Swift Energy Company is engaged in developing, exploring, acquiring, and operating oil and gas properties, with a focus on onshore and inland waters oil and natural gas reserves in Texas and Louisiana and onshore oil and natural gas reserves in New Zealand. The Company was founded in 1979 and is headquartered in Houston, Texas. As of December 31, 2003, we had interests in 998 wells located domestically in four states, in federal offshore waters, and in New Zealand. We operated 870 of these wells representing 95% of our proved reserves. At year-end 2003, we had estimated proved reserves of 820.4 Bcfe, of which approximately 47% was crude oil, 41% natural gas, and 12% NGLs, and overall 59% was proved developed. Our proved reserves are concentrated 40% in Louisiana, 37% in Texas, and 21% in New Zealand.

We currently focus primarily on development and exploration in four domestic core areas and two core areas in New Zealand:

We have a well-balanced portfolio of oil and gas properties and prospects. The AWP Olmos and Lake Washington areas and New Zealand are characterized by long-lived reserves that we expect to be steadily produced over a long period of time. The Masters Creek and Brookeland areas are characterized by shorter-lived reserves with high initial rates of production that decline rapidly. We believe these shorter-lived reserves complement our long-lived reserves. Based on our total 2003 year-end proved reserves and total 2003 production, we calculated our average reserve life as 15.4 years.

We have increased our proved reserves to 820.4 Bcfe at year-end 2003 from 436.1 Bcfe at year-end 1998, which has resulted in the replacement of 266% of our production during the same five-year period. Our five-year average reserves replacement costs were $1.25 per Mcfe. Our average annual reserve replacement costs for the last five years, starting with 2003, were $1.17, $0.91, $3.43, $0.82, and $1.21 per Mcfe. In 2003, we increased our proved reserves by 9.5%, which replaced 234% of our 2003 production. Our 2003 production increased by 7% in relation to 2002 production. We have increased our production to 53.2 Bcfe at year-end 2003 from 39.0 Bcfe at year-end 1998. Primarily due to increased production, this has resulted in average annual growth in net cash provided by operating activities of 15% per year from year-end 1998 to year-end 2003.

Through intensive efforts, we have developed an inventory of exploration and development prospects, identifying drilling locations through integrated geological and geophysical studies of our undeveloped acreage and other prospects. As a result, we added 105.6 Bcfe of proved reserves through drilling in 2003 (36.1 Bcfe from New Zealand), 83.9 Bcfe in 2002 (15.9 Bcfe from New Zealand), and 105.8 Bcfe in 2001 (17.4 Bcfe from New Zealand). The 2003 additions were driven by the result of our development completion rate, as we successfully completed 53 of 63 domestic development wells, while five of eight domestic exploratory wells were successfully completed. In New Zealand we drilled three development wells and one exploratory well. Only one of these four wells, the exploratory well, was unsuccessful.

We have also added reserves through acquisitions. In the first quarter of 2002, we purchased interests in the four TAWN fields in New Zealand for approximately $51.4 million, which also included significant infrastructure, after price adjustments. In the first quarter of 2001, we purchased interests in the Lake Washington field from Elysium Energy, LLC, for approximately $30.5 million in cash. We purchased interests in the Brookeland and Masters Creek areas from Sonat Exploration Company in the third quarter of 1998 for approximately $85.8 million in cash. In 146 transactions from 1979 to 2003, we have acquired approximately $697.6 million of producing oil and gas properties on behalf of our co-investors and ourselves. We acquired, for our own account, approximately $341.2 million of producing properties, with original proved reserves estimated at 469.0 Bcfe during this period. Our producing property acquisition expenditures in the past three years were $1.9 million in 2003, $64.2 million in 2002, and $41.3 million in 2001. Our acquisition costs have averaged $0.83 per Mcfe over this three-year period. Our acquisition costs in 2003 averaged $3.99 per Mcfe and were made up of purchases of limited partner interests in several of the remaining partnerships we manage.

We currently plan to spend $130 to $150 million in total capital expenditures in 2004, excluding acquisition costs and net of approximately $5 million to $15 million in non-core property dispositions. As always, the budget for 2004 is dependent upon our performance and commodity pricing during the year. As currently planned, domestic activities account for 80% of our budgeted spending, primarily in the Lake Washington area.

We believe that our competitive strengths, together with a balanced and comprehensive business strategy, provide us with the flexibility and capability to accomplish our goals. Our primary goals for the next five years are to increase proved oil and gas reserves at an average rate of 5% to 10% per year and production at an average rate of 7% to 12% per year.

When we believe market conditions favor increasing reserves through acquisitions, we apply our considerable experience in evaluating and negotiating prospective acquisitions. We believe this balanced approach between acquisitions and drilling has resulted in our ability to grow reserves in a relatively low cost manner, while participating in the upside potential of exploration.

