Filed pursuant to Rule 424(b)(3)

Registration No. 333-137441

PROSPECTUS

 

$300,000,000

71/2% Senior Notes due 2013

 

The Offer to Exchange
$300,000,000 71/2% Senior Notes due 2013
that have been registered under the Securities Act of 1933
for any and all
$300,000,000 71/2% Senior Notes due 2013
expired at 5:00 P.M.,
New York City time, on November 9, 2006.

 

We offered to exchange an aggregate principal amount of $300,000,000 of registered 71/2% Senior Notes due 2013, which we refer to as the new notes, for any and all of our original unregistered 71/2% Senior Notes due 2013 that were issued in a private offering on April 24, 2006, which we refer to as the old notes. The exchange offer expired at 5:00 p.m., New York City time, on November 9, 2006, which we refer to as the exchange date. Each broker-dealer (other than an affiliate of ours) that receives new notes for its own account in the exchange offer in exchange for securities that were acquired by such broker-dealer as a result of market-making or other trading activities must deliver a prospectus meeting the requirements of the Securities Act of 1933 in connection with any resale of new notes. We have agreed that, for a period of 90 days after the exchange date, we will make the prospectus available to any broker-dealer for use in connection with any such resale.

 

Terms of the exchange offer:

 

 

See “Risk Factors” beginning on page 18 for a discussion of risks you should consider in connection with the notes.

 

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

 

We may amend or supplement this prospectus from time to time by filing amendments or supplements as required. You should read this entire prospectus and related documents and any amendments or supplements to this prospectus carefully before making your investment decision.

 

The date of this prospectus is November 22, 2006.

 

TABLE OF CONTENTS

 

 

THIS PROSPECTUS IS PART OF A REGISTRATION STATEMENT WE FILED WITH THE SECURITIES AND EXCHANGE COMMISSION, OR SEC. IN MAKING YOUR INVESTMENT DECISION, YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED IN THIS PROSPECTUS, IN THE ACCOMPANYING LETTER OF TRANSMITTAL OR THE INFORMATION TO WHICH WE HAVE REFERRED YOU. WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH ANY OTHER INFORMATION. IF YOU RECEIVE ANY UNAUTHORIZED INFORMATION, YOU MUST NOT RELY ON IT. THIS PROSPECTUS MAY ONLY BE USED WHERE IT IS LEGAL TO EXCHANGE THE OLD NOTES. YOU SHOULD NOT ASSUME THAT THE INFORMATION CONTAINED IN THIS PROSPECTUS IS ACCURATE AS OF ANY DATE OTHER THAN THE DATE ON THE FRONT COVER OF THIS PROSPECTUS.

 

Until January 8, 2007, all dealers that effect transactions in these securities, whether or not participating in this exchange offer, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

 

Various statements in this prospectus, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. Our forward-looking statements are generally accompanied by words such as “may,” “will,” “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. The forward-looking statements in this prospectus speak only as of the date of this prospectus; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this prospectus. These risks, contingencies and uncertainties relate to, among other matters, the following:

 

 

We file annual, quarterly and current reports, proxy statements and other information with the SEC. Our SEC filings are available to the public over the Internet at the SEC’s web site at www.sec.gov. You also may read and copy any document we file at the SEC’s public reference room in Washington, D.C. Please call the SEC at 1-800-SEC-0330 for further information about the public reference room. Reports and other information concerning us can also be inspected at the offices of the New York Stock Exchange, 20 Broad Street, New York, New York 10005. Our common stock is listed and traded on the New York Stock Exchange under the trading symbol “ME.”

 

You may request a copy of these filings, which we will provide to you at no cost, by writing or telephoning us at the following address: Mariner Energy, Inc., One Briar Lake Plaza, Suite 2000, 2000 West Sam Houston Parkway South, Houston, Texas 77004. Our phone number is (713) 954-5555. Our website address is www.mariner-energy.com. The information on our website is not a part of this prospectus.

 

We filed a registration statement on Form S-4 to register with the SEC the new notes issued in exchange for the old notes and guarantees thereof. This prospectus is part of that registration statement. As allowed by the SEC’s rules, this prospectus does not contain all of the information you can find in the registration statement or the exhibits to the registration statement. You should note that where we summarize in the prospectus the material terms of any contract, agreement or other document filed as an exhibit to the registration statement, the summary information provided in the prospectus is less complete than the actual contract, agreement or document. You should refer to the exhibits filed to the registration statement for copies of the actual contract, agreement or document.

 

PROSPECTUS SUMMARY

																		Pro Forma
																		Production for
																		Year Ended
		Pro Forma																December 31,
		Estimated Proved																2005
		Reserve Quantities												Pro Forma				(Natural
		Oil				Natural				Total				Total Net				Gas
Geographic Area		(MMbbls)				Gas (Bcf)				(Bcfe)				Acreage				Equivalent (Bcfe))
West Texas			16.7				105.5				205.5				31,199				6.6
Gulf of Mexico Deepwater(1)			4.8				95.7				124.5				241,320				14.0
Gulf of Mexico Shelf(2)			12.7				237.6				313.7				652,086				74.3
Total			34.2				438.8				643.7				924,605				94.9
Proved Developed Reserves			18.4				252.1				362.3

(1)		Deepwater refers to water depths greater than 1,300 feet (the approximate depth of deepwater designation for royalty purposes by the U.S. Minerals Management Service).
(2)		Shelf refers to water depths less than 1,300 feet and includes an insignificant amount of Gulf Coast onshore properties.

Old Notes		71/2% Senior Notes due April 15, 2013, which were issued on April 24, 2006.
New Notes		71/2% Senior Notes due April 15, 2013. The terms of the new notes are substantially identical to those terms of the old notes, except that the transfer restrictions, registration rights and special interest provisions relating to the old notes do not apply to the new notes.
Exchange Offer		We offered to exchange $300.0 million principal amount of our new notes that have been registered under the Securities Act for an equal amount of our old notes to satisfy our obligations under the registration rights agreement.
		The new notes evidence the same debt as the old notes and are issued under and entitled to the benefits of the same indenture that governs the old notes. Holders of the old notes do not have any appraisal or dissenter’s rights in connection with the exchange offer. Because the new notes are registered, the new notes will not be subject to transfer restrictions, and holders of old notes that have tendered and had their old notes accepted in the exchange offer have no registration rights.
Expiration Date		The exchange offer expired at 5:00 P.M., New York City time, on November 9, 2006. The ability to withdraw tenders of old notes pursuant to the exchange offer ceased upon expiration of the exchange offer.

