Table of Contents

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Table of Contents

 

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      The foregoing summary description of the purchase agreement is subject in its entirety to the terms of the purchase agreement.

	TransTexas Gas Corporation

      On January 21, 2005, National Onshore LP, or National Onshore, the 1% general partnership interest of which and the 99% limited partnership interest of which are owned, respectively, by two limited liability companies, each of which is a wholly-owned subsidiary of AREP Oil & Gas, entered into an agreement and plan of merger with Highcrest Investors Corp., or Highcrest, an indirect wholly-owned subsidiary of Mr. Icahn, and TransTexas Gas Corporation, or TransTexas, pursuant to which TransTexas will merge with and into National Onshore and all of the common stock of TransTexas will be canceled and cease to exist in exchange for up to $180.0 million in cash consideration to be paid by National Onshore to Highcrest. The purchase price is subject to reduction based upon TransTexas’ oil and gas reserve reports as of January 21, 2005 to be prepared by an independent reserve engineering firm. The merger agreement contains customary representations and warranties, indemnification provisions, covenants regarding the conduct of business prior to closing and conditions to closing.

      The closing of the merger is subject to the satisfaction or waiver of certain conditions, including, for each of the parties, no action or proceeding by any governmental authority or other person shall have been instituted or threatened which (1) might have a material adverse effect on TransTexas or (2) could enjoin, restrain or prohibit, or could result in substantial damages in respect of, any provision of the merger agreement or the consummation of the transactions contemplated by the merger agreement. For National Onshore, the closing of the merger is also subject to (1) the satisfaction or waiver of the condition that no material adverse change with respect to TransTexas shall have occurred and no event shall have occurred which, in the reasonable judgment of National Onshore, is reasonably likely to have a material adverse effect and (2) the receipt of TransTexas’ oil and gas reserve reports. Highcrest has agreed to indemnify National Onshore against, and agreed to hold it harmless from, any and all losses it incurs associated with any breach of or any inaccuracy in any representation or warranty made by Highcrest in the merger agreement, or any breach of or failure by Highcrest to perform any of its covenants or obligations set out or contemplated in the merger agreement.

      The foregoing summary description of the merger agreement is subject in its entirety to the terms of the merger agreement.

	Panaco, Inc.

      On January 21, 2005, we and National Offshore LP, or National Offshore, the 1% general partnership interest of which and the 99% limited partnership interest of which are owned, respectively, by two limited liability companies, each of which is a wholly-owned subsidiary of AREP, entered into an agreement and plan of merger with Highcrest, Arnos and Panaco, pursuant to which Panaco will merge with and into National Offshore and all of the common stock of Panaco will be canceled and cease to exist in exchange for up to 4,310,345 Depositary Units, valued at $29.00 per unit, or an aggregate of up to $125.0 million. The number of Depositary Units to be issued is subject to reduction based upon Panaco’s oil and gas reserve reports as of January 21, 2005 to be prepared by an independent reserve engineering firm. Immediately following the merger, AREP will contribute each of the general partner and limited partner of National Offshore to AREH and AREH will contribute such limited liability companies to AREP Oil & Gas. The merger agreement contains customary representations and warranties, indemnification provisions, covenants regarding the conduct of business prior to closing and conditions to closing.

      The closing of the merger is subject to the satisfaction or waiver of certain conditions, including, for each of the parties, no action or proceeding by any governmental authority or other person shall have been instituted or threatened which (1) might have a material adverse effect on Panaco or (2) could enjoin, restrain or prohibit, or could result in substantial damages in respect of, any provision of the merger agreement or the consummation of the transactions contemplated by the merger agreement. The closing of the merger agreement is also subject to the approval by all depositary unit holder action required by the New York Stock Exchange. For National Offshore, the closing of the merger is also subject to (1) the satisfaction or waiver of

 

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      The foregoing summary description of the merger agreement is subject in its entirety to the terms of the merger agreement.

	GB Holdings, Inc. (The Sands)

      On January 21, 2005, we entered into a purchase agreement with Cyprus, pursuant to which we will purchase 4,121,033 shares of common stock of GB Holdings and 4,121,033 Atlantic Holdings warrants which are exercisable for an aggregate of 1,133,284 shares of common stock of Atlantic Holdings. The purchase price for these securities is 413,793 Depositary Units, valued at $29.00 per unit, or an aggregate of $12.0 million, plus up to an additional 206,897 Depositary Units, valued at $29.00 per unit, or an aggregate of $6.0 million, if GB Holdings meets certain earnings targets during 2005 and 2006. Upon the closing of the transaction, we will transfer all of our rights to these securities to AREP Sands. The purchase agreement contains customary representations and warranties, indemnification provisions, covenants regarding the conduct of business prior to closing and conditions to closing.

      The closing of the purchase agreement is subject to the satisfaction or waiver of certain conditions, including, for each of the parties, no action or proceeding by any governmental authority or other person shall have been instituted or threatened which (1) might have a material adverse effect on GB Holdings or Atlantic Holdings or (2) could enjoin, restrain or prohibit, or could result in substantial damages in respect of, any provision of the purchase agreement or the consummation of the transactions contemplated by the purchase agreement. The closing of each purchase agreement is also subject to the approval by all depositary unit holder action required by the New York Stock Exchange. For AREP, the closing of the purchase agreement is also subject to the satisfaction or waiver of the condition (1) that no material adverse change with respect to GB Holdings or Atlantic Holdings shall have occurred and no event shall have occurred which, in the reasonable judgment of AREP, is reasonably likely to have a material adverse effect and (2) that the GB Holding at Atlantic Holdings Securities are released from a bank pledge. Cyprus has agreed to indemnify AREP against, and agreed to hold it harmless from, any and all losses it incurs associated with any breach of or any inaccuracy in any representation or warranty made by Cyprus in the purchase agreement, or any breach of or failure by Cyprus to perform any of its covenants or obligations set out or contemplated in the purchase agreement.

      The foregoing summary description of the purchase agreement is subject in its entirety to the terms of the purchase agreement.

Oil and Gas

	NEG Holding LLC

      NEG Holding was formed in August 2000. In exchange for an initial membership interest in NEG Holding, substantially effective as of May 1, 2001, NEG, Inc., or NEG, contributed to NEG Holding all of its operating assets and oil and gas properties. In exchange for its initial membership interest in NEG Holding, Gascon contributed to NEG Holding (1) its sole membership interest in Shana National LLC, an oil and gas producing company, (2) cash of $75.2 million and (3) a $10.9 million revolving note evidencing borrowings under NEG’s revolving credit facility. NEG Holding initially owned 100% of the membership interest in NEG Operating. All of the oil and gas assets contributed by NEG and all of the oil and gas assets associated with Gascon’s contribution to NEG Holding were transferred from NEG Holding to NEG Operating.

 

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      NEG currently owns a membership interest in NEG Holding. The other membership interest in NEG Holding is currently owned by Gascon. Gascon is the managing member of NEG Holding. NEG Holding owns NEG Operating which is engaged in the business of oil and gas exploration and production with properties located on-shore in Texas, Louisiana, Oklahoma and Arkansas. NEG Operating’s oil and gas properties are managed by NEG. Under the NEG Holding operating agreement between NEG and Gascon, NEG is to receive, as of September 30, 2004, guaranteed payments of approximately $39.9 million and a priority distribution of approximately $148.6 million before Gascon receives any distributions. The NEG Holding operating agreement contains a provision that allows Gascon, or its successor, at any time, in its sole discretion, to redeem NEG’s membership interest in NEG Holding at a price equal to the fair market value of the interest determined as if NEG Holding had sold all of its assets for fair market value and liquidated. A determination of the fair market value of such assets shall be made by an independent third party jointly engaged by Gascon and NEG.

	Principal Areas of Operations

      NEG Holding is developing and exploiting existing properties by drilling development and exploratory wells, and recompleting and reworking existing wells. NEG Holding anticipates that it will continue its drilling operations on existing properties and will selectively participate in drilling opportunities generated by third parties. NEG Holding also seeks to acquire existing producing properties or interests in them. In November 2002, NEG Holding completed the acquisition of producing oil and gas properties in Pecos County, Texas known as Longfellow Ranch Field for $45.4 million in cash. In December 2002, NEG Holding completed the acquisition of an additional interest in Longfellow Ranch Field for $2.9 million in cash.

      The following table sets forth NEG Holding’s proved reserves of oil and gas by principal areas of operation as of December 31, 2003.

