months ended June 30, 2011 as compared to the same period in 2010, primarily driven by exploratory dry hole costs of $4.6 million for the six months ended June 30, 2011.

        Depreciation, Depletion and Amortization.    DD&A increased $7.2 million, or 13%, to $62.5 million for the six months ended June 30, 2011 as compared to the same period in 2010. The increase was attributable to our oil and gas depletion, primarily due to a higher per unit rate of $5.4 million and increased production of $1.8 million.

        Workover expense.    Workover expense decreased $4.4 million to $5.2 million for the six months ended June 30, 2011 as compared to $9.6 million for the same period in 2010, primarily as a result of decreased workover activity levels.

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

        Oil and gas revenues.    Oil and gas sales revenues increased $162.0 million, or 104%, to $317.6 million for 2010 as compared to 2009. Average daily production increased by 6,833 Boe per day, or 73%, to 16,225 Boe per day, resulting in an increase in revenue of $107.2 million, primarily as a result of acquisitions. In addition, higher realized commodity prices in 2010 increased our oil and natural gas revenues by $54.8 million.

        Other operating revenues.    Other operating revenues increased $11.0 million to $12.6 million for 2010 as compared to 2009. The increase in other operating revenues is primarily attributable to PHA fees related to our operation of the Bullwinkle platform, which was acquired in January 2010.

        Lease operating expense.    Lease operating expense increased $28.9 million, or 55%, to $81.1 million for 2010 compared to 2009. Incremental production from our acquisitions resulted in a $36.8 million increase in lease operating expense. This increase was partially offset by lower costs which decreased lease operating expense by $7.7 million. On a per unit basis, lease operating costs decreased to $13.69 per Boe for 2010 versus $15.22 per Boe for 2009.

59


Table of Contents

        Exploration expense.    Exploration expense decreased $6.8 million to $2.1 million for 2010 as compared to 2009. The higher exploration expense in 2009 was primarily due to $4.5 million of exploratory geological and geophysical data and services costs and $2.3 million of exploratory dry hole costs. We did not incur any dry hole costs in 2010.

        Depreciation, depletion and amortization.    DD&A increased $101.8 million, or 123%, to $184.3 million for 2010 as compared to 2009. The increase was attributable to our oil and gas depletion, primarily due to increased production of $52.2 million and a higher per unit rate of $3.9 million. In addition, asset impairments of $45.7 million attributable to declines in natural gas prices and well performance issues contributed to the increase.

        Workover expense.    Workover expense increased $8.0 million to $14.1 million in 2010 as compared to $6.1 million in 2009, primarily as a result of increased workover activity levels following our acquisitions.

        Accretion expense.    Accretion expense increased $6.1 million, or 120%, to $11.1 million for 2010 as compared to $5.0 million in 2009, primarily due to acquisitions. In addition, revisions to estimates and timing of our AROs contributed to the increase.

        Loss on sale of assets.    In 2010, we sold our interest in a shut-in field for $11.9 million and recognized a loss of $8.4 million from the sale, which was partially offset by gains from the sale of other interests and equipment. In 2009, we had a gain on sale of assets of $0.1 million.

        Interest expense.    Interest expense increased $6.3 million, or 76%, to $14.7 million for 2010 as compared to 2009, primarily due to increased debt levels as a result of debt assumed in the Bandon acquisition and borrowings under our revolving credit facility to fund a portion of the Samson acquisition.

        Bargain purchase gain.    In 2010, we completed an acquisition related to a preferential purchase right where the seller had attributed a negative fair value to a property. As a result, we recognized a bargain purchase gain of $4.0 million on the acquisition. Our acquisition of Bandon in 2009 resulted in a bargain purchase gain of $161.4 million, due to our estimate of the net assets' fair value exceeding the fair value of the total consideration paid.

    Year Ended December 31, 2009 Compared to the Year Ended December 31, 2008

        Oil and gas revenues.    Oil and gas sales revenues decreased $8.1 million, or 5%, to $155.6 million for 2009 as compared to 2008. Lower commodity prices in 2009, which resulted in a $130.6 million reduction in revenues, served as the primary driver for the decrease in revenues. This decrease was partially offset by an increase in average daily production of 4,064 Boe per day, or 76%, to 9,392 Boe per day in 2009, resulting in an increase in revenue of $122.5 million. The increase in average daily production sold was primarily due to acquisitions.

        Lease operating expense.    Lease operating expense increased $22.0 million, or 73%, to $52.1 million for 2009 as compared to 2008, due to incremental production from our acquisitions. On a per unit basis, lease operating costs decreased slightly to $15.22 per Boe for 2009 versus $15.48 per Boe for 2008.

        Exploration expense.    Exploration expense increased $8.8 million to $8.9 million in 2009 as compared to 2008. The increase consists of $6.5 million in exploratory geological and geophysical data and services costs and $2.3 million of exploratory dry hole costs in 2009. We did not incur any dry hole costs in 2008, and our exploration operations during that period were minimal.

60


Table of Contents

        Depreciation, depletion and amortization.    DD&A increased $41.3 million in 2009 as compared to 2008, primarily due to increased production from acquisitions. The increase was attributable to our oil and gas depletion, primarily due to increased production of $25.9 million and a higher per unit rate of $11.6 million. In addition, asset impairments of $3.8 million contributed to the increase.

        General and administrative expense.    General and administrative expense increased $7.3 million, or 47%, to $22.8 million for 2009 as compared to 2008, primarily due to costs related to a full year of operations in 2009 as compared to less than ten months for 2008. Increased payroll and legal costs also contributed to the increase.

        Workover expense.    Workover expense increased $5.1 million to $6.1 million in 2009 as compared to $1.0 million in 2008, primarily as a result of increased activity levels following our acquisitions.

        Accretion expense.    Accretion expense increased $2.3 million, or 87%, to $5.0 million in 2009 as compared to $2.7 million in 2008, primarily due to our acquisitions. In addition, revisions to the original estimates and timing of our AROs contributed to the increase.

        Insurance expense.    Insurance expense increased $16.1 million to $27.7 million from 2008 to 2009, primarily due to the significant damage to assets throughout the Gulf of Mexico caused by Hurricanes Ike and Gustav in 2008, which resulted in deterioration of commercial insurance market conditions. As a result, we experienced a 51% increase in insurance premiums from 2008 to 2009.

        Casualty loss.    During 2008, Hurricanes Ike and Gustav caused property damage and disruptions to our exploitation and production activities. Our insurance policies in effect on the occurrence dates of Hurricanes Ike and Gustav had a combined deductible of $8.8 million. In 2008, we satisfied our deductible requirement and recorded a casualty loss of $8.8 million. We did not have a casualty loss in 2009.

        Loss on abandonments.    In 2008, there was no loss on abandonments due to the turnkey platform abandonment contract with Superior which SPN entered into effective March 14, 2008. Under this agreement, Superior agreed to provide all well abandonment and platform decommissioning services for all properties owned and operated by SPN on that date at fixed prices upon abandonment of such properties. In 2009, we acquired properties that were not covered by the contract with Superior, and, as a result, we recognized a loss of $4.7 million on our AROs to reflect the difference between the recorded amount and the actual settlement cost.