Our strategy is to increase our reserves and production through both drilling and acquisitions, shifting the balance between the two activities in response to market conditions. Generally, we seek to acquire properties with the potential for additional reserves and production through development and exploration efforts. In addition, we seek to enhance the results of our drilling and production efforts through the implementation of advanced technologies.

As both oil and natural gas prices were strong in 2003, carrying over from 2002, we focused our capital expenditures on drilling mainly in the Lake Washington area and south Texas domestically and in the Rimu/Kauri area in New Zealand. Our total capital expenditures in 2003 were $144.5 million. Of this amount, $68.9 million was spent on drilling in the United States, with $57.0 million for development drilling and $11.9 million for exploratory drilling. In New Zealand we spent $17.4 million on drilling, with $15.1 million for development drilling and $2.3 for exploratory drilling. We also spent $25.9 million for the construction of domestic production and surface facilities, mainly in our Lake Washington area. Our leasehold, seismic and geological costs of prospects, both in the United States and New Zealand, were $17.8 million in 2003. The remaining capital expenditures of $14.5 million were spent on gas processing plants, field compression facilities and furniture and fixtures, both in the United States and New Zealand. During 2003, we largely relied upon cash provided by operating activities of $110.8 million, proceeds of bank borrowings of $15.9 million, and proceeds from the sale of property and equipment of $10.2 million to fund our capital expenditures.

During 2002, in response to strong oil prices throughout the year, we focused our capital expenditures on the Lake Washington area domestically and on the TAWN acquisition in New Zealand. Although oil prices remained strong in 2002, natural gas prices for most of the year were lower than prior year levels, and our cash flow generated due to these commodity prices decreased, as expected, even though production increased. As a result of lower cash flow in 2002, we reduced our capital expenditures from the 2001 level to $155.2 million. Of this amount, $58.4 million was spent on acquisitions, mainly the TAWN acquisition in New Zealand. We spent $42.7 million on drilling in the United States, with $34.4 for development drilling and $8.3 million for exploratory drilling. In New Zealand we spent $22.9 million on drilling, with $12.6 million for development drilling and $10.3 million for exploratory drilling. We also spent $10.6 million constructing a gas processing plant in New Zealand. The remaining capital expenditures of $20.6 million were spent primarily on leasehold, seismic, and geological costs of prospects, both in the United States and New Zealand. During 2002, we principally relied upon cash flows from operations of $71.6 million, net proceeds from the issuance of long-term debt of $195.0 million, and net proceeds from our public stock offering of $30.5 million, less the repayment of bank borrowings of $134.0 million, to fund our capital expenditures.

Our concentration of reserves and our significant acreage positions in our core areas allow us to realize economies of scale in drilling and production. The value of this concentration is enhanced by us acting as the operator of 95% of our proved reserves at year-end 2003. Our operational control allows us to better manage production, control our expenses, allocate capital and time field development. We intend to continue acquiring large acreage positions in under-explored and under-exploited areas, where, as operator, we can exploit successful discoveries to create new core areas or grow production from developed fields. In executing this strategy:

• We focus our resources on acquiring properties that we can operate and in which we can obtain a significant working interest. With operational control, we are able to apply our technical and operational experience to optimize our exploration and exploitation of such acquired properties.
• We acquire and operate domestic properties in a limited number of geographic areas. Operating in a concentrated area helps us to better control our overhead by enabling us to manage a greater amount of acreage with fewer employees, minimizing incremental costs of increased drilling and production.
• We continue to believe in natural gas prospects and reserves in the United States. The natural gas market in the United States has a well-developed infrastructure. Natural gas is viewed by many as the preferred fuel in North America for several reasons, including environmental concerns. We have a strong inventory of natural gas reserves that can be developed in higher priced environments.
• We seek to operate large acreage positions with high exploration and development potential. For example, on our original 100,000 acre New Zealand permit, only two wells had been drilled at the time that we acquired our interest. We have since drilled 17 wells in New Zealand since operations began in 1999. When we first acquired our interest in Masters Creek, Brookeland, and Lake Washington, these areas also had significant additional development potential, and are still viewed as such.

Our New Zealand activities provide us with long-term growth opportunities and significant potential reserves in a country with stable political and economic conditions, existing oil and gas infrastructure, and favorable tax and royalty regimes. We have completed construction of our Rimu production and gas processing facilities, which became operational in May 2002 and enabled us to begin the sale of production from the Rimu/Kauri area. We were able to bring our Rimu discovery on commercial production in a significantly shorter period than any other similar project previously undertaken in New Zealand of which we are aware.

In January 2002, we acquired the TAWN fields. In our TAWN acquisition, we also acquired extensive associated processing facilities and pipelines. These facilities and pipelines give us a competitive advantage through infrastructure that complements our existing fields, providing us with increased access to export terminals and markets and additional excess processing capacity for both oil and natural gas.

