As filed with the Securities and Exchange Commission on January 17, 2012

Registration No. 333-176521

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

AMENDMENT NO. 6
TO

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 (State or other jurisdiction of incorporation or organization)		1311 (Primary Standard Industrial Classification Code Number)		45-3034172 (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 811 Main Street, Suite 3700 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

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 JANUARY 17, 2012

Prospectus

16,666,667 Shares

Dynamic Offshore Resources, Inc.

Common Stock

Dynamic Offshore Resources, Inc. is offering 16,666,667 shares of its common stock. 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 $17.00 and $19.00 per share.

We have been approved, subject to official notice of issuance, 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

Per Share	$	$	$
Total	$	$	$

The selling stockholders have granted the underwriters the right to purchase up to an additional 2,500,000 shares of common stock to cover over-allotments. We will not receive any proceeds from the sale of shares by the selling stockholders.

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 , 2012.


Citigroup		Credit Suisse
Deutsche Bank Securities	Tudor, Pickering, Holt & Co.	UBS Investment Bank


Capital One Southcoast
	FBR Capital Markets
		Howard Weil Incorporated
			IBERIA Capital Partners L.L.C.
				Johnson Rice & Company L.L.C.


Dahlman Rose & Company		Morgan Keegan		Natixis		RBS

The date of this prospectus is , 2012.

Table of Contents

TABLE OF CONTENTS


Prospectus Summary		1
The Offering		10
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		98
Compensation Discussion and Analysis		105
Executive Compensation		118
Certain Relationships and Related Party Transactions		126
Corporate Reorganization		131
Principal and Selling Stockholders		132
Description of Capital Stock		135
Shares Eligible for Future Sale		139
Material U.S. Federal Income Tax Considerations to Non-U.S. Holders		141
Underwriters (Conflicts of Interest)		144
Legal Matters		151
Experts		151
Where You Can Find More Information		152
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 , 2012, 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" beginning on page 20 and "Cautionary Note Regarding Forward-Looking Statements" beginning on page 41.

Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Some data is also based on our good faith estimates. Although we believe these third-party sources are reliable and that the information is accurate and complete, we have not independently verified the information.

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. 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.

Unless otherwise indicated, the estimated reserve volumes and related operational measures presented in this prospectus include the properties acquired in the XTO Acquisition and the MOR Transaction described under "—Recent Developments" beginning on page 6. 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.

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 is experienced in the unique aspects of evaluating, acquiring and developing offshore properties.

As of July 31, 2011, our estimated net proved reserves were 60.1 MMBoe, of which 50% was oil and 81% was proved developed, with an associated PV-10 of approximately $1.7 billion, based on Securities and Exchange Commission ("SEC") pricing of $88.44 per Bbl for oil and $4.19 per MMBtu for natural gas. As of that same date, our estimated net probable reserves were 16.0 MMBoe with an associated PV-10 of approximately $370.1 million. Please read "—Summary Historical Operating and Reserve Data—Summary Reserve Data" beginning on page 15 for information on our estimated net proved and probable reserves, PV-10 and related pricing. During November 2011, our properties had aggregate average net daily production in excess of 27,000 Boe per day.

As of September 30, 2011, we had interests in approximately 270 net productive wells and over 250 offshore oil and gas leases in federal and state waters of the Gulf of Mexico, representing approximately 830,000 gross (490,000 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 July 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.

Table of Contents

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 ten 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 $123 million in aggregate distributions from cash flows, for a net investment of $102 million. Over this same period, we have incurred a total of $555 million in debt, with $365 million of debt outstanding and $59 million of cash and cash equivalents as of December 31, 2011. As a result of these acquisitions and our operations, the PV-10 of our proved oil and natural gas reserves totaled approximately $1.7 billion as of July 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, on August 31, 2011, we acquired substantially all of the Gulf of Mexico assets that Exxon Mobil Corporation ("Exxon") acquired as part of its acquisition of XTO Energy Inc. in 2010. Please read "—Recent Developments—XTO Acquisition" beginning on page 7. 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—Our Acquisition History" beginning on page 70.

				As of Acquisition Date(1)

Acquisition	Acquisition Date	Major Fields		Net Proved Reserves (MMBoe)		% Oil			% Proved Developed
SPN Resources(2)	March 2008	South Pass 60, West Delta 79/80			10.2		57	%		90	%
Northstar	July 2008	Eugene Island 307, Eugene Island 32			8.7		46	%		75	%
Bayou Bend Petroleum	May 2009	Marsh Island			0.6		13	%		73	%
Beryl Oil and Gas(2)	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	May 2011	High Island 52, Ship Shoal 301			2.1		12	%		100	%
XTO	August 2011	South Marsh Island 41, West Cameron 485/507			13.5		39	%		72	%
MOR	September 2011	South Pass 60, West Delta 79/80	(3)		3.4		65	%		92	%

(1): Based on reserve reports or our internally generated reserve estimates prepared at or near the acquisition date.
(2): Includes interests subsequently acquired from Superior in exchange for a 10% equity interest in us.
(3): We acquired from MOR the remaining 25% working interest in the properties that we acquired from SPN Resources in 2008.

Since our inception, we have acquired 65.5 MMBoe of net proved reserves through ten material acquisitions (including the XTO Acquisition and the MOR Transaction) and as of July 31, 2011, have produced 14.7 MMBoe. At July 31, 2011, our estimated net proved reserves were 60.1 MMBoe (including the additional reserves that we acquired 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 six largest fields accounted for approximately 66% of the PV-10 of our proved oil and natural gas reserves as of July 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

Table of Contents

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.

•: South Marsh Island 41 field: The South Marsh Island 41 field is located in approximately 100 feet of water and encompasses all of South Marsh Island blocks 40, 41, 44 and 45. Cumulative production from our South Marsh Island 41 field from first production in 1967 through April 2011 totaled approximately 14 MMBbls of oil and 87 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.
•: 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.
•: 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 July 31, 2011

Field	Acquired From	Operator	Average Working Interest			% Oil of Proved Reserves			November 2011 Average Net Daily Production (Boe/d)
Bullwinkle	Shell	Dynamic		49	%		84	%		1,745
South Marsh Island 41	XTO	Dynamic		100	%		90	%		1,835
South Pass 60	SPN	Dynamic		100	%		84	%		2,208
West Delta 79/80	SPN	Dynamic		100	%		65	%		1,395
Vermilion 362-371	Beryl	Dynamic		67	%		35	%		1,685
Vermilion 272	Samson	Dynamic		100	%		85	%		830

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 underperformance on the acquired properties while maintaining the potential for higher returns

Table of Contents

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 acquired from Moreno Offshore Resources, LLC the remaining interests in the properties we previously acquired from SPN Resources in 2008. Please read "—Recent Developments—MOR Transaction" beginning on page 7. 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 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 ten material acquisitions, creating significant value relative to the capital employed. 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 believe that our expertise related to the legal, financial and regulatory aspects of mergers and acquisitions allows us to quickly and successfully close transactions.

Table of Contents

•: 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 approximately 830,000 gross (490,000 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 July 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 September 30, 2011, after giving effect to the application of the net proceeds of this offering, we would have had approximately $108.0 million outstanding under our revolving credit facility, with additional availability of approximately $322.0 million. Please read "—Recent Developments—XTO Acquisition" beginning on page 7, "—MOR Transaction" beginning on page 7, and "—Borrowing Base Increases and Debt Repayment; Distributions to Equity Owners" beginning on page 8. 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 July 31, 2011, our estimated net proved reserves were composed of approximately 50% 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 September 30, 2011, the average realized price before the effect of commodity derivative contracts for our oil production was $104.91 per Bbl, compared to an average WTI index price of $89.54 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

Table of Contents

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, management and other employees have a meaningful economic interest in us, which is expected to total approximately 10.1% of our common stock following the completion of this offering, thereby aligning management's interests with those of our stockholders.
•: Affiliation with Riverstone. Investment funds managed or advised by Riverstone Holdings LLC ("Riverstone") have significant energy and financial expertise to complement their investment in us. To date, affiliates of Riverstone and the Carlyle Group (such affiliates, the "Riverstone/Carlyle Funds") have 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, the Riverstone/Carlyle Funds will own an approximate 52.3% interest in us. While 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, Riverstone is under no obligation to provide us with such access and is likely to do so only to the extent such access would prove beneficial to Riverstone. In addition, we have renounced our interest in certain business opportunities that may be presented to Riverstone and its affiliates. Further, affiliates of Riverstone currently have, and may make in the future, investments in other similar companies that compete with us. Please read "Certain Relationships and Related Party Transactions—Riverstone/Carlyle Funds Investments in Dynamic" beginning on page 126.
•: 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" beginning on page 128 and "Description of Capital Stock—Corporate Opportunity" on page 138.

Recent Developments

Preliminary 2011 Operational and Financial Results

Although we are in the early stages of compiling our operational and financial results for the fourth quarter and full year of 2011, our preliminary estimated results indicate our production was approximately 26,000 to 26,500 Boe per day for the three months ended December 31, 2011, an increase of 33% to 35% as compared to 19,609 Boe per day in the quarter ended September 30, 2011. The increase in our production for the three months ended December 31, 2011 was primarily attributable to the inclusion of a full quarter's results of the August 2011 XTO Acquisition described below.

We estimate that our proved reserves, net of production, increased slightly between July 31, 2011 and December 31, 2011.

We expect our average realized price before the effect of commodity derivative contracts for our oil production to be between $114.00 and $115.00 per Bbl for the three months ended December 31, 2011, compared to an average WTI index price of $94.06 per Bbl for the same period. For the three months ended December 31, 2011, we expect our average realized price before the effect of commodity

Table of Contents

derivative contracts for our natural gas production to be between $3.65 and $3.85 per Mcf, compared to an average Henry Hub benchmark price of $3.46 per MMBtu for the same period.

For the three months ended December 31, 2011 as compared to the three months ended September 30, 2011, we expect that (i) our lease operating expenses were slightly lower on a per Boe basis, (ii) our general and administrative expense was comparable and (iii) our workover expense was lower on a per Boe basis.

These results are preliminary and may differ from those ultimately reported in our future SEC filings. The preliminary financial data included in this prospectus has been prepared by, and is the responsibility of, our management. Hein & Associates LLP, our independent registered public accountants, has not audited, reviewed, compiled or performed any procedures with respect to the preliminary financial data underlying these results. Accordingly, Hein & Associates LLP does not express an opinion or any other form of assurance with respect thereto. The preliminary reserve estimates underlying our expectations described above have been prepared by our internal engineers; Netherland, Sewell & Associates, Inc., our independent reserve engineers, have not reviewed or prepared any reports with respect to those estimates.

XTO Acquisition

On August 31, 2011, we acquired from XTO Offshore Inc., HHE Energy Company and XH, LLC, each an indirect subsidiary of Exxon, certain oil and natural gas interests in the Gulf of Mexico for approximately $182.5 million (the "XTO Acquisition"). The properties 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 Historical Operating and Reserve Data—Summary Reserve Data" beginning on page 15.

The XTO Acquisition Properties include approximately 250,000 gross (130,000 net) acres and 135 gross (62 net) producing wells. At the time of acquisition, net production from the XTO Acquisition Properties during August 2011 was greater than 7,500 Boe/d. Additionally, our geological and geophysical professionals have identified an inventory of over 30 potential drilling locations within the XTO Acquisition Properties. We operate over 90% of the XTO Acquisition Properties.

For more information about the XTO Acquisition Properties, please read "Business—XTO Acquisition" beginning on page 72, "—Our Operations" beginning on page 79 and the statements of revenues and direct operating expenses for the XTO Acquisition Properties included elsewhere in this prospectus.

MOR Transaction

On September 14, 2011, we acquired directly from a subsidiary of Moreno Offshore Resources, LLC ("MOR") for $68.0 million 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 July 31, 2011, MOR's 25% working interest represented approximately 3.4 MMBoe of proved reserves, of which approximately 65% was oil, and 0.3 MMBoe 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 $104.2 million, and the PV-10 of the probable oil and natural gas reserves was approximately $10.7 million, in each case based on SEC pricing of $88.44 per Bbl for oil and $4.19 per MMBtu for natural gas. At the time of

Table of Contents

acquisition, net production attributable to MOR's 25% working interest during August 2011 was approximately 1,300 Boe/d. We currently operate substantially all of the properties we acquired in the MOR Transaction.

For more information about the properties acquired in the MOR Transaction, please read "Business—MOR Transaction" beginning on page 73.

Borrowing Base Increases and Debt Repayment; Distributions to Equity Owners

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. Following the closing of the XTO Acquisition and the MOR Transaction, our borrowing base increased from $300 million to $430 million. On November 7, 2011, the lenders under our credit facility reaffirmed the borrowing base of $430 million. On December 28, 2011, we repaid $20 million in borrowings under our revolving credit facility, leaving $365 million in borrowings outstanding as of that date. As of September 30, 2011, after giving effect to the application of the net proceeds of this offering, we would have had approximately $108.0 million outstanding under our revolving credit facility, with additional availability of approximately $322.0 million.

In the fourth quarter of 2011, we made an approved tax distribution to our equity owners of approximately $18 million, and on January 13, 2012, we made an additional approved distribution to our equity owners of $25 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" beginning on page 41.

Conflicts of Interest

Affiliates of Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., UBS Securities LLC, Capital One Southcoast, Inc., IBERIA Capital Partners L.L.C., Natixis Securities Americas LLC and RBS Securities Inc. are lenders, and in several cases, agents for the lenders, under our credit facility and may receive more than 5% of the net proceeds of this offering in connection with our repayment of outstanding borrowings under our credit facilty. See "Use of Proceeds" on page 43. 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 147.

Table of Contents

Corporate Reorganization

Pursuant to the terms of a corporate reorganization, which will be completed immediately prior to the closing of this offering, all of the interests in Dynamic Offshore Holding, LP will be transferred to its wholly owned subsidiary, Dynamic Offshore Resources, Inc., through a combination of a contribution of such interests and a merger of Dynamic Offshore Holding, LP into 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. The following diagram indicates our ownership structure after giving effect to our corporate reorganization and this offering based on an assumed initial public offering price of $18.00 per share (the mid-point of the price range set forth on the cover of this prospectus) and assuming no exercise of the underwriters' over-allotment option.

(1): Includes Superior, MOR DOH Holdings, L.L.C. and trusts held for the benefit of family members of our executive officers and other employees.

For more information regarding our principal stockholders, please read "Principal and Selling Stockholders" beginning on page 132 and "Certain Relationships and Related Party Transactions" beginning on page 126. For more information regarding our corporate reorganization, please read "Corporate Reorganization" beginning on page 131.

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.

Table of Contents

THE OFFERING


Common stock offered by Dynamic Offshore Resources, Inc.		16,666,667 shares.
Common stock to be outstanding after the offering		70,533,333 shares.
Over-allotment option		The selling stockholders have granted the underwriters a 30-day option to purchase up to an aggregate of 2,500,000 additional shares of our common stock to cover over-allotments.
Use of proceeds		We expect to receive approximately $277.0 million of net proceeds from the sale of the common stock offered by us, based upon the assumed initial public offering price of $18.00 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 $15.6 million. We intend to use the net proceeds from this offering to repay outstanding borrowings under our revolving credit facility. We will not receive any proceeds from the sale of shares by the selling stockholders 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" on page 43, "Corporate Reorganization" on page 131, and "Underwriters" beginning on page 144.
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" on page 43.
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 have been approved, subject to official notice of issuance, to list our common stock on the New York Stock Exchange under the symbol "DOR".

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" beginning on page 46, "Corporate Reorganization" beginning on page 131, "Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 51 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 nine months ended September 30, 2010 and 2011 and balance sheet data at September 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 nine months ended September 30, 2011 and pro forma balance sheet data at September 30, 2011, which has been derived from the unaudited pro forma financial statements included elsewhere in this prospectus.

We have accounted for the MOR Transaction as a transaction between entities under common control because of our relationship with Riverstone, which also controls (as defined in the accounting standards codification master glossary) the Moreno Group companies. Transfers of net assets between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information similar to the pooling method.

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 recently completed 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 nine months ended September 30, 2011 was prepared as if each of these transactions occurred on January 1, 2010. The unaudited pro forma financial information as of September 30, 2011 was prepared as if our corporate reorganization and this offering and the application of the net proceeds had occurred on September 30, 2011.

Table of Contents

		Historical																		Pro Forma

		Predecessor			Dynamic Offshore Holding, LP
		January 1, 2008 Through March 13, 2008			Year Ended December 31,									Nine Months Ended September 30,									Nine Months Ended September 30, 2011
					Year Ended December 31,									Nine Months Ended September 30,						Year Ended December 31, 2010
					2008			2009			2010			2010			2011			Year Ended December 31, 2010
		(In thousands)
Statement of operations data:
Oil and gas revenues		$	56,179		$	209,219		$	178,992		$	345,812		$	255,496		$	340,541			536,507			436,179
Other operating revenues			741			1,695			2,017			12,815			7,770			11,926			12,815			11,926

			56,920			210,914			181,009			358,627			263,266			352,467			549,322			448,105
Operating expenses:
	Lease operating expense		8,791			36,725			60,618			89,399			63,511			78,998			126,135			98,605
	Exploration expense		—			80			8,999			2,100			1,736			7,285			2,100			7,285
	Depreciation, depletion and amortization		13,414			49,648			88,573			195,122			96,205			102,417			271,568			132,289
	General and administrative expense		2,275			17,843			25,655			24,328			19,280			19,328			24,328			19,328
	Other operating expense(1)		4,786			29,930			51,142			73,047			50,114			51,709			82,931			58,328

			29,266			134,226			234,987			383,996			230,846			259,737			507,062			315,835

Income (loss) from operations			27,654			76,688			(53,978	)		(25,369	)		32,420			92,730			42,260			132,270
Other income (expense):
	Interest expense, net		(34	)		(2,492	)		(7,138	)		(13,541	)		(10,688	)		(6,409	)		(12,123	)		(4,324	)
	Commodity derivative income (expense)		—			159,939			(21,887	)		6,990			29,838			61,889			6,990			61,889
	Bargain purchase gain		—			—			161,351			4,024			4,024			—			4,024			—
	Other		—			(103	)		—			(1,080	)		—			(146	)		(1,080	)		(146	)

Income (loss) before income taxes			27,620			234,032			78,348			(28,976	)		55,594			148,064			40,071			189,689
Income tax benefit (expense)			—			(14,738	)		20,387			14,814			4,344			1,544			(14,719	)		(66,387	)

Net income (loss)			27,620			219,294			98,735			(14,162	)		59,938			149,608			25,352			123,302
Less: Net income (loss) attributable to noncontrolling interests			—			34,648			57,663			(4,070	)		10,184			460			(2,645	)		299

Net income (loss) attributable to Dynamic Offshore Holding, LP		$	27,620		$	184,646		$	41,072		$	(10,092	)	$	49,754		$	149,148		$	27,997		$	123,003

Pro forma net income (loss) attributable to Dynamic Offshore Holding, LP/Dynamic Offshore Resources, Inc.					$	129,600		$	13,634		$	(16,883	)	$	29,516		$	95,947		$	27,997		$	123,003

Pro forma basic and diluted earnings per share					$	1.84		$	0.19		$	(0.24	)	$	0.42		$	1.36		$	0.40		$	1.74
Adjusted EBITDA(2)		$	41,953		$	154,165		$	131,440		$	235,567		$	175,756		$	206,158		$	383,626		$	278,064

(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" beginning on page 13.