												Natural Gas
				Oil				Natural Gas				Equivalent				% of
				(MBbls)(1)				(MMcf)(2)				(MMcfe)(3)				Total
Area:
	Mid-Continent				451				30,399				33,105				16.7	%
	East and West Texas				3,536				125,510				146,726				74.2
	Gulf Coast				1,054				11,695				18,019				9.1
		Total			5,041				167,604				197,850				100.0	%

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(1)	“MBbls” means thousand barrels of oil.
(2)	“MMcf” means million cubic feet of natural gas.
(3)	“MMcfe” means million cubic feet of gas equivalent, determined using the ratio of six thousand cubic feet of natural gas (Mcf) to 1 barrel of 42 U.S. gallons (Bb1) of crude oil, condensate or natural gas liquids.

      The following table sets forth NEG Holding’s production by principal area of operation for the year ended December 31, 2003.

												Natural Gas
				Oil				Natural Gas				Equivalent				% of
				(MBbls)				(MMcf)				(MMcfe)				Total
Area:
	Mid-Continent				39				3,070				3,304				19.2	%
	East and West Texas				349				8,606				10,700				62.2
	Gulf Coast				241				1,761				3,207				18.6
		Total			629				13,437				17,211				100.0	%

 

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      Mid-Continent area. At December 31, 2003, approximately 16.7% (33.1 Bcfe, or billion cubic feet of gas equivalent) of NEG Holding’s proved reserves were located in the Mid-Continent area in Oklahoma and West Arkansas which includes the Anadarko and Arkoma Basins.

	Anadarko Basin. The Anadarko Basin properties are located throughout central and west Oklahoma. Anadarko Basin is among the most prolific petroliferous basins of the continental United States. The Anadarko Basin is considered a mature oil and natural gas province characterized by multiple producing horizons and long-lived and predictable reserves with low cost operations. Most Anadarko Basin reserves are produced from formations at depths ranging from approximately 5,000 to 15,000 feet. During the year ended December 31, 2003, NEG Holding drilled 2 gross (.24 net) development wells in the Anadarko Basin which were completed as commercially productive.
	Arkoma Basin. The Arkoma Basin properties are located in southeast Oklahoma and northwest Arkansas. The Arkoma Basin is considered a mature natural gas province characterized by multiple producing horizons and long-lived and predictable reserves with low cost operations. Most Arkoma Basin reserves are produced from formations at depths ranging from approximately 3,000 to 8,000 feet. The principal productive formations are Atokan and, to a lesser extent, Morrowan sandstones. During the year ended December 31, 2003, NEG Holding drilled 2 gross (1.07 net) development wells in the Arkoma Basin which were completed as commercially productive.

      East and West Texas area. At December 31, 2003, approximately 74.2% (146.7 Bcfe) of NEG Holding’s proved reserves were located in the East and West Texas area, including East Texas, South Arkansas and in West Texas, the Goldsmith Adobe Unit and Longfellow Ranch Field.

	East Texas Basin. The reserves in this region are found in the Cotton Valley formation and the Travis Peak formation. These properties produce from low permeability reservoirs that generally contain relatively long-lived reserves. A significant portion of the cost to complete Cotton Valley wells is incurred due to the low permeability of interbedded sandstones and shales, which requires large hydraulic fracture stimulation, typically of multiple zones of the producing formation, to obtain the increased production levels necessary to make such wells commercially viable. Cotton Valley production occurs in a mature natural gas province characterized by long-lived reserves producing from formations at depths ranging from 8,500 to 10,500 feet. Travis Peak is considered to be a mature oil province characterized by long-lived reserves producing from formations at a depth of 7,200 feet. During the year ended December 31, 2003, NEG Holding drilled 8 gross (8.0 net) development wells in the East Texas Basin, which were completed as commercially productive.
	West Texas. The following fields comprise the West Texas area:

	•	Goldsmith Adobe Unit, or GAU, is located in the Permian Basin of West Texas. NEG Holding now owns a 99.9% working interest in this property. Typically, wells drilled at the GAU produce from the Upper Clearfork formation at an average depth of 6,100 feet. During the year ended December 31, 2003, NEG Holding drilled 12 gross (12.0 net) development wells at the GAU which were completed as commercially productive.
	•	Longfellow Ranch area and associated producing fields are located in the Val Verde Basin, a prolific gas producing area. Longfellow Ranch Field (Pinion Field) was discovered in 1983 by Fina Oil and Gas, but was not extensively developed due to lack of necessary pipeline and associated facilities. Riata Energy Inc. acquired the field in 1996 and began an extensive development program. The primary producing horizons in the field are the Caballos Novaculites of Devonian age located at depths ranging from 4,500 feet to 10,000 feet. Additional producing horizons include the lower Pennsylvanian Dimple and upper Mississippian Tesnus formations located at depths ranging from 2,000 feet to 4,500 feet. Other objectives include a normal stratigraphic section of Devonian, Silurian and Ordovician. These horizons have produced north of the Marathon thrust belt, where the structures can produce over a Tcf, or trillion cubic feet, of gas. The Longfellow Ranch Field is not delineated by any dry holes and is considered to be immature in its oil and gas development. This field presents great opportunities, both recognized

 

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		and yet to be recognized. During the year ended December 31, 2003, NEG Holding drilled 10 gross (3.8 net) development wells and 29 gross (7.9 net) exploratory wells in Longfellow Ranch Field, all of which were completed as commercially productive. During the same period, NEG Holding drilled 1 gross (0.1 net) exploratory well that was not completed as commercially productive.

           Gulf Coast area. At December 31, 2003, approximately 9.1% (18 Bcfe) of NEG Holding’s proved reserves were located in the Gulf Coast area which includes South Louisiana and South Texas. The Gulf Coast area encompasses the large coastal plain from the southernmost tip of Texas through the southern portion of Louisiana. These rocks are comprised of sediments ranging from the Cretaceous through the Tertiary in age. NEG Holding’s production ranges in depth from as shallow as several thousand feet to in excess of 14,000 feet. New technology, including the use of 3-D seismic with subsurface mapping, has yielded many new opportunities in the entire coastal area. NEG Holding is involved in many projects using 3-D seismic technology. During the year ended December 31, 2003, NEG Holding drilled 2 gross (1.0 net) development wells in the Gulf Coast area, which were completed as commercially productive. During the same period, NEG Holding drilled 1 gross (.13 net) exploratory well and 1 gross (0.4 net) development well that were not completed as commercially productive.

	Oil and Gas Reserves

      NEG Holding reserves are located in the continental United States. NEG Holding’s reserve report was prepared using constant prices and costs in accordance with the published guidelines of the SEC. The net weighted average prices used in NEG Holding’s reserve report as of December 31, 2003 were $31.14 per barrel of oil and $5.87 per Mcf, or thousand cubic feet, of natural gas. As of December 31, 2003, NEG Holding has total proved reserves of 167,604 MMcf of natural gas and 5,041 MBbls of condensate and oil. The estimation of reserves and future net revenues can be materially affected by the oil and gas prices used in preparing the reserve report.

      The following table sets forth certain information for NEG Holding’s total proved reserves of oil and gas and the PV 10% of estimated future net revenues from such reserves, as of December 31, 2003.

											Natural Gas
			Oil				Natural Gas				Equivalent
			(MBbls)				(MMcf)				(MMcfe)				PV 10%
															(in thousands)
Proved Developed Reserves				4,096				104,207				128,783			$	303,175
Proved Undeveloped Reserves				945				63,397				69,067				152,719
	Total Proved Reserves			5,041				167,604				197,850			$	455,894

 

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Oil and Gas Production and Unit Economics

      The following table shows the approximate net production attributable to NEG Holding’s oil and gas interests, the average sales price per barrel of oil and Mcf of natural gas produced, and the average unit economics per Mcfe, or thousand cubic feet gas equivalent, related to NEG Holding’s oil and gas production for the periods indicated. Information relating to properties acquired or sold is reflected in this table only since or up to the closing date of their respective acquisition or sale.

			Four Months				Year Ended								Nine Months Ended
			Ended				December 31,								September 30,
			December 31,
			2001				2002				2003				2003				2004
Net production:
	Oil (MBbls)			246				629				629				469				437
	Natural gas (MMcf)			2,713				7,827				13,437				9,919				9,647
	Natural gas equivalent (MMcfe)			4,189				11,602				17,211				12,733				12,269
Average sales price:
	Oil (per Bbl)		$	20.81			$	23.93			$	26.54			$	26.37			$	30.24
	Natural gas (per Mcf)			2.63				3.06				4.39				4.71				5.19
Unit economics (per Mcfe):
	Average sales price		$	2.97			$	3.36			$	4.40			$	4.64			$	5.16
	Lease operating expenses			.64				.73				.66				.61				.69
	Oil and natural gas production taxes (net of refunds in 2002)			.17				.16				.34				.35				.33
	Depletion rate			1.00				1.29				1.25				1.37				1.25
	General and administrative expenses			.50				.50				.28				.32				.25

Productive Wells

      The following table sets forth NEG Holding’s interests in productive wells, by principal area of operation, as of December 31, 2003.