        Interest expense.    Interest expense increased $4.7 million, or 127%, to $8.3 million for 2009 as compared to 2008, partially due to our assumption of debt in connection with the Bandon acquisition, and partially due to a higher weighted average outstanding debt balance of our revolving credit facility, which increased to $141.3 million for 2009 compared to $87.1 million for 2008.

        Bargain purchase gain.    We did not recognize any bargain purchase gain in 2008, but we recognized $161.4 million of bargain purchase gain in 2009 in connection with the Bandon acquisition.

Liquidity and Capital Resources

        Historically, our primary sources of liquidity have been (i) capital contributions from our equity owners, (ii) borrowings under our revolving credit facility and (iii) cash flows from operations. Capital from these sources has been primarily used for the acquisition, exploration, development and retirement of our assets. Additionally, because of the substantial cash generated by our assets, we have paid down our indebtedness to $175 million at June 30, 2011 and made distributions to our equity owners of $94 million as of that date. We believe that the net proceeds from this offering, combined with our current cash, available borrowing base capacity and future cash flows from operations, will

61


Table of Contents


allow us to reduce existing indebtedness while funding capital expenditures through the remainder of 2011 and 2012 and to pursue additional acquisition opportunities.

    Revolving Credit Facility

        On June 20, 2011, we entered into a $750 million amended and restated secured credit agreement with a group of lenders led by The Royal Bank of Scotland plc. The four-year revolving credit facility, which expires on June 20, 2015, has a $300 million initial borrowing base, of which $175 million was outstanding as of June 30, 2011. In addition, up to $100 million of the borrowing base is available for the issuance of letters of credit.

        Our initial scheduled borrowing base redetermination will be effective November 1, 2011. Following the initial scheduled redetermination, our borrowing base will be redetermined on a semi-annual basis, effective April 1 and October 1. In addition to the scheduled semi-annual borrowing base redetermination, either we or the lenders have the right to request an additional borrowing base redetermination at any time, provided that no party has the right to request more than one such redetermination between the regularly scheduled borrowing base redeterminations. The determination of our borrowing base is subject to a number of factors, including the quantities of proved oil and natural gas reserves, the lenders' price assumptions and other various factors, some of which may be out of our control. The lenders can decrease the borrowing base if they determine that our oil and natural gas reserves, at the time of redetermination, are inadequate to support the borrowing base then in effect. In this case, we would be required to make six monthly payments each equal to one-sixth of the amount by which the aggregate outstanding loans and letters of credit exceed the borrowing base.

        In connection with the XTO Acquisition and the MOR Transaction, the lenders under our credit facility approved two independent increases to our borrowing base of $105 million and $25 million, respectively. Each increase is subject to the closing of the related acquisition by September 30, 2011, compliance with the provisions of the credit agreement and our entering into additional commodity derivative contracts.

        Assuming both the XTO Acquisition and the MOR Transaction are closed and we satisfy the other conditions, our borrowing base will increase from the current level of $300 million to $430 million. As of June 30, 2011, after giving effect to the XTO Acquisition and the MOR Transaction and related borrowing base increases and the application of the net proceeds of this offering, we would have had approximately $             million outstanding under our revolving credit facility, with additional availability of approximately $             million.

        At our election, interest is generally determined by reference to:

    The London interbank offered rate ("LIBOR") plus an applicable margin between 2.25% and 3.00% per annum (based upon borrowing base usage); or

    the alternate base rate plus an applicable margin between 1.25% and 2.00% per annum (based upon borrowing base usage). The alternate base rate is equal to the higher of the Royal Bank of Scotland's prime rate, the federal funds rate plus 0.5% per annum or the reference LIBOR plus 1%.

        Our revolving credit facility is secured by mortgages on greater than 80% of the present value of our oil and natural gas properties. 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;

62


Table of Contents

    a total leverage ratio, consisting of total debt (as defined in the credit agreement) of not more than 3.5 to 1.0 for the four quarters ended on the last day of each fiscal quarter; and

    an interest coverage ratio, consisting of EBITDA (as defined in the credit agreement) to cash interest expense, of not less than 3.0 to 1.0 for the four quarters ended on the last day of each fiscal quarter.

        In addition, our revolving credit facility also contains affirmative and negative covenants that are customary for credit facilities of this type. The covenants include delivery of financial statements and other financial information, notice of defaults and certain other matters, payment of obligations, compliance with laws, maintenance of books and records, certain inspection rights, execution of guarantees by material subsidiaries, further assurances, operation and maintenance of properties, limitations on liens, limitations on investments, limitations on hedging agreements, limitations on indebtedness, limitations on dispositions of properties, limitations on restricted payments, distributions and redemptions, limitations on changes in the nature of business, limitations on use of proceeds, limitations on transactions with affiliates, limitations on mergers and limitations on issuances of equity interests by guarantors. Our revolving credit facility allows for the issuance of up to $300 million in aggregate unsecured debt, provided that the borrowing base will be reduced by $0.25 for each dollar of unsecured debt that we issue.

        Management believes that we were in compliance with the terms of our revolving credit facility as of June 30, 2011.

    Capital Expenditures

        Because our growth has occurred primarily through acquisitions, our historical capital expenditures for non-acquisition activities have been relatively modest. To the extent that we increase our efforts to grow our property base organically in the future, we expect that our capital expenditures will increase accordingly. Our total capital expenditure budget for 2011 drilling, completion and recompletion activities is approximately $100 million. Of this amount, approximately $41.8 million has been spent through June 30, 2011.

    Cash Flows

        The following table summarizes our consolidated cash flows provided by or used in operating activities, investing activities and financing activities for the periods indicated (in thousands):

 
  Years Ended
December 31,
  Six Months
Ended June 30,
 
 
  2008   2009   2010   2010   2011  

Net cash provided by operating activities

  $ 124,835   $ 30,432   $ 151,814   $ 79,619   $ 93,372  

Net cash provided by (used in) investing activities

    (362,317 )   69,439     (91,200 )   (2,080 )   (89,362 )

Net cash provided by (used in) financing activities

    289,512     (63,589 )   (73,909 )   (73,157 )   (50,300 )

        Cash flows provided by operating activities.    The changes in net cash provided by operating activities are attributable to our net income (loss) adjusted for non-cash charges, as presented in our historical consolidated financial statements and related notes thereto contained elsewhere in this prospectus, and changes in our operating assets and liabilities.

        Net cash provided by operating activities increased $13.8 million for the six months ended June 30, 2011 compared to the same period in 2010, primarily due to higher realized commodity prices and higher production related to acquisitions.