Issuer		Mariner Energy, Inc.
Notes Offered		$300,000,000 principal amount of its 71/2% Senior Notes due 2013.
Maturity Date		April 15, 2013.
Interest Rate		71/2% per year (calculated using a 360-day year).
Interest Payment Dates		Each April 15 and October 15, beginning October 15, 2006.
Ranking		The notes are our general unsecured senior obligations. Accordingly, they rank:
		• effectively subordinate to all of our existing and future secured indebtedness, including indebtedness under our credit facility, to the extent of the collateral securing such indebtedness;
		• effectively subordinate to all existing and future indebtedness and other liabilities of any non-guarantor subsidiaries (other than indebtedness and liabilities owed to us);
		• pari passu in right of payment to all of our existing and future senior unsecured indebtedness; and
		• senior in right of payment to any future subordinated indebtedness.
		As of September 30, 2006, we had total indebtedness of approximately $614 million, $300 million of which was the notes, and approximately $314 million of which was secured indebtedness to which the notes effectively were subordinated as to the value of the collateral. We also then had three letters of credit outstanding for $40.0 million, $10.4 million and $4.2 million, each of which effectively was senior to the notes to the extent of the collateral securing such indebtedness.
Subsidiary Guarantees		The notes are jointly and severally guaranteed on a senior unsecured basis by our existing and future domestic subsidiaries. In the future, the guarantees may be released or terminated under certain circumstances. Each subsidiary guarantee ranks:
		• effectively subordinate to all existing and future secured indebtedness of the guarantor subsidiary, including its guarantee of indebtedness under our credit facility, to the extent of the collateral securing such indebtedness;
		• pari passu in right of payment to all existing and future senior unsecured indebtedness of the guarantor subsidiary; and
		• senior in right of payment to any future subordinated indebtedness of the guarantor subsidiary.

		As of September 30, 2006, the guarantor subsidiary Mariner Energy Resources, Inc. had approximately $176.2 million of unsecured indebtedness outstanding under an intercompany note payable to us. The other two guarantor subsidiaries were guarantors but not indebted under our senior secured credit facility and had no other indebtedness outstanding.
Optional Redemption		At any time prior to April 15, 2009, we may redeem up to 35% of each of the notes with the net cash proceeds of certain equity offerings at the redemption prices set forth under “Description of Senior Notes — Optional Redemption,” if at least 65% of the aggregate principal amount of the notes issued under the indenture remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering.
		At any time prior to April 15, 2010, we may redeem the notes, in whole or in part, at a “make whole” redemption price set forth under “Description of Senior Notes — Optional Redemption.” On and after April 15, 2010, we may redeem the notes, in whole or in part, at the redemption prices set forth under “Description of Senior Notes — Optional Redemption.”
Change of Control Triggering Event		If a Change of Control Triggering Event occurs, we must offer to repurchase the notes at the redemption price set forth under “Description of Senior Notes — Repurchase at the Option of Holders — Change of Control.”
Certain Covenants		The indenture governing the notes contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to:
		• make investments;
		• incur additional indebtedness or issue preferred stock;
		• create certain liens;
		• sell assets;
		• enter into agreements that restrict dividends or other payments from our subsidiaries to us;
		• consolidate, merge or transfer all or substantially all of the assets of our company;
		• engage in transactions with affiliates;
		• pay dividends or make other distributions on capital stock or subordinated indebtedness; and
		• create unrestricted subsidiaries.

		These covenants are subject to important exceptions and qualifications. In addition, substantially all of the covenants will terminate before the notes mature if one of two specified ratings agencies assigns the notes an investment grade rating in the future and no events of default exist under the indentures. Any covenants that cease to apply to us as a result of achieving an investment grade rating will not be restored, even if the credit rating assigned to the notes later falls below an investment grade rating. See “Description of Senior Notes — Certain Covenants.”
Absence of Established Market for the Notes		The new notes are generally freely transferable but are also new securities for which there will not initially be a market. Accordingly, we cannot assure you as to the development or liquidity of any market for the new notes. The notes will be eligible for trading in the PORTALsm Market. We do not intend to apply for a listing of the new notes on any securities exchange or for the inclusion on any automated dealer quotation system.
Use of Proceeds		We will not receive any proceeds from the exchange offer.

		Post-2004 Merger																	Pre-2004 Merger
														Period from					Period from
														March 3,					January 1,
														2004					2004
		Nine Months Ended								Year Ended				through					through
		September 30,								December 31,				December 31,					March 2,				Year Ended December 31,
		2006				2005				2005				2004					2004				2003				2002				2001
		(In millions, except per share data)
Statement of Operations Data:
Total revenues(1)		$	438.4			$	151.2			$	199.7			$	174.4				$	39.8			$	142.5			$	158.2			$	155.0
Lease operating expenses			62.9				17.7				24.9				19.3					3.5				23.2				25.2				19.2
Severance and ad valorem taxes			5.7				2.5				5.0				2.1					0.6				1.5				0.9				0.9
Transportation expenses			4.0				1.7				2.3				1.9					1.1				6.3				10.5				12.0
Depreciation, depletion and amortization			192.2				43.4				59.4				54.3					10.6				48.3				70.8				63.5
Impairment of production equipment held for use			—				0.5				1.8				1.0					—				—				—				—
Derivative settlement			—				—				—				—					—				3.2				—				—
Impairment of Enron related receivables			—				—				—				—					—				—				3.2				29.5
General and administrative expenses			25.1				26.7				37.1				7.6					1.1				8.1				7.7				9.3
Operating income			148.5				58.7				69.2				88.2					22.9				51.9				39.9				20.6
Interest income			0.5				0.7				0.8				0.2					0.1				0.8				0.4				0.7
Interest expense			(26.4	)			(5.4	)			(8.2	)			(6.0	)				—				(7.0	)			(10.3	)			(8.9	)
Income before income taxes			122.6				54.0				61.8				82.4					23.0				45.7				30.0				12.4
Provision for income taxes			(44.4	)			(18.4	)			(21.3	)			(28.8	)				(8.1	)			(9.4	)			—				—
Income before cumulative effect of change in accounting method net of tax effects		$	78.2			$	35.6				40.5				53.6					14.9				36.3				30.0				12.4
Income before cumulative effect per common share
Basic		$	1.07			$	1.10				1.24				1.80					0.50				1.22				1.01				0.42
Diluted			1.06				1.07				1.20				1.80					0.50				1.22				1.01				0.42
Cumulative effect of changes in accounting method			—				—				—				—					—				1.9				—				—
Net income		$	78.2			$	35.6			$	40.5			$	53.6				$	14.9			$	38.2			$	30.0			$	12.4
Net income per common share
Basic		$	1.07			$	1.10			$	1.24			$	1.80				$	0.50			$	1.29			$	1.01			$	0.42
Diluted			1.06				1.07				1.20				1.80					0.50				1.29				1.01				0.42
Capital Expenditure and Disposal Data:
Exploration, including leasehold/seismic			169.1				23.6			$	60.9			$	40.4				$	7.5			$	31.6			$	40.4			$	66.3
Development and other			347.9				106.8				191.8				93.2					7.8				51.7				65.7				98.2
Proceeds from property conveyances			(2.0	)			—				—				—					—				(121.6	)			(52.3	)			(90.5	)
Total capital expenditures net of proceeds from property conveyances			515.0				130.4			$	252.7			$	133.6				$	15.3			$	(38.3	)		$	53.8			$	74.0

(1)		Includes effects of hedging.