				Oil								Natural Gas								Total
				Gross				Net				Gross				Net				Gross				Net
Area:
	Mid-Continent				33				11				199				99				232				110
	East and West Texas				137				135				163				89				300				224
	Gulf Coast				25				16				88				35				113				51
		Total			195				162				450				223				645				385

 

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Leasehold Acreage

      The following table shows the approximate gross and net acres in which NEG Holding had a leasehold interest, by principal area of operation, as of December 31, 2003.

												Undeveloped
				Developed Acreage								Acreage
				Gross				Net				Gross				Net
Area:
	Mid-Continent				66,941				36,233				640				248
	East and West Texas				35,520				22,326				87,252				21,720
	Gulf Coast				27,129				10,930				10,611				5,960
		Total			129,590				69,489				98,503				27,928

      NEG Holding acquires a leasehold interest in the properties it explores. The leases grant the lessee the right to explore for and extract oil and gas from a specified area. Lease rentals usually consist of a fixed annual charge made prior to obtaining production. Once production has been established, a royalty is paid to the lessor based upon the gross proceeds from the sale of oil and gas. Once wells are drilled, a lease generally continues as long as production of oil and gas continues. In some cases, leases may be acquired in exchange for a commitment to drill or finance the drilling of a specified number of wells to predetermined depths.

      Substantially all of NEG Holding’s producing oil and gas properties are located on leases held by NEG Holding for an indeterminate number of years as long as production is maintained. All of NEG Holding’s non-producing acreage is held under leases from mineral owners or a government entity which expire at varying dates. NEG Holding is obligated to pay annual delay rentals to the lessors of certain properties in order to prevent the leases from terminating.

Drilling Activity

      The following table sets forth NEG Holding’s exploration and development drilling results for the four months ended December 31, 2001 and the years ended December 31, 2002 and 2003.

					Four Months								Year Ended December 31,
					Ended
					December 31,
					2001								2002								2003
					Gross				Net				Gross				Net				Gross				Net
Exploratory Wells(1):
	Productive(2)					5				1.0				6				1.6				29				7.9
	Non-productive					1				.3				1				.4				2				.2
		Total				6				1.3				7				2.0				31				8.1
Development Wells(1):
	Productive(2)					3				1.7				15				5.3				36				26.0
	Non-productive					1				.5				1				1.0				1				.4
		Total				4				2.2				16				6.3				37				26.4
			Combined Total			10				3.5				23				8.3				68				34.5

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(1)	The number of net wells is the sum of the fractional working interests owned in gross wells.
(2)	Productive wells consist of producing wells and wells capable of production, including gas wells awaiting pipeline connection. Wells that are completed in more than one producing zone are counted as one well.

 

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Production and Sales Prices

      NEG Holding produces oil and gas solely in the continental United States. NEG Holding currently sells a significant portion of oil pursuant to a contract with Plains Marketing and Transportation. NEG Holding has no obligations to provide a fixed and determinable quantity of oil and/or natural gas in the future under existing contracts or agreements. NEG Holding does not refine or process the oil and gas it produces, but sells the production to unaffiliated oil and gas purchasing companies in the area in which it is produced. NEG Holding expects to sell crude oil on a market price basis and to sell natural gas under contracts to both interstate and intrastate natural gas pipeline companies.

Control Over Production Activities

      NEG Holding operated 395 of the 645 producing wells in which it owned an interest as of December 31, 2003. The non-operated properties are operated by unrelated third parties pursuant to operating agreements which are generally standard in the industry. Significant decisions about operations regarding non-operated properties may be determined by the outside operator rather than by NEG Holding. If NEG Holding declines to participate in additional activities proposed by the outside operator under certain operating agreements, NEG Holding will not receive revenues from, and/or will lose its interest in, the activity in which it declined to participate.

Markets and Customers

      A large percentage of NEG Holding’s oil and gas sales are made to a small number of purchasers. For the year ended December 31, 2003, Plains accounted for 94% of NEG Holding’s oil sales and Riata Energy Company, Seminole Energy Services and Crosstex Energy accounted for 49%, 12% and 15%, respectively, of NEG Holding’s gas sales. For the year ended December 31, 2002, Plains accounted for 83% of NEG Holding’s oil sales and Crosstex Energy, Duke Energy and Oneok Gas Marketing Company accounted for 20%, 11% and 10%, respectively, of NEG Holding’s gas sales. For the nine months ended September 30, 2004, Plains accounted for 87.4% of NEG Holdings oil sales and Riata Energy Company, Seminole Energy Services and Crosstex Energy accounted for 40.4%, 23.8% and 7.2%, respectively, of NEG Holdings gas sales. NEG Holding does not believe that the loss of any purchaser would have a material adverse effect on its business because, under prevailing market conditions, other purchasers are readily available.

      The agreement with Plains, entered into in 1993, provides for Plains to purchase NEG Holding’s oil pursuant to West Texas Intermediate posted prices plus a premium. A portion of NEG Holding’s natural gas production is sold pursuant to long-term netback contracts. Under netback contracts, gas purchasers buy gas from a number of producers, process the gas for natural gas liquids, and sell liquids and residue gas. Each producer receives a fixed portion of the proceeds from the sale of the liquids and residue gas. The gas purchasers pay for transportation, processing and marketing of the gas and liquids, and assume the risk of contracting pipelines and processing plants in return for a portion of the proceeds of the sale of the gas and liquids. Generally, because the purchasers are marketing large volumes of hydrocarbons gathered from multiple producers, higher prices may be obtained for the gas and liquids. The remainder of NEG Holding’s natural gas is sold on the spot market under short-term contracts.

Employees

      NEG Holding has an operating agreement with NEG through which NEG personnel are provided to it. From time to time, it may engage the services of independent geological, engineering, land and other consultants when specific expertise is required.

TransTexas Gas Corporation

      TransTexas and its wholly-owned subsidiaries, Galveston Bay Pipeline Company and Galveston Bay Processing Company, are engaged in the exploration, production and transmission of natural gas and oil, primarily in South Texas, including the Eagle Bay field in Galveston Bay and the Southwest Bonus field in Wharton County. Its exploration and production activities consist of geological and geophysical evaluation of

 

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      On November 14, 2002, TransTexas, Galveston Bay Pipeline and Galveston Bay Processing filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas, Corpus Christi Division. The bankruptcy cases were jointly administered. TransTexas, Galveston Bay Pipeline and Galveston Bay Processing operated their businesses and managed their properties as debtors in possession. On August 28, 2003, TransTexas, Galveston Bay Processing and Galveston Bay Pipeline emerged from their joint Chapter 11 bankruptcy proceedings pursuant to the Confirmation Order of the Bankruptcy Court and the Plan of Reorganization proposed by Thornwood.

Principal Areas of Operations

      The following table sets forth TransTexas’ proved reserves of oil and gas by principal areas of operation as of December 31, 2003.

				Oil (including
				Natural Gas								Natural Gas
				Liquids)				Natural Gas				Equivalent
				(MBbls)				(MMcf)				(MMcfe)				% of Total
Area:
	Eagle Bay				2,619				11,776				27,490				47.9	%
	Southwest Bonus				466				23,641				26,437				46.1
	Other Areas				39				3,239				3,473				6.0
		Total			3,124				38,656				57,400				100.0	%

      The following table sets forth TransTexas’ production by principal area of production for the year ended December 31, 2003.

				Oil (including
				Natural Gas								Natural Gas
				Liquids)				Natural Gas				Equivalent
				(MBbls)				(MMcf)				(MMcfe)				% of Total
Area:
	Eagle Bay				710				3,945				8,210				74.7	%
	Southwest Bonus				38				1,997				2,223				20.2
	Other Areas				7				515				557				5.1
		Total			755				6,457				10,990				100.0	%

      Eagle Bay. At December 31, 2003, approximately 47.9% (27.5 Bcfe) of TransTexas’ proved reserves were located in Eagle Bay. As of December 31, 2003, TransTexas has successfully drilled and completed 12 wells in the Eagle Bay field. It intends to drill additional development wells in Eagle Bay as part of its strategy to further increase reserves and production and has identified additional drilling locations from 3-D seismic data. As of December 31, 2003, TransTexas owned a 75% working interest in approximately 4,461 net acres in the Eagle Bay area. Production from the Eagle Bay field represents 74.7% of TransTexas’ total production.