We employ oil and gas professionals, including geophysicists, petrophysicists, geologists, petroleum engineers, and production and reservoir engineers, who have an average of approximately 25 years of experience in their technical fields and have been employed by Swift for an average of over 10 years. We continually apply our extensive in-house experience and current technologies to benefit our drilling and production operations. We have developed a particular expertise in drilling horizontal wells at vertical depths below 10,000 feet, often in a high-pressure environment, involving single or dual lateral legs of several thousand feet. This results in an integrated approach to exploration using multidisciplinary data analysis and interpretation that has helped us identify a number of exploration prospects.

We use various recovery techniques, including water flooding and acid treatments, fracturing reservoir rock through the injection of high-pressure fluid, gravel packing, and inserting coiled tubing velocity strings to enhance and maintain gas flow. We believe that the application of fracturing technology and coiled tubing has resulted in significant increases in production and decreases in completion and operating costs, particularly in our AWP Olmos area.

We have increasingly used seismic technology to enhance the results of our drilling and production efforts, including 2-D and 3-D seismic analysis, amplitude versus offset studies, and detailed formation depletion studies. As a result, we have maintained internal seismic experience and have compiled an extensive database.

When appropriate, we develop new applications for existing technology. For example, in New Zealand we acquired seismic data by effectively combining marine data with the acquisition of land seismic data, an application we have not seen any other company use in New Zealand.

We practice a disciplined approach to financial management and have historically maintained a strong capital structure that provides the ability to execute our business plan. Key components of our financial discipline include maintaining a capital budget balanced between drilling and acquisitions, establishing leverage targets that are reasonable given the volatility of the oil and gas markets, and opportunistically accessing the capital markets. As of December 31, 2003, our long-term debt comprised approximately 46% of our total capitalization. At December 31, 2003, we had $233.3 million of available borrowing capacity under our credit facility.

Domestic Core Operating Areas

AWP Olmos Area. As of December 31, 2003, we owned 27,900 net acres in the AWP Olmos Area in South Texas. We have extensive experience with low-permeability, tight-sand formations typical of this area, having acquired our first acreage there in 1988. These reserves are approximately 66% gas. At year-end 2003, we owned interests in and operated 504 wells in this area producing gas from the Olmos sand formation at depths of approximately 9,000 to 11,500 feet. We own nearly 100% of the working interests in all our operated wells.

In 2003, we completed eight development wells in this area, performed four fracture extensions, and installed coiled tubing velocity strings in six wells. At year-end 2003, we had 124 proved undeveloped locations. Also in 2003, we purchased interests in the AWP Olmos area from partnerships we managed. Our planned 2004 capital expenditures in this area will focus on drilling 15 to 18 development wells.

Brookeland Area. As of December 31, 2003, we owned drilling and production rights in 72,516 net acres and 3,500 fee mineral acres in the Brookeland area, which contains substantial proved undeveloped reserves. This area was part of the acquisition from Sonat in 1998 and is located in East Texas near the border of Louisiana in Jasper and Newton counties. It primarily contains horizontal wells producing from the Austin Chalk formation. The reserves are approximately 56% oil and natural gas liquids. In 2003, we completed one development well in this area. At year-end 2003, we had 12 proved undeveloped locations in this area. Our planned 2004 capital expenditures in this area include drilling one development well.

Lake Washington Field. As of December 31, 2003, we owned drilling and production rights in 12,911 net acres in the Lake Washington Field. This area is located in Plaquemines Parish in South Louisiana. The reserves are approximately 94% oil and natural gas liquids. We acquired our interests in the Lake Washington Field in March 2001. This field produces oil from multiple Miocene sands ranging in depth from less than 1,700 feet to greater than 9,000 feet. The field is located on a salt dome and has produced over 300 million BOE since its inception in the 1930s. The area around the dome is heavily faulted, thereby creating a large number of potential traps. Oil and gas from approximately 77 producing wells is gathered from three platforms located in water depths from 2 to 12 feet, with drilling and workover operations performed with barge rigs. In 2003, 52 development wells and six exploratory wells were drilled in the area; 42 development and five exploratory wells were completed. At year-end 2003, we had 82 proved undeveloped locations in this field. Our planned 2004 capital expenditures in this area include drilling 25 to 30 development wells and two to four exploratory wells.

Masters Creek Area. As of December 31, 2003, we owned drilling and production rights in 62,560 net acres and 91,994 fee mineral acres in the Masters Creek area, which contains substantial proved undeveloped reserves. This area was also part of the acquisition from Sonat in 1998. It is located in Central Louisiana near the Texas-Louisiana border in the two parishes of Vernon and Rapides. It contains horizontal wells producing both oil and gas from the Austin Chalk formation. The reserves are approximately 71% oil and natural gas liquids. At year-end 2003, we had 12 proved undeveloped locations in the area. Our planned 2004 capital expenditures in this area include drilling one to two development wells.