		Post-2004 Merger																	Pre-2004 Merger
		September 30,								December 31,				December 31,					December 31,
		2006				2005				2005				2004					2003				2002				2001
		(In millions)
Balance Sheet Data(1)
Property and equipment, net, full cost method		$	2,061.9			$	393.3			$	515.9			$	303.8				$	207.9			$	287.6			$	290.6
Total assets			2,700.7				502.2				665.5				376.0					312.1				360.2				363.9
Long-term debt, less current maturities			614.0				79.0				156.0				115.0					—				99.8				99.8
Stockholders’ equity			1,267.1				178.6				213.3				133.9					218.2				170.1				180.1
Working capital (deficit)(2)			(75.3	)			(30.2	)			(46.4	)			(18.7	)				38.3				(24.4	)			(19.6	)
Other Financial Data
Ratio of earnings to fixed charges(3)			5.43				10.23				7.88				17.17					6.83				3.56				1.82

(1)		Balance sheet data as of September 30, 2006 reflects consolidation of the assets of the Forest Gulf of Mexico operations effective March 2, 2006. Balance sheet data as of December 31, 2004 reflects purchase accounting adjustments to oil and gas properties, total assets and stockholders’ equity resulting from the acquisition of our former indirect parent on March 2, 2004.
(2)		Working capital (deficit) excludes current derivative assets and liabilities, deferred tax assets and restricted cash.
(3)		For the purposes of determining the ratio of earnings to fixed charges, earnings consist of income before taxes, plus fixed charges, less capitalized interest, and fixed charges consist of interest expense (net of capitalized interest), plus capitalized interest, plus amortized discounts related to indebtedness.

		Post-2004 Merger																	Pre-2004 Merger
														Period from					Period from
														March 3,					January 1,
														2004					2004
		Nine Months Ended								Year Ended				through					through
		September 30,								December 31,				December 31,					March 2,				Year Ended December 31,
		2006				2005				2005				2004					2004				2003				2002				2001
		(In millions)
Other Financial Data:
EBITDA(1)		$	340.7			$	102.7			$	130.4			$	143.5				$	33.4			$	100.3			$	113.9			$	113.6
Net cash provided by operating activities			172.8				135.4				165.4				135.2					20.3				88.9				60.3				113.5
Net cash (used) provided by investing activities			(423.5	)			(142.1	)			(247.8	)			(133.0	)				(15.3	)			52.9				(53.8	)			(74.0	)
Net cash (used) provided by financing activities			251.0				8.7				84.4				64.9					—				(100.0	)			—				(30.0	)
Reconciliation of Non-GAAP Measures:
EBITDA(1)		$	340.7			$	102.7			$	130.4			$	143.5				$	33.4			$	100.3			$	113.9			$	113.6
Changes in working capital			(158.9	)			25.1				20.0				6.2					(13.2	)			7.2				(20.4	)			7.5
Non-cash hedge gain/(loss)(2)			8.2				(3.6	)			(4.5	)			(7.9	)				—				(2.0	)			(23.2	)			—
Amortization/other			(0.3	)			0.9				1.2				0.8					—				—				(0.1	)			0.6
Stock compensation expense			9.0				17.6				25.7				—					—				—				—				—
Net interest expense			(25.9	)			(4.7	)			(7.4	)			(5.8	)				0.1				(6.2	)			(9.9	)			(8.2	)
Income tax expense			—				(2.6	)			—				(1.6	)				—				(10.4	)			—				—
Net cash provided by operating activities		$	172.8			$	135.4			$	165.4			$	135.2				$	20.3			$	88.9			$	60.3			$	113.5

(1)		EBITDA means earnings before interest, income taxes, depreciation, depletion and amortization and impairments. For the nine months ended September 30, 2006 and 2005, EBITDA includes $9.0 million and $17.6 million, respectively, in non-cash compensation expense related to restricted stock and stock options. For the year ended December 31, 2005, EBITDA includes $25.7 million in non-cash compensation expense related to restricted stock and stock options granted in 2005. We believe that EBITDA is a widely accepted financial indicator that provides additional information about our ability to meet our future requirements for debt service, capital expenditures and working capital, but EBITDA should not be considered in isolation or as a substitute for net income, operating income, net cash provided by operating activities or any other measure of financial performance presented in accordance with generally accepted accounting principles or as a measure of a company’s profitability or liquidity.
(2)		In accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137 and No. 138, we de-designated our contracts effective December 2, 2001 after the counterparty (an affiliate of Enron Corp.) filed for bankruptcy and recognized all market value changes subsequent to such de-designation in our earnings. The value recorded up to the time of dedesignation and included in Accumulated Other Comprehensive Income (“AOCI”), has reversed out of AOCI and into earnings as the original corresponding production, as hedged by the contracts, is produced. In accordance with purchase price accounting implemented at the time of the merger of our former indirect parent on March 2, 2004, we recorded the mark to market liability of our hedge contracts at such date totaling $12.4 million as a liability on our balance sheet. The value at the time of the merger and included in AOCI has reversed out of AOCI and into earnings as the original corresponding production, as hedged by the contracts, is produced. We have designated subsequent hedge contracts as cash flow hedges with gains and losses resulting from the transactions recorded at market value in AOCI, as appropriate, until recognized as operating income in our Statement of Operations as the physical production hedged by the contracts is delivered.

		Nine Months				Year Ended
		Ended				December 31,
		September 30, 2006				2005
		(In millions, except earnings per share and share data)
OPERATING RESULTS:
Revenues		$	505.9			$	592.0
Net income			92.6				58.0
Earnings per share
Basic		$	1.09			$	0.70
Diluted		$	1.09			$	0.69
Weighted average shares outstanding
Basic			84,770,289				83,304,592
Diluted			85,245,547				84,454,427

		Pro Forma				As of the Year Ended
		Year Ended				December 31,
		December 31, 2005				2005				2004				2003
Estimated proved oil and natural gas reserves:
Natural gas reserves (Bcf)			438.8				207.7				151.9				127.6
Oil (MMbbls)			34.1				21.6				14.3				13.1
Total proved oil and natural gas reserves (Bcfe)			643.7				337.6				237.5				206.1
Total proved developed reserves (Bcfe)			362.3				167.4				109.4				96.6
PV10 value ($ in millions):
Proved developed reserves		$	2,023.4			$	849.6			$	335.4			$	314.6
Proved undeveloped reserves			1,028.4				432.2				332.6				218.9
Total PV10 value			3,051.8				1,281.8				668.0				533.5
Standardized measure			2,201.7				906.6				494.4				418.2
Prices used in calculating end of period proved reserve measures (excluding effects of hedging)(1):
Natural gas ($/MMBtu)		$	10.05			$	10.05			$	6.15			$	5.96
Oil ($/bbl)			61.04				61.04				43.45				32.52

(1)		Our PV10 values have been calculated using NYMEX prices at the end of the relevant period, as adjusted for our price differentials. Please read Note 11 to the audited Mariner financial statements contained in this prospectus.