	As of December 31,

	As of December 31,				As of September 30, 2011		Pro Forma As of September 30, 2011
	2009		2010		As of September 30, 2011		Pro Forma As of September 30, 2011
	(In thousands)
Balance sheet data:
Cash and cash equivalents	$	88,457	$	75,162	$	18,765	$	18,766
Net property, plant and equipment		861,204		864,645		1,145,544		1,145,544
Total assets		1,138,999		1,067,131		1,374,766		1,371,767
Long-term debt		243,000		203,205		385,000		108,000
Total owners'/stockholders' equity		526,244		475,531		530,579		704,580

Table of Contents

	Predecessor			Dynamic Offshore Holding, LP

	January 1, 2008 Through March 13, 2008			Years Ended December 31,									Nine Months Ended September 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		$	173,704		$	37,796		$	157,656		$	139,553		$	156,602
Net cash provided by (used in) investing activities		(3,627	)		(431,423	)		62,075			(94,605	)		(113,576	)		(296,676	)
Net cash provided by (used in) financing activities		—-			309,749			(63,589	)		(76,346	)		5,823			83,677

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;

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.

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,									Nine Months Ended September 30,									Nine Months Ended September 30, 2011
			Year Ended December 31,									Nine Months Ended September 30,						Year Ended December 31, 2010
			2008			2009			2010			2010			2011			Year Ended December 31, 2010
	(In thousands)
Reconciliation of net income (loss) to Adjusted EBITDA:
Net income (loss)	$	27,620	$	219,294		$	98,735		$	(14,162	)	$	59,938		$	149,608		$	25,352		$	123,302
Interest expense, net		34		2,492			7,138			13,541			10,688			6,409			12,123			4,324
Income tax expense (benefit)		—		14,738			(20,387	)		(14,814	)		(4,344	)		(1,544	)		14,719			66,387
Depreciation, depletion and amortization		13,414		49,648			88,573			195,122			96,205			102,417			271,568			132,289
Unrealized (gain) loss on commodity derivatives		—		(146,671	)		97,975			36,181			7,043			(67,507	)		36,181			(67,507	)
Other operating expense		885		14,561			20,757			22,643			10,250			16,629			26,627			19,123
Bargain purchase gain		—		—			(161,351	)		(4,024	)		(4,024	)		—			(4,024	)		—
Other		—		103			—			1,080			—			146			1,080			146

Adjusted EBITDA	$	41,953	$	154,165		$	131,440		$	235,567		$	175,756		$	206,158		$	383,626			278,064

Reconciliation of net cash provided by operating activities to Adjusted EBITDA:
Net cash provided by operating activities	$	22,836	$	173,704		$	37,796		$	157,656		$	139,553		$	156,602
Derivative settlements		—		13,268			76,088			43,171			36,881			(5,618	)
Interest expense, net		34		2,492			7,138			13,541			10,688			6,409
Exploration expense		—		80			8,999			2,100			1,736			7,285
Amortization in interest expense, net		—		315			219			(287	)		(332	)		(291	)
Current income tax expense		—		—			(2,188	)		—			—			—
Changes in operating assets and liabilities		18,978		(45,784	)		(1,299	)		19,156			(10,806	)		41,178
Other		105		10,090			4,687			230			(1,964	)		593

Adjusted EBITDA	$	41,953	$	154,165		$	131,440		$	235,567		$	175,756		$	206,158

Table of Contents

Summary Historical Operating and Reserve Data

Summary 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 July 31, 2011 for our estimated net proved and probable oil and natural gas reserves and for the estimated net proved and probable oil and natural gas reserves that we acquired in the MOR Transaction 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 estimates of the net proved and probable oil and natural gas reserves that we acquired in the XTO Acquisition at July 31, 2011 presented in the tables below are based, in part, on reports prepared by NSAI for the XTO Acquisition 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 for the XTO Acquisition are based on estimates prepared by our internal engineers.

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" beginning on page 79 and NSAI's reports, which have been filed as exhibits to the registration statement containing this prospectus.

The reserve estimates and the associated PV-10 and standardized measure included in this prospectus do not include the effects of insurance costs. For more detail about our aggregate insurance costs, please read the operating expense information contained within Note 3 to the audited consolidated financial statements of Dynamic Offshore Holding, LP.

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.

Table of Contents

						At July 31, 2011

			At December 31, 2010(1)			Dynamic(2)			XTO			Total
Reserve Data(3):
Estimated proved reserves:
	Oil (MMBbls)			18.5			24.6			5.2			29.8
	Natural gas (Bcf)(4)			91.3			131.8			49.8			181.6
		Total estimated proved reserves (MMBoe)(5)		33.7			46.6			13.5			60.1
	Proved developed:
		Oil (MMBbls)		15.0			19.5			4.4			24.0
		Natural gas (Bcf)		80.7			116.1			32.0			148.0
		Total (MMBoe)		28.5			38.9			9.8			48.7
	Percent proved developed			85	%		84	%		72	%		81	%
	Proved undeveloped:
		Oil (MMBbls)		3.4			5.1			0.8			5.9
		Natural gas (Bcf)		10.5			15.7			17.9			33.6
		Total (MMBoe)		5.2			7.7			3.8			11.5
PV-10 of proved reserves (in millions)(6)			$	947.7		$	1,381.5		$	328.5		$	1,710.0
Standardized Measure (in millions)(6)			$	1,184.5			n/a			n/a			n/a
Estimated probable reserves:
	Oil (MMBbls)			4.6			4.7			1.5			6.2
	Natural gas (Bcf)(4)			49.0			25.6			33.3			58.9
		Total estimated probable reserves (MMBoe)		12.7			9.0			7.0			16.0
PV-10 of probable reserves (in millions)(6)			$	285.1		$	282.7		$	87.4		$	370.1

(1): Reflects 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): Includes interests acquired in the MOR Transaction.
(3): Our estimated proved and probable reserves and related future net revenues and PV-10 at December 31, 2010 and July 31, 2011 and Standardized Measure at December 31, 2010 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 $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, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead on a historical basis.
(4): Includes NGL volumes, which we do not believe are significant.
(5): One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency.
(6): For more information about our PV-10 and Standardized Measure, please read "—PV-10 and Standardized Measure" beginning on page 17.

Price Sensitivity

Table of Contents

the pricing sensitivity are based on our historical lease and well operating costs and have been held constant throughout the life of the properties. The assumed capital and abandonment costs were held constant to the date of the expenditure. Based on SEC pricing, the PV-10 of our proved oil and natural gas reserves was approximately $1.7 billion while, based on NYMEX forward pricing at July 22, 2011, as set forth below, the PV-10 of our proved oil and natural gas reserves was approximately $2.1 billion. Please read "Business—Our Operations" beginning on page 79 for further discussion of why we believe the presentation of oil and natural gas reserves using forward pricing is useful for investors.

			At July 31, 2011

			Dynamic (1)		XTO		Total
Reserve Data(2):
Estimated proved reserves:
	Oil (MMBbls)			25.1		5.3		30.4
	Natural gas (Bcf)(3)			134.4		50.4		184.9
		Total estimated proved reserves (MMBoe)(4)		47.6		13.7		61.3
PV-10 of proved reserves (in millions)(5)			$	1,725.9	$	413.7	$	2,139.6
Estimated probable reserves:
	Oil (MMBbls)			4.8		1.5		6.3
	Natural gas (Bcf)(3)			27.5		37.4		64.9
		Total estimated probable reserves (MMBoe)		9.4		7.7		17.1
PV-10 of probable reserves (in millions)(5)			$	349.5	$	129.7	$	479.2

(1): Includes interests acquired in the MOR Transaction.
(2): Our 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. At July 22, 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.
(3): Includes NGL volumes, which we do not believe are significant.
(4): One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency.
(5): For more information about our PV-10 and Standardized Measure, please read "—PV-10 and Standardized Measure" below.

PV-10 and Standardized Measure

We and others in the oil and natural gas industry use PV-10 as a measure to compare the relative size and value of proved reserves held by a company without regard to the specific tax characteristics of the entity. Investors should be cautioned, however, that neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas reserves. PV-10 differs from Standardized 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 remain 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.

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

Table of Contents

at 10% per annum to reflect timing of future cash flows. Our 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 which 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. Assuming our anticipated conversion into a corporation had occurred on December 31, 2010, we estimate that incremental income taxes of $372.9 million would have reduced our Standardized Measure to $898.1 million. For further discussion of income taxes, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 51.

The following table presents a reconciliation of the PV-10 of our proved reserves as of December 31, 2010 to our Standardized Measure at that date.

	At December 31, 2010

	(in millions)
PV-10 of proved reserves	$	947.7
Proved reserves attributable to noncontrolling interests		170.2
Proved reserves attributable to the MOR Transaction		91.4
Discounted future net income taxes		(24.8	)

Standardized Measure	$	1,184.5

In addition, we have disclosed PV-10 in certain other contexts in this prospectus, including: (i) PV-10 calculated as of an interim date, (ii) PV-10 of probable reserves, (iii) PV-10 of proved and probable reserves attributable to acquired properties and (iv) PV-10 of proved and probable reserves adjusted for pricing sensitivities. In each of these cases, the PV-10 disclosed differs from Standardized Measure of proved reserves as of December 31, 2010, which cannot be calculated on the same basis as the respective PV-10 amounts disclosed.

With respect to PV-10 calculated as of an interim date, including in connection with reserves attributable to acquired properties, it is not practicable to calculate the taxes for the related interim period because GAAP does not provide for disclosure of the Standardized Measure on an interim basis. For acquired properties, combining the seller's Standardized Measure with ours would not produce a meaningful number because the seller's tax status is irrelevant to our calculation on a going-forward basis. Similarly, Standardized Measure is based on proved reserves as of fiscal year end calculated using unweighted arithmetic average first-day-of-the-month prices for the prior 12 months. GAAP does not prescribe any corresponding GAAP measure for PV-10 of probable reserves or PV-10 of reserves adjusted for pricing sensitivities. For these reasons, it is not practicable for us to reconcile these additional PV-10 measures to GAAP Standardized Measure.

Because probable reserves are, by definition, less certain to be recovered than proved reserves, PV-10 of probable reserves is not equivalent to and should not be given the same weight as PV-10 of proved reserves.

Table of Contents

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.

		Historical												Pro Forma

		Predecessor		Dynamic Offshore Holding, LP
		January 1, 2008 Through March 13, 2008		Year Ended December 31,						Nine Months Ended September 30,						Nine Months Ended September 30, 2011
				Year Ended December 31,						Nine Months Ended September 30,				Year Ended December 31, 2010
				2008		2009		2010		2010		2011		Year Ended December 31, 2010
Operating data:
Net sales volumes:
	Oil (MBbls)		364		1,363		2,145		3,289		2,447		2,559		4,792		3,171
	Natural gas (MMcf)		2,575		6,692		10,555		18,468		14,086		14,482		33,403		20,521

	Total (MBoe)		793		2,478		3,904		6,367		4,795		4,973		10,359		6,591

	Average net daily production (Boe/d)		10,859		6,770		10,696		17,444		17,564		18,216		28,381		24,143

Average sales prices:
	Oil, without realized derivatives ($/Bbl)		96.72		103.80		62.64		78.65		76.37		106.23		78.42		106.41
	Natural gas, without realized derivatives ($/Mcf)		8.16		10.12		4.23		4.72		4.87		4.74		4.81		4.81
	Oil, with realized derivatives ($/Bbl)(1)		96.72		113.65		89.95		86.35		86.32		99.85		83.71		101.26	(2)
	Natural gas, with realized derivatives ($/Mcf)(1)		8.16		10.10		5.89		5.68		5.76		5.48		5.35		5.33
	Oil, WTI benchmark ($/Bbl)		96.25		99.75		62.09		79.61		77.69		95.47		79.61		95.47	(2)
	Natural gas, Henry Hub benchmark ($/MMBtu)		8.58		8.90		4.16		4.38		4.52		4.21		4.38		4.21
Costs and expenses ($/Boe):
	Lease operating expense(3)		11.09		14.82		15.53		14.04		13.25		15.89		12.18		14.96
	Depreciation, depletion and amortization		16.92		20.04		22.69		30.65		20.06		20.59		26.22		20.07
	General and administrative expense		2.87		7.20		6.57		3.82		4.02		3.89		2.35		2.93

(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 September 30, 2011, the average realized price before the effect of commodity derivative contracts for our oil production was $104.91 per Bbl, compared to an average WTI index price of $89.54 per Bbl for the same period.
(3): Our lease operating expenses do not include the effects of insurance costs. For more detail about our aggregate insurance costs, please read the operating expense information contained within Note 3 to the audited consolidated financial statements of Dynamic Offshore Holding, LP.

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" beginning on page 26.

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 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" beginning on page 25.

Table of Contents

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.

In addition, an oil spill on or related to our properties and operations could expose us to joint and several strict liability, without regard to fault, under applicable law for all containment and oil removal costs and a variety of public and private damages 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. If an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and damages could be material to our results of operations and financial position.

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.

Table of Contents

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit drilling locations or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, 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" below. 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" beginning on page 79 for information about our estimated oil and natural gas reserves and the PV-10 as of July 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.

Table of Contents

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, 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 U.S. Department of the Interior, initially through its federal Minerals Management Service (the "MMS"), which was subsequently renamed the Bureau of Ocean Energy Management, Regulation and Enforcement (the "BOEMRE") in June 2010, 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 from the BOEMRE. Effective October 1, 2011, the BOEMRE was split into two federal bureaus, the Bureau of Ocean Energy Management (the "BOEM"), which handles offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, National Environmental Policy Act ("NEPA") analysis and environmental studies, and the Bureau of Safety and Environmental Enforcement (the "BSEE"), which is responsible for the safety and enforcement functions of offshore oil and gas operations, including the development and enforcement of safety and environmental regulations, permitting of offshore exploration, development and production activities, inspections, offshore regulatory programs, oil spill response and newly formed training and environmental compliance programs. Consequently, after October 1, 2011, we will be required to interact with two newly formed federal bureaus to obtain approval of our exploration and development plans and issuance of drilling permits, which may result in added plan approval or drilling permit delays as the functions of the former BOEMRE are fully divested and implemented in the two federal bureaus. While 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, 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

Table of Contents

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 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, BOEM or BSEE 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 ("SEMS") in order to reduce human and organizational errors as root causes of work-related accidents and offshore spills.

Only recently, on September 14, 2011, BOEMRE issued proposed rules that would amend the Workplace Safety Rule by requiring the imposition of certain added safety procedures to a company's SEMS not covered by the original rule and revising existing obligations that a company's SEMS be audited by requiring the use of an independent third party auditor who has been pre-approved by the agency to perform the auditing task. 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

Table of Contents

operations. Moreover, effective October 1, 2011, the BOEMRE was split into two separate federal bureaus, the BOEM and the BSEE. 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, BOEM's or BSEE'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, BOEM or BSEE 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 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 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 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 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 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

Table of Contents

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 the PV-10 of our proved reserves as of July 31, 2011 would decrease approximately $21.2 million. If natural gas prices decline by $0.10 per MMBtu, then the PV-10 of our proved reserves as of July 31, 2011 would decrease approximately $15.1 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.

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 $57.7 million and $71.5 million related to capital and exploration expenditures for the year ended December 31, 2010 and the nine months ended September 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.

Table of Contents

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.

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

Table of Contents

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 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, BOEM or BSEE could significantly impact our estimates of future asset retirement obligations from period to period" beginning on page 25, 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

Table of Contents

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 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 19% of our total proved reserves were classified as proved undeveloped as of July 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

Table of Contents

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.

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.

Table of Contents

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.

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.

Table of Contents

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

Upon the completion of this offering, we expect to have $88 million in outstanding indebtedness and will have available borrowing capacity of $342 million under our revolving credit facility. In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties.

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

•: a significant portion of our cash flows could be used to service our indebtedness;
•: a high level of debt would increase our vulnerability to general adverse economic and industry conditions;
•: the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;
•: a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;
•: our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;
•: a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; and
•: a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

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

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 September 30, 2011, total outstanding borrowings under our revolving credit facility were $385 million, and our borrowing base was $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

Table of Contents

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 ($20.3 million at September 30, 2011), receivables resulting from the sale of our oil and natural gas production ($56.0 million at September 30, 2011), which we market to energy marketing companies, and advances to joint interest parties ($0.9 million at September 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.

Table of Contents

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.

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.

Table of Contents

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.

The proposed American Jobs Act of 2011 includes potential legislation 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 any legislation as a result of these proposals 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 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.

Table of Contents

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.

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 beginning on page 144, and may not be indicative of the market price of our common stock

Table of Contents

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.

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 $8.01 per share.

Based on an assumed initial public offering price of $18.00 per share, purchasers of our common stock in this offering will experience an immediate and substantial dilution of $8.01 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 September 30, 2011 after giving effect to this offering would be $9.99 per share. Please read "Dilution" on page 45 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;

Table of Contents

•: 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 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 70,533,333 outstanding shares of common stock. This number includes 16,666,667 shares that we are issuing in this offering, which may be resold immediately in the public market. Following the completion of this offering (assuming no exercise of the underwriters' over-allotment option), the selling stockholders will own 52,119,868 shares, or approximately 73.9% of our total outstanding shares (including our officers and directors, who will own 3,629,037 shares, or approximately 5.1% 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" beginning on page 144, but may be sold into the market in the future. Certain selling stockholders will be a party to a registration rights agreement with us which will require us to effect the registration of their 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 1,002,967 shares, or approximately 1.4% of our total outstanding shares, are not subject to lock-up agreements. 743,831 of these shares will be issued under our Long-Term Incentive Plan pursuant to our registration statement on Form S-8 prior to the completion of this offering and may be sold into the public market. The remaining 259,136 shares may be sold into the public market, subject to compliance with Rule 144 under the Securities Act.

Prior to the completion of this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of 11,500,000 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

Table of Contents

acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

Our amended and restated certificate of incorporation and amended and restated 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 amended and restated 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 amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

•: a classified board of directors, so that only approximately one-third of our directors are elected each year;
•: limitations on the removal of directors; and
•: limitations on the ability of our stockholders to call special meetings and establish advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders.

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 the Riverstone/Carlyle Funds will initially own up to approximately 52.3% of our outstanding common stock. Consequently, the Riverstone/Carlyle Funds 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 the Riverstone/Carlyle Funds, including their portfolio companies, on the other hand, concerning among other things, potential competitive business activities or business opportunities. Riverstone manages or advises investment funds that regularly make investments in entities in the oil and natural gas industry. As a result, such 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. Further, while we expect that Riverstone will continue to provide us with access to potential transactions in the future, Riverstone is under no obligation to do so. As a result, it is likely that Riverstone will only provide us with such access in situations that are beneficial to Riverstone.

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" below.

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 the

Table of Contents

Riverstone/Carlyle Funds 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, any such business opportunity is expressly offered to such director or officer in writing solely in his or her capacity as our director.

Riverstone does not have a formal policy regarding business opportunities presented to the investment funds managed or advised by it and their respective portfolio companies. However, it is generally Riverstone's practice that any such funds may pursue or direct to a portfolio company any business opportunity that is presented both to such fund and any portfolio company of any such funds, and do not pursue business opportunities presented to an employee of an affiliate of Riverstone solely in his or her capacity as a director of a portfolio company of any such fund.

As a result, the Riverstone/Carlyle Funds or their 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 opportunities. 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 the Riverstone/Carlyle Funds and their 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—Corporate Opportunity" on page 138.

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 the Riverstone/Carlyle Funds and our other equity owners that will be party to the stockholders agreement 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. The significant ownership interest of the Riverstone/Carlyle Funds could adversely affect investors' perceptions of our corporate governance.

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" beginning on page 20 and "Management's

Table of Contents

Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 51 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.

Table of Contents

USE OF PROCEEDS

We expect to receive net proceeds of approximately $277.0 million from the sale of the common stock offered by us, assuming an initial public offering price of $18.00 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 $23.0 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 $15.6 million.

We intend to use the net proceeds from this offering to repay outstanding borrowings under our revolving credit facility, of which $385 million was outstanding as of September 30, 2011. Our revolving credit facility matures on June 20, 2015 and bears interest at a variable rate, which was 3.1% as of September 30, 2011. The borrowings to be repaid were incurred primarily to fund our recently completed XTO Acquisition and our recently completed MOR Transaction. While we do not currently have any plans to immediately borrow additional amounts under the revolving credit facility, we may at any time reborrow amounts repaid under the revolving credit facility.