63


Table of Contents

        Net cash provided by operating activities increased $121.4 million in 2010 compared to 2009, primarily due to higher production related to the Bandon acquisition in 2009, which we owned for all of 2010 compared to less than three months in 2009, and the Samson and Bullwinkle acquisitions in 2010.

        Net cash provided by operating activities decreased $94.4 million in 2009 compared to 2008, primarily due to lower commodity prices in 2009.

        Cash flows provided by (used in) investing activities.    The $87.3 million increase in cash used in investing activities from the six months ended June 30, 2010 to the six months ended June 30, 2011 was primarily a result of our acquisitions and derivative settlements. In the six months ended June 30, 2011, our acquisitions resulted in our paying net cash of $40.1 million compared to 2010 when our acquisitions resulted in our paying net cash of $0.2 million. Net derivative settlement losses were $7.4 million for the six months ended June 30, 2011, compared to settlement gains of $28.0 million for the same period in 2010.

        The $160.6 million increase in cash used in investing activities from 2009 to 2010 was primarily a result of changes in our cash expenditures and receipts related to our acquisitions. In 2010, we paid a total of $92.4 million for our acquisitions (net of $8.9 million cash acquired). In 2009, we received $41.7 million in connection with the Bandon acquisition. This amount was partially offset by $15.6 million paid in connection with our acquisitions in 2009, resulting in $26.1 million net received in connection with acquisitions in 2009.

        The $431.8 million decrease in cash used in investing activities from 2008 to 2009 was primarily a result of changes in our cash expenditures and receipts related to our acquisitions. In 2009, we received $41.7 million in connection with the Bandon acquisition. This amount was partially offset by $15.6 million paid in connection with our acquisitions in 2009, resulting in $26.1 million net received in connection with acquisitions in 2009. In 2008, we paid a total of $321.7 million for our acquisitions (net of $32.5 million cash acquired).

        Cash flows provided by financing activities.    The $22.9 million decrease in cash used in financing activities from the six months ended June 30, 2010 to the six months ended June 30, 2011 was primarily a result of the $20.1 million decrease in distributions to our equity owners.

        The $10.3 million increase in cash used in financing activities from 2009 to 2010 is primarily a result of the $29.8 million increase in distributions to our equity owners and the $34.8 million increase in repayments of borrowings outstanding under our revolving credit facility, partially offset by the $46.2 million decrease in repayments of the Bandon term loan.

        The $353.1 million increase in cash used in financing activities from 2008 to 2009 is primarily a result of borrowings under our revolving credit facility in 2008, which provided $158.0 million of cash and the $174.0 million of contributions from our equity owners in 2008, compared with $22.3 million contributed in 2009. In 2009, we also increased our distributions to our partners by $33.0 million and increased our repayments of debt by $36.2 million.

Off-Balance Sheet Arrangements

        We currently have no off-balance sheet arrangements. Please read "—Contractual Obligations" and Note 16 to our consolidated financial statements included elsewhere in this prospectus for a discussion of our commitments and contingencies, some of which are not recognized in the consolidated balance sheets under GAAP.

64


Table of Contents

Contractual Obligations

        The following table presents a summary of our contractual cash obligations over the next several fiscal years, as of December 31, 2010:

 
  Payments Due by Period  
 
  Total   Less than
1 year
  1 to 3 years   3 to 5 years   More than
5 years
 
 
  (In thousands)
 

Long-term debt obligation(1)

  $ 203,205   $   $ 145,000   $ 58,205   $  

Interest on debt obligation(1)

    24,532     9,032     11,577     3,923      

Operating lease obligations(2)

    4,400     2,400     2,000          

Asset retirement obligations(3)(4)

    284,800     60,302     9,777     66,942     147,799  
                       

Total

  $ 516,937   $ 71,734   $ 168,354   $ 129,070   $ 147,799  
                       

                        

                               

(1)
On June 20, 2011, we entered into an amended and restated revolving credit facility, which matures on June 20, 2015. Please read "—Liquidity and Capital Resources—Revolving Credit Facility." As of June 30, 2011, our outstanding balance was $175 million. At the current interest rate of 2.75% and commitment fee rate of 0.5%, our interest expense on the outstanding balance as of June 30, 2011 would be $2.8 million for the remainder of 2011, $5.5 million for each of the years ending December 31, 2012, 2013 and 2014 and $2.6 million for the year ending December 31, 2015.

(2)
Please read Note 16 to our consolidated financial statements included elsewhere in this prospectus for a description of our operating lease obligations.

(3)
Represents 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 on numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. Please read Note 7 to our consolidated financial statements included elsewhere in this prospectus.

(4)
Does not reflect $25.1 million of contractually obligated reimbursements due from previous owners of certain properties.

Quantitative and Qualitative Disclosures About Market Risk

        We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below.

        The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

    Commodity Price Risk

        Our major market risk exposure is in the pricing that we receive for our oil and natural gas production. Realized pricing is primarily driven by the spot market prices applicable to our oil and natural gas production. Pricing for oil and natural gas has been volatile for several years, and we expect this volatility to continue in the future. The prices we receive for our oil and natural gas production depend on many factors outside of our control, such as the strength of the global economy.

65


Table of Contents

        We intend to continue to manage our exposure to commodity price risk in the near term while remaining opportunistic over the long term. We use a variety of hedging instruments to accomplish our risk management objectives and enhance the stability of our cash flows. Our commodity derivative contracts are currently in the form of basic swaps and collars that are designed to provide a fixed price (swaps) or defined range of prices (collars) that we will receive. We have a policy of hedging at least 50% of our forecasted proved developed producing volumes on a two-year rolling basis. We actively monitor our hedge portfolio to support our cash flow objectives.

        We had commodity derivative contracts with the following terms outstanding as of June 30, 2011, none of which have been designated as cash-flow hedges:

 
  Year Ending December 31,  
 
  2011   2012   2013  

Crude oil:

                   
 

Swaps (Bbl)

    707,000     1,662,000     1,250,000  
   

Average WTI price ($/Bbl)

    88.01     91.86     100.47  
 

Collars (Bbl)

   
180,000
   
250,000
   
 
   

Average WTI price ($/Bbl)

                   
     

Floor price (put)

    65.00     85.00      
     

Ceiling price (call)

    87.90     114.00      

Natural gas:

                   
 

Swaps (MMBtu)

    1,800,000     3,630,000      
   

Average NYMEX price ($/MMBtu)

    5.90     6.16      
 

Collars (MMBtu)

   
2,500,000
   
2,115,000
   
 
   

Average NYMEX price ($/MMBtu)

                   
     

Floor price (put)

    5.24     5.00      
     

Ceiling price (call)

    7.71     6.54      

        Additionally, on August 22, 2011, we entered into commodity derivative contracts to provide a fixed price for the LLS-WTI crude oil price differential. These commodity derivative contracts cover 800,000 Bbls in 2011 at an average price differential of $20.03 per Bbl and 1,800,000 Bbls in 2012 at an average price differential of $16.80 per Bbl.