      Southwest Bonus. At December 31, 2003, approximately 46% (26.4 Bcfe) of TransTexas’ proved reserves were located in the Southwest Bonus field. As of January  31, 2003, TransTexas had successfully drilled 22 wells in the Southwest Bonus field and held a 97% working interest covering approximately 4,652 net acres in the Southwest Bonus field. TransTexas has identified additional drilling locations from 3-D seismic data. Production from the Southwest Bonus field represents 20.2% of TransTexas’ production.

      Other Areas. TransTexas also has an inventory of exploration and exploitation prospects along the Upper Texas Gulf Coast which it continues to assemble as part of its strategy to increase reserves and production. Its

 

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Oil and Gas Reserves

      TransTexas’ reserves are located in the continental United States. TransTexas’ reserve report was prepared using constant prices and costs in accordance with published guidelines of the SEC. The net weighted average prices used in TransTexas’ reserve report as of December 31, 2003 were $25.91 per barrel of oil and $6.00 per Mcf of natural gas. As of December 31, 2003, TransTexas has total proved reserves of 38,656 MMcf of natural gas and 3.125 MBbls of condensate and oil. The estimation of reserves and future net revenues can be materially affected by the oil and gas prices used in preparing the reserve report.

      The following table sets forth information for TransTexas’ total proved reserves of oil and gas and the PV 10% of estimated future net revenues from such reserves, as of December 31, 2003.

			Oil (including
			Natural Gas								Natural Gas
			Liquids)				Natural Gas				Equivalent
			(in MBbls)				(in MMcf)				(MMcfe)				PV 10%
															(in thousands)
Proved Developed Reserves				2,755				21,558				38,091			$	112,115
Proved Undeveloped Reserves				369				17,098				19,309				52,323
	Total Proved Reserves			3,124				38,656				57,400			$	164,438

Oil and Gas Production Economics

      The following table shows the approximate net production attributable to TransTexas’ oil and gas interests, the average sales price per barrel of oil and Mcf of natural gas produced, and the average unit economics per Mcfe, or thousand cubic feet gas equivalent, related to TransTexas oil and gas production for the periods indicated. Information relating to properties acquired or disposed of is reflected in this table only since or up to the closing date of their respective acquisition or sale.

			Year Ended								Year Ended
			January 31,								December 31,
			2002				2003				2003
Production:
	Natural Gas (MMcf)			22.5				10.7				6.5
	Natural Gas Liquids (MMgals)			40.1				31.3				12.7
	Natural Gas Liquids
	Condensate and oil (MBbls)			1,286.0				860.0				454.0
Average sales prices:
	Gas (dry) (per Mcf)		$	3.89			$	3.38			$	5.03
	Natural Gas Liquids (per gallon)			0.36				0.33				0.50
	Natural Gas Liquids
	Condensate and oil (per Bbl)			23.63				25.93				31.12
Average lifting cost per Mcfe(1)				0.49				0.59				0.61

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(1)	Condensate and oil are converted to a common unit of measure on the basis of six Mcf of natural gas to one barrel of condensate or oil. The components of production costs may vary substantially among wells depending on the methods of recovery employed and other factors.

 

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Productive Wells

      The following table sets forth TransTexas’ interests in productive wells, by principal area of operation, as of December 31, 2003.

				Oil								Natural Gas								Total
				Gross				Net				Gross				Net				Gross				Net
Area:
	Eagle Bay				0				0				11				8.5				11.0				8.5
	Southwest Bonus				1				0.224				26				21.85				27.0				22.099
	Other areas				1				0				16				12.278				17.0				12.278
		Total			2				0.224				53				42.628				55.0				42.877

	Leasehold Acreage

      The following table shows the approximate gross and net acres in which TransTexas had a leasehold interest, by principal area of operation, as of December 31, 2003.

												Undeveloped
				Developed Acreage								Acreage
				Gross				Net				Gross				Net
Area:
	Eagle Bay				3,231				2,412				2,727				2,049
	Southwest Bonus				4,434				4,300				529				352
	Other areas				7,825				5,532				20,431				13,372
		Total			15,490				12,244				23,687				15,773

      TransTexas acquires a leasehold interest in the properties to be explored. The leases grant the lessee the right to explore for and extract oil and gas from a specified area. Lease rentals usually consist of a fixed annual charge made prior to obtaining production. Once production has been established, a royalty is paid to the lessor based upon the gross proceeds from the sale of oil and gas. Once wells are drilled, a lease generally continues as long as production of oil and gas continues. In some cases, leases may be acquired in exchange for a commitment to drill or finance the drilling of a specified number of wells to predetermined depths.

      Substantially all of TransTexas’ producing oil and gas properties are located on leases held by TransTexas for an indeterminate number of years as long as production is maintained. All of TransTexas’ non-producing acreage is held under leases from mineral owners or a government entity which expire at varying dates. TransTexas is obligated to pay annual delay rentals to the lessors of certain properties in order to prevent the leases from terminating.

 

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	Drilling Activity

      The following table sets forth TransTexas’ exploration and development drilling results for the 12 months ended January 31, 2002 and 2003 and the eleven months ended December 31, 2003.

				Year Ended January 31,																Eleven Months
																				Ended
																				December 31,
				2002								2003								2003
				Gross				Net				Net				Gross				Net				Gross
Exploratory Wells(1):
	Productive(2)				1				1				—				—				0				0
	Non-Productive				1				1				—				—				0				0
		Total			2				2				—				—				0				0
Development Wells(1):
	Productive(2)				12				11				—				—				1.4				2
	Non-Productive				1				1				—				—				0				0
		Total			13				12				—				—				1.4				2

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(1)	The number of net wells is the sum of the fractional working interests owned in gross wells.
(2)	Productive wells consist of producing wells and wells capable of production, including gas wells awaiting pipeline connection. Wells that are completed in more than one producing zone are counted as one well.

      TransTexas’ business strategy is to utilize its experience in drilling and operating wells to find, develop and produce reserves at a low cost. Its long-term goal is to convert unproven acreage to proved reserves by drilling in under-exploited areas. In order to meet our long-term goals, TransTexas’ strategy is to drill wells in areas of the Upper Texas Gulf Coast where 3-D seismic data indicates productive potential and to drill development wells in its proven producing areas such as the Eagle Bay field and Southwest Bonus field.

	Transportation, Processing and Marketing

      TransTexas has entered into various agreements for the gathering, transportation, processing and sale of substantially all of its natural gas and natural gas liquids produced from its Eagle Bay prospects. TransTexas monitors its transportation needs closely and is actively in discussions with pipeline companies regarding additional agreements in order to meet potential future production increases.

      Galveston Bay Processing operates onshore facilities, located 60 miles east of Houston at Winnie, Texas, to separate produced natural gas and condensate, dehydrate and treat natural gas for the removal of carbon dioxide and stabilize condensate from Eagle Bay field.

      TransTexas has entered into contracts with Kinder Morgan Ship Channel Pipeline, LP for transportation of its production from the Eagle Bay field to the Winnie facilities at a fixed negotiated rate.

      TransTexas has entered into a gas purchase contract with Kinder Morgan Tejas Pipeline, L.P. (formerly Tejas Gas Marketing, LLC) covering the sale by TransTexas of substantially all of its residue gas production from the Eagle Bay field. The agreement provides for a price payable for the first fifty percent (50%) of the first of the month nominated MMBtu at a price based on a published first of the month industry index. The remaining fifty percent (50%) of the first of the month nominated volume is sold each day at a price based on a published daily industry index.

      TransTexas and Duke Energy Field Services, LP entered into a gas gathering and processing contract to gather and process the high-Btu natural gas produced from the Eagle Bay field leaving the Winnie facilities for a negotiated fee. TransTexas can elect to process ethane, at its sole discretion on a monthly basis, from the net recovered natural gas liquids attributable to TransTexas’ gas and is priced based on prevailing market prices. TranTexas has the right to market 100% of its allocable residue gas in kind at the tailgate of the “Duke” plant.

 

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      For the year ended December 31, 2003, two purchasers represented approximately 71% of the consolidated natural gas, condensate and natural gas liquids revenues of TransTexas. TransTexas believes that the loss of any single purchaser would not have a material adverse effect on TransTexas due to the availability of other purchasers for TransTexas’ production at comparable prices.