		Pro Forma								Nine Months
		Nine Months				Year Ended				Ended
		Ended				December 31,				September 30,				Year Ended December 31,
		September 30, 2006				2005				2006				2005				2004				2003
Production:
Natural gas (Bcf)			45.6				67.5				39.3				18.4				23.8				23.8
Oil (Mbbls)			2.8				4.6				2.5				1.8				2.3				1.6
Total natural gas equivalent (Bcfe)			62.4				94.9				54.5				29.1				37.6				33.4
Average daily natural gas equivalent (MMcfe)			228.5				260.0				200.0				79.7				103.0				91.5
Average realized sales price per unit (excluding the effects of hedging):
Natural gas ($/Mcf)		$	7.25			$	8.04			$	7.05			$	8.33			$	6.12			$	5.43
Oil ($/bbl)			61.23				48.86				62.13				51.66				38.52				26.85
Total natural gas equivalent ($/Mcfe)			8.05				8.07				7.94				8.43				6.23				5.15
Average realized sales price per unit (including the effects of hedging):
Natural gas ($/Mcf)		$	7.42			$	6.40			$	7.25			$	6.66			$	5.80			$	4.40
Oil ($/bbl)			58.95				34.18				59.58				41.23				33.17				23.74
Total natural gas equivalent ($/Mcfe)			8.07				6.20				8.00				6.74				5.70				4.27
Expenses ($/Mcfe):
Lease operating expenses		$	1.26			$	1.04			$	1.15			$	0.86			$	0.61			$	0.69
Severance and ad valorem taxes			0.10				0.13				0.10				0.17				0.07				0.05
Transportation			0.07				0.06				0.07				0.08				0.08				0.19
General and administrative, net(1)			—				—				0.46				1.27				0.23				0.24
Depreciation, depletion and amortization (excluding impairments)(2)			3.51				3.47				3.53				2.04				1.73				1.45

(1)		Net of overhead reimbursements received from other working interest owners and amounts capitalized under the full cost accounting method. Includes non-cash stock compensation expense of $9.0 million for the nine months ended September 30, 2006 and $17.6 million in 2005. General and administrative expenses, net of capitalized amounts, are not included in pro forma 2005 because accounts of such costs were not historically maintained for the Forest Gulf of Mexico operations as a separate business unit. We

		believe the overhead costs associated with the Forest Gulf of Mexico operations in 2006 will approximate $6.4 million, net of capitalized amounts.
(2)		Pro forma depreciation, depletion and amortization gives effect to the acquisition of the Forest Gulf of Mexico operations and a preliminary estimate of their step-up in value basis the unit of production method under the full cost method of accounting.

 

You should consider carefully the following risks, as well as the other information set forth in this prospectus, before deciding to participate in the exchange offer. Any of the following risks could materially adversely affect our business, financial condition or results of operations, which in turn could adversely affect our ability to pay the notes. In such case, you may lose all or part of your original investment.

 

Risks Related to the Exchange Offer

 

If you do not properly tender your old notes, you will continue to hold unregistered outstanding notes and your ability to transfer those notes will be adversely affected.

 

If you do not exchange your old notes for new notes in the exchange offer, you will continue to be subject to the restrictions on transfer of your old notes described in the legend on the certificates representing your old notes. In general, you may only offer or sell the old notes if they are registered under the Securities Act and applicable state securities laws or offered and sold under an exemption from those requirements. We do not plan to register any sale of the old notes under the Securities Act unless required to do so under the limited circumstances set forth in the registration rights agreement. In addition, the issuance of the new notes may adversely affect the trading market for untendered, or tendered but unaccepted, old notes. For further information regarding the consequences of not tendering your old notes in the exchange offer, see “The Exchange Offer — Consequences of Failure to Exchange” and “Material United States Federal Income Tax Considerations.”

 

We will only issue new notes in exchange for old notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of the old notes and you should carefully follow the instructions on how to tender your old notes. Neither we nor the exchange agent is required to tell you of any defects or irregularities with respect to your tender of old notes. See “The Exchange Offer — Procedures for Tendering Old Notes” and “Description of Senior Notes.”

 

You may find it difficult to sell your new notes.

 

Because there is no public market for the new notes, you may not be able to resell them. The new notes will be registered under the Securities Act but will constitute a new issue of securities with no established trading market. An active market may not develop for the new notes and any trading market that does develop may not be liquid. We do not intend to apply to list the new notes for trading on any securities exchange or to arrange for quotation on any automated dealer quotation system. The trading market for the new notes may be adversely affected by:

 

 

Historically, the market for non-investment grade debt has been subject to substantial volatility in prices. The market for the new notes, if any, may be subject to similar volatility. Prospective investors in the new notes should be aware that they may be required to bear the financial risks of such investment for an indefinite period of time.

 

Some holders who exchange their old notes may be deemed to be underwriters.

 

If you exchange your old notes in the exchange offer for the purpose of participating in a distribution of the new notes, you may be deemed to have received restricted securities and, if so, will be required to comply

with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction. See “The Exchange Offer — Resale of the New Notes; Plan of Distribution.”

 

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

 

Oil and natural gas prices are volatile, and a decline in oil and natural gas prices would reduce our revenues, profitability and cash flow and impede our growth.

 

Our revenues, profitability and cash flow depend substantially upon the prices and demand for oil and natural gas. The markets for these commodities are volatile and even relatively modest drops in prices can affect significantly our financial results and impede our growth. Oil and natural gas prices are currently at or near historical highs and may fluctuate and decline significantly in the near future. Prices for oil and natural gas fluctuate in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control, such as:

 

 

Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because approximately 62% of our estimated proved reserves (68% on a pro forma basis) as of December 31, 2005 were natural gas reserves, our financial results are more sensitive to movements in natural gas prices. Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves and could have a material adverse effect on our financial condition and results of operations.

 

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will affect materially the quantities and present value of our reserves, which may lower our bank borrowing base and reduce our access to capital.

 

Estimating oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of the available technical data and making many assumptions about future conditions, including price and other economic conditions. In preparing estimates we project production rates and timing of development expenditures. We also analyze the available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. This 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. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates, perhaps significantly. 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. At December 31, 2005, 50% of our estimated proved reserves were proved undeveloped (44% on a pro forma basis).

 

If the interpretations or assumptions we use in arriving at our estimates prove to be inaccurate, the amount of oil and natural gas that we ultimately recover may differ materially from the estimated quantities and net present value of reserves shown in this prospectus. See “Business — Estimated Proved Reserves” for information about our oil and gas reserves.

 

In estimating future net revenues from proved reserves, we assume that future prices and costs are fixed and apply a fixed discount factor. If any such assumption or the discount factor is materially inaccurate, our revenues, profitability and cash flow could be materially less than our estimates.

 

The present value of future net revenues from our proved reserves referred to in this prospectus is not necessarily the actual current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on fixed prices and costs as of the date of the estimate. Actual future prices and costs fluctuate over time and may differ materially from those used in the present value estimate. In addition, discounted future net cash flows are estimated assuming that royalties to the Minerals Management Service, or MMS, with respect to our affected offshore Gulf of Mexico properties will be paid or suspended for the life of the properties based upon oil and natural gas prices as of the date of the estimate. See “Business — Royalty Relief,” and “Business — Legal Proceedings.” Since actual future prices fluctuate over time, royalties may be required to be paid for various portions of the life of the properties and suspended for other portions of the life of the properties.

 

The timing of both the production and expenses from the development and production of oil and natural gas properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. In addition, the 10% discount factor that we use to calculate the net present value of future net cash flows for reporting purposes in accordance with the SEC’s rules may not necessarily be the most appropriate discount factor. The effective interest rate at various times and the risks associated with our business or the oil and gas industry in general will affect the appropriateness of the 10% discount factor in arriving at an accurate net present value of future net cash flows.

 

If oil and natural gas prices decrease, we may be required to write-down the carrying value and/or the estimates of total reserves of our oil and natural gas properties.

 

Accounting rules applicable to us require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write-down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. We may incur non-cash charges in the future, which could have a material adverse effect on our results of operations in the period taken. We may also reduce our estimates of the reserves that may be economically recovered, which could have the effect of reducing the value of our reserves.

 

We need to replace our reserves at a faster rate than companies whose reserves have longer production periods. Our failure to replace our reserves would result in decreasing reserves and production over time.