We will not receive any of the proceeds from the sale of shares of our common stock by the selling stockholders pursuant to any exercise of the underwriters' over-allotment option. 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 will receive a portion of the proceeds of this offering. Accordingly, this offering is being made in compliance with Rule 5121 of FINRA. Please read "Underwriters" beginning on page 144.

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.

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 September 30, 2011:

•: on an actual basis; and
•: on an as adjusted basis to give effect to this offering, the transactions described under "Corporate Reorganization" beginning on page 131 which will occur simultaneously with the closing of this offering, and the application of the net proceeds as set forth under "Use of Proceeds" beginning on page 43.

You should read the following table in conjunction with "Use of Proceeds" beginning on page 43, "Selected Historical Consolidated and Unaudited Pro Forma Financial Data" beginning on page 46, "Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 51 and our historical consolidated financial statements and unaudited pro forma financial information and related notes thereto appearing elsewhere in this prospectus.

		As of September 30, 2011

		Actual		As Adjusted
		(In thousands)
Cash and cash equivalents(1)		$	18,765	$	18,766

Long-term debt, including current maturities:
	Revolving credit facility(1)	$	385,000	$	108,000

	Total long-term debt		385,000		108,000

Owners'/stockholders' equity:
	Partners' capital		530,579		—
	Common stock, $0.01 par value; 300,000,000 shares authorized (as further adjusted); 70,533,333 shares issued and outstanding (as further adjusted)		—		705
	Preferred stock, $0.01 par value; 50,000,000 shares authorized (as further adjusted); no shares issued and outstanding (as further adjusted)		—		—
	Additional paid-in capital		—		703,875
	Retained earnings (accumulated loss)(2)		—		—

	Total owners'/stockholders' equity		530,579		704,580

	Total capitalization	$	915,579	$	812,580

(1): As of December 31, 2011, we had cash and cash equivalents of $59 million and $365 million was outstanding under our revolving credit facility, leaving $65 million available for borrowing. This cash balance does not give effect to our subsequent $25 million approved distribution.
(2): In connection with our corporate reorganization, an estimated incremental net deferred tax liability of $103.0 million will be established for differences between the tax and book basis of our assets and liabilities that are not currently subject to entity-level taxation, and a corresponding expense will be recorded to net income from continuing operations.

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 September 30, 2011, after giving pro forma effect to the transactions described under "Corporate Reorganization" beginning on page 131, was approximately $427.6 million, or $7.94 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 September 30, 2011 would have been approximately $704.6 million, or $9.99 per share. This represents an immediate increase in the net tangible book value of $2.05 per share to our existing stockholders and an immediate dilution to new investors purchasing shares in this offering of $8.01 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			$	18.00
Pro forma net tangible book value per share as of September 30, 2011 (after giving effect to our corporate reorganization)	$	7.94
Increase per share attributable to new investors in this offering		2.05

Pro forma as adjusted net tangible book value per share after giving effect to our corporate reorganization and this offering				9.99

Dilution in pro forma net tangible book value per share to new investors in this offering			$	8.01

The following table summarizes, on a pro forma basis as adjusted as of September 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 $18.00, 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

		Shares Acquired					Total Consideration					Average Price Per Share
		Number		Percent			Amount		Percent			Average Price Per Share
Existing stockholders(1)			53,866,666		76.4	%	$	427,580,000		58.9	%	$	7.94
New investors(2)			16,666,667		23.6	%		300,000,000		41.1	%		18.00

	Total		70,533,333		100.0	%	$	727,580,000		100.0	%	$	10.32

(1): The number of shares disclosed for the existing stockholders includes 2,500,000 shares that may be sold by the selling stockholders in this offering pursuant to any exercise of the underwriters' over-allotment option and 743,831 shares of our common stock to be granted upon completion of this offering to the former bonus pool participants at Dynamic Offshore Holding, LP.
(2): The number of shares disclosed for the new investors does not include the 2,500,000 shares that may be purchased by the new investors from the selling stockholders in this offering pursuant to any exercise of the underwriters' over-allotment option.

Table of Contents

SELECTED HISTORICAL CONSOLIDATED AND UNAUDITED PRO FORMA FINANCIAL DATA

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 recently completed 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 nine months ended September 30, 2011 was prepared as if each of these transactions occurred on January 1, 2010. The unaudited pro forma financial information as of September 30, 2011 was prepared as if our corporate reorganization and this offering and the application of the net proceeds had occurred on September 30, 2011.

You should read the following summary financial data in conjunction with "Corporate Reorganization" beginning on page 131, "Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 51, 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" beginning on page 52.

Table of Contents

		Historical																		Pro Forma

		Predecessor			Dynamic Offshore Holding, LP
		January 1, 2008 Through March 13, 2008			Year Ended December 31,									Nine Months Ended September 30,
																							Nine Months Ended September 30, 2011
																				Year Ended December 31, 2010
					2008			2009			2010			2010			2011			Year Ended December 31, 2010
		(In thousands)
Statement of operations data:
Oil and gas revenues		$	56,179		$	209,219		$	178,992		$	345,812		$	255,496		$	340,541			536,507			436,179
Other operating revenues			741			1,695			2,017			12,815			7,770			11,926			12,815			11,926

			56,920			210,914			181,009			358,627			263,266			352,467			549,322			448,105
Operating expenses:
	Lease operating expense		8,791			36,725			60,618			89,399			63,511			78,998			126,135			98,605
	Exploration expense		—			80			8,999			2,100			1,736			7,285			2,100			7,285
	Depreciation, depletion and amortization		13,414			49,648			88,573			195,122			96,205			102,417			271,568			132,289
	General and administrative expense		2,275			17,843			25,655			24,328			19,280			19,328			24,328			19,328
	Other operating expense(1)		4,786			29,930			51,142			73,047			50,114			51,709			82,931			58,328

			29,266			134,226			234,987			383,996			230,846			259,737			507,062			315,835

Income (loss) from operations			27,654			76,688			(53,978	)		(25,369	)		32,420			92,730			42,260			132,270
Other income (expense):
	Interest expense, net		(34	)		(2,492	)		(7,138	)		(13,541	)		(10,688	)		(6,409	)		(12,123	)		(4,324	)
	Commodity derivative income (expense)		—			159,939			(21,887	)		6,990			29,838			61,889			6,990			61,889
	Bargain purchase gain		—			—			161,351			4,024			4,024			—			4,024			—
	Other		—			(103	)		—			(1,080	)		—			(146	)		(1,080	)		(146	)

Income (loss) before income taxes			27,620			234,032			78,348			(28,976	)		55,594			148,064			40,071			189,689
Income tax benefit (expense)			—			(14,738	)		20,387			14,814			4,344			1,544			(14,719	)		(66,387	)

Net income (loss)			27,620			219,294			98,735			(14,162	)		59,938			149,608			25,352			123,302
Less: Net income (loss) attributable to noncontrolling interests			—			34,648			57,663			(4,070	)		10,184			460			(2,645	)		299

Net income (loss) attributable to Dynamic Offshore Holding, LP		$	27,620		$	184,646		$	41,072		$	(10,092	)	$	49,754		$	149,148		$	27,997		$	123,003

Pro forma net income (loss) attributable to Dynamic Offshore Holding, LP/Dynamic Offshore Resources, Inc.					$	129,600		$	13,634		$	(16,883	)	$	29,516		$	95,947		$	27,997		$	123,003

Pro forma basic and diluted earnings per share					$	1.84		$	0.19		$	(0.24	)	$	0.42		$	1.36		$	0.40		$	1.74
Adjusted EBITDA(2)		$	41,953		$	154,165		$	131,440		$	235,567		$	175,756		$	206,158		$	383,626		$	278,064

(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" beginning on page 48.

Table of Contents

	As of December 31,

	As of December 31,				As of September 30, 2011		Pro Forma As of September 30, 2011
	2009		2010		As of September 30, 2011		Pro Forma As of September 30, 2011
	(In thousands)
Balance sheet data:
Cash and cash equivalents	$	88,457	$	75,162	$	18,765	$	18,766
Net property, plant and equipment		861,204		864,645		1,145,544		1,145,544
Total assets		1,138,999		1,067,131		1,374,766		1,371,767
Long-term debt		243,000		203,205		385,000		108,000
Total owners'/stockholders' equity		526,244		475,531		530,579		704,580

				Dynamic Offshore Holding, LP

	Predecessor			Dynamic Offshore Holding, LP
	Predecessor			Years Ended December 31,									Nine Months Ended September 30,
	January 1, 2008 Through March 13, 2008			Years Ended December 31,									Nine Months Ended September 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		$	173,704		$	37,796		$	157,656		$	139,553		$	156,602
Net cash provided by (used in) investing activities		(3,627	)		(431,423	)		62,075			(94,605	)		(113,576	)		(296,676	)
Net cash provided by (used in) financing activities		—			309,749			(63,589	)		(76,346	)		5,823			83,677

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	$	139,726	$	196,629
Other operating revenues		2,482		3,449

		142,208		200,078
Direct operating expenses		46,565		44,615

Excess of revenues over direct operating expenses	$	95,683	$	155,463

Non-GAAP Financial Measure

Adjusted EBITDA

Table of Contents

•: 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.

•: 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.

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,									Nine Months Ended September 30,
																					Nine Months Ended September 30, 2011
																		Year Ended December 31, 2010
			2008			2009			2010			2010			2011			Year Ended December 31, 2010
	(In thousands)
Reconciliation of net income (loss) to Adjusted EBITDA:
Net income (loss)	$	27,620	$	219,294		$	98,735		$	(14,162	)	$	59,938		$	149,608		$	25,352		$	123,302
Interest expense, net		34		2,492			7,138			13,541			10,688			6,409			12,123			4,324
Income tax expense (benefit)		—		14,738			(20,387	)		(14,814	)		(4,344	)		(1,544	)		14,719			66,387
Depreciation, depletion and amortization		13,414		49,648			88,573			195,122			96,205			102,417			271,568			132,289
Unrealized (gain) loss on commodity derivatives		—		(146,671	)		97,975			36,181			7,043			(67,507	)		36,181			(67,507	)
Other operating expense		885		14,561			20,757			22,643			10,250			16,629			26,627			19,123
Bargain purchase gain		—		—			(161,351	)		(4,024	)		(4,024	)		—			(4,024	)		—
Other		—		103			—			1,080			—			146			1,080			146

Adjusted EBITDA	$	41,953	$	154,165		$	131,440		$	235,567		$	175,756		$	206,158		$	383,626		$	278,064

Reconciliation of net cash provided by operating activities to Adjusted EBITDA:
Net cash provided by operating activities	$	22,836	$	173,704		$	37,796		$	157,656		$	139,553		$	156,602
Derivative settlements		—		13,268			76,088			43,171			36,881			(5,618	)
Interest expense, net		34		2,492			7,138			13,541			10,688			6,409
Exploration expense		—		80			8,999			2,100			1,736			7,285
Amortization in interest expense, net		—		315			219			(287	)		(332	)		(291	)
Current income tax expense		—		—			(2,188	)		—			—			—
Changes in operating assets and liabilities		18,978		(45,784	)		(1,299	)		19,156			(10,806	)		41,178
Other		105		10,090			4,687			230			(1,964	)		593

Adjusted EBITDA	$	41,953	$	154,165		$	131,440		$	235,567		$	175,756		$	206,158

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" beginning on page 20 and "Cautionary Note Regarding Forward-Looking Statements" beginning on page 41.

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 July 31, 2011, our estimated net proved reserves were 60.1 MMBoe, of which 50% was oil and 81% was proved developed, with an associated PV-10 of approximately $1.7 billion, based on SEC pricing of $88.44 per Bbl for oil and $4.19 per MMBtu for natural gas. As of that same date, our estimated net probable reserves were 16.0 MMBoe with an associated PV-10 of approximately $370.1 million. Please read "Prospectus Summary—Summary Historical Operating and Reserve Data—Summary Reserve Data" beginning on page 15 for information on our estimated net proved and probable reserves, PV-10 and related pricing. During November 2011, our properties had aggregate average net daily production in excess of 27,000 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 ten material acquisitions. For example, we recently acquired substantially all of the Gulf of Mexico assets that Exxon acquired as part of its acquisition of XTO Energy Inc. in 2010 and completed an acquisition from MOR of 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.

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"

Table of Contents

beginning on page 70, "—XTO Acquisition" beginning on page 72 and "—MOR Transaction" beginning on page 73.

Acquisition	Acquisition Date	Major Fields

SPN Resources(2)	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(2)	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	May 2011	High Island 52, Ship Shoal 301		2.1
XTO	August 2011	South Marsh Island 41, West Cameron 485/507		13.5
MOR	September 2011	South Pass 60, West Delta 79/80	(3)	3.4

(1): Based on reserve reports or our internally generated reserve estimates prepared at or near the acquisition date.
(2): Includes interests subsequently acquired from Superior in exchange for a 10% equity interest in us.
(3): We acquired from MOR the remaining 25% interest in the properties that we acquired from SPN Resources in 2008.

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.

We have accounted for the MOR Transaction as a transaction between entities under common control because of our relationship with the Riverstone/Carlyle Funds, which also control (as defined in the accounting standards codification master glossary) the Moreno Group companies. Transfers of net assets between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information similar to the pooling method.

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 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

Table of Contents

may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments" beginning on page 20.

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 $102.59 and $92.19 per Bbl and $3.78 and $2.99 per MMBtu during the period from November 1, 2011 to December 31, 2011. At December 31, 2011, the NYMEX oil price and NYMEX natural gas price were $98.83 per Bbl and $3.10 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,						Nine Months Ended September 30,

		2008		2009		2010		2010		2011
Average sales prices:
	Oil, without realized derivatives ($/Bbl)		103.80		62.64		78.65		76.37		106.23
	Natural gas, without realized derivatives ($/Mcf)(1)		10.12		4.23		4.72		4.87		4.74
	Oil, with realized derivatives ($/Bbl)		113.65		89.95		86.35		86.32		99.85
	Natural gas, with realized derivatives ($/Mcf)(1)		10.10		5.89		5.68		5.76		5.48
	Oil, WTI benchmark ($/Bbl)		99.75		62.09		79.61		77.69		95.47
	Natural gas, Henry Hub benchmark ($/MMBtu)		8.90		4.16		4.38		4.52		4.21

(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 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" beginning on page 66.

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 September 30, 2011, the average realized price before the effect of commodity derivative contracts for our oil production was $104.91 per Bbl, compared to an average WTI forward index price of $89.54 per Bbl for the same period.

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,						Nine Months Ended September 30,

		2008		2009		2010		2010		2011
Net sales volumes:
	Oil (MBbls)		1,363		2,145		3,289		2,447		2,559
	Natural gas (MMcf)		6,692		10,555		18,468		14,086		14,482

	Total (MBoe)		2,478		3,904		6,367		4,795		4,973

	Average net daily production (Boe/d)		6,770		10,696		17,444		17,564		18,216

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

•: 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

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" beginning on page 13.

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" beginning on page 22.

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" beginning on page 56.

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

		Year Ended December 31,						Nine Months Ended September 30,

		2008		2009		2010		2010		2011
Costs and expenses ($/Boe):
	Lease operating expense(1)		14.82		15.53		14.04		13.25		15.89
	Depreciation, depletion and amortization		20.04		22.69		30.65		20.06		20.59
	General and administrative expense		7.20		6.57		3.82		4.02		3.89

(1): Our lease operating expenses do not include the effects of insurance costs. For more detail about our aggregate insurance costs, please read the operating expense information contained within Note 3 to the audited consolidated financial statements of Dynamic Offshore Holding, LP.

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.

Table of Contents

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.

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 include field personnel compensation, production and ad valorem taxes, utilities, maintenance, and repair expenses related to our oil and natural gas properties. We do not believe that the amounts of production and ad valorem taxes that we incur are material to our operations.

On a field-by-field basis, we do not expect personnel costs to change significantly in the near term. Transportation and equipment rental expenses depend on the level of demand for these services, which we cannot predict. Costs for fuel, lubricants and chemicals are expected to fluctuate with the price of crude oil.

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. Following this offering and giving effect to the discontinuance of our management fee payments, we anticipate incurring incremental general and administrative expenses of approximately $0.4 million per year (not including non-cash costs related to incremental executive compensation) related to being a publicly traded company. We currently pay to an affiliate of Riverstone an annual monitoring fee capped at $1.5 million. We anticipate that, although the requirement to pay the monitoring fee will be discontinued in connection with this offering, that portion of our annual general and administrative expenses will be replaced with costs of being a publicly traded company.

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.

Table of Contents

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.

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 that are not currently subject to entity-level taxation and a corresponding expense will be recorded to net income. We estimate the incremental net deferred tax liability to be approximately $103.0 million.

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,									Nine Months Ended September 30,

		2008(1)			2009			2010			2010			2011
											(unaudited)
		(In thousands)
Oil and gas revenues		$	209,219		$	178,992		$	345,812		$	255,496		$	340,541
Other operating revenues			1,695			2,017			12,815			7,770			11,926

			210,914			181,009			358,627			263,266			352,467
Operating expenses:
	Lease operating expense		36,725			60,618			89,399			63,511			78,998
	Exploration expense		80			8,999			2,100			1,736			7,285
	Depreciation, depletion and amortization		49,648			88,573			195,122			96,205			102,417
	General and administrative expense		17,843			25,655			24,328			19,280			19,328
	Insurance expense		14,315			32,688			36,677			29,121			26,323
	Workover expense		1,134			6,696			15,827			12,479			16,042
	Accretion expense		4,494			7,211			13,183			9,630			8,897
	Casualty loss (gain), net		10,000			—			(3,380	)		(2,363	)		(208	)
	Loss (gain) on abandonments		—			4,687			2,601			1,550			2,486
	Loss (gain) on sale of assets		—			(140	)		8,139			(303	)		—
	Other		(13	)		—			—			—			(1,831	)

			134,226			234,987			383,996			230,846			259,737

Income (loss) from operations			76,688			(53,978	)		(25,369	)		32,420			92,730
Other income (expense):
	Interest expense, net		(2,492	)		(7,138	)		(13,541	)		(10,688	)		(6,409	)
	Commodity derivative income (expense)		159,939			(21,887	)		6,990			29,838			61,889
	Bargain purchase gain		—			161,351			4,024			4,024			—
	Other		(103	)		—			(1,080	)		—			(146	)

Income (loss) before income taxes			234,032			78,348			(28,976	)		55,594			148,064
Income tax benefit (expense)			(14,738	)		20,387			14,814			4,344			1,544

Net income (loss)			219,294			98,735			(14,162	)		59,938			149,608
Less: Net income (loss) attributable to noncontrolling interests			34,648			57,663			(4,070	)		10,184			460

Net income (loss) attributable to Dynamic Offshore Holding, LP		$	184,646		$	41,072		$	(10,092	)	$	49,754		$	149,148

Adjusted EBITDA(2)		$	154,165		$	131,440		$	235,567		$	175,756		$	206,158

(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" beginning on page 46.
(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" beginning on page 13.

Table of Contents

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Oil and gas revenues. Oil and gas revenues increased $85.0 million, or 33%, to $340.5 million for the nine months ended September 30, 2011 as compared to the same period in 2010. Higher realized commodity prices in 2011 accounted for $74.5 million of this increase, and higher production volumes accounted for $10.5 million of the increase.

Oil production increased 0.4 MBbl per day, or 5%, to 9.4 MBbl per day for the nine months ended September 30, 2011 as compared to the same period in 2010. Production from acquisitions subsequent to September 30, 2010 increased production by 0.9 MBbl per day, partially offset by a net 0.5 MBbl per day decrease comprising: (i) a 0.3 MBbl per day increase due to the resumption of operations at fields affected by hurricanes; (ii) a 0.4 MBbl per day decrease due to gas pipeline problems, which limited a field's ability to produce oil, of which we expect the gas pipeline repairs to be completed before the end of the year; and (iii) normal production and other declines.