Domestic Emerging Growth Areas

The Frio Trend. We have been focusing on the deep sands of the Frio formation (10,000 to 16,000 feet) in an area identified as Garcia Ranch, which straddles the border of Kenedy County and Willacy County in the southern tip of Texas. Retaining a 65% working interest, we had three discoveries in the area in 2001 and 2002, one in the Rome prospect in Willacy County, one in the Siena prospect in Kenedy County and one in the Milan prospect in Kenedy county. In 2003, we participated in completing one well in the Milan prospect with a 33% working interest. Two exploratory wells drilled in this area during 2003 were not successful. We plan to participate in drilling up to five wells in 2004 in this area.

The Wilcox Sands. We had three discoveries in the Wilcox sands during 2001, two of which were located in Goliad County, Texas: the Nita prospect drilled to a depth of approximately 15,000 feet and the Brandon prospect drilled to a depth of about 13,000 feet. Our working interests in the two wells are 73% and 60%, respectively. The third well, in which we have a 25% working interest, was in the Falcon Ridge prospect in Zapata County, Texas. We plan to participate in one exploratory well in this area in 2004, contingent upon finding a working interest partner.

The Woodbine Formation. The Woodbine formation is located in southeast Texas in San Jacinto, Polk, and Tyler counties. We drilled one well to the Woodbine formation in 2001, in the Lion prospect in San Jacinto County, Texas, to a depth of 15,000 feet. Although hydrocarbon-bearing intervals were found, the well was deemed noncommercial. The Company has another Woodbine prospect, the Jaguar prospect, located in Polk County. The Jaguar prospect may be drilled in 2004 if a working interest partner joins us for the project.

New Zealand Core Operating Areas

Our activity in New Zealand began in 1995. As of December 31, 2003, our permit 38719, which we operate, included approximately 49,800 acres in the Taranaki Basin of New Zealand’s north island. This acreage includes our Rimu and Kauri areas, as well as our Tawa and Matai prospects.

We expanded our operation in New Zealand in January 2002 with our TAWN purchase of Southern Petroleum (New Zealand) Exploration, Limited (Southern NZ), from Shell New Zealand, through which we acquired interests in four fields and significant infrastructure assets.

In March 2002, we completed the acquisition of all of the New Zealand assets of Antrim. These assets included a 5% working interest in the Swift-operated permit 38719, increasing the Company’s interest in this permit to 95%. An additional 7.5% interest was also acquired in permit 38716 (Huinga prospect), increasing the Company’s interest to 15%.

In August 2002, we were awarded two additional onshore permits, permits 38756 and 38759. These permits include approximately 8,100 and 20,400 gross acres, respectively, in proximity to our permit 38719.

In September 2002, we completed the acquisition of Bligh’s 5% working interest in permit 38719 and 5% interest in the Rimu petroleum mining permit 38151, along with their 3.24% working interest in the four TAWN petroleum mining licenses. The Company’s interests in permit 38719, petroleum mining permit 38151, and the TAWN petroleum mining licenses are now 100%.

In December 2002, we agreed to acquire an additional 50% interest in permit 38718 (Tuihu prospect) from Shell New Zealand through an existing pre-emptive right under the joint operating agreement. Following the transaction, SENZ sold a 20% interest in the permit to a subsidiary of New Zealand Oil and Gas Limited. The purchase and subsequent sale resulted in SENZ holding a 50% working interest in this permit. We were named operator of the permit. Permit 38718 contains the Tuihu #1 exploratory well, which was drilled in 2001 and temporarily abandoned. In 2003 this well was re-entered but was unsuccessful.

As of December 31, 2003, our gross capitalized oil and gas property costs in New Zealand totaled approximately $205.3 million. Approximately $169.5 million of our investment costs have been included in the proved properties portion of our oil and gas properties, while $35.8 million is included as unproved properties. Our functional currency in New Zealand is the U.S. Dollar.

Natural gas prices are substantially lower in New Zealand as compared to domestic prices, due largely to the predominant supply from the Maui Field under long standing supply contracts. However, the Maui Field that in recent years has supplied over 70% of the nation’s natural gas appears to have reached its peak sooner than anticipated, and its production is projected to decline sharply over the next few years and has begun to put upward pressure on natural gas prices in New Zealand.

Rimu Area. Early in 2002, we were awarded petroleum mining permit 38151 by the New Zealand Ministry for Economic Development for the development of the Rimu discovery over an approximately 5,500 acre area for a primary term of 30 years. Commercial production from the Rimu area began in May 2002.

Kauri Area. During 2003, we completed three of four wells in the Kauri area. Two of these wells successfully targeted the Kauri Sand, the third was completed in the Manutahi Sand. We also fracture stimulated three Kauri Sand wells in 2003.

TAWN Area. The TAWN acquisition in January 2002 consisted of a 96.76% working interest in four petroleum mining licenses, or PML, covering producing oil and gas fields and extensive associated hydrocarbon-processing facilities and pipelines. The TAWN assets are located approximately 17 miles north of the Rimu area.