 

Unless we conduct successful exploration and development activities or acquire properties containing proven reserves, our proved reserves will decline as reserves are depleted. Producing oil and natural gas reserves are generally characterized by declining production rates that vary depending on reservoir characteristics and other factors. High production rates generally result in recovery of a relatively higher percentage of reserves from properties during the initial few years of production. A significant portion of our current operations are conducted in the Gulf of Mexico, especially since our merger with Forest Energy Resources. Production from reserves in the Gulf of Mexico generally declines more rapidly than reserves from reservoirs in other producing regions. As a result, our need to replace reserves from new investments is relatively greater than those of producers who produce their reserves over a longer time period, such as those

producers whose reserves are located in areas where the rate of reserve production is lower. If we are not able to find, develop or acquire additional reserves to replace our current and future production, our production rates will decline even if we drill the undeveloped locations that were included in our proved reserves. Our future oil and natural gas reserves and production, and therefore our cash flow and income, are dependent on our success in economically finding or acquiring new reserves and efficiently developing our existing reserves.

 

Approximately 65% of our total estimated proved reserves are either developed non-producing or undeveloped (71% on a pro forma basis), and those reserves may not ultimately be produced or developed.

 

As of December 31, 2005, approximately 15% of our total estimated proved reserves were developed non-producing (27% on a pro forma basis) and approximately 50% were undeveloped (44% on a pro forma basis). These reserves may not ultimately be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be ultimately produced during the time periods we have planned, at the costs we have budgeted, or at all, which in turn may have in a material adverse effect on our results of operations.

 

Any production problems related to our Gulf of Mexico properties could reduce our revenue, profitability and cash flow materially.

 

A substantial portion of our exploration and production activities is located in the Gulf of Mexico. This concentration of activity makes us more vulnerable than some other industry participants to the risks associated with the Gulf of Mexico, including delays and increased costs relating to adverse weather conditions such as hurricanes, which are common in the Gulf of Mexico during certain times of the year, drilling rig and other oilfield services and compliance with environmental and other laws and regulations.

 

Our exploration and development activities may not be commercially successful.

 

Exploration activities involve numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be discovered. In addition, the future cost and timing of drilling, completing and producing wells is often uncertain. Furthermore, drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

 

 

If any of these factors were to occur with respect to a particular project, we could lose all or a part of our investment in the project, or we could fail to realize the expected benefits from the project, either of which could materially and adversely affect our revenues and profitability.

 

Our exploratory drilling projects are based in part on seismic data, which is costly and cannot ensure the commercial success of the project.

 

Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often uncertain. Even when used and properly interpreted, 3-D seismic data and visualization

techniques only assist geoscientists and geologists in identifying subsurface structures and hydrocarbon indicators. 3-D seismic data does not enable an interpreter to conclusively determine whether hydrocarbons are present or producible economically. In addition, the use of 3-D seismic and other advanced technologies require greater predrilling expenditures than other drilling strategies. Because of these factors, we could incur losses as a result of exploratory drilling expenditures. Poor results from exploration activities could have a material adverse effect on our future cash flows, ability to replace reserves and results of operations.

 

Oil and gas drilling and production involve many business and operating risks, any one of which could reduce our levels of production, cause substantial losses or prevent us from realizing profits.

 

Our business is subject to all of the operating risks associated with drilling for and producing oil and natural gas, including:

 

 

If any of these events occurs, we could incur substantial losses as a result of injury or loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of our operations and repairs to resume operations.

 

Our offshore operations involve special risks that could increase our cost of operations and adversely affect our ability to produce oil and gas.

 

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. For more information on the impact of recent hurricanes on our operations, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments.”

 

Exploration for oil or natural gas in the deepwater of the Gulf of Mexico generally involves greater operational and financial risks than exploration on the shelf. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs. Our deepwater wells utilize subsea completion and tieback technology. As of September 30, 2006, we had 18 subsea wells. These wells were tied back to 13 host production facilities for production processing. An additional nine wells were then under development for tieback to five additional host production facilities. The installation of subsea production systems to tieback and operate subsea wells requires substantial time and the use of advanced and very sophisticated installation equipment supported by remotely operated vehicles. These operations may encounter mechanical difficulties and equipment failures that could result in significant cost overruns. Furthermore, the deepwater operations generally lack the physical

and oilfield service infrastructure present in the shallow waters of the Gulf of Mexico. As a result, a significant amount of time may elapse between a deepwater discovery and our marketing of the associated oil or natural gas, increasing both the financial and operational risk involved with these operations. Because of the lack and high cost of infrastructure, some reserve discoveries in the deepwater may never be produced economically.

 

Our hedging transactions may not protect us adequately from fluctuations in oil and natural gas prices and may limit future potential gains from increases in commodity prices or result in losses.

 

We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in oil and natural gas prices and to achieve more predictable cash flow. These financial arrangements typically take the form of price swap contracts and costless collars. Hedging arrangements expose us to the risk of financial loss in some circumstances, including situations when the other party to the hedging contract defaults on its contract or production is less than expected. During periods of high commodity prices, hedging arrangements may limit significantly the extent to which we can realize financial gains from such higher prices. For example, our hedging arrangements reduced the benefit we received from increases in the prices for oil and natural gas by approximately $49 million for the calendar year 2005 and increased the benefit we received by $1.5 million for the nine months ended September 30, 2006. Although we currently maintain an active hedging program, we may choose not to engage in hedging transactions in the future. As a result, we may be affected adversely during periods of declining oil and natural gas prices.

 

We will require additional capital to fund our future activities. If we fail to obtain additional capital, we may not be able to implement fully our business plan, which could lead to a decline in reserves.

 

We depend on our ability to obtain financing beyond our cash flow from operations. Historically, we have financed our business plan and operations primarily with internally generated cash flow, bank borrowings, proceeds from the sale of oil and natural gas properties, exploration arrangements with other parties, the issuance of debt securities, privately raised equity and, prior to the bankruptcy of Enron Corp. (our indirect parent company until March 2, 2004), borrowings from Enron affiliates. In the future, we will require substantial capital to fund our business plan and operations. We expect to be required to meet our needs from our excess cash flow, debt financings and additional equity offerings (subject to certain federal tax limitations during the two-year period following the spin-off). Sufficient capital may not be available on acceptable terms or at all. If we cannot obtain additional capital resources, we may curtail our drilling, development and other activities or be forced to sell some of our assets on unfavorable terms.

 

The issuance of additional debt would require that a portion of our cash flow from operations be used for the payment of interest on our debt, thereby reducing our ability to use our cash flow to fund working capital, capital expenditures, acquisitions and general corporate requirements, which could place us at a competitive disadvantage relative to other competitors. Additionally, if revenues decrease as a result of lower oil or natural gas prices, operating difficulties or declines in reserves, our ability to obtain the capital necessary to undertake or complete future exploration and development programs and to pursue other opportunities may be limited, which could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could result in a decline in our oil and natural gas reserves.

 

Properties we acquire (including the Forest Gulf of Mexico properties we acquired in March 2006) may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.

 

Properties we acquire, including the Forest Gulf of Mexico properties, may not produce as expected, may be in an unexpected condition and may subject us to increased costs and liabilities, including environmental liabilities. The reviews we conduct of acquired properties prior to acquisition are not capable of identifying all potential adverse conditions. Generally, it is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher value properties or properties with known adverse conditions and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems or permit a buyer to become sufficiently

familiar with the properties to assess fully their condition, any deficiencies, and development potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.