	Employees

      TransTexas has a management agreement with NEG through which NEG personnel are provided to it. From time to time, it may engage the services of independent geological, engineering, land and other consultants when specific expertise is required.

Panaco, Inc.

      Panaco is an independent oil and gas exploration and production company focused primarily on opportunities in the Gulf Coast Region and offshore opportunities in the Gulf of Mexico. Panaco is in the business of selling oil and gas, produced on properties it leases, to third party purchasers. It obtains reserves of crude oil and gas by either buying them from others or drilling developmental and exploratory wells on acquired properties. It acquires producing properties with a view toward further exploitation and development, capitalizing on 3-D seismic and advanced directional drilling technology to recover reserves that were bypassed or previously overlooked.

      On July 16, 2002, Panaco filed a petition for reorganization under Chapter 11 of the United States Bankruptcy Code with the U.S. Bankruptcy Court for the Southern District of Texas. On August 27, 2004, the Court entered an Amended Order approving the Fifth Amended Joint Disclosure Statement Regarding the Fifth Amended Joint Plan of Reorganization. On November 2, 2004, the Amended Plan was approved. Panaco emerged from bankruptcy on November 16, 2004.

	Significant Operating Control

      As of December 31, 2004, Panaco operates 71.7% of its properties as measured by Pretax PV-10 value. The operator of an oil and gas property supervises production, maintains production records, employs field personnel and performs other functions required in the production and administration of such property.

	Principal Areas of Operations

      East Breaks 160/161/205. The East Breaks is located offshore Texas, approximately 100 miles south of Galveston, in water depths of approximately 930 feet. The field is comprised of three blocks, East Breaks Block 160 and East Breaks Block 161, which were originally leased in 1974 and are owned equally by Panaco, British Petroleum and Unocal, with Unocal currently serving as the operator; and East Breaks Block 205, acquired in 1996, which is 25% owned by Panaco. Field production is handled on the Cervesa platform, located on Block 160.

      Utilizing the field’s existing infrastructure, Panaco receives processing fees from a former Mobil sub-sea well, now owned by BP Amoco, drilled in East Breaks Block 117. Because of the platform’s strategic location on the edge of deepwater, the facility has potential for additional processing and handling fees as discoveries are made nearby and tied into the platform. Panaco also owns a 33.3% interest in a 12.67 mile 12 inch natural gas pipeline connecting the East Breaks Block 160 platform to the High Island Offshore System, a natural gas pipeline system in the Gulf of Mexico, as well as a 33.3% interest in a 17.47 mile 10 inch oil pipeline connecting the platform to the High Island Pipeline System, a crude oil pipeline system in the Gulf of Mexico.

      West Delta Blocks 54/55/58 Field Area. There are currently approximately 32 wells in West Delta Blocks 54/55/58 Field Area, which produce from depths ranging from 900 feet to 17,000 feet. Panaco operates the West Delta Field and owns 100% of most of the area’s wells. The production facility is a four-platform complex located in West Delta Block 54, in water that ranges in depth from six to fifteen feet.

 

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      Panaco has also allowed Noble Energy, Millennium Energy and Stone Energy to drill on the West Delta Block 58 acreage under farmout agreements. These agreements provide that Panaco shall receive an overriding royalty interest, with an optional back in after payout in addition to processing fees for the handling of production. Panaco has earned a 25% back in interest in the Millenium well.

      West Delta 52. Panaco acquired a 100% working interest in a portion of West Delta Block 52 Field in April 2001 from Delta Petroleum Corporation. The acquisition included seven producing oil wells, one salt-water disposal well and 18 shut-in wells. At that time, a 7,600-foot oil sand was the only productive sand for the property, producing approximately 180-200 barrels of oil per day. No gas was being sold. Panaco has since recompleted three of the shut-in wells to gas wells.

      Umbrella Point Field. Umbrella Point Field is a well-defined, low relief, 4-way structural closure centered on Texas State Tracts 73, 74, 87 and 88 in the Galveston/Trinity Bay portion of Chambers County, Texas. In 2001, Panaco drilled an exploratory well on the property to test the Vicksburg sand. This well encountered no productive pay zones and was plugged and abandoned.

      East Breaks 165. The East Breaks 165 geological structure is an interdomal faulted paleostructure. The shallower horizons exhibit four-way dip closure, while at deeper horizons a faulted anticline is mapped. The main reservoir sands at East Breaks 165 are of excellent quality. Panaco recently reprocessed 3-D seismic imaging that was previously generated on the East Breaks 165 area. The reprocessed data better defines the structural morphology, improves the fault resolution, images the potentially productive upthrown fault block to the north, and clarifies limits of the production.

      East Breaks 109/110. East Breaks 109/110 is located approximately 100 miles south of Galveston Island, offshore Texas, in water depths of approximately 650 feet. Panaco is party to two processing agreements with third parties that yield $450,000 per month in operating income. Additionally, Panaco produces 1,100 Mcf of natural gas per day from the East Breaks 109/110 Fields.

	Exploitation and Development of Acquired Properties

      Primarily through acquisitions, Panaco has developed an inventory of exploitation projects including development drilling, workovers, sidetrack drilling, recompletions and artificial lift enhancements. As of December 31, 2003, 54.3% of Panaco’s pretax PV-10 relates to Proved Undeveloped Reserves.

	Marketing of Existing Infrastructure

      Panaco owns interests in 15 offshore platforms and approximately 215 miles of offshore oil and gas pipelines with diameters of 10” or greater. It markets the use of this infrastructure to other lease operators as a source of additional revenue and as a way for other lease operators to produce their hydrocarbons in a more economical fashion. Panaco currently has facility use or processing agreements in the East Breaks 160/161/205 Fields, the Umbrella Point Field, the East Cameron 359 Field, the East Breaks 165 Fields, the East Breaks 109/110 Fields and the West Delta 54/52 Fields, each located in the Gulf of Mexico. The major focus of marketing these facilities has been in the East Breaks area. Panaco owns 100% of the platforms and related pipelines in the East Breaks 109 and East Breaks 165 Fields and 33% of the platforms and related pipelines in the East Breaks 160 Fields. These existing platforms are three of the furthest from the coastline in the Gulf of Mexico and are in 700 to 900 feet of water. These existing platforms can significantly improve the economics of operating an adjacent oil and gas lease and in return lower our costs of operating this infrastructure.

	Oil and Gas Reserves

      As of December 31, 2003, Panaco had total proved reserves of 74,654,890 MMcfe and had a Pretax PV-10 value of $136.2 million. Approximately 45.7% of these reserves are classified as Proved Developed Reserves and approximately 51% are natural gas. Panaco’s primary producing properties are located along the Gulf Coast in Texas and Louisiana and offshore in the federal and state waters of the Gulf of Mexico. Panaco owns interests in a total of 123 producing oil wells and 24 producing natural gas wells.

 

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      The following is a summary of Panaco’s significant properties as of December 31, 2003. These properties represent 80.3% of the aggregate Pretax PV-10 value of its proved reserves.

			Total Proved Reserves
							Pretax PV-10				% of				Total Pretax
Field			Oil (MBbls)				Natural Gas (Bcf)				Value (000s)				PV-10
East Breaks 160/161/205				703.453				6.234			$	26,545.978				19.48	%
West Delta 52				162.660				0.516				511.714				0.38
West Delta 54/55/58				237.015				8.746				22,633.234				16.61
Umbrella Point Field				659.340				2.450				9,488.087				6.96
East Breaks 165				2,462.455				14.975				48,311.700				33.99
East Breaks 109/110				0.380				1.633				3,958.600				2.91
	Total			4,225.303				34.554			$	109,449.313				80.33	%

	Oil and Gas Production Economics

      The following table sets forth information with respect to net production attributable to Panaco oil and gas interests and average unit sales prices and costs for the periods indicated:

			Year Ended
			December 31,
			2003
Production:
	Gas (MMcf)			5,043
	Condensate and oil (MBbls)			689
	Gas equivalent (MMcfe)			9,177
Average sales prices:
	Gas (dry) (per Mcf):			5.66
	Condensate and oil (per Bbl)			30.76
	Gas equivalent (MMcfe)			5.47
Average lifting cost per Mcfe(1)				1.84

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(1)	Condensate and oil are converted to a common unit of measure on the basis of six Mcf of natural gas to one barrel of condensate or oil. The components of production costs may vary substantially among wells depending on the methods of recovery employed and other factors.

 

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Productive Wells(1)

      The following table presents the number of producing oil and gas wells attributable to our properties, as of December 31, 2003.