    Interest Rate Risk

        As of June 30, 2011, we had total debt outstanding of $175 million, accruing interest at a variable rate, which was 2.75% (a variable rate of 0.25% plus an applicable margin of 2.50%) as of that date. Assuming no change in the amount outstanding, the impact on interest expense of a 10% increase or decrease in the average variable interest rate would be less than $0.1 million.

    Counterparty and Purchaser Credit Risk

        Joint interest receivables arise from entities which own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we operate. We have limited ability to control participation in our wells. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant purchasers. The inability or failure of our significant purchasers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In addition, our commodity derivative contracts expose us to credit risk in the event of nonperformance by counterparties.

        While we generally do not require our purchasers to post collateral and do not have a formal process in place to evaluate and assess the credit standing of our significant purchasers or the counterparties on our commodity derivative contracts, we do evaluate the credit standing of our

66


Table of Contents


purchasers and such counterparties as we deem appropriate under the circumstances. This evaluation may include reviewing a counterparty's credit rating and latest financial information or, in the case of purchasers with which we have receivables, reviewing their historical payment record, the financial ability of the purchaser's parent company to make payment if the purchaser cannot and undertaking the due diligence necessary to determine credit terms and credit limits. The counterparties on our commodity derivative contracts currently in place are lenders under our credit facilities, with investment grade ratings and we are likely to enter into any future commodity derivative contracts with these or other lenders under our new credit facility that also carry investment grade ratings. Several of our significant purchasers have a credit rating below investment grade or do not have rated debt securities. In these circumstances, we have considered the lack of investment grade credit rating in addition to the other factors described above.

Critical Accounting Policies and Estimates

        The policies discussed below are considered by management to be critical to an understanding of our financial statements because their application requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. See the description of our accounting policies in the notes to the financial statements for additional information about our critical accounting policies and estimates.

    Revenue Recognition

        We record revenues from the sales of crude oil, natural gas and natural gas liquids when product is delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured.

        When we have an interest with other producers in properties from which natural gas is produced, we use the entitlement method to account for any imbalances. Imbalances occur when we sell more or less product than we are entitled to under our ownership percentage. Revenue is recognized only on the entitlement percentage of volumes sold. Any amount that we sell in excess of our entitlement is treated as a liability and is not recognized as revenue. Any amount of entitlement in excess of the amount we sell is recognized as revenue and a receivable is accrued.

    Use of Estimates

        The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available.

        Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenues and operating and general and administrative costs, (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing tangible and intangible assets for possible impairment, (4) estimating the useful lives of assets and (5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results could differ materially from estimated amounts.

    Property and Equipment

        We use the successful efforts method to account for our oil and gas exploration and production activities. All costs for development wells, related plant and equipment, proved mineral interests in oil and gas properties, and related ARO costs are capitalized. Costs of exploratory wells are capitalized

67


Table of Contents

pending determination of whether the wells find proved reserves. Costs of wells that are assigned proved reserves remain capitalized. Costs also are capitalized for exploratory wells that have found oil and gas reserves even if the reserves cannot be classified as proved when the drilling is completed, provided the exploratory well has found a sufficient quantity of reserves to justify its completion as a producing well and we are making sufficient progress toward assessing the reserves and the economic and operating viability of the project. Unproved leasehold costs are capitalized and amortized on a composite basis if we judge them to be individually insignificant based on past success, experience, and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease-by-lease basis if unsuccessful or if the lease term has expired. All other exploratory wells and costs are expensed. Oil and gas property costs associated with unproved oil and gas reserves arising from business combinations are assessed for transfer to proved properties based on the change in estimated field-by-field unproved reserve volumes from the acquisition closing date, beginning with the second fiscal year-end subsequent to the acquisition closing date.

        Capitalized costs of producing oil and gas properties, along with support equipment and facilities, are amortized to expense by the unit-of-production method based on proved oil and gas reserves on a field-by-field basis. Upon sale or retirement, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss is recognized.

        Long-lived assets to be held and used, including proved and unproved oil and gas properties, are assessed for possible impairment by comparing their carrying values with their associated undiscounted, risk-weighted estimated future net cash flows. Events that can trigger assessments for possible impairments include write-downs of proved and unproved reserves based on field performance, significant decreases in the market value of an asset, significant changes in the extent or manner of use or a physical change in an asset, significant changes in the relationship between an asset's capitalized cost and the associated oil and gas reserves, and a more-likely-than-not expectation that a long-lived asset will be sold or otherwise disposed of significantly sooner than the end of its previously estimated useful life. Impaired assets are written down to their estimated fair values, generally their estimated discounted future net cash flows as adjusted by additional risk-weighting factors. For proved and unproved oil and gas properties, we perform the impairment review on an individual field basis. Impairment amounts are recorded as incremental depreciation, depletion and amortization expense. We recorded property impairment charges in 2010, 2009 and 2008 as described in Note 6 to our consolidated financial statements included elsewhere in this prospectus. It is reasonably possible that other proved and unproved oil and gas properties could become impaired in the future if commodity prices decline.

        In determining the fair values of proved and unproved properties acquired in business combinations, we prepare estimates of oil and gas reserves. We estimate future prices to apply to the estimated reserve quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net cash flows. For the fair value assigned to proved, probable and possible reserves, the estimated future net cash flows are discounted using a market-based weighted average cost of capital rate deemed appropriate at the time of the business combination. To compensate for the inherent risk of estimating and valuing reserves, the discounted future net cash flows of proved, probable and possible reserves are reduced by additional risk-weighting factors.

        Other property and equipment, consisting primarily of office furniture, equipment, leasehold improvements, computers and computer software, is stated at cost. Depreciation on other property and equipment is calculated on the straight-line method over the estimated useful lives of the assets, which range from three to seven years.

    Commodity Derivative Contracts

        We record all commodity derivative contracts on the consolidated balance sheets as either assets or liabilities, measured at their estimated fair value. We have not designated any commodity derivative contracts as cash-flow hedges for accounting purposes. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and are included in other income (expense) in our consolidated statements of operations.

68


Table of Contents


BUSINESS

Overview

        We are an independent exploration and production company focused on the acquisition and development of producing oil and natural gas properties in the Gulf of Mexico. Since we commenced operations in 2008, we have pursued an active growth strategy as an acquirer of producing assets that provide attractive development opportunities. We seek to maximize the value of our reserves through focused operations and exploitation to generate attractive cash returns. Our management team has an average of more than 28 years of energy industry experience, primarily in the Gulf of Mexico, and are experienced in the unique aspects of evaluating, acquiring and developing offshore properties.

        As of March 31, 2011, our estimated net proved reserves were 45,223 MBoe, of which 52% was oil and 84% was proved developed, with an associated PV-10 of approximately $1.2 billion, based on SEC pricing of $80.04 per Bbl for oil and $4.10 per MMBtu for natural gas. As of that same date, our estimated net probable reserves were 8,782 MBoe with an associated PV-10 of approximately $237.5 million. Please read "Prospectus Summary—Summary Reserve Data" for information on our estimated net proved and probable reserves, PV-10 and related pricing. During June 2011, our properties had aggregate average net daily production of 17,634 Boe per day.