Natural gas production increased 1.5 MMcf per day, or 3%, to 53.0 MMcf per day for the nine months ended September 30, 2011 as compared to the same period in 2010. Production from acquisitions subsequent to September 30, 2010 increased production by 9.6 MMcf per day, while production from existing fields decreased 8.2 MMcf per day. The net decrease in production from existing fields consisted of: (i) a 5.4 MMcf per day decrease due to the gas pipeline problems discussed previously; (ii) a 4.1 MMcf per day increase due to the resumptions of operations at fields affected by hurricanes; (iii) a 2.4 MMcf per day decrease due to a field shut-in for the installation of compression facilities, which we have subsequently sold our interest in the property; and (iv) normal production and other declines.

Other operating revenues. Other operating revenues increased $4.2 million, or 53%, to $11.9 million for the nine months ended September 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 $15.5 million, or 24%, to $79.0 million for the nine months ended September 30, 2011 as compared to the same period in 2010. Higher costs primarily for transportation, fuel and chemicals and repairs and maintenance increased lease operating expense by $6.5 million. Incremental production from our acquisitions resulted in a $9.0 million increase in lease operating expense. On a per unit basis, lease operating costs increased to $15.89 per Boe for the nine months ended September 30, 2011 versus $13.25 per Boe for the nine months ended September 30, 2010.

Exploration expense. Exploration expense increased by $5.5 million to $7.3 million for the nine months ended September 30, 2011 as compared to the same period in 2010, primarily driven by exploratory dry hole costs of $6.1 million for the nine months ended September 30, 2011.

Depreciation, Depletion and Amortization. DD&A increased $6.2 million, or 6%, to $102.4 million for the nine months ended September 30, 2011 as compared to the same period in 2010. The increase was attributable to our oil and gas depletion, primarily related to our acquisitions of Samson and XTO (which accounted for $11.7 million of the increase) and in connection with our Ship Shoal 166/167 field, which reached its economic limit after mechanical problems forced us to shut in production (with the associated reserve revision accounting for $10.0 million of the increase), partially offset by a $17.1 million decrease due to the gas pipeline problems previously discussed.

Workover expense. Workover expense increased $3.6 million to $16.0 million for the nine months ended September 30, 2011 as compared to $12.5 million for the same period in 2010, primarily as a result of increased workover activity levels.

Table of Contents

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

Oil and gas revenues. Oil and gas sales revenues increased $166.8 million, or 93%, to $345.8 million for 2010 as compared to 2009. Average daily production increased by 6,748 Boe per day, or 63%, to 17,444 Boe per day, resulting in an increase in revenue of $105.1 million, primarily as a result of acquisitions. In addition, higher realized commodity prices in 2010 increased our oil and natural gas revenues by $61.7 million.

Other operating revenues. Other operating revenues increased $10.8 million to $12.8 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 $28.8 million, or 47%, to $89.4 million for 2010 compared to 2009 due to incremental production from our acquisitions. On a per unit basis, lease operating costs decreased to $14.04 per Boe for 2010 versus $15.53 per Boe for 2009, primarily due to lower per unit costs on our Bandon acquisition in October 2009 and our 2010 acquisitions.

Exploration expense. Exploration expense decreased $6.9 million to $2.1 million for 2010 as compared to 2009. The higher exploration expense in 2009 was primarily due to $4.6 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 $106.5 million, or 120%, to $195.1 million for 2010 as compared to 2009. The increase was attributable to our oil and gas depletion, primarily due to increased production, which accounted for $50.2 million of the increase and a higher per Boe DD&A rate, which accounted for $6.6 million of the increase. Impairments of $60.5 million for the year ended December 31, 2010 consisted primarily of: (i) $16.4 million at the West Cameron 598/599 field due to an election not to drill a proved undeveloped location when new seismic interpretation and lower gas prices yielded less reserves than previously mapped; (ii) $15.8 million at the Ship Shoal 166/167 field where a recompletion did not perform as expected, leading to reduced economics on other planned workovers in the field; (iii) $5.6 million at the Vermilion 261 field and $2.0 million at the East Cameron 320 field due to steeper production rate declines than previously forecast; and (iv) $11.9 million at the South Marsh Island 142 field and $3.8 million at the West Cameron 432 field due to downhole mechanical problems.

Workover expense. Workover expense increased $9.1 million to $15.8 million in 2010 as compared to $6.7 million in 2009, primarily as a result of increased workover activity levels following our acquisitions.

Accretion expense. Accretion expense increased $6.0 million, or 83%, to $13.2 million for 2010 as compared to $7.2 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 $6.4 million, or 90%, to $13.5 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.

Table of Contents

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 $30.2 million, or 14%, to $179.0 million for 2009 as compared to 2008. Lower commodity prices in 2009, which resulted in a $150.5 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 3,926 Boe per day, or 58%, to 10,696 Boe per day in 2009, resulting in an increase in revenue of $120.3 million. The increase in average daily production sold was primarily due to acquisitions.

Lease operating expense. Lease operating expense increased $23.9 million, or 65%, to $60.6 million for 2009 as compared to 2008, due to incremental production from our acquisitions. On a per unit basis, lease operating costs increased to $15.53 per Boe for 2009 versus $14.82 per Boe for 2008.

Exploration expense. Exploration expense increased $8.9 million in 2009 as compared to 2008. The increase consists of $6.6 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.

Depreciation, depletion and amortization. DD&A increased $38.9 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, which accounted for $24.3 million of the increase and a higher per Boe DD&A rate, which accounted for $10.4 million of the increase. Our per unit rate increase was primarily due to the full-year effect of the Northstar acquisition on our composite per unit rate. In addition, asset impairments of $3.8 million contributed to the increase.

General and administrative expense. General and administrative expense increased $7.8 million, or 44%, to $25.7 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 $5.6 million to $6.7 million in 2009 as compared to $1.1 million in 2008, primarily as a result of increased activity levels following our acquisitions.

Accretion expense. Accretion expense increased $2.7 million, or 60%, to $7.2 million in 2009 as compared to $4.5 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 $18.4 million to $32.7 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 $10.0 million. In 2008, we satisfied our deductible requirement and recorded a casualty loss of $10.0 million. We did not have a casualty loss in 2009.

Table of Contents

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 $4.6 million, or 186%, to $7.1 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 approximately $28.2 million of our indebtedness during the first nine months of 2011 and made distributions to our equity owners of $94 million from inception to September 30, 2011. In addition, as of the date of this prospectus, we have made total distributions to our equity owners of $137 million. At September 30, 2011, we had a working capital surplus of approximately $24.5 million. Our working capital fluctuates for various reasons, including the fair value of our commodity derivative instruments. 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 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 $430 million borrowing base, of which $385 million was outstanding as of September 30, 2011. In addition, up to $100 million of the borrowing base is available for the issuance of letters of credit.

Our borrowing base is 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 initial borrowing base of $105 million and

Table of Contents

$25 million, respectively. Following the closing of the XTO Acquisition and the MOR Transaction, our borrowing base increased from $300 million to $430 million. On November 7, 2011, the lenders under our credit facility reaffirmed the borrowing base of $430 million. As of September 30, 2011, after giving effect to the application of the net proceeds of this offering, we would have had approximately $108.0 million outstanding under our revolving credit facility, with additional availability of approximately $322.0 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;
•: 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 September 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 $71.5 million has been spent through September 30, 2011.

Table of Contents

We expect that our 2012 budget for capital expenditures will be between $200 and $250 million, which is less than our projected cash flow for 2012. As part of our capital expenditure plan, we expect to drill between 12 and 16 wells during 2012, including between 3 and 6 wells included in the XTO Acquisition Properties.

In connection with our 2012 drilling program, we have contracted for one jackup drilling rig, with the option to extend into 2013, and one platform rig for use at the Bullwinkle field. In addition to this capital expenditure program, we expect to continue to pursue a proactive P&A program by removing inactive platforms, wellbores and pipelines in advance of legal requirements.

Other than our rig commitments and legal P&A requirements, our capital expenditure budget and P&A activities are subject to a substantial amount of discretion. As a result, we may reduce our expected spending, including if we experience sustained oil and natural gas prices significantly below current levels, failures to obtain necessary permits or partner approvals, operational problems that extend the time and cost required to complete projects, acquisition opportunities that may divert our attention or capital resources, weather delays or substantial increases in our costs. To the extent our cash flow from operations is not sufficient to meet our funding needs, we would consider funding our capital expenditures with borrowings under our credit facility or capital markets transactions.

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,									Nine Months Ended September 30,

	2008			2009			2010			2010			2011
Net cash provided by operating activities	$	173,704		$	37,796		$	157,656		$	139,553		$	156,602
Net cash provided by (used in) investing activities		(431,423	)		62,075			(94,605	)		(113,576	)		(296,676	)
Net cash provided by (used in) financing activities		309,749			(63,589	)		(76,346	)		5,823			83,677

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 $17.0 million for the nine months ended September 30, 2011 compared to the same period in 2010, primarily due to higher realized commodity prices and higher production related to acquisitions.

Net cash provided by operating activities increased $119.9 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 $135.9 million in 2009 compared to 2008, primarily due to lower commodity prices in 2009.

Cash flows provided by (used in) investing activities. The $183.1 million increase in cash used in investing activities from the nine months ended September 30, 2010 to the nine months ended September 30, 2011 was primarily a result of our acquisitions and derivative settlements. In the nine months ended September 30, 2011, our acquisitions resulted in our paying net cash of $219.6 million compared to 2010 when our acquisitions resulted in our paying net cash of $100.1 million. Net

Table of Contents

derivative settlement losses were $5.6 million for the nine months ended September 30, 2011, compared to settlement gains of $36.9 million for the same period in 2010.

The $156.7 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 $493.5 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 $376.7 million for our acquisitions (net of $32.5 million cash acquired).

Cash flows provided by financing activities. The $77.9 million increase in cash provided by financing activities from the nine months ended September 30, 2010 to the nine months ended September 30, 2011 was primarily a result of the $333.0 million increase in borrowings under our revolving credit facility, partially offset by the $120.0 million increase in repayments of borrowings outstanding under our revolving credit facility, the $58.2 million increase in repayments of the Bandon term loan, and the $68.0 million payment to MOR for our purchase of the remaining 25% working interest in the properties that we acquired from SPN Resources in 2008, which was accounted for as a transfer of assets under common control.

The $12.8 million increase in cash used in financing activities from 2009 to 2010 is primarily a result of the $32.2 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 $373.3 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 $229.0 million of contributions from our equity owners in 2008, compared with $22.3 million contributed in 2009. In 2009, we also 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" below 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.

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)		318,065		61,948		9,933		73,948		172,776

Total	$	550,202	$	73,380	$	168,510	$	136,076	$	172,776

(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" beginning on page 62. As of September 30, 2011, our outstanding balance was $385 million. At the current interest rate of 3.1% and commitment fee rate of 0.5%, our interest expense on the outstanding balance as of September 30, 2011 would be $3.1 million for the remainder of 2011, $12.2 million for each of the years ending December 31, 2012, 2013 and 2014 and $5.7 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.

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.

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

Table of Contents

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 actively monitor our hedge portfolio to support our cash flow objectives.

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

				Year Ending December 31,

				2011		2012		2013
Crude oil:
	Swaps (Bbl)				362,000		1,662,000		1,250,000
		Average WTI price ($/Bbl)			88.48		91.86		100.47
	Collars (Bbl)				90,000		418,000		168,000
		Average WTI price ($/Bbl)
			Floor price (put)		65.00		82.99		80.00
			Ceiling price (call)		87.90		108.51		102.50
	LLS-WTI Differential Spread (Bbl)				615,000		2,300,000		—
		Average price ($/Bbl)			20.03		17.17		—
Natural gas:
	Swaps (MMBtu)				880,000		3,630,000		—
		Average NYMEX price ($/MMBtu)			5.92		6.16		—
	Collars (MMBtu)				1,139,000		8,115,000		6,000,000
		Average NYMEX price ($/MMBtu)
			Floor price (put)		5.26		4.08		3.75
			Ceiling price (call)		7.83		6.62		6.65

Interest Rate Risk

As of September 30, 2011, we had total debt outstanding of $385 million, accruing interest at a variable rate, which was 3.1% (a variable rate of 0.35% plus an applicable margin of 2.75%) 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 approximately $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 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

Table of Contents

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 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

Table of Contents

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.

Table of Contents

BUSINESS

Overview

As of July 31, 2011, our estimated net proved reserves were 60.1 MMBoe, of which 50% was oil and 81% was proved developed, with an associated PV-10 of approximately $1.7 billion, based on SEC pricing of $88.44 per Bbl for oil and $4.19 per MMBtu for natural gas. As of that same date, our estimated net probable reserves were 16.0 MMBoe with an associated PV-10 of approximately $370.1 million. Please read "Prospectus Summary—Summary Historical Operating and Reserve Data—Summary Reserve Data" beginning on page 15 for information on our estimated net proved and probable reserves, PV-10 and related pricing. During November 2011, our properties had aggregate average net daily production in excess of 27,000 Boe per day.

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 ten 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 $123 million in aggregate distributions from cash flows, for a net investment of $102 million. Over this same period, we have incurred a total of $555 million in debt, with $365 million of debt outstanding and $59 million of cash and cash equivalents as of December 31, 2011. As a result of these acquisitions and our operations, PV-10 of our proved oil and natural gas reserves totaled approximately $1.7 billion as of July 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, on August 31, 2011, we acquired substantially all of the Gulf of Mexico assets that Exxon acquired as part of its acquisition of XTO Energy Inc. in 2010. Please read "—XTO Acquisition" beginning on page 72. 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.

Table of Contents

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

				As of Acquisition Date(1)

Acquisition	Acquisition Date	Major Fields		Net Proved Reserves (MMBoe)		% Oil			% Proved Developed
SPN Resources(2)	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(2)	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	May 2011	High Island 52, Ship Shoal 301			2.1		12	%		100	%
XTO	August 2011	South Marsh Island 41, West Cameron 485/507			13.5		39	%		72	%
MOR	September 2011	South Pass 60, West Delta 79/80	(3)		3.4		65	%		92	%

(1): Based on reserve reports or our internally generated reserve estimates prepared at or near the aquisition date.
(2): Includes interests subsequently acquired from Superior in exchange for a 10% equity interest in us.
(3): We acquired the remaining 25% working interest in the properties that we acquired from SPN Resources in 2008.

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.
•: 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

Table of Contents

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.
•: In August 2011, we acquired the Gulf of Mexico assets previously owned by XTO Energy, Inc., for approximately $182.5 million. Proved reserves associated with the acquired properties are composed of approximately 13.5 MMBoe, 39% of which were oil. Please read "—XTO Acquisition" below.
•: In September 2011, we acquired the remaining 25% interest in the SPN Resources properties from Moreno Offshore Resources for $68 million. Proved reserves associated with the acquired properties are composed of approximately 3.4 MMBoe, 65% of which were oil and 92% of which were developed. The consolidated interests were substantially all comprised of operated properties, including several major fields. Please read "MOR Transaction" beginning on page 73.

XTO Acquisition

On August 31, 2011, we acquired from XTO Offshore Inc., HHE Energy Company and XH, LLC, each an indirect subsidiary of Exxon, certain oil and natural gas interests in the Gulf of Mexico for approximately $182.5 million (the "XTO Acquisition"). The properties 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.

Table of Contents

Please read "—Our Operations" beginning on page 79.

MOR Transaction

On September 14, 2011, we acquired directly from a subsidiary of Moreno Offshore Resources, LLC ("MOR") for $68.0 million 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 July 31, 2011, MOR's 25% working interest represented approximately 3.4 MMBoe of proved reserves, of which approximately 65% was oil, and 0.3 MMBoe of probable reserves. As of that same date, the PV-10 of the proved oil and natural gas reserves was approximately $104.2 million, and the PV-10 of the probable oil and natural gas reserves associated with MOR's working interest was approximately $10.7 million, in each case based on SEC pricing of $88.44 per Bbl for oil and $4.19 per MMBtu for natural gas. At the time of acquisition, net production attributable to MOR's 25% working interest during August 2011 was approximately 1,300 Boe/d. We currently operate substantially all of the properties we acquired in the MOR Transaction.

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 270 net productive wells. As of July 31, 2011, our total estimated net proved reserves were approximately 60.1 MMBoe, of which 50% was oil and 81% was proved developed. We operate more than 90% of our assets, based on PV-10 as of July 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" beginning on page 23.

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. For example, we have recently begun preliminarily exploring options to pursue acquisition opportunities in the North Sea, which we believe represents an attractive market for acquisitions, similar to the Gulf of Mexico. 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.

Table of Contents

Our Significant Fields

In the aggregate, our six largest fields accounted for approximately 66% of the PV-10 of our proved oil and natural gas reserves as of July 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 1,745 Boe/d for the month ended November 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. In 2011, we engaged in an active multi-well workover and recompletion program which we intend to complete in 2012. We have identified multiple drilling opportunities in the field and intend to drill five wells in 2012, with additional drilling possible in future years.

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.

South Marsh Island 41 field: We own a 100% working interest and serve as operator in the South Marsh Island 41 field. The South Marsh Island 41 field is located in approximately 100 feet of water and encompasses all of South Marsh Island blocks 40, 41, 44 and 45. Cumulative production from our South Marsh Island 41 field from first production in 1967 through April 2011 totaled approximately 14 MMBbls of oil and 87 Bcf of natural gas. Our 10 wells in the South Marsh Island 41 field produced net to our interest at an average rate of 1,835 Boe/d for the month ended November 30, 2011.

In the South Marsh Island 41 field, we primarily target the PA1 and PA2 sands, which are at depths of 9,500 feet to 10,300 feet. The reservoirs primarily exhibit a strong water drive and a faulted salt dome. We own an aggregate of 17,500 gross (12,500 net) acres in the field. We have identified significant recompletion and drilling opportunities in the field.

South Pass 60 field: We own a 100% 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 64 wells producing to eight 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 64 wells in the South Pass 60 field produced net to our interest at an average rate of 2,208 Boe/d for the month ended November 30, 2011.

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 and net acres in the field. During 2011, we conducted 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. In 2012, we plan to initiate two waterfloods and conduct a two well recompletion program.

West Delta 79/80 field: We own a 100% 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 five 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 1,395 Boe/d for the month ended November 30, 2011.

In the West Delta 79/80 field, we primarily target the G sands. The reservoirs primarily exhibit moderate to strong water drive and fault and anticline traps. We own an aggregate of 9,375 gross and net acres in the field. During 2011, we conducted recompletion operations on two wells. We believe that the field will support multiple wells. In 2012, we plan to conduct a seven well recompletion program.

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 1,685 Boe/d for the month ended November 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 conducted recompletion operations on three wells and conducted three acid jobs. In 2012, we plan to conduct two recompletions in this field.

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 four 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 830 Boe/d for the month ended November 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. In 2011, we performed several facility upgrades in the field, which resulted in improved production. In 2012, we plan to conduct a four well recompletion program.

Table of Contents

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

			As of July 31, 2011

Field	Acquired From	Operator	Average Working Interest			% Oil of Proved Reserves			November 2011 Average Net Daily Production (Boe/d)
Bullwinkle	Shell	Dynamic		49	%		84	%		1,745
South Marsh Island 41	XTO	Dynamic		100	%		90	%		1,835
South Pass 60	SPN	Dynamic		100	%		84	%		2,208
West Delta 79/80	SPN	Dynamic		100	%		65	%		1,395
Vermilion 362-371	Beryl	Dynamic		67	%		35	%		1,685
Vermilion 272	Samson	Dynamic		100	%		85	%		830

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 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 acquired from Moreno Offshore Resources, LLC the remaining interests in the properties we previously acquired from SPN Resources in 2008. Please read "—Business—MOR Transaction" beginning on page 73. 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

Table of Contents

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 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 ten material acquisitions, creating significant value relative to the capital employed. 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 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 approximately 830,000 gross (490,000 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 July 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.