				Producing Wells				Company Operated
Gross producing offshore wells(2):
	Oil				62				37
	Natural Gas				22				18
		Total			84				55
Net producing offshore wells(3):
	Oil				40.978				37
	Natural Gas				20.185				19.2
		Total			61.163				56.2
Gross producing onshore wells(2):
	Oil				61				57
	Natural				2				2
		Total			63				59
Net productive onshore wells(3):
	Oil				57.5				56.18
	Natural				0.6				0
		Total			58.1				56.18

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(1)	One or more completions in the same borehole are counted as one well.
(2)	A “gross well” is a well in which we own a working interest.
(3)	A “net well” is deemed to exist when the sum of the fractional working interests in gross wells equals one.

Leasehold Acreage

      The following table presents the estimated developed acreage attributable to Panaco’s properties, as of December 31, 2003.

      Developed onshore acreage(1):

	Gross acres(2)			5,986
	Net acres(3)			4,410
Undeveloped onshore acreage(1):
	Gross acres(2)			1,388
	Net acres(3)			1,207
Developed offshore acreage(1):
	Gross acres(2)			32,889
	Net acres(3)			31,448
Undeveloped offshore acreage(1):
	Gross acres(2)			960
	Net acres(3)			384

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(1)	Developed acreage is acreage assignable to producing wells.
(2)	A “gross acre” is one in which we own a working interest.

 

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(3)	A “net acre” is deemed to exist when the sum of the fractional working interests in gross acres equals one.

      Panaco generally acquires a leasehold interest in the properties to be explored. The leases grant the lessee the right to explore for and extract oil and gas from a specified area. Lease rentals usually consist of a fixed annual charge made prior to obtaining production. Once production has been established, a royalty is paid to the lessor based upon the gross proceeds from the sale of oil and gas. Once wells are drilled, a lease generally continues as long as production of oil and gas continues. In some cases, leases may be acquired in exchange for a commitment to drill or finance the drilling of a specified number of wells to predetermined depths.

      Substantially all of Panaco’s producing oil and gas properties are located on leases held by Panaco for an indeterminate number of years as long as production is maintained. All of Panaco’s non-producing acreage is held under leases from mineral owners or a government entity which expire at varying dates. Panaco is obligated to pay annual delay rentals to the lessors of certain properties in order to prevent the leases from terminating.

Drilling Activity

      The following table presents the number of gross productive and dry wells in which Panaco had an interest that were drilled and completed during the five years ended December 31, 2003.

		Development Wells																Exploratory Wells
		Completed								Dry								Completed								Dry
		Oil				Gas				Oil				Gas				Oil				Gas				Oil				Gas
1999			1				2				3				1				0				0				0				0
2000			0				5				1				0				0				0				0				0
2001			0				4				0				0				0				0				0				1
2002			0				0				0				0				0				0				0				0
2003			0				0				0				0				0				0				0				0
Total			1				11				4				1				0				0				0				1

Well Operations

      Panaco operates 98 productive offshore wells and owns all of the working interests in a majority of those wells. Third party operators, including Unocal Corporation, Newfield Exploration, Apache and Burlington, operate its 32 remaining productive offshore wells. It also operates 98 productive onshore wells in which Panaco owns a majority or all of the working interest. In addition, Panaco owns working interests in 32 productive onshore wells operated by others. Where properties are operated by others, operations are conducted pursuant to joint operating agreements that were in effect at the time Panaco acquired its interest in these properties. The compensation paid to the operator for such services customarily varies from property to property, depending on the nature, depth, and location of the property being operated.

Marketing of Production

      Panaco sells the production from its properties in accordance with industry practices, which include the sale of oil and gas at the wellhead to third parties. It sells both at prices based on factors normally considered in the industry, such as index price for natural gas or the posted price for oil, price premiums or bonuses with adjustments for transportation and the quality of the oil and gas.

      Panaco markets all of its offshore oil production to Plains, Amoco, Oxy, Conoco, Texaco, Unocal and British Petroleum. British Petroleum has a call on all of the oil production from Panaco’s properties acquired from BP at their posted prices. If Panaco has a bona fide offer from a crude oil purchaser at a higher price than BP’s posted price, then BP must match that price or release the call. Oil from the Zapata Properties is sold to Unocal and BP, but can be sold to any crude oil purchaser of Panaco’s choice. Plains purchases the oil production from the Umbrella Point Fields, the East Breaks 165 Fields, the Price Lake Field and on some of

 

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Plugging and Abandonment

      All of Panaco’s offshore reserve values include the estimated future liability to plug and abandon all of the wells, platforms and pipelines in accordance with guidelines established by regulatory authorities. These costs vary according to the location of the lease, depth of water, number of wells, etc. As of September 30, 2004, the total estimated future net abandonment costs for all of Panaco’s properties is approximately $70.1 million. The Minerals Management Service of the U.S. Department of the Interior requires operators of offshore platforms to provide evidence of the ability to satisfy these future obligations. The companies that we acquire properties from may also require evidence of our ability to satisfy these future obligations. Panaco’s preferred method of providing evidence to these parties is a combination of escrow accounts and surety bonds.

Employees

      Panaco has a management agreement with NEG, through which NEG personnel are provided to it.

Hotel and Casino

GB Holdings, Inc. (The Sands)

      GB Holdings has no operating activities. Its significant asset is its investment in Atlantic Holdings, which is the parent company of ACE Gaming. The principal business activity of ACE Gaming is its ownership and operation of The Sands Hotel and Casino. Pursuant to a purchase agreement, dated January 21, 2005, with Cyprus, we will acquire approximately 41.2% of the outstanding common stock of GB Holdings and warrants to purchase, upon the occurrence of certain events, approximately 11.3% of the fully diluted common stock of Atlantic Holdings in exchange for 413,793 Depositary Units, valued at $29.00 per unit, or an aggregate of $12.0 million, plus up to an additional 206,897 Depositary Units, valued at $29.00 per unit, or an aggregate of $6.0 million, if GB Holdings meets certain earnings targets during 2005 and 2006. AREH will contribute approximately 36.3% of the outstanding common stock of GB Holdings, warrants to purchase approximately 10.0% of the fully diluted common stock of Atlantic Holdings and its $26.9 million principal amount of the Atlantic Holdings Notes to AREP Sands. After giving effect to these transactions, AREP Sands will own approximately 77.5% of the outstanding common stock of GB Holdings, approximately $63.9 million principal amount, or approximately 96.4%, of the Atlantic Holdings Notes, and warrants to purchase approximately 21.3% of the fully diluted common stock of Atlantic Holdings. Warrants to purchase, upon the occurrence of certain events, approximately 27.5% of the fully diluted common stock of Atlantic Holdings are currently outstanding. Under certain circumstances, the Atlantic Holdings Notes are convertible into approximately 41.3% of the fully diluted common stock of Atlantic Holdings. If all outstanding Atlantic Holdings notes were converted and warrants exercised, we would own 63.4% of the Atlantic Holdings common stock and GB Holdings would own 28.8% of the Atlantic Holdings common stock and the remaining shares would be owned by the public.

Casino and Hotel

      The Sands Hotel and Casino is located in Atlantic City, New Jersey, on approximately 6.1 acres of land one-half block from the Boardwalk at Brighton Park between Indiana Avenue and Dr. Martin Luther King, Jr. Boulevard. The Sands Hotel and Casino facility currently consists of a casino and simulcasting facility with approximately 78,000 square feet of gaming space containing approximately 2,200 slot machines and 73 table games; two hotels with a total of 620 rooms, including 170 suites; five restaurants; two cocktail lounges; two private lounges for invited guests; an 800-seat cabaret theater; retail space; an adjacent nine-story office building with approximately 77,000 square feet of office space for its executive, financial and administrative personnel; the “People Mover,” an elevated, enclosed, one-way moving sidewalk connecting The Sands Hotel

 

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      The Sands Hotel and Casino entered into a long-term lease of the Madison House Hotel. The initial lease period is from December 2000 to December 2012 with lease payments ranging from $1.8 million per year to $2.2 million per year. The Madison House is physically connected at two floors to the existing Sands casino-hotel complex. The Sands Hotel and Casino recently completed renovations to upgrade and combine the rooms of the Madison House into a total of 113 suites and 13 single rooms. It is the intention of The Sands Hotel and Casino to maintain and operate the Madison House at the same quality level as The Sands Hotel and Casino. For the years ended December 31, 2001, 2002 and 2003 and the nine months ended September 30, 2003 and 2004 approximately 69.5%, 81.7%, 81.6%, 83.2% and 79.2%, respectively, of The Sands Hotel and Casino’s gaming revenue was generated by slot machine play and 29.4%, 17.6%, 17.7%, 16.2% and 20.0%, respectively, by table games. The Sands Hotel and Casino derives its other gaming revenue from poker and simulcast, which primarily serves to attract customers for slot machines and table games.