        As of March 31, 2011, we had interests in approximately 200 net productive wells and over 200 offshore oil and gas leases in federal and state waters of the Gulf of Mexico, representing approximately 661,000 gross (317,000 net) acres. Importantly, we operate more than 90% of our assets based on the PV-10 of our proved oil and natural gas reserves as of March 31, 2011, allowing us to maintain better control over our asset portfolio. Our properties are predominantly located in water depths of less than 300 feet. In addition, we own a 49% interest in and operate the deepwater Bullwinkle field and associated platform, located in approximately 1,350 feet of water. Similar to our shallow water properties, the Bullwinkle field produces from a fixed-leg platform utilizing surface wellheads and blowout preventers and, consequently, is not subject to recent regulations instituted for deepwater drilling.

Our Acquisition History

        A significant portion of our growth has been achieved through a series of acquisitions. Since we began operations in 2008, we have completed eight material acquisitions, creating significant value relative to the capital employed. Since inception, our principal equity owners have invested approximately $225 million and have received approximately $83 million in aggregate distributions from cash flows, for a net investment of $142 million. Over this same period, we have incurred a total of $340 million in debt, with $175 million of debt outstanding as of June 30, 2011. As a result of these acquisitions and our operations, the PV-10 of our proved oil and natural gas reserves totaled approximately $1.2 billion as of March 31, 2011.

        We believe that the Gulf of Mexico continues to represent an attractive buyer's market, given the limited number of competitors and the availability of acquisition opportunities, as other oil and natural gas companies divest their Gulf of Mexico properties. For example, we recently entered into an agreement with subsidiaries of Exxon to acquire offshore assets formerly owned by certain subsidiaries of XTO Energy Inc. Please read "—XTO Acquisition." We will continue to be opportunistic in evaluating potential acquisition targets, which we expect will include both shallow water properties and properties in deeper waters with characteristics similar to the Bullwinkle field.

70


Table of Contents

        The following table presents key metrics related to each of our acquisitions.

 
   
   
  As of Acquisition Date  
Acquisition
  Acquisition
Date
  Major Fields   Net
Proved
Reserves
(MMBoe)
  % Oil   % Proved
Developed
 

SPN Resources(1)

  March 2008     South Pass 60, West Delta 79/80     10.2     57 %   90 %

Northstar

  July 2008     Eugene Island 307, Eugene Island 32     8.7     47 %   75 %

Bayou Bend Petroleum

  May 2009     Marsh Island     0.6     13 %   73 %

Beryl Oil and Gas(1)

  October 2009     Vermilion 362-371     14.3     25 %   85 %

Shell

  January 2010     Bullwinkle     6.2     89 %   68 %

Samson Resources

  July 2010     Vermilion 272, High Island 52     4.9     48 %   92 %

Providence Resources

  March 2011     Ship Shoal 252/253, Main Pass 19     1.4     22 %   82 %

Gryphon Exploration(2)

  May 2011     High Island 52, Ship Shoal 301     2.1     12 %   100 %

XTO

  Pending     South Marsh Island 41,
West Cameron 485/507
    13.5 (3)   39 %(3)   72 %(3)

MOR

  Pending     (4)                 3.5 (5)   65 %(5)   92 %(5)

(1)
Includes interests subsequently acquired from Superior in exchange for a 10% equity interest in us.

(2)
The reserve information relating to Gryphon Exploration as of May 1, 2011 is included in NSAI's March 31, 2011 reserve report for our oil and natural gas properties.

(3)
As of July 31, 2011, based on a reserve report prepared by NSAI and our internally prepared reserve estimates.

(4)
We expect to acquire the remaining 25% working interest in the properties that we acquired from SPN Resources in 2008, including the South Pass 60 and West Delta 79/80 fields.

(5)
As of March 31, 2011, based on a reserve report prepared by NSAI.

        Since our inception, we have acquired 48,509 MBoe of net proved reserves through eight material acquisitions and produced 13,885 MBoe (excluding the XTO Acquisition and the MOR Transaction). At March 31, 2011, our estimated net proved reserves were 45,223 MBoe (excluding the additional reserves that we expect to acquire in the XTO Acquisition and the MOR Transaction).

        The primary highlights of these acquisitions include:

    In March 2008, we acquired a 66.7% membership interest in SPN Resources LLC ("SPN") from Superior for $110 million, representing the inaugural step in our acquisition strategy. The acquisition included proved reserves of approximately 6.8 MMBoe, 57% of which were oil and 90% of which were developed. We assumed all of SPN's employees, providing us with a fully functioning operation with a highly competent technical staff. In the first quarter of 2011, Superior exchanged, in part, its ownership interests in SPN for a 10% equity interest in us. As a result, we now own 100% of the membership interests in SPN.

    In July 2008, we acquired Northstar Exploration & Production, Inc. for approximately $235 million. Proved reserves associated with the acquired properties are composed of approximately 8.7 MMBoe, 47% of which were oil and 75% of which were developed. The acquisition significantly increased the scale of our operations and provided us with geographic diversification across the Gulf of Mexico shelf.

    In May 2009, we acquired all of Bayou Bend Petroleum Ltd.'s U.S. oil and natural gas properties for $12.5 million. The acquisition added proved reserves of approximately 0.6 MMBoe, 13% of which were oil and 73% of which were developed. Importantly, the acquisition provided us with a new growth area in the Louisiana state waters and included a significant portfolio of exploratory drilling prospects centered on the Marsh Island area.

71


Table of Contents

    In October 2009, together with Superior, we acquired a combined 85% interest in Beryl Oil and Gas LP (which was subsequently renamed Bandon Oil and Gas LP ("Bandon")) for approximately $30 million in cash and the assumption of $125 million of second lien indebtedness. The acquired assets included 14.3 MMBoe of proved reserves, 25% of which were oil and 85% of which were developed. In the first quarter of 2011, Superior exchanged, in part, its ownership interests in Bandon for a 10% equity interest in us. In addition, we acquired the remaining 15% equity interest in Bandon in a series of transactions between November 2009 and June 2011. As a result, we now own 100% of Bandon and have retired all of the associated second lien indebtedness.

    In January 2010, together with Superior, we acquired the Bullwinkle field and the associated platform from Shell for nominal cash consideration. We own a 49% working interest in the field and serve as operator. The Bullwinkle field added 6.2 MMBoe of proved reserves, 89% of which were oil and 68% of which were developed. In connection with the acquisition, we assumed $49 million of fixed cost abandonment liability associated with the Bullwinkle wellbores. Importantly, we have not retained any liability associated with the abandonment of the Bullwinkle platform.

    In July 2010, we acquired the shallow water Gulf of Mexico assets of Samson Resources for approximately $100 million. Proved reserves associated with the acquired properties are composed of approximately 4.9 MMBoe, 48% of which were oil and 92% of which were developed. The acquisition further strengthened our Gulf of Mexico shelf presence and provided us with another major operated field.