The properties are collectively identified as the TAWN properties, an acronym derived from the first letters of the field names – the Tariki Field (PML 38138), the Ahuroa Field (PML 38139), the Waihapa Field (PML 38140), and the Ngaere Field (PML 38141). The four fields include 17 wells where the purchaser of gas, Contact Energy, has contracted to take minimum quantities and can call for higher production levels to meet electrical demand in New Zealand. Sales gas deliveries to Contact exceeded the contract minimum during all of 2003.

Solution gas gathered from the Waihapa Production Station (“WPS”) flows to the Tariki Ahuroa gas plant (“TAG”). The current processing capacity per day of the WPS facility is up to 15,000 barrels of oil and 45 MMcf of natural gas. Processing capacity tests conducted following facility modifications completed in the third quarter of 2002 confirmed a 12% increase in the gas processing capacity of the TAG plant up to the 45 MMcf per day level. A 32-mile, 8-inch diameter oil export line runs from the WPS to the Omata Tank Farm at New Plymouth, where oil export facilities allow for sales into international markets. An additional 32-mile, 8-inch diameter natural gas pipeline runs from the WPS to the Taranaki Combined Cycle Electric Generation Facility near Stratford and on to the New Plymouth Power Station.

We have a service agreement with the owner of the Omata Tank Farm to utilize the blending, storage, and export capabilities of the facility. The operator of the facility provides services for a fixed fee per barrel received and other variable costs as required by the agreement. Under the terms of the agreement, crude oil produced from the TAWN and Rimu/Kauri areas have access to the Omata Tank Farm.

Our current contract with Shell Petroleum Mining (“SPM”), under which SPM purchases all of our New Zealand crude oil production, runs through the end of 2004. The delivery point for our crude oil sales is the ship’s flange. SPM and the Omata Tank Farm coordinate logistical issues for shipments, and thus SPM’s decisions regarding sales from the Omata Tank Farm can affect the timing of sales of that portion of our production.

Rimu Production Station. We completed construction on the Rimu Production Station (“RPS”) during the first quarter of 2002, and production was processed through this facility beginning in the second quarter of 2002. Our oil production processed through the RPS is transported the 17 miles by truck to our WPS facility and then sent by pipeline to the Omata Tank Farm. Our natural gas production processed through the RPS is sold to Genesis Power Ltd. under a long-term contract for use at its Huntly Power Station, New Zealand’s largest thermal power station.

New Zealand Emerging Growth Areas

The Tawa prospect is located northwest of the Rimu and Kauri areas in permit 38719. Its main targets are the Kapuni sands, the Kauri sandstones, and the Tariki sandstone. Consisting of a combination of structural and stratigraphic traps, this prospect was developed based upon our analysis of existing three-dimensional seismic data plus two-dimensional seismic data acquired during Swift surveys in 1997 and 2000. The Tawa prospect may also include a shallower prospect located on the southeast flank of the Tawa prospect. It was identified based upon the analysis of the two-dimensional seismic data we acquired in 2000.

Three prospects are located in the Company’s TAWN area and are identified as the Waihapa Deep prospect, the Toko Deep prospect, and the Ahuroa Flank prospect. All three prospects will have the Kapuni group sands (the major reservoir in the basin) as their main target, but as these wells are drilled they will also pass through the Tariki sandstone and other major producers in the basin.

The Tuihu prospect, permit 38718, is located northeast of our TAWN area. In December 2002, we agreed to acquire an additional 50% interest in permit 38718 from Shell New Zealand through an existing pre-emptive right under the joint operating agreement. Following the transaction, SENZ sold a 20% interest in the permit to a subsidiary of New Zealand Oil and Gas Limited. The purchase and subsequent sale resulted in SENZ holding a 50% working interest in this permit. We are the operator of the permit. Permit 38718 contains the Tuihu #1 exploratory well, which was drilled in 2001 and was temporarily abandoned. In 2003, this well was re-entered but was unsuccessful.

The Huinga prospect, permit 38716, is located northeast of our Rimu/Kauri areas. An exploratory well was drilled on this permit, of which we own 15%, in 1998 and was temporarily abandoned. This well was re-entered in 2002 and was unsuccessful. The operator is currently re-evaluating this prospect.

Oil and Gas Reserves

The following table presents information regarding proved reserves of oil and gas attributable to our interests in producing properties as of December 31, 2003, 2002, and 2001. The information set forth in the table regarding reserves is based on proved reserves reports prepared by us and audited by H. J. Gruy and Associates, Inc., Houston, Texas, independent petroleum engineers. Gruy’s audit was conducted according to standards approved by the Board of Directors of the Society of Petroleum Engineers, Inc. and included examination, on a test basis, of the evidence supporting our reserves. Gruy’s audit was based upon review of production histories and other geological, economic, and engineering data provided by Swift. Where Gruy had material disagreements with Swift reserve estimates, we revised our estimates to be in agreement.