      With the exception of the land over which the People Mover is constructed and the Madison Hotel, The Sands Hotel and Casino owns the land and improvements comprising The Sands Hotel and Casino facility. The Sands Hotel and Casino owns and operates the casino, the hotel, the restaurants, the cocktail lounge, the private lounges, the theatre and a retail gift shop. In addition, The Sands Hotel and Casino has licensed certain space within the hotel building to unrelated third parties who operate a beauty shop, a peanut shop, a game room and a coffee stand.

Business and Marketing Strategy

      The Sands Hotel and Casino’s marketing strategy consists of seeking premium and middle category patrons. The Sands Hotel and Casino markets to these premium patrons through its offering of private, limited-access facilities and related amenities. It uses information technology to monitor patron play, control certain casino operating costs and target marketing efforts toward frequent visitors with above average gaming budgets.

      “The Sands Hotel and Casino” name has a strong brand recognition and a rich heritage in gaming that dates back to the original property in Las Vegas of the 1950’s. Beginning in 2003, the Atlantic City Sands stylized a new Sands logo, which reflected this rich heritage and began to transform the property theme into the “Players Place.” The Players Place strategy offers outstanding gaming odds, highest table limits, more liberal player rewards to the avid customer and unparalleled, personal boutique service that exceeds guest expectations; all in an environment that makes the avid player feel like he has a “home court advantage.” ACE Gaming licenses the “Sands” tradename from Las Vegas Sands, Inc., an unaffiliated third party, pursuant to a license agreement, that expires in 2086. The Sands Hotel and Casino pays an annual licensing fee of the greater of $100,000 or 3% of the gross room charges at the location. In 2003, the licensing fee was approximately $0.3 million.

      As part of The Sands Hotel and Casino capital expenditure program, certain improvements, additions and enhancements have recently been made, or are planned to be made in the near future, to the facility. In 2003, The Sands Hotel and Casino renovated the casino floor. The Swingers lounge was constructed in the center of the casino to provide a multi-faceted state-of-the-art entertainment experience. The Swingers lounge includes bartop slot machines and is staffed by “Flair Bartenders.” In addition, further renovations to the Platinum and Plaza Clubs, the Copa showroom and the promotions center, and the building of a new bus reception area improved the customer experience by providing easier access to facilities, shorter lines and a more relaxing and personal environment. More table games, including poker, were added during 2003 and some slot machines were displaced. The slot product was upgraded during 2003, including the initial phase of converting the slots to coinless system technology. These slots accept paper cash, coin or coupons and allow the player an option to return winnings or cash-outs in the form of redeemable tickets. During 2004, over 70% of the slot product was upgraded with coinless technology. In 2004, an entire floor of 37 rooms in The Sands Hotel and Casino was converted into suites to improve the inventory of accommodations for the premium category players. In 2005, The Sands Hotel and Casino plans to: (1) relocate the poker/simulcast

 

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Employees and Labor Relations

      In Atlantic City, all employees, except certain hotel employees, must be licensed under the NJCCA. Due to the seasonality of the operations of The Sands Hotel and Casino, the number of employees varies during the course of the year. As of December 31, 2004, The Sands Hotel and Casino had approximately 1,900 employees. The Sands Hotel and Casino has collective bargaining agreements with three unions that represent approximately 700 employees, most of whom are represented by the Hotel, Restaurant Employees and Bartenders International Union, AFL-CIO, Local 54. The collective bargaining agreement with Local 54 has been negotiated. The collective bargaining agreements with the Carpenters, Local 623 and Entertainment Workers, Local 68 expire in April and July 2005, respectively. Management considers its labor relations to be good.

Competition

      The Sands Hotel and Casino faces intense competition from the eleven other existing Atlantic City casinos, including the newly opened Borgata. According to reports of the Casino Control Commission, the twelve Atlantic City casinos currently offer approximately 1.4 million square feet of gaming space.

      The gaming industry is highly competitive and competitors may have greater resources than The Sands Hotel and Casino. If other properties operate more successfully, if existing properties are enhanced or expanded, or if additional hotels and casinos are established in and around the location in which The Sands Hotel and Casino conducts business, The Sands Hotel and Casino may lose market share. In particular, expansion of gaming in or near the geographic area from which The Sands Hotel and Casino attracts or expects to attract a significant number of customers could have a significant adverse effect on The Sands Hotel and Casino’s business, financial condition and results of operations. The Sands Hotel and Casino competes, and will in the future compete, with all forms of existing legalized gaming and with any new forms of gaming that may be legalized in the future. Additionally, The Sands Hotel and Casino faces competition from all other types of entertainment.

      The Sands Hotel and Casino also competes with legalized gaming from casinos located on Native American tribal lands. In October 2001, the New York State Legislature enacted a bill, which the governor signed, authorizing a total of six Indian casinos in the State of New York — three in Western New York and three in the Catskill Region — and approved the use of video lottery terminals at racetracks and authorized the participation of New York State in a multi-state lottery. The governor of New York has proposed increasing the number of casinos from three to five.

      A significant amount of The Sands Hotel and Casino’s revenues is derived from patrons living within a 120-mile radius of Atlantic City, New Jersey, particularly northern New Jersey, southeastern Pennsylvania and metropolitan New York City. Proposals to allow casino gaming in certain areas of Pennsylvania had been defeated within the past three years, although Pennsylvania gaming was approved in 2004. If additional casino gaming were to be legalized in venues that are convenient to Northern New Jersey, Southern Pennsylvania and Metropolitan New York City, it could have a material adverse effect on The Sands Hotel and Casino.

 

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OIL AND GAS RISK FACTORS

We face substantial risks in the oil and gas industry.

      The exploration for and production of oil and gas involves numerous risks. The cost of drilling, completing and operating wells for oil or gas is often uncertain, and a number of factors can delay or prevent drilling operations or production, including:

	•	unexpected drilling conditions;
	•	pressure or irregularities in formation;
	•	equipment failures or repairs;
	•	fires or other accidents;
	•	adverse weather conditions;
	•	pipeline ruptures or spills; and
	•	shortages or delays in the availability of drilling rigs and the delivery of equipment.

The oil and gas industry is subject to environmental regulation by state and federal agencies.

      Our operations and the operations that we expect to acquire are affected by extensive regulation through various federal, state and local laws and regulations relating to the exploration for and development, production, gathering and marketing of oil and gas. Matters subject to regulation include discharge permits for drilling operations, drilling and abandonment bonds or other financial responsibility requirements, reports concerning operations, the spacing of wells, unitization and pooling of properties, and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas.

      Our operations are also subject to numerous environmental laws, including but not limited to, those governing management of waste, protection of water, air quality, the discharge of materials into the environment, and preservation of natural resources. Non-compliance with environmental laws and the discharge of oil, natural gas, or other materials into the air, soil or water may give rise to liabilities to the government and third parties, including civil and criminal penalties, and may require us to incur costs to remedy the discharge. Oil and gas may be discharged in many ways, including from a well or drilling equipment at a drill site, leakage from pipelines or other gathering and transportation facilities, leakage from storage tanks, and sudden discharges from oil and gas wells or explosion at processing plants. Hydrocarbons tend to degrade slowly in soil and water, which makes remediation costly, and discharged hydrocarbons may migrate through soil and water supplies or adjoining property, giving rise to additional liabilities. Laws and regulations protecting the environment have become more stringent in recent years, and may in certain circumstances impose retroactive, strict, and joint and several liabilities rendering entities liable for environmental damage without regard to negligence or fault. In the past, we have agreed to indemnify sellers of producing properties against certain liabilities for environmental claims associated with those properties. We cannot assure you that new laws or regulations, or modifications of or new interpretations of existing laws and regulations, will not substantially increase the cost of compliance or otherwise adversely affect our oil and gas operations and financial condition or that material indemnity claims will not arise with respect to properties that we acquire. While we do not anticipate incurring material costs in connection with environmental compliance and remediation, we cannot guarantee that material costs will not be incurred.

We may experience difficulty finding and acquiring additional reserves and be unable to compensate for the depletion of our proved reserves.