Table of Contents

•: 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 September 30, 2011, after giving effect to the application of the net proceeds of this offering, we would have had approximately $108.0 million outstanding under our revolving credit facility, with additional availability of approximately $322.0 million. Please read "—XTO Acquisition" beginning on page 72, "—MOR Transaction" beginning on page 73 and "Prospectus Summary—Recent Developments—Borrowing Base Increases and Debt Repayment; Distributions to Equity Owners" beginning on page 8. 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 July 31, 2011, our estimated net proved reserves were composed of approximately 50% 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 September 30, 2011, the average realized price before the effect of commodity derivative contracts for our oil production was $104.91 per Bbl, compared to an average WTI index price of $89.54 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, management and other employees have a meaningful economic interest in us, which is expected to total approximately 10.1% of our common stock following the completion of this offering, thereby aligning management's interests with those of our stockholders.
•: Affiliation with Riverstone. Investment funds managed by Riverstone have significant energy and financial expertise to complement their investment in us. To date, affiliates of Riverstone and the Carlyle Group (such affiliates, the "Riverstone/Carlyle Funds") have 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, the Riverstone/Carlyle Funds will own an approximate 52.3% interest in us. While 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, Riverstone is under no obligation to provide us with such access and is likely to do so only to the extent such access would prove beneficial to Riverstone. In addition, we have renounced our interest in certain business opportunities that may be presented to Riverstone and its affiliates. Further, affiliates of Riverstone currently have, and may make in the future, investments in other similar companies that compete with us. Please read "Certain Related Party Transactions—Riverstone/Carlyle Funds Investments in Dynamic" beginning on page 126.

Table of Contents

•: 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" beginning on page 128 and "Description of Capital Stock—Corporate Opportunity" beginning on page 138.

Our Operations

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 July 31, 2011 for our estimated net proved and probable oil and natural gas reserves and for the estimated net proved and probable oil and natural gas reserves that we acquired in the MOR Transaction 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 estimates of the net proved and probable oil and natural gas reserves that we acquired in the XTO Acquisition at July 31, 2011 presented in the tables below are based, in part, on reports prepared by NSAI for the XTO Acquisition 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 for the XTO Acquisition are based on estimates prepared by our internal engineers.

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.

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 July 31, 2011

			At December 31, 2010(1)			At July 31, 2011
			At December 31, 2010(1)			Dynamic(2)			XTO			Total
Reserve Data(3):
Estimated proved reserves:
	Oil (MMBbls)			18.5			24.6			5.2			29.8
	Natural gas (Bcf)(4)			91.3			131.8			49.8			181.6
		Total estimated proved reserves (MMBoe)(5)		33.7			46.6			13.5			60.1
	Proved developed:
		Oil (MMBbls)		15.0			19.5			4.4			24.0
		Natural gas (Bcf)		80.7			116.1			32.0			148.0
		Total (MMBoe)		28.5			38.9			9.8			48.7
		Percent proved developed		85	%		84	%		72	%		81	%
	Proved undeveloped:
		Oil (MMBbls)		3.4			5.1			0.8			5.9
		Natural gas (Bcf)		10.5			15.7			17.9			33.6
		Total (MMBoe)		5.2			7.7			3.8			11.5
PV-10 of proved reserves (in millions)(6)			$	947.7		$	1,381.5		$	328.5		$	1,710.0
Standardized Measure (in millions)(6)			$	1,184.5			n/a			n/a			n/a
Estimated probable reserves:
	Oil (MMBbls)			4.6			4.7			1.5			6.2
	Natural gas (Bcf)(4)			49.0			25.6			33.3			58.9
		Total estimated probable reserves (MMBoe)		12.7			9.0			7.0			16.0
PV-10 of probable reserves (in millions)(6)			$	285.1		$	282.7		$	87.4		$	370.1

(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): Includes interests acquired in the MOR Transaction.
(3): Our estimated proved and probable reserves and related future net revenues and PV-10 at December 31, 2010 and July 31, 2011 and Standardized Measure at December 31, 2010 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 $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, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead on a historical basis.
(4): Includes NGL volumes, which we do not believe are significant.
(5): One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency.
(6): For more information about our PV-10 and Standardized Measure, please read "Prospectus Summary—Summary Historical Operating and Reserve Data—PV-10 and Standardized Measure" beginning on page 17.

Our proved reserves at July 31, 2011 were 60.1 MMBoe, a 78.3% increase from reserves of 33.7 MMBoe at December 31, 2010. Our proved developed reserves increased 20.0 MMBoe, or 70.2%,

Table of Contents

to 48.7 MMBoe at July 31, 2011 from 28.5 MMBoe at December 31, 2010. In each case, the increases were due primarily to acquisitions.

Our proved reserves at December 31, 2010 were 33.7 MMBoe, a 39% increase from reserves of 24.3 MMBoe at December 31, 2009, based on our internal reserves estimates at December 31, 2009. Our estimated proved reserves increased 9.4 MMBoe during the year ended December 31, 2010 due primarily to acquisitions. Our proved developed reserves increased 8.2 MMBoe, or 40.4%, to 28.5 MMBoe at December 31, 2010 from 20.3 MMBoe at December 31, 2009 due primarily to acquisitions.

Price Sensitivity

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 (i) that NSAI's report for the properties acquired in the XTO Acquisition covers 84% of the present value of the total proved reserves acquired and (ii) 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. We believe that the use of forward prices provides investors with additional useful information about our reserves, as the forward prices are based on the market's forward-looking expectations of oil and natural gas prices as of a certain date. Investors should be careful to consider forward prices in addition to, and not as a substitute for, SEC prices, when considering our oil and natural gas reserves. The assumed lease and well operating costs included in the pricing sensitivity are based on our historical lease and well operating costs and have been held constant throughout the life of the properties. The assumed capital and abandonment costs were held constant to the date of the expenditure. Based on SEC pricing, the PV-10 of our proved oil and natural gas reserves was approximately $1.7 billion while, based on NYMEX forward pricing at July 22, 2011, as set forth below, the PV-10 of our proved oil and natural gas reserves was approximately $2.1 billion.

			At July 31, 2011

			Dynamic(1)		XTO		Total
Reserve Data(2):
Estimated proved reserves:
	Oil (MMBbls)			25.1		5.3		30.4
	Natural gas (Bcf)(3)			134.4		50.4		184.9
		Total estimated proved reserves (MMBoe)(4)		47.6		13.7		61.3
PV-10 of proved reserves (in millions)(5)			$	1,725.9	$	413.7	$	2,139.6
Estimated probable reserves:
	Oil (MMBbls)			4.8		1.5		6.3
	Natural gas (Bcf)(3)			27.5		37.4		64.9
		Total estimated probable reserves (MMBoe)		9.4		7.7		17.1
PV-10 of probable reserves (in millions)(5)			$	349.5	$	129.7	$	479.2

(1): Includes interests acquired in the MOR Transaction.
(2): Our 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. At July 22, 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,

Table of Contents

historical geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

(3): Includes NGL volumes, which we do not believe are significant.
(4): One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency.
(5): For more information about our PV-10 and Standardized Measure, please read "Prospectus Summary—Summary Historical Operating and Reserve Data—PV-10 and Standardized Measure" beginning on page 17.

The following table sets forth the estimated future net revenues, excluding derivatives contracts, from proved reserves, the PV-10, and the expected benchmark prices used in projecting net revenues at December 31, 2010 and July 31, 2011:

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

Future net revenues		$	1,197,797	$	2,166,055
Present value of future net revenues:
	PV-10($/thousands)	$	947,683	$	1,710,007
	After income tax (Standardized Measure)($/thousands)	$	1,184,518		n/a
	Benchmark oil price(2)($/Bbl)	$	79.40	$	88.44
	Benchmark natural gas price(2)($/MMBtu)	$	4.38	$	4.19

(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 and PV-10 at December 31, 2010 and July 31, 2011 and Standardized Measure at December 31, 2010 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 $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, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead on a historical basis.

Future net revenues represent projected revenues from the sale of proved reserves net of production and development costs (including operating expenses and production taxes). There can be no assurance that the proved reserves will be produced within the periods indicated or that prices and costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information and different reservoir engineers often arrive at different estimates for the same properties.

Proved Undeveloped Reserves

Our proved undeveloped reserves were 11.5 MMBoe at July 31, 2011, an increase of 121.2%, from 5.2 MMBoe at December 31, 2010, due primarily to acquisitions.

Our proved undeveloped reserves increased 1.2 MMBoe, or 30%, to 5.2 MMBoe at December 31, 2010 from 4.0 MMBoe at December 31, 2009, due primarily to acquisitions.

In the year ended December 31, 2010, we converted 991 MBbls of oil and 5,900 MMcf of natural gas, or 1,974 total MBoe, from proved undeveloped reserves into proved developed reserves at an investment cost of $22.4 million. For the period from January 1, 2011 through July 31, 2011, we converted 25 MBbls of oil and 12 MMcf of natural gas, or 27 total MBoe, from proved undeveloped reserves into proved developed reserves at an investment cost of $3.7 million. In total, we have converted 2,231 MBbls of oil and 8,451 MMcf of natural gas, or 3,640 total MBoe, from proved undeveloped reserves into proved developed reserves at an investment cost of $86.3 million.

Table of Contents

At July 31, 2011, we had total estimated future proved undeveloped reserves of 7,679 MBoe and estimated future net cash flows associated with production of $386.7 million. At July 31, 2011, for the period from August 1, 2011 through December 31, 2011, we had estimated future proved undeveloped reserves of 74 MBoe and estimated future net cash outflows associated with production of $14.5 million. At July 31, 2011, we had estimated future proved undeveloped reserves of 1,059 MBoe, 1,845 MBoe, 1,520 MBoe, 952 MBoe and 621 MBoe and estimated future net cash flows associated with production of $1.6 million, $101.2 million, $99.2 million, $57.9 million and $32.0 million for the years ending December 31, 2012, 2013, 2014 and 2015, respectively, and for the time period thereafter. Beginning in 2012 and thereafter, the production and cash flows represent the drilling results from the respective year plus the incremental effects of proved undeveloped drilling from the preceding years.

Historically, our drilling programs have been funded from our cash flows, and our expectation in the future is to continue to fund our drilling programs primarily from our cash flows. Based on our current expectations of our cash flows and drilling programs, which includes drilling of proved undeveloped and unproven locations, we believe that we can substantially fund from our cash flows and, if needed, our credit facility, the drilling of our current inventory of proved undeveloped locations in the next five years. As of December 31, 2010, we did not have any commitments to deliver fixed or determinable quantities of oil or natural gas.

Independent Petroleum Engineers

Our estimated reserves and related future net revenues and PV-10 at July 31, 2011, a substantial majority of the estimated reserves and related future net revenues and PV-10 at July 31, 2011 of the XTO Acquisition properties and the estimated reserves and future net revenues and PV-10 at July 31, 2011 of the MOR Transaction properties are each based on reports prepared by NSAI, our independent reserve engineers, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and current guidelines established by the SEC. A copy of each of these reports has been filed as an exhibit to the registration statement containing this prospectus.

Qualifications of Responsible Technical Persons—NSAI

NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-002699. Within NSAI, the technical person primarily responsible for preparing the estimates set forth in the NSAI letters, each of which is filed as an exhibit to the registration statement containing this prospectus, was Richard B. Talley, Jr., Vice President, Team Leader, and a consulting petroleum engineer. Mr. Talley is a Registered Professional Engineer in the State of Texas (License No. 102425). Mr. Talley joined NSAI in 2004 after serving as a Senior Engineer at ExxonMobil Production Company. Mr. Talley's areas of specific expertise include probabilistic assessment of exploration prospects and new discoveries, estimation of oil and gas reserves, and workovers and completions. Mr. Talley received an MBA degree from Tulane University in 2001 and a BS degree in Mechanical Engineering from University of Oklahoma in 1998. Mr. Talley meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Technology Used to Establish Proved and Probable Reserves

Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs from a given date forward, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right

Table of Contents

to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The term "reasonable certainty" implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Under SEC rules, probable reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered from a given date forward, and under existing economic conditions, operating methods, and government regulations prior to the time which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probalistic methods are used for the estimation.

In order to establish reasonable certainty with respect to our estimated proved reserves, NSAI employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved and probable reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data.

Internal Controls over Reserves Estimation Process

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to third-party reserve engineers in their reserves estimation process. Our Senior Vice President—Acquisitions & Engineering is the technical person primarily responsible for overseeing the preparation of our reserves estimates. He has over 29 years of industry experience with positions of increasing responsibility in engineering and evaluations and holds a BS degree in Petroleum Engineering. He reports directly to our President and Chief Executive Officer.

Throughout each fiscal year, our technical team meets with representatives of our independent reserve engineers to review properties and discuss methods and assumptions used in preparation of the proved reserves estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a preliminary copy of the reserve report is reviewed by our President and Chief Executive Officer with representatives of our independent reserve engineers and internal technical staff. Following the consummation of this offering, we anticipate that our audit committee will conduct a similar review on an annual basis.

In connection with our historical reserves as of December 31, 2010, we had fully engineered reserve reports prepared by independent third-party reserve engineers in accordance with the definitions and guidelines set forth in the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers rather than SEC definitions and guidelines. The reserve data included in this prospectus as of December 31, 2010 has been derived from these reports and modified by our internal technical staff to conform with the SEC definitions and guidelines and to reflect our net interest in the reserves.

Table of Contents

Production, Revenues and Price History

Oil and natural gas are commodities. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand for oil and natural gas in the United States has increased dramatically during this decade. However, the current economic slowdown reduced this demand during the second half of 2008 and through 2009. Demand for oil increased during 2010, but demand for natural gas remained sluggish. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or natural gas can result in substantial price volatility. Historically, commodity prices have been volatile and we expect that volatility to continue in the future. A substantial or extended decline in oil or natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access capital markets.

The following table sets forth information regarding oil and natural gas production, revenues and realized prices and production costs for the 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. For additional information on price calculations, please read information set forth in "Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 51.

		Historical												Pro Forma

		Predecessor		Dynamic Offshore Holding, LP
		January 1, 2008 Through March 13, 2008		Year Ended December 31,						Nine Months Ended September 30,						Nine Months Ended September 30, 2011
				Year Ended December 31,						Nine Months Ended September 30,				Year Ended December 31, 2010
				2008		2009		2010		2010		2011		Year Ended December 31, 2010
Operating data:
Net sales volumes:
	Oil (MBbls)		364		1,363		2,145		3,289		2,447		2,559		4,792		3,171
	Natural gas (MMcf)		2,575		6,692		10,555		18,468		14,086		14,482		33,403		20,521

	Total (MBoe)		793		2,478		3,904		6,367		4,795		4,973		10,359		6,591

	Average net daily production (Boe/d)		10,859		6,770		10,696		17,444		17,564		18,216		28,381		24,143

Average sales prices:
	Oil, without realized derivatives ($/Bbl)		96.72		103.80		62.64		78.65		76.37		106.23		78.42		106.41
	Natural gas, without realized derivatives ($/Mcf)		8.16		10.12		4.23		4.72		4.87		4.74		4.81		4.81
	Oil, with realized derivatives ($/Bbl)(1)		96.72		113.65		89.95		86.35		86.32		99.85		83.71		101.26	(2)
	Natural gas, with realized derivatives ($/Mcf)(1)		8.16		10.10		5.89		5.68		5.76		5.48		5.35		5.33
	Oil, WTI benchmark ($/Bbl)		96.25		99.75		62.09		79.61		77.69		95.47		79.61		95.47	(2)
	Natural gas, Henry Hub benchmark ($/MMBtu)		8.58		8.90		4.16		4.38		4.52		4.21		4.38		4.21
Costs and expenses ($/Boe):
	Lease operating expense(3)		11.09		14.82		15.53		14.04		13.25		15.89		12.18		14.96
	Depreciation, depletion and amortization		16.92		20.04		22.69		30.65		20.06		20.59		26.22		20.07
	General and administrative expense		2.87		7.20		6.57		3.82		4.02		3.89		2.35		2.93

(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.

Table of Contents

(2): For the three months ended September 30, 2011, the average realized price before the effect of commodity derivative contracts for our oil production was $104.91 per Bbl, compared to an average WTI index price of $89.54 per Bbl for the same period.
(3): Our lease operating expenses do not include the effects of insurance costs. For more detail about our aggregate insurance costs, please read the operating expense information contained within Note 3 to the audited consolidated financial statements of Dynamic Offshore Holding, LP.

For more information about the changes in production volumes, sales prices and costs and expenses, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations" beginning on page 58.

Productive Wells

The following table presents the total gross and net productive wells by oil or gas completion as of September 30, 2011:

	Oil				Natural Gas				Total

	Gross		Net		Gross		Net		Gross		Net
Total productive wells		274		171		204		102		478		273

Gross wells are the number of wells in which a working interest is owned and net wells are the total of our fractional working interests owned in gross wells.

Acreage

The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of September 30, 2011. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.

	Developed Acres				Undeveloped Acres(1)				Total Acres

	Gross		Net		Gross		Net		Gross		Net
Total acreage		699,957		380,513		128,698		110,127		828,654		490,640

(1): Leases covering our undeveloped gross acreage will expire at a rate of approximately 4% on a gross basis (2% net) in 2011, 32% on a gross basis (32% net) in 2012 and 45% on a gross basis (44% net) in 2013. As of July 31, 2011, all of our proved undeveloped reserves were held by production, and, therefore, there were no proved undeveloped reserves attributed to the acreage expiring in 2011, 2012 or 2013.

Table of Contents

Drilling activity

The following table summarizes our drilling activity for the periods presented. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells.

		Predecessor				Dynamic Offshore Resources, LLC

		January 1, 2008 Through March 13, 2008
						Year Ended December 31,												Nine Months Ended September 30,
						2008				2009				2010				2010				2011
		Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Development wells:
	Oil		—		—		3		2.5		2		2		1		0.6		—		—		2		0.3
	Natural gas		—		—		—		—		—		—		1		0.4		1		0.4		—		—
	Dry holes		—		—		—		—		—		—		—		—		—		—		1		0.2

	Total		—		—		3		2.5		2		2		2		1.0		—		—		3		0.5

Exploratory wells:
	Oil		—		—		—		—		—		—		—		—		—		—		—		—
	Natural gas		—		—		—		—		—		—		2		0.8		2		0.8		—		—
	Dry holes		—		—		1		0.5		—		—		—		—		—		—		1		0.7

	Total		—		—		1		0.5		—		—		2		0.8		2		0.8		1		0.7

	Total wells		—		—		4		3		2		2		4		1.8		3		1.2		4		1.2

As of September 30, 2011, we had no wells in the process of drilling or completion. In the first nine months of 2011, we participated on a non-operated basis in the drilling of 3 gross (0.5 net) development wells, of which 2 gross (0.3 net) were completed as producers. During the same period, we drilled 1 gross (0.7 net) exploration well that was deemed a dry hole. In 2009 and 2010, we achieved a 100% success rate, with a total of 6 gross (3.8 net) wells, of which 2 gross (0.8 net) wells were exploration wells. In 2008, we drilled 4 gross (3.0 net) wells, of which 1 gross (0.5 net) well was deemed a dry hole and 3 gross (2.5 net) wells were completed as producers.

Because we expect to drill several wells during 2012, we recently contracted for a jackup drilling rig for 2012, with the option to extend into 2013, and one platform drilling rig for use at the Bullwinkle field.