 

Market conditions or transportation impediments may hinder our access to oil and natural gas markets or delay our production.

 

Market conditions, the unavailability of satisfactory oil and natural gas transportation or the remote location of our drilling operations may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines or trucking and terminal facilities. In deepwater operations, the availability of a ready market depends on the proximity of and our ability to tie into existing production platforms owned or operated by others and the ability to negotiate commercially satisfactory arrangements with the owners or operators. We may be required to shut in wells or delay initial production for lack of a market or because of inadequacy or unavailability of pipeline or gathering system capacity. When that occurs, we are unable to realize revenue from those wells until the production can be tied to a gathering system. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and natural gas and realization of revenues.

 

The unavailability or high cost of drilling rigs, equipment, supplies or personnel could affect adversely our ability to execute on a timely basis our exploration and development plans within budget, which could have a material adverse effect on our financial condition and results of operations.

 

Shortages in availability or the high cost of drilling rigs, equipment, supplies or personnel could delay or affect adversely our exploration and development operations, which could have a material adverse effect on our financial condition and results of operations. An increase in drilling activity in the U.S. or the Gulf of Mexico could increase the cost and decrease the availability of necessary drilling rigs, equipment, supplies and personnel.

 

Competition in the oil and natural gas industry is intense, and many of our competitors have resources that are greater than ours giving them an advantage in evaluating and obtaining properties and prospects.

 

We operate in a highly competitive environment for acquiring prospects and productive properties, marketing oil and natural gas and securing equipment and trained personnel. Many of our competitors are major and large independent oil and natural gas companies, and possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more prospects and productive properties than our financial or personnel resources permit. Our ability to acquire additional prospects and discover reserves in the future will depend on our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Larger competitors may be better able to withstand sustained periods of unsuccessful drilling and absorb the burden of changes in laws and regulations more easily than we can, which would adversely affect our competitive position. 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.

 

Financial difficulties encountered by our farm-out partners or third-party operators could adversely affect our ability to timely complete the exploration and development of our prospects.

 

From time to time, we enter into farm-out agreements to fund a portion of the exploration and development costs of our prospects. Moreover, other companies operate some of the other properties in which we have an ownership interest. Liquidity and cash flow problems encountered by our partners and co-owners of our properties may lead to a delay in the pace of drilling or project development that may be detrimental to a project. In addition, our farm-out partners and working interest owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farm-out partner, we may have to

obtain alternative funding in order to complete the exploration and development of the prospects subject to the farm-out agreement. In the case of a working interest owner, we may be required to pay the working interest owner’s share of the project costs. We cannot assure you that we would be able to obtain the capital necessary in order to fund either of these contingencies.

 

We cannot control the timing or scope of drilling and development activities on properties we do not operate, and therefore we may not be in a position to control the associated costs or the rate of production of the reserves.

 

Other companies operate some of the properties in which we have an interest. As a result, we have a limited ability to exercise influence over operations for these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of drilling and development activities on properties operated by others therefore depend upon a number of factors that are outside of our control, including timing and amount of capital expenditures, the operator’s expertise and financial resources, approval of other participants in drilling wells and selection of technology.

 

Compliance with environmental and other government regulations could be costly and could affect production negatively.

 

Exploration for and development, production and sale of oil and natural gas in the U.S. and the Gulf of Mexico are subject to extensive federal, state and local laws and regulations, including environmental and health and safety laws and regulations. We may be required to make large expenditures to comply with these environmental and other requirements. Matters subject to regulation include, among others, environmental assessment prior to development, discharge and emission permits for drilling and production operations, drilling bonds, and reports concerning operations and taxation.

 

Under these laws and regulations, and also common law causes of action, we could be liable for personal injuries, property damage, oil spills, discharge of pollutants and hazardous materials, remediation and clean-up costs and other environmental damages. Failure to comply with these laws and regulations or to obtain or comply with required permits may result in the suspension or termination of our operations and subject us to remedial obligations as well as administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that substantially increase our costs. We cannot predict how agencies or courts will interpret existing laws and regulations, whether additional or more stringent laws and regulations will be adopted or the effect these interpretations and adoptions may have on our business or financial condition. For example, the Oil Pollution Act of 1990, or OPA, imposes a variety of regulations on “responsible parties” related to the prevention of oil spills. The implementation of new, or the modification of existing, environmental laws or regulations promulgated pursuant to the OPA could have a material adverse impact on us. Further, Congress or the MMS could decide to limit exploratory drilling or natural gas production in additional areas of the Gulf of Mexico. Accordingly, any of these liabilities, penalties, suspensions, terminations or regulatory changes could have a material adverse effect on our financial condition and results of operations. See “Business — Regulation” for more information on our regulatory and environmental matters.

 

Compliance with MMS regulations could significantly delay or curtail our operations or require us to make material expenditures, all of which could have a material adverse effect on our financial condition or results of operations.

 

A significant portion of our operations are located on federal oil and natural gas leases that are administered by the MMS. As an offshore operator, we must obtain MMS approval for our exploration, development and production plans prior to commencing such operations. The MMS has promulgated regulations that, among other things, require us to meet stringent engineering and construction specifications, restrict the flaring or venting of natural gas, govern the plug and abandonment of wells located offshore and

the installation and removal of all production facilities, and govern the calculation of royalties and the valuation of crude oil produced from federal leases.

 

Our insurance may not protect us against our 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. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all.

 

Although we maintain insurance at levels which we believe are appropriate and consistent with industry practice, we are not fully insured against all risks, including 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. The impact of Hurricanes Katrina and Rita have resulted in escalating insurance costs and less favorable coverage terms. In addition, we have not yet been able to determine the full extent of our insurance recovery and the net cost to us resulting from the hurricanes. See “Business — Insurance Matters” for more information.

 

Risks Relating to Our Merger with Forest Energy Resources

 

The integration of the Forest Gulf of Mexico operations will be difficult, and will divert our management’s attention away from our normal operations.

 

There is a significant degree of difficulty and management involvement inherent in the process of integrating the Forest Gulf of Mexico operations. These difficulties include:

 

 

The process of integrating our operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

 

If we fail to realize the anticipated benefits of the merger, our results of operations may be lower than we expect.

 

The success of the merger will depend, in part, on our ability to realize the anticipated growth opportunities from combining the Forest Gulf of Mexico operations with Mariner. Even if we are able to successfully combine the two businesses, it may not be possible to realize the full benefits of the proved

reserves, enhanced growth of production volume, cost savings from operating synergies and other benefits that we currently expect to result from the merger, or realize these benefits within the time frame that is currently expected. The benefits of the merger may be offset by operating losses relating to changes in commodity prices, or in oil and gas industry conditions, or by risks and uncertainties relating to the combined company’s exploratory prospects, or an increase in operating or other costs or other difficulties. If we fail to realize the benefits we anticipate from the merger, our results of operations may be adversely affected.

 

We expect to incur significant charges relating to the integration plan that could materially and adversely affect our period-to-period results of operations.

 

We anticipate that from time to time we will incur charges to our earnings in connection with the integration of the Forest Gulf of Mexico operations into our business. These charges will include expenses incurred in connection with relocating and retaining employees and increased professional and consulting costs. We also expect to incur significant expenses related to being a public company. We are not yet able to quantify the costs or timing of the integration. Some factors affecting the cost of the integration include the training of new employees, the amount of severance and other employee-related payments resulting from the merger, and the limited length of time during which transitional services were provided by Forest. During the nine months ended September 30, 2006, we incurred approximately $2.6 million of such costs.