In accordance with Securities and Exchange Commission guidelines, estimates of future net revenues from our proved reserves and the PV-10 Value are made using oil and gas sales prices in effect as of the dates of such estimates adjusted for the effects of hedging and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including, in the case of gas contracts, the use of fixed and determinable contractual price escalations. Our hedges at year-end 2003 consisted of natural gas price floors with strike prices lower than the period end price and thus did not affect prices used in these calculations. Proved reserves as of December 31, 2003, were estimated based upon prices in effect at year-end. The weighted averages of such year-end prices domestically were $5.53 per Mcf of natural gas, $30.88 per barrel of oil, and $21.81 per barrel of NGL, compared to $4.23, $29.36, and $17.30 at year-end 2002 and $2.68, $18.51, and $11.00 at year-end 2001, respectively. The weighted averages of such year-end 2003 prices for New Zealand were $2.04 per Mcf of natural gas, $26.78 per barrel of oil, and $14.10 per barrel of NGL, compared to $1.48, $28.80, and $12.24 in 2002 and $1.18, $18.25, and $8.90 in 2001, respectively. The weighted averages of such year-end 2003 prices for all our reserves, both domestically and in New Zealand, were $4.56 per Mcf of natural gas, $30.16 per barrel of oil, and $20.61 per barrel of NGL, compared to $3.49, $29.27, and $16.54 in 2002 and $2.51, $18.45, and $10.70 in 2001, respectively. We have interests in certain tracts that are estimated to have additional hydrocarbon reserves that cannot be classified as proved and are not reflected in the following table.

The table sets forth estimates of future net revenues presented on the basis of unescalated prices and costs in accordance with criteria prescribed by the Securities and Exchange Commission and its PV-10 Value. Operating costs, development costs, asset retirement obligation costs, and certain production-related taxes were deducted in arriving at the estimated future net revenues. No provision was made for income taxes. The estimates of future net revenues and their present value differ in this respect from the standardized measure of discounted future net cash flows set forth in Supplemental Information to our Consolidated Financial Statements, which is calculated after provision for future income taxes.

	Year Ended December 31, 2003
	Total	Domestic	New Zealand
	-----------------	-----------------	-----------------
Estimated Proved Oil and Gas Reserves
Net natural gas reserves (Mcf):
Proved developed	210,119,927	138,173,341	71,946,586
Proved undeveloped	125,684,935	104,147,935	21,537,000
	-----------------	-----------------	-----------------
Total	335,804,862	242,321,276	93,483,586
	==========	==========	==========
Net oil and NGL reserves (Bbl):
Proved developed	45,525,366	38,767,983	6,757,383
Proved undeveloped	35,234,537	28,247,710	6,986,827
	-----------------	-----------------	-----------------
Total	80,759,903	67,015,693	13,744,210
	==========	==========	==========
Estimated Present Value of Proved Reserves
Estimated present value of future net cash flows from proved reserves discounted at 10%per annum:
Proved developed	$940,882,612	$805,834,173	$135,048,439
Proved undeveloped	597,912,185	517,485,024	80,427,161
	-----------------	-----------------	-----------------
Total	$1,538,794,797	$1,323,319,197	$215,475,600
	==========	==========	==========
	Year Ended December 31, 2002
	Total	Domestic	New Zealand
	-----------------	-----------------	-----------------
Estimated Proved Oil and Gas Reserves
Net natural gas reserves (Mcf):
Proved developed	233,514,572	149,731,562	83,783,010
Proved undeveloped	93,217,100	90,092,500	3,124,600
	-----------------	-----------------	-----------------
Total	326,731,672	239,824,062	86,907,610
	==========	==========	==========
Net oil and NGL reserves (Bbl):
Proved developed	35,928,395	26,530,112	9,398,283
Proved undeveloped	34,510,568	32,499,528	2,011,040
	-----------------	-----------------	-----------------
Total	70,438,963	59,029,640	11,409,323
	==========	==========	==========
Estimated Present Value Proved Reserves
Estimated present value of future net cash flows from proved reserves discounted at 10%per annum:
Proved developed	$679,356,172	$516,832,848	$162,523,324
Proved undeveloped	481,833,151	456,632,145	25,201,006
	-----------------	-----------------	-----------------
Total	$1,161,189,323	$973,464,993	$187,724,330
	==========	==========	==========
	Year Ended December 31, 2001
	Total	Domestic	New Zealand
	-----------------	-----------------	-----------------
Estimated Proved Oil and Gas Reserves
Net natural gas reserves (Mcf):
Proved developed	181,651,578	167,401,736	14,249,842
Proved undeveloped	143,260,547	121,087,764	22,172,783
	-----------------	-----------------	-----------------
Total	324,912,125	288,489,500	36,422,625
	==========	==========	==========
Net oil and NGL reserves (Bbl):
Proved developed	23,759,574	20,393,142	3,366,432
Proved undeveloped	29,723,062	22,171,591	7,551,471
	-----------------	-----------------	-----------------
Total	53,482,636	42,564,733	10,917,903
	==========	==========	==========
Estimated Present Value Proved Reserves
Estimated present value of future net cash flows from proved reserves discounted at 10%per annum:
Proved developed	$344,478,834	$306,095,381	$38,383,453
Proved undeveloped	258,507,354	186,012,413	72,494,941
	-----------------	-----------------	-----------------
Total	$602,986,188	$492,107,794	$110,878,394
	==========	==========	==========

 

At year-end 2003, 59% of the proved reserves were developed reserves. At year-end 2002, 60% of proved reserves were developed. At year-end 2001, 50% of proved reserves were developed.