Marketing and Major Purchasers

We sell our oil and natural gas to third-party purchasers. We are not dependent upon, or contractually limited to, any one purchaser or small group of purchasers. However, in 2010 we received over 10% of our total revenues from each of Shell Trading (US) Company, Texon LP and ConocoPhillips. Due to the nature of oil and natural gas markets and because oil and natural gas are freely traded commodities and there are numerous purchasers in the Gulf of Mexico, we do not believe the loss of a single purchaser or a few purchasers would materially affect our ability to sell our production.

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. To the extent title opinions or other investigations reflect defects affecting those properties, we are typically responsible for curing any such defects at our expense. We generally will not commence drilling operations on a property until we have cured known material title defects on such property. We have reviewed the title to substantially all of our producing properties and believe that we have satisfactory title to our producing properties in

Table of Contents

accordance with standards generally accepted in the oil and natural gas industry. Prior to completing an acquisition of producing oil and natural gas properties, we perform title reviews on the most significant properties and, depending on the materiality of properties, we may obtain a title opinion or review or update previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens to secure borrowings under our credit facility, liens for current taxes and other burdens which we believe do not materially interfere with the use or affect our carrying value of the properties.

Seasonality

Generally, the demand for and price of natural gas increases during the winter months and decreases during the summer months. However, these seasonal fluctuations are somewhat reduced because during the summer, pipeline companies, utilities, local distribution companies and industrial users purchase and place into storage facilities a portion of their anticipated winter requirements of natural gas. Seasonal weather changes affect our operations. Tropical storms and hurricanes occur in the Gulf of Mexico during the summer and fall, which may require us to evacuate personnel and shut in production until these storms subside. Also, periodic storms during the winter often impede our ability to safely load, unload and transport personnel and equipment, which delays the installation of production facilities, thereby delaying sales of our oil and natural gas.

Competition

The oil and natural gas industry is highly competitive. We operate exclusively in the Gulf of Mexico area and compete for the acquisition of oil and natural gas properties primarily on the basis of financial strength, bidder's perceived ability to close the transaction and price for such properties. We compete with numerous entities, including major domestic and foreign oil companies, other independent oil and natural gas companies and individual producers and operators. Many of these competitors are large, well-established companies and have financial and other resources substantially greater than ours. Our ability to acquire additional oil and natural gas properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment. For a more thorough discussion of how competition could impact our ability to successfully complete our business strategy, please read "Risk Factors" beginning on page 20.

Insurance

We maintain insurance programs to provide coverage for a high percentage of our assets in the event of physical damage and well control events. While we may not obtain insurance for some risks if we believe the cost of available insurance is excessive relative to the risks presented, we intend to continue to pursue a strong risk mitigation program by maintaining comprehensive insurance coverage related to our exposure to operational and weather related risk. For example, we believe our wind storm loss limits are higher than those of our peers. Our wind storm loss limits extend beyond historic loss levels that our properties have experienced and provide for adequate room to add assets in connection with future acquisitions.

Regulation of the Oil and Natural Gas Industry

General

Various aspects of our oil and natural gas operations are subject to extensive and continually changing regulation as legislation affecting the oil and natural gas industry is under constant review for amendment or expansion. Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding upon the oil and natural gas industry

Table of Contents

and its individual members. The Federal Energy Regulatory Commission ("FERC") regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 (the "NGA") and the Natural Gas Policy Act of 1978 (the "NGPA"). In 1989, however, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and nonprice controls affecting wellhead sales of natural gas, effective January 1, 1993. While sales by producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.

In addition, the Federal Trade Commission, the FERC and the CFTC hold statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil or other energy commodities, and any related hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations, and financial condition.

Regulation and Transportation of Natural Gas

Our sales of natural gas are affected by the availability, terms and cost of transportation. The rates and terms for access to pipeline transportation are subject to extensive regulation. In recent years, the FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No. 636 require that interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas supplies. The results of Order No. 636 and related initiatives have been to eliminate the interstate pipelines' traditional role of providing bundled sales service of natural gas and to require pipelines to offer unbundled storage, transportation, and sales services. The rates for such storage and transportation services are subject to FERC ratemaking authority, and FERC exercises its authority either by applying cost-of-service principles, allowing for the negotiation of rates where there is a cost-based alternative rate or granting market based rates in certain circumstances, typically with respect to storage services.

Similarly, natural gas pipelines may also be subject to state regulations which may change from time to time. Pipelines that operate only in a single state may be considered to be intrastate pipelines subject to regulation by state regulatory agencies with respect to safety, rates and/or terms and conditions of service, including requirements for ratable takes or non-discriminatory access to pipeline services. The basis for intrastate regulation and the degree of regulatory oversight and scrutiny given to intrastate pipelines varies from state to state. Many states operate on a complaint-based system and state commissions have generally not initiated investigations of the rates or practices of gas pipelines in the absence of a complaint.

The Outer Continental Shelf Lands Act (the "OCSLA") which was administered by the BOEMRE and, after October 1, 2011, its successors, the BOEM and the BSEE, and the FERC, requires that all pipelines operating on or across the OCS provide open access, non-discriminatory transportation service. One of the FERC's principal goals in carrying out OCSLA's mandate is to increase transparency in the market to provide producers and shippers working in the OCS with greater assurance of open access service on pipelines located on the OCS and non-discriminatory rates and conditions of service on such pipelines. On June 18, 2008, the BOEMRE's predecessor, the MMS, issued a final rule, effective August 18, 2008, that implements a hotline, alternative dispute resolution procedures, and complaint procedures for resolving claims of having been denied open and nondiscriminatory access to pipelines on the OCS.

Table of Contents

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the CFTC and the Federal Trade Commission ("FTC"). Please read "—Other Federal Laws and Regulations Affecting Our Industry—Energy Policy Act of 2005" beginning on page 91 and "—FERC Market Transparency Rules" beginning on page 91.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state commissions and the courts. The natural gas industry historically has been very heavily regulated. As a result, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.

While the changes by these federal and state regulators for the most part affect us only indirectly, they are intended to further enhance competition in natural gas markets. We cannot predict what further action the FERC, the BOEM, the BSEE or state regulators will take on these matters; however, we do not believe that any such action taken will affect us differently, in any material way, than other natural gas producers with which we compete.

Oil and Natural Gas Liquids Transportation Rates

Our sales of crude oil, condensate and natural gas liquids are not currently regulated and are transacted at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act and the Energy Policy Act of 1992. The price we receive from the sale of oil and natural gas liquids is affected by the cost of transporting those products to market. Interstate transportation rates for oil, natural gas liquids, and other products are regulated by the FERC, and in general, these rates must be cost-based, although settlement rates and market-based rates may be permitted in certain circumstances. In addition, the FERC has established an indexing system for such transportation, which allows such pipelines to take an annual inflation-based rate increase.

In other instances involving intrastate-only transportation of oil, natural gas liquids, and other products, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. Such pipelines may be subject to regulation by state regulatory agencies with respect to safety, rates and/or terms and conditions of service, including requirements for ratable takes or non-discriminatory access to pipeline services. The basis for intrastate regulation and the degree of regulatory oversight and scrutiny given to intrastate pipelines varies from state to state. Many states operate on a complaint-based system and state commissions have generally not initiated investigations of the rates or practices of liquids pipelines in the absence of a complaint.

Regulation of Oil and Natural Gas Exploration and Production

Our exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits, bonds and pollution liability insurance for the drilling of wells, regulating the location of wells, the method of drilling, casing, operating, plugging and abandoning wells, and governing the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing conservation of oil and gas resources, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the regulation of spacing of such wells.

In 2010, there were numerous new and proposed regulations related to oil and gas exploration and production activities. Please read "Risk Factors" beginning on page 20 for more information. The

Table of Contents

failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Other Federal Laws and Regulations Affecting Our Industry

Energy Policy Act of 2005. On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (the "EPAct 2005"). EPAct 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, EPAct 2005 amends the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. EPAct 2005 provides the FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increases the FERC's civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provision of EPAct 2005, and subsequently denied rehearing. The rule makes it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, (1) to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act, practice, or course of business that operates as a fraud or deceit upon any person. The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted "in connection with" gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order No. 704. The anti-manipulation rules and enhanced civil penalty authority reflect an expansion of FERC's NGA enforcement authority. Should we fail to comply with all FERC administered statutes, rules, regulations, and orders that are applicable to us, we could be subject to substantial penalties and fines.

FERC Market Transparency Rules. On December 26, 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing ("Order No. 704"). Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers, are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC's policy statement on price reporting.

Effective November 4, 2009, pursuant to the Energy Independence and Security Act of 2007, the FTC issued a rule prohibiting market manipulation in the petroleum industry. The FTC rule prohibits any person, directly or indirectly, in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale from: (a) knowingly engaging in any act, practice or course of business, including the making of any untrue statement of material fact, that operates or would operate as a fraud or deceit upon any person; or (b) intentionally failing to state a material fact that under the circumstances renders a statement made by such person misleading, provided that such omission

Table of Contents

distorts or is likely to distort market conditions for any such product. A violation of this rule may result in civil penalties of up to $1 million per day per violation, in addition to any applicable penalty under the Federal Trade Commission Act.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.

Regulation of Offshore Oil and Natural Gas Exploration and Production

Most of our operations are conducted on federal oil and natural gas leases, which are administered by the BOEMRE, BOEM or BSEE pursuant to the OCSLA. The BOEMRE and its successors, the BOEM and the BSEE, regulate offshore operations, including engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the Gulf of Mexico shelf, and removal of facilities. On January 19, 2011, the U.S. Department of the Interior announced that it would divide offshore oil and gas responsibilities among three separate agencies, with the reorganization to be completed in 2011. The Department of the Interior first created the Office of Natural Resources Revenue to manage revenue collection on October 1, 2010. Effective October 1, 2011, the remaining functions of BOEMRE were split into two federal bureaus, the BOEM, which handles offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, NEPA analysis and environmental studies, and the BSEE, which is responsible for the safety and enforcement functions of offshore oil and gas operations, including the development and enforcement of safety and environmental regulations, permitting of offshore exploration, development and production activities, inspections, offshore regulatory programs, oil spill response and newly formed training and environmental compliance programs. Consequently, after October 1, 2011, we will be required to interact with two newly formed federal bureaus to obtain approval of our exploration and development plans and issuance of drilling permits, which may result in added plan approval or drilling permit delays as the functions of the former BOEMRE are fully divested and implemented in the two federal bureaus. At this time, we cannot predict the impact that this reorganization, or future regulations of enforcement actions taken by the new agencies, may have on our operations. Our federal oil and natural gas leases are awarded based on competitive bidding and contain relatively standardized terms. These leases require compliance with detailed BOEMRE regulations and orders that are subject to interpretation and change by the BOEM or BSEE. The BOEMRE has promulgated other regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities, structures and pipelines, and the BOEM or the BSEE may in the future amend these regulations. Please read "Risk Factors" beginning on page 20 for more information on new regulations.

To cover the various obligations of lessees on the OCS, the BOEMRE and its successors generally require that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be satisfied. The cost of these bonds or assurances can be substantial and there is no assurance that they can be obtained in all cases. We are currently exempt from supplemental bonding requirements. As many regulations are being reviewed, we may be subject to supplemental bonding requirements in the future. Under some circumstances, the BOEM may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially adversely affect our financial condition and results of operations.

Hurricanes in the Gulf of Mexico can have a significant impact on oil and gas operations on the OCS. The effects from past hurricanes have included structural damage to pipelines, wells, fixed production facilities, semi-submersibles and jack-up drilling rigs. The BOEMRE has been in the past, and the BOEM and the BSEE will be in the future, concerned about the loss of these facilities and rigs as well as the potential for catastrophic damage to key infrastructure and the resultant pollution from

Table of Contents

future storms. In an effort to reduce the potential for future damage, the BOEMRE has periodically issued guidance aimed at improving platform survivability by taking into account environmental and oceanic conditions in the design of platforms and related structures. It is possible that similar, if not more stringent, requirements will be issued by the BOEM or the BSEE for future hurricane seasons. New requirements, if any, could increase our operating costs.

The Office of Natural Resources Revenue (the "ONRR") in the U.S. Department of the Interior administers the collection of royalties under the terms of the OCSLA and the oil and natural gas leases issued thereunder. The amount of royalties due is based upon the terms of the oil and natural gas leases as well as the regulations promulgated by the ONRR.

Environmental Regulation

As a lessee and operator of offshore oil and gas properties in the U.S. Gulf of Mexico, we are subject to stringent federal, regional, state and local environmental laws and regulations relating to the release or discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations, among other things, govern the issuance of permits to conduct exploration, drilling and producing operations, the amounts and types of materials that may be released into the environment, the discharge and disposal of waste materials, the remediation of contaminated sites and the reclamation and abandonment of wells, platforms and facilities. As with the industry generally, compliance with current and anticipated environmental laws and regulations increases our overall costs of business, including our capital costs to construct, maintain and upgrade equipment and facilities. Numerous governmental agencies, including the BOEMRE (formerly known as the MMS, which split into two separate federal bureaus, the BOEM and the BSEE, on October 1, 2011), the U.S. Coast Guard and the EPA issue regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial civil and even criminal penalties for failure to comply.

Some laws and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration and production activities in environmentally sensitive areas. The regulatory burden on the oil and natural gas industry increases our cost of doing business and consequently affects our profitability. The remediation, reclamation and abandonment of wells, platforms and other facilities result in our incurring significant costs but these are considered a normal, recurring cost of operations for us as well as for similarly situated competitors. Environmental laws and regulations have been subject to frequent changes over the years and the imposition of more stringent requirements could have a material adverse effect upon our capital expenditures, earnings or competitive position, including the suspension or cessation of operations in affected areas. As such, there can be no assurance that material cost and liabilities will not be incurred in the future.

Following the April 2010 fire and explosion and subsequent release of oil from the Macondo well in the U.S. Gulf of Mexico, the MMS issued a moratorium on deepwater drilling activities in the U.S. Gulf of Mexico that was lifted on October 12, 2010 by the BOEMRE, and also implemented a series of environmental, technological and safety measures intended to improve offshore safety systems and environmental protection. Implementation of new BOEM or BSEE guidelines or regulations may subject us to increased costs or delays and may limit our operations in the U.S. Gulf of Mexico, which could have a material adverse effect on our results of operations and financial condition. For example, the BOEM is in the process of a comprehensive review of its application of the National Environmental Policy Act of 1969 ("NEPA") in reviewing drilling plans, lease sales and other drilling activities in the U.S. Gulf of Mexico, particularly the use of categorical exclusions under NEPA to preclude the requirement for or limit the scope of environmental assessments. Moreover, there have

Table of Contents

been proposals by governmental and private constituencies to amend existing laws, regulations, guidance and policy that could affect our operations in the U.S. Gulf of Mexico and could cause us to incur substantial losses or expenditures, including increasing inspection requirements, increasing amounts of financial responsibility to conduct operations, and contemplation of an outright ban on drilling. Adoption of such proposals could have a material adverse effect on operations in the U.S. Gulf of Mexico by raising operating expenditures, increasing insurance premiums, delaying drilling operations and increasing regulatory costs.

The primary federal law for oil spill liability is the OPA which amends and augments oil spill provisions of the federal Water Pollution Control Act (the "Clean Water Act"). The OPA imposes certain duties and liabilities on "responsible parties" related to the prevention of oil spills and damages resulting from such spills in or threatening U.S. waters, including the Outer Continental Shelf (the "OCS") or adjoining shorelines. A liable "responsible party" includes the owner or operator of an onshore facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. The OPA assigns joint and several strict liability, without regard to fault, to each liable party for all containment and oil removal costs and a variety of public and private damages 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. Although defenses exist to the liability imposed by the OPA, they are limited. If an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and damages could be material to our results of operations and financial position.

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 OCS, although the Secretary of Interior may increase this amount up to $150 million in certain situations. As a result of the Macondo well incident, legislation was introduced, but not adopted, in last year's session of Congress to increase the minimum level of financial responsibility to $300 million or more. Whether similar legislation will be introduced and adopted in the current session or future sessions of Congress to amend the OPA to increase the minimum level of financial responsibility to $300 million is unknown, but if such legislation were to be ever adopted, we could 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 could be forced to sell our properties or operations located on the OCS or enter into partnerships with other companies that can meet the increased financial responsibility requirement, and any such developments could have an adverse effect on the value of our offshore assets and the results of our operations.

The Clean Water Act and analogous state laws prohibit the discharge of oil or hazardous substances in U.S. navigable waters or analogous state waters without a permit and impose strict liability in the form of penalties for unauthorized discharges. The regulations implementing the Clean Water Act require permits to be obtained by an operator before specified exploration activities occur. Spill prevention control and countermeasure requirements of federal laws and some state laws require containment to mitigate or prevent contamination of navigable waters in the event of an oil release. The OPA also requires covered facilities such as ours to develop and implement spill response plans intended to prepare the owner of the facility to respond to a hazardous substance or oil discharge. We maintain such plans, and where required have submitted plans and received federal and state approvals necessary to comply with the OPA, the Clean Water Act and related regulations. We are a member of Clean Gulf Associates, an industry sponsored organization that owns and operates spill response and clean up equipment. We contract with third party companies that provide qualified and trained personnel to operate the response equipment and to assist in spill mitigation. Additionally, we contract

Table of Contents

with a third party company that provides an expert team of spill management professionals that make up the majority of our spill management team. Our senior management receives annual required training to fill the role of qualified individuals to assist in directing the spill management team and our operations personnel required for source control in the event of a non-permitted discharge or release.

The OCSLA authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the OCS. Included among these regulations are requirements mandating the preparation of spill contingency plans and the establishment of air quality standards for certain pollutants, including particulate matter, volatile organic compounds, sulfur dioxide, carbon monoxide and nitrogen oxides. Specific design and operational standards may apply to OCS vessels, rigs, platforms and structures. Violations of lease conditions or regulations related to the environment issued pursuant to OCSLA can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and canceling leases. Such enforcement liabilities can result from either governmental or citizen prosecution.

The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), also known as the "Superfund" law, and analogous state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include the current or former owner or operator of the disposal site where the release occurred and companies that disposed or arranged for the disposal of hazardous substances released at the site. Under CERCLA, such persons are subject to joint and several strict liability for the cost of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the cost of certain health studies. Additionally, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. We generate materials in the course of our operations that are regulated as hazardous substances.

We also may incur liability under the Resource Conservation and Recovery Act ("RCRA") and comparable state statutes, which impose requirements related to the generation, transportation, storage, treatment and disposal of solid and hazardous wastes and can require cleanup of hazardous waste disposal sites. While there exists an exclusion under RCRA from the definition of hazardous wastes for certain materials generated in the exploration, development or production of oil and natural gas, these wastes may be regulated by the EPA and state environmental agencies as non-hazardous solid wastes. Other wastes handled at exploration, development and production sites may not fall within this regulatory exclusion. Moreover, stricter standards for waste handling and disposal may be imposed on the oil and natural gas industry in the future. From time to time, legislation is proposed in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from the RCRA definition of "hazardous wastes," thereby potentially subjecting such wastes to more stringent handling, disposal and cleanup requirements. In September 2010, the Natural Resources Defense Council filed a petition with the EPA, requesting them to reconsider the RCRA exemption for exploration, production and development wastes. To date, the EPA has not taken any action on the petition. If legislation is enacted or regulatory changes adopted that remove this RCRA exemption, it could have a significant impact on our operating costs as well as the oil and natural gas industry in general. The impact of future revisions to environmental laws and regulations cannot be predicted.

Our operations are also subject to the CAA and comparable state and local requirements. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. For example, on July 28, 2011, the EPA proposed four sets of new regulations which, if adopted, will impose more stringent standards for air emissions from oil and gas development and production operations which may require us to incur additional expenses to control air emissions from current operations and during new well developments by installing emissions control technologies and adhering

Table of Contents

to a variety of work practice and other requirements. Any such requirements could increase the costs of development and production, though at this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements. However, we believe our operations will not be materially adversely affected by any such requirements and the requirements are not expected to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.