    In March 2011, we acquired the Gulf of Mexico shelf assets of Providence Resources for $15 million. The acquisition included proved reserves of approximately 1.4 MMBoe, 22% of which were oil and 82% of which were developed. We previously operated three of the seven acquired fields, comprising more than 70% of the acquired reserves.

    In May 2011, we acquired the Gulf of Mexico assets of Gryphon Exploration Company, a wholly owned subsidiary of Woodside Petroleum Ltd., for $27.5 million. Proved reserves associated with the acquired properties are composed of approximately 2.1 MMBoe, 12% of which were oil and 100% of which were developed. The acquisition consolidated our existing interest in a significant property and added several higher value operated fields.

XTO Acquisition

        On July 29, 2011, we entered into an agreement with XTO Offshore Inc., HHE Energy Company and XH, LLC, each an indirect subsidiary of Exxon, to acquire certain oil and natural gas interests in the Gulf of Mexico for approximately $182.5 million (the "XTO Acquisition"). The properties to be acquired comprise substantially all of the Gulf of Mexico assets acquired by Exxon as part of its acquisition of XTO Energy, Inc. in 2010 (the "XTO Acquisition Properties"). As of July 31, 2011, based on a reserve report prepared by NSAI and our internally prepared reserve estimates these properties contained 13,535 MBoe of proved reserves, of which 39% was oil, and 7,025 MBoe of probable reserves. As of that same date, the PV-10 of the proved oil and natural gas reserves was approximately $329 million, and the PV-10 of the probable oil and natural gas reserves was approximately $87 million, in each case based on SEC pricing of $88.44 per Bbl for oil and $4.19 per MMBtu for natural gas.

        The XTO Acquisition Properties include approximately 250,000 gross (130,000 net) acres and 135 gross (62 net) producing wells. We expect net production from the XTO Acquisition Properties during August 2011 to exceed 7,000 Boe/d. Additionally, our geological and geophysical professionals have identified an inventory of over 30 potential drilling locations. We will operate over 90% of the XTO Acquisition Properties.

72


Table of Contents

        We expect to complete the XTO Acquisition by August 31, 2011, subject to customary closing conditions. The description of the XTO Acquisition Properties does not give effect to any potential adjustments, including adjustments resulting from the exercise of preferential rights to purchase, which we do not expect to be material. Please read "—Estimated Reserves—XTO."

MOR Transaction

        On August 25, 2011, we agreed with Moreno Offshore Resources, LLC ("MOR") to pay $68.0 million to acquire the remaining 25% working interest in the properties that we acquired from SPN Resources in 2008 (the "MOR Transaction"). MOR had originally acquired this interest from SPN Resources at the same time as our initial acquisition. As of March 31, 2011, MOR's 25% working interest represented approximately 3,548 MBoe of proved reserves, of which approximately 65% was oil, and 302 MBoe of probable reserves. As of that same date, the PV-10 of the proved oil and natural gas reserves was approximately $92 million, and the PV-10 of the probable oil and natural gas reserves associated with MOR's working interest was approximately $9 million, in each case based on SEC pricing of $80.04 per Bbl for oil and $4.10 per MMBtu for natural gas. Net production attributable to MOR's 25% working interest during June 2011 was approximately 1,369 Boe/d. We currently operate the vast majority of the properties in which we expect to acquire the remaining interest.

        We expect to complete the MOR Transaction on or about September 15, 2011. Please read "—Estimated Reserves—MOR."

Our Operating Assets

        All of our oil and natural gas properties are located in the federal and state waters in the Gulf of Mexico and consist of approximately 200 net productive wells. As of March 31, 2011, our total estimated net proved reserves were approximately 45,223 MBoe, of which 52% was oil and 84% was proved developed. We operate more than 90% of our assets, based on PV-10 as of March 31, 2011. All of our assets are shallow-water assets, except for the Bullwinkle field, which is a deepwater asset. Importantly, however, all of our production in the Bullwinkle field is from a fixed-leg platform with surface blow-out preventers, making it not subject to the drilling moratorium instituted for deepwater drilling following the Macondo well incident in April 2010. Please read "Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business—The Macondo well explosion and ensuing oil spill could have broad adverse consequences affecting our operations in the Gulf of Mexico, some of which may be unforeseeable."

        When we find commercially exploitable oil or natural gas, a significant advantage to our development strategy is that the infrastructure to support the production and delivery of product is in most cases already in place and available. We believe this presents us with a material competitive advantage in bringing our discoveries on line and lowering related development costs.

        Currently, all of our operations are located in the Gulf of Mexico and we have no foreign subsidiaries. However, in the future, we may apply the experience and operational expertise we have developed in the Gulf of Mexico to other locations. As with our acquisition strategy in the Gulf of Mexico, in any such acquisition we would expect to selectively acquire companies and producing properties based on disciplined valuations of proved reserves.

73


Table of Contents

    Our Significant Fields

        In the aggregate, our five largest fields, based on proved reserves, accounted for approximately 64% of the PV-10 of our proved oil and natural gas reserves as of March 31, 2011. Our largest fields include the following:

        Bullwinkle field:    We own a 49% working interest and serve as operator in the Bullwinkle field. The Bullwinkle field is located 158 miles south-southwest of New Orleans in approximately 1,350 feet of water and encompasses all of Green Canyon blocks 65, 108 and 109. Although the Bullwinkle field is a deepwater asset, it produces from a fixed-leg platform with surface wellheads and blowout preventers. As a result, our operations in the Bullwinkle field share many key characteristics with our shallow water operations. Cumulative production from our Bullwinkle field from first production in 1989 through April 2011 totaled approximately 113 MMBbls of oil and 175 Bcf of natural gas. Our seven wells in the Bullwinkle field produced net to our interest at an average rate of 1,796 Boe/d for the three months ended June 30, 2011.

        We primarily target the J sands in the Bullwinkle field, which are at depths of 10,900 feet to 13,000 feet. The reservoirs primarily exhibit water drive and strati-structural traps. We own an aggregate of 17,280 gross (8,467 net) acres in the Bullwinkle field. We are engaged in an active workover and recompletion program with an additional seven wells scheduled for near-term activities. In addition, our reservoir simulation model has identified two proved undeveloped locations and two recompletion opportunities, which we intend to pursue in 2012. We have also identified additional drilling opportunities in the field.

        The Bullwinkle platform is the deepest fixed-leg platform in the world and serves as a major production processing hub of third party deepwater fields for which we currently receive significant production handling revenues. The platform has processing capacity of approximately 160,000 Bbl of oil per day, 320 MMcf of natural gas per day and 65,000 Bbl of water per day. Currently, we handle production from six fields via sub-sea tie backs to the platform and have significant excess capacity to handle additional production. Since the platform commenced operation, it has processed a total of over 450 million barrels of oil equivalent.