 

In order to preserve the tax-free treatment of the spin-off of Forest Energy Resources, we are required to abide by potentially significant restrictions which could limit our ability to undertake certain corporate actions (such as the issuance of our common shares or the undertaking of a change in control) that otherwise could be advantageous.

 

In connection with the merger we entered into a tax sharing agreement, which imposes ongoing restrictions on Forest and on us to ensure that applicable statutory requirements under the Internal Revenue Code of 1986, as amended, or the Code, and applicable Treasury regulations continue to be met so that the spin-off of Forest Energy Resources remains tax-free to Forest and its shareholders. As a result of these restrictions, our ability to engage in certain transactions, such as the redemption of our common stock, the issuance of equity securities and the utilization of our stock as currency in an acquisition, will be limited for a period of two years following the spin-off.

 

If Forest or Mariner takes or permits an action to be taken (or omits to take an action) that causes the spin-off to become taxable, the relevant entity generally will be required to bear the cost of the resulting tax liability to the extent that the liability results from the actions or omissions of that entity. If the spin-off became taxable, Forest would be expected to recognize a substantial amount of income, which would result in a material amount of taxes. Any such taxes allocated to us would be expected to be material to us, and could cause our business, financial condition and operating results to suffer. These restrictions may reduce our ability to engage in certain business transactions that otherwise might be advantageous to us and could have a negative impact on our business.

 

Risks Relating to the Notes

 

We may not be able to generate enough cash flow to meet our debt obligations.

 

We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments, including the notes. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt, including the notes. Many of these factors, such as oil and gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.

If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

 

 

However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations, including our obligations under the notes, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.

 

The notes and the guarantees will be unsecured and effectively subordinated to our and our subsidiary guarantors’ existing and future secured indebtedness.

 

The notes and the guarantees are general unsecured senior obligations ranking effectively junior in right of payment to all existing and future secured debt of ours and that of each subsidiary guarantor, respectively, including obligations under our credit facility, to the extent of the value of the collateral securing the debt. As of September 30, 2006, after giving effect to borrowings under our amended and restated credit facility and to the offering of the old notes and the application of the proceeds therefrom, our total indebtedness was $614.0 million, $300.0 million of which was the old notes and $314.0 million of which effectively was senior in right of payment to the notes to the extent of the value of the collateral securing that indebtedness. We also then had three letters of credit outstanding for $40.0 million, $10.4 million and $4.2 million, each of which effectively is senior to the notes to the extent of the collateral securing such indebtedness. Further, we then had $121.4 million in additional borrowing capacity under our credit facility which if borrowed would have been secured debt effectively senior in right of payment to the notes to the extent of the value of the collateral securing that indebtedness.

 

If we or a subsidiary guarantor are declared bankrupt, become insolvent or are liquidated or reorganized, any secured debt of ours or that subsidiary guarantor will be entitled to be paid in full from our assets or the assets of the guarantor, as applicable, securing that debt before any payment may be made with respect to the notes or the affected guarantees. Holders of the notes participate ratably with all holders of our unsecured indebtedness that does not rank junior to the notes, including all of our other general creditors, based upon the respective amounts owed to each holder or creditor, in our remaining assets. In any of the foregoing events, we cannot assure you that there will be sufficient assets to pay amounts due on the notes. As a result, holders of the notes would likely receive less, ratably, than holders of secured indebtedness.

 

Our debt level and the covenants in the agreements governing our debt could negatively impact our financial condition, results of operations and business prospects and prevent us from fulfilling our obligations under the notes.

 

Our level of indebtedness, and the covenants contained in the agreements governing our debt, could have important consequences for our operations, including by:

 

 

 

We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances. If we fail to comply with the covenants and other restrictions in the agreements governing our debt, it could lead to an event of default and the consequent acceleration of our obligation to repay outstanding debt. Our ability to comply with these covenants and other restrictions may be affected by events beyond our control, including prevailing economic and financial conditions.

 

In addition, under the terms of our credit facility and the indenture, we must comply with certain financial covenants, including current asset and total debt ratio requirements. Our ability to comply with these covenants in future periods will depend on our ongoing financial and operating performance, which in turn will be subject to general economic conditions and financial, market and competitive factors, in particular the selling prices for our products and our ability to successfully implement our overall business strategy.

 

The breach of any of the covenants in the indenture or the credit facility could result in a default under the applicable agreement which would permit the applicable lenders or noteholders, as the case may be, to declare all amounts outstanding thereunder to be due and payable, together with accrued and unpaid interest. We may not have sufficient funds to make such payments. If we are unable to repay our debt out of cash on hand, we could attempt to refinance such debt, sell assets or repay such debt with the proceeds from an equity offering. We cannot assure you that we will be able to generate sufficient cash flow to pay the interest on our debt or that future borrowings, equity financings or proceeds from the sale of assets will be available to pay or refinance such debt. The terms of our debt, including our credit facility, may also prohibit us from taking such actions. Factors that will affect our ability to raise cash through an offering of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions, restrictions in our tax sharing agreement with Forest and the value of our assets and operating performance at the time of such offering or other financing. We cannot assure you that any such offering, refinancing or sale of assets could be successfully completed.

 

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

 

Borrowings under our credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease.

 

Despite our and our subsidiaries’ current level of indebtedness, we may still be able to incur substantially more debt. This could further exacerbate the risks associated with our substantial indebtedness.

 

We and our subsidiaries may be able to incur substantial additional indebtedness in the future, subject to certain limitations. The terms of our indenture will not prohibit us or our subsidiaries from doing so. For example, as of September 30, 2006, we were able to borrow up to $362.5 million on a revolving basis under our credit facility that was increased to $450 million in October 2006. If new debt is added to our current debt levels, the related risks that we and our subsidiaries now face could intensify. Our level of indebtedness could, for instance, prevent us from engaging in transactions that might otherwise be beneficial to us or from making desirable capital expenditures. This could put us at a competitive disadvantage relative to other less leveraged competitors that have more cash flow to devote to their operations. In addition, the incurrence of additional

indebtedness could make it more difficult to satisfy our existing financial obligations, including those relating to the notes.

 

We may not be able to repurchase the notes upon a change of control.

 

Upon the occurrence of certain change of control events, we are required to offer to repurchase all or any part of the notes then outstanding for cash at 101% of the principal amount. The source of funds for any repurchase required as a result of any change of control will be our available cash or cash generated from our operations or other sources, including:

 

 

We cannot assure you that sufficient funds would be available at the time of any change of control to repurchase your notes. In addition, our credit facility prohibits, and any future credit facilities may prohibit, such repurchases. Additionally, a “change of control” (as defined in the indenture for the notes) will be an event of default under our credit facility that would permit the lenders to accelerate the debt outstanding under the credit facility. Finally, using available cash to fund the potential consequences of a change of control may impair our ability to obtain additional financing in the future, which could negatively impact our ability to conduct our business operations.

 

A subsidiary guarantee could be voided if it constitutes a fraudulent transfer under U.S. bankruptcy or similar state law, which would prevent the holders of the notes from relying on that subsidiary to satisfy claims.