In December 2009, 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 these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. The EPA has adopted rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and another 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. We are not currently required to report under these rules, but if we are required to report in the future, we do not believe that our operations would be materially affected by any such requirements.

Certain flora and fauna that have officially been classified as "threatened" or "endangered" are protected by the Endangered Species Act. This law prohibits any activities that could "take" a protected plant or animal or reduce or degrade its habitat area. If endangered species are located in an area where we wish to conduct seismic surveys, development or abandonment operations, the work could be prohibited or delayed or expensive mitigation might be required.

Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal

Table of Contents

proceeding. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us.

Employees

As of December 31, 2011, we employed 148 people. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory. From time to time we utilize the services of independent contractors to perform various field and other services.

Offices

We currently lease approximately 74,000 square feet of office space in Houston, Texas at 1301 McKinney, Suite 900, where our principal offices are located. The lease for our principal Houston office expires on August 31, 2017. We believe that our facilities are adequate for our current operations and that additional leased space can be obtained if needed.

Table of Contents

MANAGEMENT

Directors, Executive Officers and Other Non-Executive Officers

The following table sets forth information regarding our directors, director nominees and executive officers as of January 10, 2012. There are no family relationships among any of our directors, director nominees or executive officers.

Name	Age	Title

G.M. McCarroll	52	President, Chief Executive Officer and Chairman of the Board of Directors
John Y. Jo	53	Senior Vice President, Acquisitions & Engineering
Thomas R. Lamme	44	Senior Vice President and General Counsel
Howard M. Tate	43	Senior Vice President, Chief Financial Officer and Secretary
N. John Lancaster	43	Director
Robert F. Fulton	60	Director Nominee
Terence E. Hall	66	Director Nominee
John P. Ryan	60	Director Nominee

The following table sets forth information regarding other non-executive officers as of January 10, 2012.

Name		Title

James E. Brokmeyer	59	Vice President, Production
Gary G. Janik, P.E.	56	Vice President, Exploitation and Development
Carey J. Naquin	54	Vice President, Operations
John H. Smith	51	Vice President, Land and Business Development
William B. Swingle, CPA	52	Vice President and Chief Accounting Officer

Set forth below is the description of the backgrounds of our directors, director nominees, executive officers and other non-executive officers.

G.M. McCarroll—President, Chief Executive Officer and Chairman of the Board of Directors. Mr. McCarroll is our founder and has been CEO since our formation in January 2008. Prior to our formation, Mr. McCarroll was President of Maritech Resources, Inc., a wholly owned subsidiary of TETRA Technologies, Inc. (NYSE: TTI) from September 2001 to October 2007. Prior to Maritech, Mr. McCarroll served as President of Augusta Petroleum Partners in Houston from 1998 to 2001. Mr. McCarroll was an original member of the Senior Management Team of Plains Resources, Inc. from 1988 to 1998, holding several management positions including Vice President of Land and Exploration. Early in his career he also held positions with Great Southern Oil and Gas in Lafayette, Louisiana and Amoco Production Company in New Orleans, Louisiana. Mr. McCarroll holds a Bachelor's Degree in Business Administration and Finance from Louisiana State University. He is an active member in numerous industry associations and currently serves on the Board of Directors of the National Ocean Industries Association. He is also a member of The Dean's Advisory Council of the E.J. Ourso College of Business at Louisiana State University.

As our founder, Mr. McCarroll is the principal driving force behind us and our success to date. Over the course of our history, Mr. McCarroll has successfully grown us through his leadership skills, operational expertise and business judgment and for this reason we believe Mr. McCarroll is a valuable asset to our board of directors and is the appropriate person to serve as Chairman of the Board.

John Y. Jo—Senior Vice President, Acquisitions & Engineering. Mr. Jo is our Senior Vice President, Acquisitions & Engineering, a position he has held since January 2008. Prior to joining us, he was

Table of Contents

President and Chief Operating Officer of Turnkey E&P Corporation, a drilling services and E&P company, from December 2005 until January 2008. Prior to Turnkey E&P, Mr. Jo was Manager, Corporate Engineering with Forest Oil Corporation (NYSE: FST) from April 2004 to December 2005 after working at Apache Corporation (NYSE: APA) since July 1993 where he held various domestic and international positions including Engineering Director. Earlier in his career, Mr. Jo held positions with Hunt Petroleum Corporation including Manager of Acquisitions and Joint Operations. Mr. Jo holds a BS degree in Petroleum Engineering from the Colorado School of Mines. He is a registered Professional Engineer in the State of Texas and is a member of the Society of Petroleum Engineers. He served on various committees of industry organizations including President of the Petroleum Engineers Club of Dallas, Director and Treasurer of the SPE Dallas Section.

Thomas R. Lamme—Senior Vice President and General Counsel. Mr. Lamme is our Senior Vice President and General Counsel, a position he has held since June 2011. Mr. Lamme previously served as a senior partner at Thompson & Knight LLP, where he worked from August 1999 until June 2011. Prior to joining Thompson & Knight LLP, Mr. Lamme was an associate attorney at Brown, Parker & Leahy LLP from October 1996 until August 1999, when the firm merged with Thompson & Knight LLP. Prior to that, Mr. Lamme was employed as an accounting staff professional with Arthur Andersen LLP from September 1994 until October 1996. Mr. Lamme holds a Bachelor's of Arts degree from Dartmouth College and a J.D. from the University of Houston Law Center.

Howard M. Tate—Senior Vice President, Chief Financial Officer and Secretary. Mr. Tate is our Senior Vice President, Chief Financial Officer and Secretary, a position he has held since March 2008. Mr. Tate previously served as Vice President—Finance and Treasurer of Targa Resources, Inc. (which controlled the general partner of Targa Resources Partners, LP (NYSE: NGLS)) from September 2005 to March 2008. Prior to joining Targa, Mr. Tate served as Vice President of Finance and Capital Markets for Magnum Hunter Resources, Inc. from April 2002 until its acquisition by Cimarex Energy, Inc (NYSE: XEC) in June 2005. Early in his career, he held positions with Pride International, Inc., Tejas Gas Corporation and Tenneco, Inc. Mr. Tate holds an Accounting degree from Oklahoma State University and a Masters of Business Administration from the University of Houston.

James E. Brokmeyer—Vice President, Production. Mr. Brokmeyer is our Vice President, Production, a position he has held since March 2008. Prior to joining us, Mr. Brokmeyer held the position of VP—Production at SPN Resources from April 2004 to March 2008. Previously, he has held management positions with El Paso Production Company, Coastal Oil & Gas, British-Borneo Exploration, Inc. and Energy Development Corporation. Mr. Brokmeyer holds a petroleum engineering degree from Texas A&M University. He is a member of the Society of Petroleum Engineers and American Petroleum Institute.

N. John Lancaster—Director. Mr. Lancaster is currently a Partner and Managing Director of Riverstone, where he is responsible for managing investments across the energy industry, with a focus on oil services and exploration and production. Prior to joining Riverstone in 2000, Mr. Lancaster was a director with The Beacon Group, LLC., a privately held firm specializing in principal investing and strategic advisory services in the energy and other industries. Prior to joining Beacon, Mr. Lancaster was a Vice President with Credit Suisse First Boston's Natural Resources Group in Houston, Texas. Mr. Lancaster has served as a director of Cobalt International Energy, Inc. since 2010 and previously served as a director of Magellan Midstream Partners, L.P. from 2003 until 2007. He also currently serves as a director of several of Riverstone's private portfolio companies. Mr. Lancaster received his B.B.A. from the University of Texas at Austin and his M.B.A. from Harvard Business School.

Mr. Lancaster brings extensive business and financial expertise to our board of directors from his background in banking and private equity fund management. Mr. Lancaster also brings extensive prior board service experience to our board of directors from service on numerous other corporate boards and limited partnership advisory boards.

Table of Contents

Robert F. Fulton—Director Nominee. Mr. Fulton will become a member of our board of directors concurrently with the listing of our common stock on the NYSE. Mr. Fulton also will serve as the chairman of our audit committee. He has served on the board of directors of Basic Energy Services, Inc. since August 2001 and currently is a member of Basic Energy Service's nominating and governance committee. He served as President and Chief Executive Officer of Frontier Drilling ASA, an offshore oil and gas drilling and production contractor, from September 2002 through July 2010. From December 2001 to August 2002, he managed personal investments. Prior to December 2001, he spent most of his business career in the energy service and contract drilling industry. He served as Executive Vice President and Chief Financial Officer of Merlin Offshore Holdings, Inc. from August 1999 until November 2001. From January 1998 to June 1999, Mr. Fulton served as Executive Vice President of Finance for R&B Falcon Corporation, during which time he closed the merger of Falcon Drilling Company with Reading & Bates Corporation to create R&B Falcon Corporation and then the merger of R&B Falcon Corporation with Cliffs Drilling Company. He graduated with a B.S. degree in Accountancy from the University of Illinois and an M.B.A. in finance from Northwestern University.

Mr. Fulton brings substantial experience to our board through his extensive work in the energy industry. We believe that Mr. Fulton's expertise in finance-related activities, thorough understanding of audit and accounting-related matters and experience with numerous energy companies as a senior financial officer in both the private and public sectors provides significant insight, value and perspective to the board of directors, our audit committee (as chairman and designated "financial expert") and us.

Terence E. Hall—Director Nominee. Mr. Hall will become a member of our board of directors concurrently with the listing of our common stock on the NYSE. Mr. Hall will also serve as a member of our audit committee. He has served as the Chairman of the Board and a Director of Superior Energy Services, Inc. since December 1995. From December 1995 to April 2010, he served as Superior's Chief Executive Officer, and from December 1995 until November 2004, he also served as its President. Mr. Hall also serves as a director of Whitney Holding Corp. Mr. Hall holds a B.S. and J.D. from Tulane University.

Mr. Hall's detailed knowledge of the industry in which we operate and his perspective regarding strategic and operational opportunities and challenges facing the oil and gas industry enable him to provide invaluable strategic advice and focus to our board, to our audit committee and to us.

John P. Ryan—Director Nominee. Mr. Ryan will become a member of our board of directors concurrently with the listing of our common stock on the NYSE. He served as President and Chief Executive Officer of Dresser, Inc. from April 2007 until it was acquired by GE in February 2011. From December 2004 to April 2007, he served as Dresser, Inc.'s President and Chief Operating Officer and in various other management positions at the company from February 1976 to December 2004. Mr. Ryan has served as a board member of Hudson Products, Inc. since January 2010, Flex Energy Inc. since October 2011 and The World Affairs Council of Dallas/Ft. Worth since January 2009. Mr. Ryan holds a B.A. in Psychology from Villanova University.

Mr. Ryan brings to our board extensive executive and managerial experience and competency in developing and executing corporate strategies from his background in the global energy industry. Through his prior board memberships and executive role at Dresser, Inc., including and since its sale to General Electric, Mr. Ryan provides our board with a proven ability to interface with shareholders, private equity sponsors and members of the management team.

Gary G. Janik, P.E.—Vice President, Exploitation and Development. Mr. Janik is our Vice President, Exploitation and Development, a position he has held since March 2008. Prior to joining us, Mr. Janik held the positions of Manager and VP—Acquisitions and Reserves at SPN Resources from February 2004 to March 2008. Previously, he served as Director of Oil and Gas Property Management with Duke Energy Hydrocarbons from July 2000 to August 2003. He has also served as Manager of

100

Table of Contents

Reserves at Enron Oil & Gas, as well as held other engineering positions with Enron Oil & Gas Company, NP Energy Corporation and Amoco Production Company. Mr. Janik holds a degree in Chemical Engineering from Texas A&M University. He is a registered Professional Engineer and a member of the Society of Petroleum Engineers and the American Petroleum Institute.

Carey J. Naquin—Vice President, Operations. Mr. Naquin is our Vice President, Operations, a position he has held since March 2008. Prior to joining us, Mr. Naquin held the position of VP—Operations at SPN Resources from March 2005 to March 2008. Previously, he served as Senior Managing Consultant for Landmark and in various management and senior engineering positions for Halliburton from May 1995 to March 2005. Prior to Halliburton, he was employed in similar positions related to exploration and development for Placid Oil Company. Mr. Naquin holds a Petroleum Engineering degree from Louisiana State University. He is a member of the American Association of Drilling Engineers and Society of Petroleum Engineers.

John H. Smith—Vice President, Land and Business Development. Mr. Smith is our Vice President, Land and Business Development, a position he has held since June 2009. Prior to joining us, Mr. Smith held the position of Negotiations and Business Manager for Australia and Southeast Asia for Hess Corporation from September 2007 to June 2009. Prior to this role, Mr. Smith held numerous positions within Land and Business Development at Hess Corporation during his 26-year career there. Mr. Smith holds a BS in Business Administration from Oklahoma State University. He is a member of the Association of International Petroleum Negotiators, Independent Petroleum Association of America, and American Association of Professional Landmen.

William B. Swingle, CPA—Vice President and Chief Accounting Officer. Mr. Swingle is our Vice President and Chief Accounting Officer, a position he has held since January 2012. Mr. Swingle is responsible for all of our accounting and financial reporting functions. From December 2009 to December 2011, Mr. Swingle served as our Vice President, Accounting. Prior to joining us, he was Senior Director—Financial Reporting of Targa Resources, Inc. from December 2004 to November 2009; Assistant Controller/Accounting Manager—Financial Reporting of Plains Exploration and Production Company from July 2001 to December 2004; Controller of DA Consulting Group from August 2000 to June 2001 and held various financial management positions with PetroCorp Incorporated from May 1985 to December 1999. Mr. Swingle holds a degree in Accounting from the University of Houston. He also has a CPA license in the State of Texas.

Board of Directors

Our board of directors currently consists of two members, G.M. McCarroll, our Chief Executive Officer, and N. John Lancaster, a designee of the Riverstone/Carlyle Funds, which we expect will control a majority of the voting power of our outstanding common stock following this offering. Robert F. Fulton, Terence E. Hall and John P. Ryan will become members of our board of directors concurrent with the listing of our common stock on the NYSE. Mr. Ryan is designated by the Riverstone/Carlyle Funds. We anticipate that our board will determine each of Mr. Fulton and Mr. Hall are independent under the independence standards of the NYSE.

Pursuant to the Stockholders Agreement that we expect to enter into with the Riverstone/Carlyle Funds and certain other stockholders, the Riverstone/Carlyle Funds will have the ability to nominate three directors to our board initially, subject to reduction as their level of ownership decreases. Two of these nominees will initially be Mr. Lancaster and Mr. Ryan. The Riverstone/Carlyle Funds have not yet informed us as to their other nominee. As a result, our board may initially consist of five directors. Please read "Certain Relationships and Related Party Transactions—Stockholders Agreement" on page 126.

101

Table of Contents

In addition to Mr. Fulton and Mr. Hall, we intend to appoint at least one additional independent director (who will not be a Riverstone/Carlyle Funds designee) to our board of directors following the completion of this offering to meet the NYSE's phase-in requirements for the composition of the audit committee following an initial public offering (i.e., a third independent member within one year). Therefore, we anticipate that within one year from the date of the offering, our board will consist of seven members, three of which will be designated by the Riverstone/Carlyle Funds.

We expect that our board will review the independence of our current directors using the independence standards of the NYSE.

In evaluating director candidates, we will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance the board's ability to manage and direct the affairs and business of the company, including, when applicable, to enhance the ability of committees of the board to fulfill their duties. We currently are in the process of identifying individuals who meet these standards and the relevant independence requirements.

Following the completion of this offering, our directors will be divided into three classes serving staggered three-year terms. Class I, Class II and Class III directors will serve until our annual meetings of stockholders in 2013, 2014 and 2015, respectively. We anticipate that Mr. Fulton will be assigned to Class I, Messrs. Hall and Ryan will be assigned to Class II and Messrs. McCarroll and Lancaster will be assigned to Class III. At each annual meeting of stockholders held after the initial classification, directors will be elected to succeed the class of directors whose terms have expired. This classification of our board of directors could have the effect of increasing the length of time necessary to change the composition of a majority of the board of directors. In general, at least two annual meetings of stockholders will be necessary for stockholders to effect a change in a majority of the members of the board of directors.

Status as a "Controlled Company"

Because the Riverstone/Carlyle Funds and our other equity owners that will be party to the stockholders agreement will own a majority of our outstanding common stock following the completion of this offering, we expect to be a "controlled company" under NYSE corporate governance standards. A controlled company need not comply with NYSE corporate governance rules that require its board of directors to have a majority of independent directors and independent compensation and nominating and corporate governance committees. We intend to avail ourselves of the controlled company exception under the NYSE corporate governance standards. Notwithstanding our status as a controlled company, we will remain subject to the NYSE corporate governance standard that requires us to have an audit committee composed entirely of independent directors. As a result, we must have at least one independent director on our audit committee by the date our common stock is listed on the NYSE, at least two independent directors within 90 days of the listing date and at least three independent directors within one year of the listing date. In connection with the completion of this offering, we expect that Mr. Fulton will become the chairman and Mr. Hall will be a member of the audit committee.

Once we cease to be a controlled company, our board of directors will be required to have a compensation committee and a nominating and governance committee, each with at least one independent director. Within 90 days of ceasing to be a controlled company, we will be required to have each of a compensation committee and a nominating and governance committee with a majority of independent directors, and within one year of ceasing to be a controlled company, a majority of our board of directors must be comprised of independent directors.

102

Table of Contents

Committees of the Board of Directors

Upon the conclusion of this offering, we intend to have an audit committee, and in the event we are no longer a controlled company, a compensation committee and nominating and governance committee, of our board of directors, and may have such other committees as the board of directors shall determine from time to time. We anticipate that each of the standing committees of the board of directors will have the composition and responsibilities described below.

Audit Committee

We will establish an audit committee prior to completion of this offering. We anticipate that the audit committee will consist of three directors, each of whom will be independent under the rules of the SEC following the end of the NYSE's phase-in period. As required by the rules of the SEC and listing standards of the NYSE, the audit committee will consist solely of independent directors. SEC rules also require that a public company disclose whether or not its audit committee has an "audit committee financial expert" as a member. An "audit committee financial expert" is defined as a person who, based on his or her experience, possesses the attributes outlined in such rules. In connection with the completion of this offering, we expect that Mr. Fulton will become the chairman of the audit committee and Mr. Hall will serve as a member. In addition, we expect that our board will determine that Mr. Fulton is an "audit committee financial expert" as defined in the SEC rules.

This committee will oversee, review, act on and report on various auditing and accounting matters to our board of directors, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the audit committee will oversee our compliance programs relating to legal and regulatory requirements. Upon formation of the audit committee, we expect to adopt an audit committee charter defining the committee's primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards.

Compensation Committee

Because we will be a "controlled company" within the meaning of the NYSE corporate governance standards, we will not be required to, and will not, have a compensation committee.

If and when we are no longer a controlled company, we will be required to establish a compensation committee. We anticipate that the compensation committee will consist of three directors, each of whom will be "independent" under the rules of the SEC. As required by the rules of the SEC and listing standards of the NYSE, a majority of the compensation committee will be independent directors. This committee will establish salaries, incentives and other forms of compensation for officers and other employees. Our compensation committee will also administer our incentive compensation and benefit plans. Upon formation of the compensation committee, we expect to adopt a compensation committee charter defining the committee's primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards.

Nominating and Corporate Governance Committee

Because we will be a "controlled company" within the meaning of the NYSE corporate governance standards, we will not be required to, and will not, have a nominating and corporate governance committee. While we are a controlled company, our board of directors will identify and evaluate potential candidates for nomination as a director and recommend any such candidates to our board of directors.