        West Delta 79/80 field:    We own a 75% working interest and serve as operator in the West Delta 79/80 field. The West Delta 79/80 field is located 80 miles south southeast of New Orleans, includes 17 wells producing to six platforms in approximately 150 feet of water and encompasses all or portions of West Delta blocks 57, 79 and 80. Cumulative production from our West Delta 79/80 field from first production in 1970 through April 2011 totaled approximately 162 MMBbls of oil and 616 Bcf of natural gas. Our 17 wells in the West Delta 79/80 field produced net to our interest at an average rate of 991 Boe/d for the three months ended June 30, 2011.

        In the West Delta 79/80 field, we primarily target the C sands. The reservoirs primarily exhibit moderate to strong water drive and fault and anticline traps. We own an aggregate of 9,375 gross (7,031 net) acres in the field. During 2011, we have conducted recompletion operations on four wells. We believe that the field will support multiple wells.

        South Pass 60 field:    We own a 75% working interest and serve as operator in the South Pass 60 field. The South Pass 60 field, located 97 miles southeast of New Orleans, includes 65 wells producing to 8 platforms in approximately 250 feet of water and encompasses all or portions of South Pass blocks 6, 17, 59, 60, 61, 66 and 67. Cumulative production from our South Pass 60 field from first production in 1972 through April 2011 totaled approximately 229 MMBbls of oil and 498 Bcf of natural gas. Our 65 wells in the South Pass 60 field produced net to our interest at an average rate of 1,308 Boe/d for the three months ended June 30, 2011.

74


Table of Contents

        We primarily target the I and K sands in the South Pass 60 field. The reservoirs primarily exhibit a solution gas drive with weak aquifer support and fault traps. We own an aggregate of 23,427 gross (17,570 net) acres in the field. During 2011, we have conducted or are conducting nine recompletions and four tubing replacements. In addition, we believe that the field exhibits waterflood potential, which could potentially increase our production efficiency in the future. Recent studies have identified proved undeveloped and re-drill locations, which we intend to pursue in 2012.

        Vermilion 362-371 field:    We own an approximately 67% working interest and serve as operator in the Vermilion 362-371 field. The field, located 210 miles southwest of New Orleans, includes six wells producing to two platforms in approximately 300 feet of water and encompasses all of Vermilion blocks 362, 363 and 371. Cumulative production from our Vermilion 362-371 field from first production in 1994 through April 2011 totaled approximately 6 MMBbls of oil and 65 Bcf of natural gas. Our six wells in the Vermilion 362-371 field produced net to our interest at an average rate of 1,935 Boe/d for the three months ended June 30, 2011.

        We primarily target the Lentic sands in the Vermilion 362-371 field. We own an aggregate of 11,250 gross (7,500 net) acres in the field. The reservoirs primarily exhibit a depletion and partial water drive. During 2011, we have conducted recompletion operations on one well and have conducted three acid jobs.

        Vermilion 272 field:    We own a 100% working interest and serve as operator in the Vermilion 272 field. The Vermilion 272 field, located 180 miles southwest of New Orleans, includes 12 wells producing to three platforms in approximately 175 feet of water and encompasses all of Vermilion block 272 and all of South Marsh Island blocks 87 and 102. Cumulative production from our Vermilion 272 field from first production in 2003 through April 2011 totaled approximately 6 MMBbls of oil and 14 Bcf of natural gas. Our 12 wells in the Vermilion 272 field produced net to our interest at an average rate of 929 Boe/d for the three months ended June 30, 2011.

        We primarily target the Q and T sands in the Vermilion 272 field. The reservoirs primarily exhibit moderate aquifer support with salt piercement fault traps. We own an aggregate of 10,571 gross and net acres in the Vermilion 272 field.

        The following table presents summary data regarding our largest fields as of the date and for the period indicated:

 
   
   
  As of
March 31, 2011
   
 
Field
  Acquired From   Operator   Average
Working
Interest
  % Oil of
Proved
Reserves
  June 2011 Average
Net Daily
Production (Boe/d)
 

Bullwinkle

  Shell   Dynamic     49 %   84 %   1,796  

West Delta 79/80

  SPN   Dynamic     75 %(1)   66 %   991  

South Pass 60

  SPN   Dynamic     75 %(1)   84 %   1,308  

Vermilion 362-371

  Beryl   Dynamic     67 %   34 %   1,935  

Vermilion 272

  Samson   Dynamic     100 %   85 %   929  

(1)
We will own a 100% working interest following the completion of the MOR Transaction.

Our Business Strategies

        Our goal is to increase stockholder value by growing reserves, production and cash flows at an attractive return on invested capital. We seek to achieve this goal through the following strategies:

    Continue to pursue strategic acquisitions.  We intend to continue to selectively acquire companies and producing properties based on disciplined valuations of proved reserves. Our acquisition

75


Table of Contents

      strategy is focused on identifying motivated sellers of operated properties with underworked assets where the total asset retirement obligation is proportionate to the proved reserve value of the assets. We believe these types of assets are candidates for lower-risk production enhancement activities. By applying a disciplined valuation methodology, we reduce the risk of underperformance on the acquired properties while maintaining the potential for higher returns on our investment. We believe that opportunities to consolidate interests in our existing properties will continue to be available and that these consolidation transactions can generate attractive returns without the risks associated with acquiring and operating new assets. For example, we recently entered into an agreement with Moreno Offshore Resources, LLC to consolidate our interests in the properties we previously acquired from SPN Resources. Please read "—Business—MOR Transaction." We also believe that maintaining a strong financial profile through our disciplined financial policy helps position us as a preferred buyer by mitigating sellers' concerns regarding our ability to close transactions and fund future abandonment obligations.

    Enhance returns by focusing on operations and cost efficiencies.  We believe that our focus on lower risk production enhancement activities, such as workovers and recompletions on producing and shut-in wellbores, is one of the most cost-effective ways to maintain and grow production. We are engaged in a continual effort to monitor and reduce operating expenses by finding opportunities to safely increase operational efficiencies related to staffing, transportation and operational procedures. Moreover, our ability to accurately estimate and manage P&A costs associated with potential acquisitions increases the likelihood of achieving our target returns on investment.

    Focus primarily on the shallow waters of the Gulf of Mexico.  Our experience in the Gulf of Mexico has led us to focus our efforts in that particular region, where we are familiar with the regulatory, geological and operational characteristics of this environment. This geographic focus enables us to minimize logistical costs and required staff.

    Maintain a disciplined financial policy.  We intend to continue to pursue a disciplined financial policy by maintaining a prudent capital structure and managing our exposure to interest rate and commodity price risk. We plan to continue maintaining relatively modest leverage and financing our growth with a balanced combination of equity and debt. Maintaining a balanced capital structure allows us to use our available capital to selectively pursue attractive investments or acquisition opportunities.