Changes in quantity estimates and the estimated present value of proved reserves are affected by the change in crude oil and natural gas prices at the end of each year. Our total proved reserves quantities at year-end 2003 increased by 9% over reserves quantities a year earlier, while the PV-10 Value of those reserves increased 33% from the PV-10 Value at year-end 2002. While our total proved reserves quantities, on an equivalent Bcfe basis, at year-end 2002 increased by 16% over reserves quantities in 2001, the PV-10 Value of those reserves increased 93% from the PV-10 Value at year-end 2001. The PV-10 Value increases in 2003 and 2002 were heavily influenced by higher prices at year-end 2003 as compared to year-end 2002 and year-end 2002 as compared to year-end 2001. Product prices for natural gas increased 31% during 2003, from $3.49 per Mcf at year-end 2002 to $4.56 at year-end 2003, while oil prices increased 3% between the same two dates, from $29.27 to $30.16 per barrel. Product prices for natural gas increased 39% during 2002, from $2.51 per Mcf at December 31, 2001, to $3.49 per Mcf at year-end 2002, while oil prices increased 59% between the two dates, from $18.45 to $29.27 per barrel. Product prices for natural gas decreased 75% during 2001, from $9.86 per Mcf at December 31, 2000, to $2.51 per Mcf at year-end 2001, matched by a 25% decrease in the price of oil between the two dates, from $24.62 to $18.45 per barrel.

Proved reserves are estimates of hydrocarbons to be recovered in the future. Reservoir engineering is a subjective process of estimating the sizes of underground accumulations of oil and gas that cannot be measured in an exact way. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserves reports of other engineers might differ from the reports contained herein. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. 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, reserves estimates are often different from the quantities of oil and gas that are ultimately recovered. There can be no assurance that these estimates are accurate predictions of the present value of future net cash flows from oil and gas reserves.

No other reports on our reserves have been filed with any federal agency.

Oil and Gas Wells

As we continued to liquidate partnerships for those partnerships that voted to do so, our total gross well count decreased from 2001 levels. Acquisitions such as Lake Washington, where we own nearly a 100% interest in all operated wells, have increased well ownership on a net basis. The following table sets forth the gross and net wells in which we owned an interest at the following dates:

	Oil Wells	Gas Wells	Total Wells1
	---------------	---------------	---------------
December 31, 2003
Gross	397	560	957
Net	340.6	504.0	844.6
December 31, 2002
Gross	342	555	897
Net	278.9	479.8	758.7
December 31, 2001
Gross	396	786	1,182
Net	297.0	467.9	764.9

(1) Excludes 41 service wells in 2003, 35 service wells in 2002, and 48 service wells in 2001.

 

Oil and Gas Acreage

As is customary in the industry, we generally acquire oil and gas acreage without any warranty of title except as to claims made by, through, or under the transferor. Although we have title to developed acreage examined prior to acquisition in those cases in which the economic significance of the acreage justifies the cost, there can be no assurance that losses will not result from title defects or from defects in the assignment of leasehold rights. In many instances, title opinions may not be obtained if in our judgment it would be uneconomical or impractical to do so.

The following table sets forth the developed and undeveloped leasehold acreage held by us at December 31, 2003:

	Developed1			Undeveloped1
	Gross	Net		Gross	Net
	--------------	--------------		--------------	--------------
Alabama	9,686.01	2,859.10		644.22	183.99
Louisiana	82,257.09	65,415.99		16,637.34	10,296.57
Mississippi	630.03	163.32		60.00	15.80
Texas	166,636.81	113,555.70		31,284.03	19,017.64
Wyoming	681.07	151.06		67,698.95	66,078.96
All other states	320.00	266.66		400.00	257.32
Offshore Louisiana	4,609.37	276.56		5,000.00	258.34
Offshore Texas	2,880.00	74.39		---	---
	--------------	--------------		--------------	--------------
Total Domestic	267,700.38	182,762.78		121,724.54	96,108.62
New Zealand	7,600.00	7,181.70		162,422.37	124,766.10
	--------------	--------------		--------------	--------------
Total	275,300.38	189,944.48		284,146.91	220,874.72
	=========	=========		=========	=========

(1) Fee mineral acres acquired in the Brookeland and Masters Creek areas acquisition are not included in the above leasehold acreage table. We have 26,345 developed fee mineral acres and 69,149 undeveloped fee mineral acres for a total of 95,494 fee mineral acres.