If and when we are no longer a controlled company, we will be required to establish a nominating and corporate governance committee. We anticipate that the nominating and corporate governance

103

Table of Contents

committee will consist of three directors. As required by the rules of the SEC and listing standards of the NYSE, the nominating and corporate governance committee will consist of a majority of independent directors. This committee will identify, evaluate and recommend qualified nominees to serve on our board of directors, develop and oversee our internal corporate governance processes and maintain a management succession plan. Upon formation of the nominating and corporate governance committee, we expect to adopt a nominating and corporate governance committee charter defining the committee's primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards.

Compensation Committee Interlocks and Insider Participation

Because we will be a "controlled company" within the meaning of the NYSE corporate governance standards, we will not be required to, and will not, have a compensation committee. None of our executive officers serve on the board of directors or compensation committee of a company that has an executive officer that serves on our board or compensation committee. No member of our board is an executive officer of a company in which one of our executive officers serves as a member of the board of directors or compensation committee of that company.

Code of Business Conduct and Ethics

Prior to the completion of this offering, our board of directors will adopt a code of business conduct and ethics applicable to our employees, directors and officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of the NYSE. Any waiver of this code may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE.

Corporate Governance Guidelines

Prior to the completion of this offering, our board of directors will adopt corporate governance guidelines in accordance with the corporate governance rules of the NYSE.

104

Table of Contents

COMPENSATION DISCUSSION AND ANALYSIS

Overview of Executive Compensation

As a private company, our compensation arrangements with our executive officers have been determined on an individual basis, based on negotiations between the individual and our chief executive officer (our "CEO"), in consultation with Riverstone. Our CEO negotiated his own compensation directly with Riverstone in connection with the Riverstone/Carlyle Funds' initial equity commitment in us. All of our executive officers have entered into employment agreements, which will be amended and restated in connection with the closing of this offering.

Historically, we have operated as a limited partnership. As a limited partnership, our operations are managed by our general partner and all of our employees, including our executive officers, are employed by our general partner. When we refer to "our employees," "our executive officers" or "our board," or make similar statements, we are referring to individuals who are employed by or serve our general partner on our behalf. When we refer to our "named executive officers" within this "Compensation Discussion and Analysis" for the 2011 fiscal year, we are referring to: (1) G.M. McCarroll, our CEO, President and Chairman of the Board; (2) Howard M. Tate, our Senior Vice President, Chief Financial Officer and Secretary; (3) John Y. Jo, our Senior Vice President, Acquisitions & Engineering; and (4) Thomas R. Lamme, our Senior Vice President and General Counsel. Messrs. McCarroll, Tate, Jo and Lamme were our only executive officers during the year ended December 31, 2011. Following our merger with and into Dynamic Offshore Resources, Inc., our employees, including our executive officers, will become employees of the corporation.

Although we have not historically had a formal compensation committee, our CEO and one of the managing directors of Riverstone, N. John Lancaster, currently operate as an informal compensation committee of our board. In 2011, we, through our informal compensation committee, began the process of analyzing our executive compensation program with the goal of modifying it to be more suitable for a public company. Going forward, we believe that our executive compensation program will help us attract, motivate and retain key executives and reward executives for creating and improving the value of our company. To aid in this process, in 2011, we engaged Longnecker & Associates ("Longnecker"), a nationally recognized compensation consulting firm with experience in assisting similar companies that own and operate upstream oil and natural gas assets, including properties in the Gulf of Mexico. We are working with Longnecker to refine our executive compensation programs to ensure (i) that our executive total direct compensation is in line with total direct compensation among our peer group and (ii) that our overall compensation aligns our executives' interests with those of our stockholders by tying a meaningful portion of each executive's cash and equity compensation to the achievement of performance targets and by including time-based vesting requirements in our long-term equity grants.

Following the completion of this offering, we expect to be a "controlled company" within the meaning of the NYSE listing rules. If we are a controlled company, we will not be required to have a compensation committee composed entirely of independent directors. If we do not form a formal compensation committee comprised entirely of independent directors, we intend to continue to rely on our informal compensation committee process. Future independent directors that we add to our board may be included in this process.

If we cease to be a controlled company, our board of directors will be required to have a compensation committee with at least one independent director. Within 90 days of ceasing to be a controlled company, we will be required to have a compensation committee with a majority of independent directors, and within one year of ceasing to be a controlled company, our compensation committee would have to be composed of entirely independent directors.

105

Table of Contents

Goals of the Compensation Program

We are focused on establishing an executive compensation program that is intended to attract, motivate, and retain key executives and to reward executives for creating and increasing the value of our company. In meeting those objectives, we intend to use peer group total direct compensation data to develop a general targeted range for our executive compensation. To that end, we worked closely with Longnecker to identify an appropriate peer group of similarly situated U.S.-based oil and natural gas exploration and production companies using factors such as revenues, asset book value, EBITDA, and assumed market value and including our direct competitors with whom we compete for employees and management personnel. As a result of that collaborative analysis, we have identified the following companies as an appropriate peer group:


Cobalt International, Inc.	Eagle Rock Energy Partners, L.P.	W&T Offshore
Berry Petroleum	Stone Energy Corporation	Energy XXI Limited
ATP Oil & Gas Corporation	Swift Energy Company	McMoRan Exploration Co.
Comstock Resources, Inc.	Rosetta Resources Inc.	Venoco, Inc.
Energy Partners, Ltd.	Petroquest Energy, Inc.	Goodrich Petroleum Corporation
Carrizo Oil & Gas, Inc.	Oasis Petroleum Inc.	Endeavour International Corporation

Longnecker prepared a compensation study in 2011, utilizing published survey information and publicly filed proxy statements of our peer group companies to assist us in developing the general range of targeted overall total direct compensation. The compensation data included a breakdown of compensation amounts in the 25^th, 50^th, and 75^th percentiles for our peer group. Our executive officers' combined base salary and bonus (other than the CEO) paid in 2010 (the year reflected in the study) generally fell below the market 50^th percentile, and our CEO's combined base salary and bonus paid in 2010 is at the market 25^th percentile. We anticipate that our executives' 2011 base salary and bonus levels will fall within these same percentiles. We are in the process of determining an appropriate compensation philosophy and the appropriate targeted range for our executive compensation going forward. The Longnecker study provided reflective pay data for companies with average revenues of approximately $425 million that maintain areas of oil and gas operations which are similar to our business strategies and against whom we compete for executive talent.

Although we intend to rely most heavily on the peer group data, we also reviewed additional information to gain a sense of total direct compensation trends in the broader public company market. In 2011, we reviewed additional compensation data provided by Longnecker for individuals holding positions similar to our executive officers obtained from compensation survey sources and proxy statements. Survey data presented were collected from a combination of industry-specific and general industry sources, including: 2011 Economic Research Institute Executive Compensation Assessor, 2011 US Mercer MTCS for the Energy Sector, World at Work's 2010/2011 Total Salary Increase Budget Survey, 2010 ECI Oil & Gas E&P Industry Compensation Survey and 2010/2011 Towers Watson Top Management Compensation. Longnecker will prepare an updated survey for us during the 2012 year covering overall total direct compensation within our industry for the fiscal year ended December 31, 2011.

Components of Our Executive Compensation Program

Our executive compensation program currently has the following three principal elements: base salary, cash bonuses and equity. Each component is set forth in each executive officer's employment

106

Table of Contents

agreement and restricted unit grant agreement (the Class B Units described below). We believe this mix of compensation appropriately aligns our executives' compensation with our short term and long term goals. The employment agreements we maintain with our named executive officers govern essentially all terms of compensation outside of the equity-based compensation awards that the executives may receive, and we feel that these agreements are beneficial to both the executive and the company in that all expectations and obligations of both parties are clearly set forth.

Below is a description of each of the principal elements of our current compensation program and our current view on these elements going forward. We recognize that as the structure of our compensation committee (either formal or informal) changes, the goals themselves and the methods of implementing those goals may change.

Base Salary

2011. Each named executive officer's base salary is a fixed component of compensation for each year and does not vary in a given year depending on the level of performance achieved. As described above, our executive officers' base salaries were originally set pursuant to negotiations with our CEO, in consultation with Riverstone (or, in the case of our CEO, directly with Riverstone) based on prevailing average market salaries for professionals in the oil and natural gas industry, as published in the most recent ECI Oil & Gas E&P Industry Compensation Survey, and based on the respective named executive officer's experience and knowledge in the industry. The original base salary levels were minimums subject to increase by our board of directors based on our growth and individual performance by the executive. Since it was originally determined, our CEO's base salary has been increased by approximately 30% as a reward for growing the company and demonstrating a strong ability to lead a successful management team. For 2011, base salaries for our named executive officers were set by our board as follows: Mr. McCarroll—$400,000; Mr. Tate—$245,000; Mr. Jo—$255,000; and Mr. Lamme—$300,000. In November 2010, in connection with our normal salary review process, the base salaries for Messrs. Tate and Jo were increased from $220,000 and $245,000, respectively, to reflect a more appropriate level of base salary for those executive officers but no changes were made to salaries during the 2011 year.

2012 and going forward. For 2012 and subsequent years, we are analyzing the appropriateness of all of our executive officers' base salaries in light of the targeted range of base salaries from our peer group, both on a standalone basis and as a component of total direct compensation. As a result of that analysis, our board determined that certain of our named executive officers' salaries for 2012 should be increased in connection with this offering as follows: Mr. McCarroll—$600,000; Mr. Tate—$295,000; and Mr. Jo—$285,000. In the future, we expect to review base salaries on an annual basis to determine if the company's financial and operational performance and the executive officer's personal performance (both individually and as a leader of his respective team) support any adjustment to base salary. We expect that each executive officer's employment agreement will set forth the initial determination as a minimum base salary; for more information about the amended and restated employment agreements that we intend to enter into with our named executive officers, please read "—Actions To Be Taken Following the 2011 Fiscal Year" beginning on page 114. We anticipate that a formal compensation committee, if constituted, would continue similar analyses with respect to base salary.

Cash Bonus

General. Each executive officer's (other than our CEO's, which is set at the discretion of the board) current employment agreement sets a general targeted bonus opportunity expressed as a percentage of base salary; for Messrs. Tate and Jo, the target annual bonus will be set by our board of directors on an annual basis in the target range of 60-75%. For Mr. Lamme, the target is 60%. Each named executive officer's employment agreement requires us to make his bonus payment, if any, no

107

Table of Contents

earlier than January 1st, but no later than March 15th, of the year following the year to which the bonus relates. Messrs. Tate, Jo and Lamme's employment agreements requires them to remain employed with us until the last day of the calendar year to which the bonus relates, and Mr. McCarroll's agreement requires him to remain employed with us until January 1 of the calendar year following the applicable year with respect to which the bonus relates, in order to be eligible to receive a bonus. In general, our board has discretion to decide whether the executive bonuses will be subject to any particular performance criteria.

2010. For 2010, our board determined that it would be appropriate to review our company's annual performance (such as our actual adjusted EBITDA and cash flow performance) as compared to budgeted and anticipated amounts, as well as each executive officer's individual performance, in determining whether bonuses were warranted for the executive officers. During 2010, the company performed in excess of 85% of our budgeted plan performance, and while our board did not set or communicate to any officer any particular company performance metrics, our board felt that any bonuses actually paid at the end of the year should take into account the company's performance in a variety of areas. With respect to individual performance, our CEO provided our board with a qualitative assessment of each executive officer's performance during the 2010 year. Our CEO's performance and associated bonus was determined entirely in the board's discretion, although the board reviewed both company performance and individual actions for our CEO, as it did for our other executive officers. Our board believes that this process of largely analyzing qualitative standards provides an incentive to the executive officers to maximize our overall performance rather than requiring the executives to focus solely on one particular or decisive factor. The primary qualitative items discussed for each of the three named executive officers for 2010 included effective leadership, communication to team members, and dedication to performing his duties. Because the bonus amounts are generally limited by the range set forth in the employment agreements and are determined at the board's discretion, we believe that we have historically created a cooperative atmosphere among the executive officers.

We believe it is important that our board, or the compensation committee, as the case may be, maintain ultimate discretion in assessing our CEO's individual performance. We expect that our CEO will maintain ultimate discretion in assessing the individual performances of our other executive officers. Our board, or the compensation committee, as the case may be, will maintain ultimate discretion in determining whether our corporate financial or operational goals have been met in a satisfactory manner to warrant paying cash bonuses and, if applicable, the amount of such cash bonuses.

For 2010, our board authorized the payment of cash bonuses (which were paid in 2011) to each of our executive officers; for Messrs. Tate and Jo, the bonuses were authorized within the named executive officer's target bonus amount set forth in his employment agreement. As described above, the bonus generally consisted of our board's determination of performance in two areas: performance of the company during 2010 as compared to our budgeted plan and individual performance. Each component could earn the executive up to 50% of the bonus amount that our board determined to pay in the aggregate. Based on its analysis of our performance in 2010 and based on recommendations of our CEO on individual performances of each executive (or, in the case of our CEO, our board's evaluation of his performance), our board authorized cash bonuses for our named executive officers as follows:

•: Mr. McCarroll—$400,000, or 100% of base salary;
•: Mr. Tate—$155,000, or 70% of base salary; and
•: Mr. Jo—$175,000, or 71% of base salary.

2011. Our board has not met to consider bonuses for the fiscal year ending December 31, 2011. We anticipate that our board will follow the same process for 2011 as described above for 2010.

108

Table of Contents

2012 and going forward. For 2012 and subsequent years, we intend to continue to provide annual incentive cash bonuses to reward achievement of financial or operational goals so that total direct compensation more accurately reflects actual company and individual performance. We expect that any formal compensation committee of our board would continue this policy. We are reviewing information prepared by Longnecker to determine the appropriate types of goals to be used in determining cash bonuses to align our executive officers' compensation with the performance of the company as a whole. We expect that specific details regarding each executive's future bonus potential will be set forth in the amended and restated employment agreements that are described in greater detail below.

Long-Term Incentives

As a private limited partnership, we historically have offered long-term incentives to our executive officers through grants of Class B Units in Dynamic Offshore Holding, LP ("DOH"). These Class B Units represent an interest in the future profits of DOH and are intended to be treated as "profits interests" for federal income tax purposes rather than capital interests. Profits interests have no value for tax purposes on the date of grant, but instead are designed to gain value only after DOH has realized a certain return hurdle, defined in the DOH partnership agreement as the amount of aggregate capital contributions plus a preferred rate of return on the capital contributions. Generally, this means that DOH distributions will first be made to "Class A Unit" holders until such holders have received a full return on their capital contributions to DOH. Second, distributions will be divided between the Class A Unit and Class B Unit holders, with the Class B Unit holders receiving an individual sharing percentage of 20% of the total distribution.

The Class B Units are subject to both time-vesting requirements as well as the return hurdle requirement, which we believe provides an incentive for our named executive officers to grow the value of our company. Each unit will vest in equal installments annually over a four year period, although vesting will be immediately accelerated upon a DOH change in control or liquidity event (which is described in more detail within the "Potential Payments Upon Termination or a Change in Control" section below). If a Class B Unit holder terminates his or her employment prior to vesting, the unit will be forfeited. The actual number of Class B Units held by our named executive officers and the associated vesting schedules are described in the "Outstanding Equity Awards at 2011 Fiscal Year-End" table below.

As part of our corporate reorganization in connection with this offering, DOH will be merged into Dynamic Offshore Resources, Inc., and the Class B Units will be converted into the right to receive common stock at a conversion rate to be determined based on the offering price of our common stock to the public. All of the Class B Units also will fully vest upon the completion of this offering. Please read "Corporate Reorganization" beginning on page 131.

To create incentives for our executive officers to continue to grow our company, we are in the process of evaluating a formal long-term incentive plan. We intend to adopt the formal plan in connection with the completion of this offering. The material terms of the plan that we intend to adopt are described below. We believe that having an equity component to our compensation program is vital to align our executive officers' interests with our stockholders' interests through shared ownership. Longnecker will help us design the long-term incentive plan by providing a survey of the main components of long-term incentive plans for similarly-situated public companies.

2012 Long Term Incentive Plan

Our board of directors intends to adopt a 2012 Long Term Incentive Plan (the "LTIP") to be effective prior to the consummation of this offering, in order to attract and retain the best personnel for positions of substantial responsibility, to provide additional incentives to our employees, directors and consultants, and to promote the success of our business. The LTIP will provide for grants of

109

Table of Contents

(a) incentive stock options qualified as such under the Code, (b) nonqualified stock options that do not qualify as incentive stock options, (c) stock appreciation rights ("SARs"), (d) restricted stock awards, (e) restricted stock units, (f) performance awards, (g) stock awards, (h) other incentive awards, or (i) any combination of such awards.

The LTIP is not subject to the Employee Retirement Income Security Act of 1974, as amended ("ERISA"). The LTIP, for a limited period of time following this offering, will qualify for an exception to the deductibility limitations imposed by Section 162(m) of the Code. As a result, during that limited period of time, certain awards will be exempt from the limitations on the deductibility of compensation that exceeds $1,000,000.

Shares Available. The maximum aggregate number of shares of our common stock that may be reserved and available for delivery in connection with awards under the LTIP is 11,500,000, subject to adjustment in accordance with the terms of the LTIP. This number includes 743,831 shares of our common stock to be granted in connection with this offering to the former bonus pool participants at DOH (none of whom is an executive officer). If common stock subject to any award is not issued or transferred, or ceases to be issuable or transferable for any reason, including stock subject to an award that is cancelled, forfeited or settled in cash, those shares of common stock will again be available for delivery under the LTIP to the extent allowable by law. Except for adjustments made in accordance with the terms of the LTIP, no award may be repriced, replaced, regranted through cancellation or modified without shareholder approval, if the effect would be to reduce the exercise price for the shares underlying such award, and the Plan Administrator may not cancel an outstanding option that is under water for the purpose of granting a replacement award of a different type. The maximum number of shares of common stock that may be subject to stock options and SARs granted under the LTIP to any one participant during a fiscal year is 3,450,000 shares. The maximum aggregate number of shares that may be issued under the LTIP through incentive stock options is 11,500,000 shares.

Eligibility. Any individual who provides services to us or our affiliates, including officers, employees, non-employee directors and consultants, is eligible to participate in the LTIP (each, an "Eligible Person"). Each Eligible Person who is designated by the board of directors (or a committee thereof performing the functions of a compensation committee) (the "Plan Administrator") to receive an award under the LTIP will be a "Participant." An Eligible Person will be eligible to receive an award pursuant to the terms of the LTIP and subject to any limitations imposed by appropriate action of the Plan Administrator.

Administration. The Plan Administrator will administer the LTIP pursuant to its terms, except in the event our board of directors chooses to take action under the LTIP. Unless otherwise limited by our board of directors, the Plan Administrator has broad discretion to administer the LTIP, including the power to determine to whom and when awards will be granted, to determine the amount of such awards (measured in cash, shares of common stock or as otherwise designated), to prescribe and interpret the terms and provisions of each award agreement, to accelerate the exercise terms of any award, to delegate duties under the LTIP and to execute all other responsibilities permitted or required under the LTIP.

Terms of Options. The Plan Administrator may grant options to Eligible Persons including (a) incentive stock options (only to our employees) that comply with Section 422 of the Code and (b) nonqualified stock options. The exercise price for an option must not be less than the greater of (a) the par value per share of common stock or (b) the fair market value per share as of the date of grant. Options may be exercised as the Plan Administrator determines, but not later than ten years from the date of grant. Any incentive stock option granted to an employee who possesses more than 10% of the total combined voting power of all classes of our shares within the meaning of Section 422(b)(6) of the Code must have an exercise price of at least 110% of the fair market value of

110

Table of Contents

the underlying shares at the time the option is granted and may not be exercised later than five years from the date of grant.

Terms of SARs. SARs may be awarded in connection with or separate from an option. A SAR is the right to receive an amount equal to the excess of the fair market value of one share of our common stock on the date of exercise over the grant price of the SAR. The grant price of a SAR must be

Dynamic Offshore Resources, Inc. S-1/A