    Manage our exposure to commodity price risk.  We intend to continue to manage our exposure to commodity price risk in the near term while remaining opportunistic over the long term. We use a variety of hedging instruments to accomplish our risk management objectives and enhance the stability of our cash flows. Our commodity derivative contracts are currently in the form of basic swaps and collars that are designed to provide a fixed price (swaps) or defined range of prices (collars) that we will receive. We have a policy of hedging at least 50% of our forecasted proved developed producing volumes on a two-year rolling basis. We actively monitor our hedge portfolio to support our cash flow objectives.

Our Competitive Strengths

        We have a number of competitive strengths that we believe will help us to successfully execute our business strategies:

    Acquisition execution capabilities.  We have a proven track record of identifying, evaluating and executing the purchase of oil and natural gas assets and companies. Since we began operations in 2008, we have completed eight material acquisitions, creating significant value relative to the capital employed. In addition, we have two acquisitions currently pending. The significant

76


Table of Contents

      history, experience and familiarity of our executive management team with the Gulf of Mexico leads potential sellers to contact us directly, which reduces potential competition from other buyers. We have an experienced team of professionals dedicated primarily to the technical evaluation of acquisitions and reserve analysis, which allows us to continuously pursue opportunities without compromising the management of our existing assets. Moreover, we believe that our expertise related to the legal, financial and regulatory aspects of mergers and acquisitions allows us to quickly and successfully close transactions.

    High-quality asset base with significant production enhancement opportunities.  Our producing asset base is composed of some of the largest fields discovered in the Gulf of Mexico. Given the prolific nature of our assets, we believe that our fields are characterized by lower-risk properties and offer significant additional development and exploration potential. Specifically, our geological and geophysical professionals have identified a multi-year inventory of potential drilling locations in our fields associated with our proved reserves, which we believe represent lower-risk opportunities. In addition, we have identified a substantial inventory of unproven prospects through the technical evaluation of our properties. We have licenses for recent 3-D seismic data utilizing modern processing techniques on more than 450 offshore blocks. Our seismic data covers the vast majority of our acreage holdings, including multiple data sets over several of our more valuable properties. Many of our fields contain several producing zones, providing us increased opportunities for production enhancement activities within each wellbore. Additionally, we own the rights to deep intervals on the vast majority of our 661,000 gross (317,000 net) acres in the Gulf of Mexico, which includes the depths at which ultra-deep exploration is underway on the Gulf of Mexico Shelf.

    Operating control over the majority of our portfolio of assets.  We operate more than 90% of our assets based on the PV-10 of our proved oil and natural gas reserves as of March 31, 2011, allowing us to maintain better control over our asset portfolio. We believe that 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 also believe that maintaining operational control over the majority of our assets allows us to better pursue our strategies of enhancing returns through focusing on production enhancement opportunities, operational and cost efficiencies, maximizing hydrocarbon recovery and effectively managing our P&A liabilities.

    Strong financial profile.  We believe that our strong financial profile positions us as a preferred buyer for potential acquisitions. After the completion of this offering, we expect to continue to have strong liquidity and financial flexibility sufficient to fund our anticipated capital needs and future growth opportunities. As of June 30, 2011, after giving effect to the XTO Acquisition and the MOR Transaction and related borrowing base increases and the application of the net proceeds of this offering, we would have had approximately $             million outstanding under our revolving credit facility, with additional availability of approximately $             million. Please read "—XTO Acquisition," "—MOR Transaction" and "Prospectus Summary—Recent Developments—Borrowing Base Increases." We expect that cash flows from our assets will be sufficient to fund our planned capital expenditure activities, and given our high level of operational control, we should be able to maintain control over the pace of spending.

    Significant oil exposure.  As of March 31, 2011, our estimated net proved reserves were composed of approximately 52% oil. This oil exposure allows us to benefit from the disparity between relative oil and natural gas prices, which has persisted over the last several years and which we expect to continue in the future. Nearly all of our oil is sold at LLS, HLS and EIC prices, which have recently traded at a significant premium to NYMEX WTI benchmark prices. Consequently, our oil production benefits from higher pricing differentials relative to many other North American crude oil producers in other areas. For example, for the three months ended June 30, 2011, the average realized price before the effect of commodity derivative contracts for our oil

77


Table of Contents

      production was $113.85 per Bbl, compared to an average WTI index price of $102.34 per Bbl for the same period.

    Efficient management of our P&A activities.  We consider the evaluation and execution of P&A activities to be one of our core competencies. We have an experienced internal team with a dedicated focus on managing our P&A activities and estimating P&A costs associated with acquisition opportunities. Our ongoing effort to manage our P&A liabilities by proactively removing inactive structures, wellbores and pipelines meaningfully reduces our operating expenses, maintenance expenses, insurance premiums and overall risk exposure.

    Experienced and incentivized management team.  Our management team has an average of more than 28 years of energy industry experience, primarily focused on the Gulf of Mexico. In addition, our executive officers have a meaningful economic interest in us, which is expected to total approximately        % of our common stock following the completion of this offering, thereby aligning management's interests with those of our stockholders.

    Affiliation with Riverstone.  Riverstone has significant energy and financial expertise to complement its investment in us. To date, Riverstone has committed approximately $16.0 billion to 79 investments across the midstream, upstream, power, oilfield service and renewable sectors of the energy industry. Following the completion of this offering, Riverstone and its affiliates will own an approximate        % interest in us. We expect that our relationship with Riverstone will continue to provide us with several significant benefits, including access to potential transactions and financial professionals with a successful track record of investing in energy assets. Please read "Certain Related Party Transactions—Riverstone Investments in Dynamic."

    Relationship with Superior.  Superior will continue to own a significant equity interest in us following this offering and is a co-owner in Bullwinkle. We believe this relationship offers several significant benefits, including access to technical expertise related to well intervention and decommissioning and insight into offshore service market conditions. Our complementary areas of expertise and operational capabilities position us favorably in the pursuit of future acquisition opportunities. Please read "Certain Relationships and Related Party Transactions—Transactions with Superior."

Our Operations

    Estimated Reserves—Dynamic

        The following table presents summary data with respect to our estimated net proved and probable oil and natural gas reserves as of the dates indicated. The reserve estimates at March 31, 2011 presented in the tables below are based on reports prepared by NSAI in accordance with the rules and regulations of the SEC regarding oil and natural gas reserve reporting. The reserve estimates at December 31, 2010 presented in the table below are based on estimates prepared by our internal engineers, in accordance with the rules and regulations regarding oil and natural gas reserve reporting. For more information about our summary reserve data, please read NSAI's reports, which have been filed as exhibits to the registration statement containing this prospectus.

        Proved reserves are reserves 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 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. Probable reserves are reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves which may potentially be recoverable through additional drilling or

78


Table of Contents


recovery techniques are by nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by us.

 
  At December 31,
2010(1)
  At March 31,
2011
 

Reserve Data(2):

             

Estimated proved reserves:

             
 

Oil (MMBbls)

    18.5     23.3  
 

Natural gas (Bcf)

&