 

Drilling Activities

The following table sets forth the results of our drilling activities during the three years ended December 31, 2003:

			Gross Wells						Net Wells
						Temporarily						Temporarily
Year		Type of Well	Total	Producing	Dry	Abandoned			Total	Producing	Dry	Abandoned
2003		Exploratory--Domestic	8	5	3	---			7.3	5.0	2.3	---
		Development--Domestic	63	53	10	---			61.9	51.9	10.0	---
		Exploratory--New Zealand	1	---	1	---			0.5	---	0.5	---
		Development--New Zealand	3	3	---	---			3.0	3.0	---	---
2002		Exploratory--Domestic	7	3	4	---			5.0	2.3	2.7	---
		Development--Domestic	23	17	6	---			23.0	17.0	6.0	---
		Exploratory--New Zealand	3	2	1	---			2.2	2.0	0.2	---
		Development--New Zealand	3	2	1	---			3.0	2.0	1.0	---
2001		Exploratory--Domestic	11	6	5	---			6.2	4.0	2.2	---
		Development--Domestic	36	36	---	---			29.5	29.5	---	---
		Exploratory--New Zealand	2	---	1	1			1.1	---	0.9	0.2
		Development--New Zealand	4	2	2	---			3.6	1.8	1.8	---

 

Operations

We generally seek to be operator in the wells in which we have a significant economic interest. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. We do not own drilling rigs or other oil field services equipment used for drilling or maintaining wells on properties we operate. Independent contractors supervised by us provide all the equipment and personnel. We employ drilling, production, and reservoir engineers, geologists, and other specialists who work to improve production rates, increase reserves, and lower the cost of operating our oil and gas properties.

Oil and gas properties are customarily operated under the terms of a joint operating agreement. These agreements usually provide for reimbursement of the operator’s direct expenses and for payment of monthly per-well supervision fees. Supervision fees vary widely depending on the geographic location and depth of the well and whether the well produces oil or gas. The fees for these activities paid to us in 2003 totaled $5.1 million and ranged from $450 to $2,107 per well per month.

Marketing of Production

Domestically, we typically sell our oil and gas production at market prices near the wellhead or at a central point after gathering and/or processing. Gas production is sold in the spot market on a monthly basis, while we sell our oil production at prevailing market prices. We do not refine any oil we produce. Shell, both domestically and in New Zealand, and Contact Energy in New Zealand each accounted for 10% or more of our total revenues during the year ended December 31, 2003, with those purchasers accounting for approximately 26% of revenues in the aggregate. For the year ended December 31, 2002, Eastex Crude Company and Contact Energy in New Zealand accounted for approximately 28% of our total revenues. However, due to the availability of other purchasers, we do not believe that the loss of any single oil or gas purchaser or contract would materially affect our revenues.

In 1998, we entered into gas processing and gas transportation agreements for our gas production in the AWP Olmos area with PG&E Energy Trading Corporation, which was assumed in December 2000 by El Paso Hydrocarbon, LP, and El Paso Industrial, LP, both affiliates of El Paso Merchant Energy, for up to 75,000 Mcf per day, which provided for a ten-year term with automatic one-year extensions unless earlier terminated. We believe that these arrangements adequately provide for our gas transportation and processing needs in the AWP Olmos area for the foreseeable future.

Our oil production from the Brookeland and Masters Creek areas is sold to various purchasers at prevailing market prices. Our gas production from these areas is processed under long-term gas processing contracts with Duke Energy Field Services, Inc. The processed liquids and residue gas production are sold in the spot market at prevailing prices.

Our oil production from the Lake Washington area is delivered into ExxonMobil’s crude oil pipeline system or barges for sales to various purchasers at prevailing market prices. Our gas production from this area is either consumed on the lease or is delivered into El Paso’s Tennessee Gas Pipeline system and then sold in the spot market at prevailing prices.

Our oil production in New Zealand is sold to Shell Petroleum Mining at international prices tied to the Asia Petroleum Price Index (APPI) Tapis posting, less the cost of storage, trucking, and transportation.

Our gas production from our TAWN fields is sold under a long-term contract with Contact Energy. Our gas production from the Rimu field is sold to Genesis Power Ltd. under a long-term contract that was modified in 2003 and covers approximately 7.2 Bcfe per year for a three year period. During 2003, additional production volumes from our TAWN fields, over the contract maximum, were sold to Contact Energy or Genesis Power Ltd. at prevailing market rates. The gas sales above the contract maximum expired at the end of 2003.

Our New Zealand natural gas liquids production is sold to Rockgas Ltd. under long-term contracts tied to New Zealand’s domestic natural gas liquids market.

The following table summarizes sales volumes, sales prices, and production cost information for our net oil and gas production for the three-year period ended December 31, 2003. “Net” production is production that is owned by us directly or indirectly through partnerships or joint venture interests and is produced to our interest after deducting royalty, limited partner, and other similar interests.