 

Under U.S. bankruptcy law and comparable provisions of state fraudulent transfer laws, our subsidiary guarantees can be voided, or claims under the subsidiary guarantees may be subordinated to all other debts of that subsidiary guarantor if, among other things, the subsidiary guarantor, at the time it incurred the indebtedness evidenced by its guarantee or, in some states, when payments become due under the guarantee, received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee and:

 

 

Our subsidiary guarantees may also be voided, without regard to the above factors, if a court found that the subsidiary guarantor entered into the guarantee with the actual intent to hinder, delay or defraud its creditors.

 

A court would likely find that a subsidiary guarantor did not receive reasonably equivalent value or fair consideration for its guarantee if the subsidiary guarantor did not substantially benefit directly or indirectly from the issuance of the guarantees. If a court were to void a subsidiary guarantee, you would no longer have a claim against the subsidiary guarantor. Sufficient funds to repay the notes may not be available from other sources, including the remaining subsidiary guarantors, if any. In addition, the court might direct you to repay any amounts that you already received from the subsidiary guarantor.

 

The measures of insolvency for purposes of fraudulent transfer laws vary depending upon the governing law. Generally, a guarantor would be considered insolvent if:

 

 

 

Each subsidiary guarantee contains a provision intended to limit the subsidiary guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its subsidiary guarantee to be a fraudulent transfer. Such provision may not be effective to protect the subsidiary guarantees from being voided under fraudulent transfer law.

 

A financial failure by us or our subsidiaries may result in the assets of any or all of those entities becoming subject to the claims of all creditors of those entities.

 

A financial failure by us or our subsidiaries could affect payment of the notes if a bankruptcy court were to substantively consolidate us and our subsidiaries. If a bankruptcy court substantively consolidated us and our subsidiaries, the assets of each entity would become subject to the claims of creditors of all entities. This would expose holders of notes not only to the usual impairments arising from bankruptcy, but also to potential dilution of the amount ultimately recoverable because of the larger creditor base. Furthermore, forced restructuring of the notes could occur through the “cram-down” provisions of the bankruptcy code. Under these provisions, the notes could be restructured over your objections as to their general terms, primarily interest rate and maturity.

 

This section of the prospectus describes certain aspects of the exchange offer which expired on November 9, 2006. Each broker-dealer (other than an affiliate of ours) that receives new notes for its own account in the exchange offer in exchange for securities that were acquired by such broker-dealer as a result of market-making or other trading activities must deliver a prospectus meeting the requirements of the Securities Act of 1933 in connection with any resale of new notes. We have agreed that, for a period of 90 days after the exchange date, we will make the prospectus available to any broker-dealer for use in connection with any such resale. While we believe that this description covers the material terms of the exchange offer that may remain relevant notwithstanding expiration or the exchange offer, this summary may not contain all of the information that is important to you. You should carefully read this entire document.

 

Purpose and Effects of the Exchange Offer

 

We initially issued $300.0 million principal amount of old notes on April 24, 2006 in a private offering. The initial purchasers subsequently offered and sold a portion of the old notes only to “qualified institutional buyers” as defined in and in compliance with Rule 144A and outside the United States in compliance with Regulation S of the Securities Act.

 

In connection with the sale of the old notes, we entered into an exchange and registration rights agreement, which requires us

 

 

We made the exchange offer to satisfy our obligations under the exchange and registration rights agreement. The term “holder” with respect to the exchange offer means any person in whose name old notes are registered on our or the Depository Trust Company’s (“DTC”) books or any other person who has obtained a properly completed bond power from the registered holder, or any person whose old notes are held of record by DTC who desires to deliver such old notes by book-entry transfer at DTC.

 

We have not requested, and do not intend to request, an interpretation by the staff of the SEC with respect to whether the new notes issued in the exchange offer in exchange for the old notes may be offered for sale, resold or otherwise transferred by any holder without compliance with the registration and prospectus delivery provisions of the Securities Act. Based on interpretations by the staff of the SEC set forth in no-action letters issued to third parties, we believe the new notes issued in exchange for old notes may be offered for resale, resold and otherwise transferred by any holder without compliance with the registration and prospectus delivery provisions of the Securities Act provided that:

 

 

Any holder who tenders in the exchange offer with the intention to participate, or for the purpose of participating, in a distribution of the new notes or who is our affiliate may not rely upon such interpretations by the staff of the SEC and, in the absence of an exemption, must comply with the registration and prospectus

delivery requirements of the Securities Act in connection with any secondary resale transaction. Any holder to comply with such requirements may incur liabilities under the Securities Act for which the holder is not indemnified by us.

 

Resale of the New Notes; Plan of Distribution

 

Each broker-dealer that receives new notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of new notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired as a result of market-making activities or other trading activities. In addition, until January 8, 2007, all dealers effecting transactions in the new notes, whether or not participating in this distribution, may be required to deliver a prospectus. This requirement is in addition to the obligation of dealers to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

 

We will not receive any proceeds from any sale of new notes by broker-dealers. New notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions:

 

 

Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such new notes.

 

Any broker-dealer that resells new notes received for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such new notes may be deemed to be an “underwriter” within the meaning of the Securities Act and any profit on any such resale of new notes and any commission on concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver a prospectus and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

 

The exchange offer was intended to satisfy our obligations under the registration rights agreement. We will not receive any proceeds from the issuance of the new notes in the exchange offer. In consideration for issuing the new notes as contemplated in this prospectus, we will receive, in exchange, outstanding old notes in like principal amount. We will cancel all old notes surrendered in exchange for new notes in the exchange offer. As a result, the issuance of the new notes will not result in any increase or decrease in our indebtedness.

 

The net proceeds from the offering of the sale of the old notes in the initial private placement were approximately $287.9 million. We used those proceeds, together with cash on hand, to repay borrowings under our amended and restated credit facility. The borrowings under the credit facility were used to:

 

 

The following table sets forth our consolidated capitalization as of September 30, 2006.

 

This table should be read together with our financial statements and the related notes included in this prospectus.

 

 

 

 

The merger between a subsidiary of Mariner and Forest Energy Resources was consummated on March 2, 2006. Accordingly, actual balance sheet information of the combined company as of September 30, 2006 is included elsewhere in this prospectus.

 

The following unaudited pro forma combined statements of operations and explanatory notes present how the combined statements of Mariner and the Forest Gulf of Mexico operations may have appeared had the businesses actually been combined as of January 1, 2005.

 

The unaudited pro forma combined financial information has been derived from and should be read together with the historical consolidated financial statements of Mariner and the statements of revenues and direct operating expenses of the Forest Gulf of Mexico operations, which are included elsewhere in this prospectus. The statements of revenues and direct operating expenses of the Forest Gulf of Mexico operations do not include all of the costs of doing business.

 

The unaudited pro forma combined condensed financial information is for illustrative purposes only. The financial results may have been different had the Forest Gulf of Mexico operations been an independent company and had the companies always been combined. You should not rely on the unaudited pro forma combined condensed financial information as being indicative of the historical results that would have been achieved had the merger occurred in the past or the future financial results that Mariner will achieve after the merger.

MARINER ENERGY, INC.

 

UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENT OF OPERATIONS

For the Nine Months Ended September 30, 2006

 

MARINER ENERGY, INC.

 

UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENT OF OPERATIONS
For the Year Ended December 31, 2005