      Our future success and growth depends upon the ability to find or acquire additional oil and gas reserves that are economically recoverable. Except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, our proved reserves will generally decline as they are produced. The decline rate varies depending upon reservoir characteristics and other

 

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factors. Our future oil and gas reserves and production, and, therefore, cash flow and income are highly dependent upon the level of success in exploiting our current reserves and acquiring or finding additional reserves. The business of exploring for, developing or acquiring reserves is capital intensive. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investments to maintain or expand this asset base of oil and gas reserves could be impaired. Development projects and acquisition activities may not result in additional reserves. We may not have success drilling productive wells at economic returns sufficient to replace our current and future production. We may acquire reserves which contain undetected problems or issues that did not initially appear to be significant to us.

      Reservoir engineering is a subjective process of estimating the volumes of underground accumulations of oil and gas which cannot be measured precisely. The accuracy of any reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserve estimates prepared by other engineers might differ from the estimates contained herein. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Future prices received for the sale of oil and gas may be different from those used in preparing these reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

      Proved reserves are the estimated quantities of natural gas, condensate and oil that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. The estimation of reserves requires substantial judgment on the part of petroleum engineers, resulting in imprecise determinations, particularly with respect to recent discoveries. The accuracy of any reserve estimate depends on the quality of available data and engineering and geological interpretation and judgment. Results of drilling, testing and production after the date of the estimate may result in revisions of the estimate. Accordingly, estimates of reserves are often materially different from the quantities of natural gas, condensate and oil that are ultimately recovered, and these estimates will change as future production and development information becomes available. The reserve data represent estimates only and should not be construed as being exact.

Difficulties in exploration and development could adversely affect our financial condition.

      The costs of drilling all types of wells are uncertain, as are the quantity of reserves to be found, the prices that NEG Holding, TransTexas or Panaco will receive for the oil or natural gas and the costs to operate the well. While each has successfully drilled wells, you should know that there are inherent risks in doing so, and those difficulties could materially affect our financial condition and results of operations. Also, just because we complete a well and begin producing oil or natural gas, we cannot assure you that we will recover our investment or make a profit.

Oil and gas prices are likely to be volatile.

      Our revenues, profitability and the carrying value of oil and gas properties are substantially dependent upon prevailing prices of, and demand for, oil and gas and the costs of acquiring, finding, developing and producing reserves. Historically, the markets for oil and gas have been volatile. Markets for oil and gas likely will continue to be volatile in the future. Prices for oil and gas are subject to wide fluctuations in response to: (1) relatively minor changes in the supply of, and demand for, oil and gas; (2) market uncertainty; and (3) a variety of additional factors, all of which are beyond our control. These factors include, among others; domestic and foreign political conditions; the price and availability of domestic and imported oil and gas; the level of consumer and industrial demand; weather, domestic and foreign government relations; and the price and availability of alternative fuels and overall economic conditions. Our production is weighted toward natural gas, making earnings and cash flow more sensitive to natural gas price fluctuations.

 

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There is inherent uncertainty in estimates of reserves which may affect future net cash flows.

      The basis for the success and long-term prospects for our oil and gas business is the price that we receive for our oil and gas. These prices are the primary factors for all aspects of our business including reserve values, future net cash flows, borrowing availability and results of operations. The reserve valuations are prepared annually by independent petroleum consultants, including the Pretax PV-10 values included elsewhere in this offering memorandum. However, there are many uncertainties inherent in preparing these reports and the third party consultants rely on information we provide them. The Pretax PV-10 calculations assume constant oil and gas prices, operating expenses and capital expenditures over the lives of the reserves. They also assume certain timing for completion of projects and that we will have the financial ability to conduct operations and capital expenditures without regard to factors independent of the reserve report. The actual results realized by the operations we propose to acquire may have historically varied from these reports and may do so in the future. The volumes estimated in these reports may also vary due to a variety of reasons including incorrect assumptions, unsuccessful drilling and the actual oil and gas prices that we receive.

      You should not assume that the Pretax PV-10 values of reserves included elsewhere in this offering memorandum represent the market value for those reserves. These values are prepared in accordance with strict guidelines imposed by the SEC. These valuations are the estimated discounted future net cash flows from our proved reserves. These estimates use prices, that the operations we propose to acquire, received or would have received on December 31, 2003 and use costs for operating and capital expenditures in effect at that date. These assumptions are then used to calculate a future cash flow stream that is discounted at a rate of 10%.

      The base prices used for the Pretax PV-10 calculation were public spot prices on December 31, 2003 adjusted by differentials to those spot market prices. These price adjustments were done on a property-by-property basis for the quality of the oil and gas and for transportation to the appropriate location.

Operating hazards and uninsured risks are inherent to the oil and gas industry.

      Our oil and gas business involves a variety of operating risks, including, but not limited to, unexpected formations or pressures, uncontrollable flows of oil, natural gas, brine or well fluids into the environment (including groundwater contamination), blowouts, fires, explosions, pollution and other risks, any of which could result in personal injuries, loss of life, damage to properties and substantial losses. Although we carry insurance at levels we believe are reasonable, we are not fully insured against all risks. Losses and liabilities arising from uninsured or under-insured events could have a material adverse effect on our financial condition and operations.

Our use of hedging arrangements could reduce our income.

      NEG Holding and the companies that we intend to acquire, TransTexas and Panaco, typically hedge a portion of oil and gas production during periods when market prices for products are higher than historical average prices. During 2003, NEG Holding and TransTexas hedged 54% and 28%, respectively, of annual natural gas production and NEG Holding hedged 49% of annual oil production.

      Typically, NEG Holding, TransTexas and Panaco have used swaps, cost-free collars and options to put products to a purchaser at a specified price, or floor. In these transactions, NEG Holding, TransTexas and Panaco will usually have the option to receive from the counterparty to the hedge a specified price or the excess of a specified price over a floating market price. If the floating price exceeds the fixed price, the hedging party is required to pay the counterparty all or a portion of this difference multiplied by the quantity hedged.

Government regulations impose costs on abandoning oil and gas facilities.

      Government regulations and lease terms require all oil and gas producers to plug and abandon platforms and production facilities at the end of the properties’ lives. The reserve valuations for NEG Holding,

 

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TransTexas and Panaco include the estimated costs of plugging the wells and abandoning the platforms and equipment on their properties, less any cash deposited in escrow accounts for these obligations. These costs are usually higher on offshore properties, as are most expenditures on offshore properties. As of December 31, 2003, the total estimated abandonment costs, net of $22.0 million already in escrow, were approximately $48.0 million. Those future liabilities are accounted for by accruing for them in depreciation, depletion and amortization expense over the lives of each property’s total proved reserves.

The oil and gas industry is highly competitive.

      There are many companies and individuals engaged in the exploration for and development of oil and gas properties. Competition is particularly intense with respect to the acquisition of oil and gas producing properties and securing experienced personnel. We encounter competition from various oil and gas companies in raising capital and in acquiring producing properties. Many of our competitors have financial and other resources considerably larger than ours.

MANAGEMENT 2004 ESTIMATED RESERVES FOR NEG HOLDING, TRANSTEXAS AND PANACO.

      As of January 21, 2005, management of NEG Holding, TransTexas and Panaco estimates that proved reserves of oil and gas were approximately 249,700 MMcfe, 53,800 MMcfe and 54,300 MMcfe, respectively. MMcfe means million cubic feet of gas equivalent determined using the ratio: six thousand cubic feet of natural gas (Mcf) to one barrel of 42 U.S. gallons (Bbl) of crude oil, condensate or natural gas. These reserve estimates have been prepared by internal engineering staffs and have not been prepared, reviewed or assessed by independent reserve engineering firms. Reserves prepared by independent reserve engineering firms might differ materially from these estimates. Each of NEG Holding, TransTexas and Panaco annually obtain reserve estimates prepared by independent engineers and such estimates as of January 21, 2005 are being prepared currently. See “The Acquisitions” for reserve information for each of these companies for previous years. In addition, the preparation of estimates inherently is subject to uncertainty. The estimation of reserves requires substantial judgment on the part of petroleum engineers, resulting in imprecise determinations, particularly with respect to recent discoveries. The accuracy of any reserve estimate depends on the quality of available data and engineering and geological interpretation and judgment. Results of drilling, testing and production after the date of the estimate may result in revisions of the estimate. Accordingly, estimates of reserves are often materially different from the quantities of natural gas, condensate and oil that are ultimately recovered, and these estimates will change as future production and development information becomes available. The reserve data presented in this offering memorandum, including the internally prepared data as of January 21, 2005 presented above represent estimates only and should not be construed as being exact. In the past, the proved reserves as reported by independent reserve engineering firms have varied from the estimates provided by management, and such variations have been material.

 

 

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