Items 1 and 2. Business and Properties

See pages 71 and 72 for explanations of abbreviations and terms used herein.

General

Swift Energy Company is engaged in developing, exploring, acquiring, and operating oil and gas properties, with a focus on oil and natural gas reserves onshore and in the inland waters of Louisiana and Texas and onshore in New Zealand. We were founded in 1979 and are headquartered in Houston, Texas. At year-end 2004, we had estimated proved reserves of 799.8 Bcfe with a PV-10 Value of $2.0 billion. Our proved reserves at year-end 2004 were comprised of approximately 49% crude oil, 40% natural gas, and 11% NGLs, of which 56% were proved developed. Our proved reserves are concentrated 46% in Louisiana, 33% in Texas, and 18% in New Zealand.

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

• AWP Olmos — South Texas
• Brookeland — East Texas
• Lake Washington — South Louisiana
• Masters Creek — Central Louisiana
• Rimu/Kauri — New Zealand
• TAWN — New Zealand

Competitive Strengths and Business Strategy

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

We have grown our proved reserves from 454.8 Bcfe to 799.8 Bcfe over the five-year period ended December 31, 2004. Over the same period, our annual production has grown from 42.9 Bcfe to 58.3 Bcfe and our annual net cash provided by operations has increased from $73.6 million to $182.6 million. Our growth in reserves and production over this five year period has resulted primarily from drilling activities in our six core areas combined with producing property acquisitions. More recently, we increased our production by 10% during 2004 as compared to 2003 production. During 2004, our proved reserves decreased by 3%, which replaced 65% of our 2004 production, primarily due to a slowdown in drilling activity in Lake Washington in order to allow for the implementation of a three-dimensional seismic survey and facilities improvements in the area. Also, we focused our drilling efforts in 2004 mainly on development wells, which converted proved undeveloped reserves to proved developed, but did not increase our overall proved reserves. Based on our long-term historical performance and our business strategy going forward, we believe that we have the opportunities, experience, and knowledge to grow our reserves and production.

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. In general, we focus on drilling in our core property and emerging growth areas when oil and natural gas prices are strong. When prices weaken and the per unit cost of acquisitions becomes more attractive, or a strategic opportunity exists, we shift our focus toward acquisitions. We believe this balanced approach has resulted in our ability to grow in a strategically cost effective manner. Over the five-year period ended December 31, 2004, we replaced 239% of our production at an average cost of $1.47 per Mcfe. For 2005, we are targeting total production and proved reserves to increase 7% to 12% over the 2004 levels.

Our 2005 capital expenditures are currently budgeted at $200 million to $220 million, net of approximately $5 million to $15 million of non-core property dispositions. Approximately 80% of the budget is targeted for domestic activities, primarily in South Louisiana for Lake Washington and the surrounding area, with about 20% planned for activities in New Zealand. Approximately $15 million to $20 million will be focused on activities at our new properties in the Bay de Chene and Cote Blanche Island fields in South Louisiana that were acquired in December 2004. No acquisitions are currently included in our 2005 capital budget. We expect our 2005 capital expenditures will initially be at the low end of the range, and depending on commodity prices and operational performance, they may increase to the high end of the range during the course of the year. We anticipate 2005 capital expenditures to approximate our cash flow provided from operating activities during 2005.

Historically we have added proved reserves due to both our drilling and acquisition activities. We believe that this strategy will continue to add reserves for us, however, external factors beyond our control, such as governmental regulations and commodity market factors, could limit our ability to drill wells and acquire proved properties in the future. We calculate and analyze reserve replacement ratios and costs to use as benchmarks against our competitors. These ratios and costs are limited in use by the inherent uncertainties in the reserve estimation process, and other factors discussed below. We have included a table listing the vintages of our proved undeveloped reserves in the table titled "Proved Undeveloped Reserves," and believe this table will provide an understanding of the time horizon required to convert proved undeveloped reserves to oil and gas production. Our reserve additions for each year are estimates. Reserve volumes can change over time and, therefore cannot be absolutely known or verified until all volumes have been produced and a cumulative production total for a well or field can be calculated. Many factors will impact our ability to access these reserves, such as availability of capital, new and existing government regulations, competition within our industry, the requirement of new or upgraded infrastructure at the production site, and technological advances.

The reserve replacement ratio is calculated using reserve replacement volumes divided by production volumes during a specific period. The reserve replacement volumes used in this calculation are listed in the "Supplemental Information (Unaudited)" section of this report, specifically in a table titled "Supplemental Reserve Information." Within this table there are categories titled "Revisions of previous estimates," "Purchases of minerals in place" and "Extensions, discoveries, and other additions," which when added total the reserve replacement volumes. Production volumes are also listed in the same table, and these production volumes are also used in the reserve replacement ratio calculation.

The reserve replacement cost is calculated using reserve replacement volumes divided by acquisition, exploration and development costs incurred during a specific period. Our acquisition, exploration, and development costs are listed in the "Supplemental Information (Unaudited)" section of this report, specifically in a table titled "Costs Incurred." Development costs as defined by Securities and Exchange Commission rules, include costs incurred to obtain access to proved reserves and provide facilities for extracting, treating, gathering and storing the oil and gas. Development costs thus include well costs for our development wells and facility costs, such as those facility and platform costs we have incurred in our Lake Washington area over the past several years. Costs incurred to explore and develop reserves may extend over several years. We believe a reserve replacement cost estimate is more meaningful when calculated over several periods. Future development costs from prior years are included in this calculation to the extent that they have been included, in our actual costs incurred.

The concentration of our operations in six core areas allows us to realize economies of scale in drilling and production by enabling us to manage larger producing fields with less personnel while minimizing incremental costs of increased drilling and completions. Our average lease operating costs, excluding taxes, were $0.71, $0.64, and $0.58 per Mcfe in 2004, 2003, and 2002, respectively. This concentration allows us to utilize the experience and knowledge we gain in these areas to continually improve our operations and guide us in developing our future activities and in operating similar type assets. For example, we will apply the experience we have gained in Lake Washington to our recently acquired Bay de Chene and Cote Blanche Island properties, which are also situated around South Louisiana salt domes. The value of this concentration is enhanced by our operating 97% of our proved oil and natural gas reserve base as of December 31, 2004. Retaining operational control allows us to more effectively manage production, control operating costs, allocate capital and time field development.

We are focused on applying modern technologies and recovery methods to areas with known hydrocarbon resources to optimize our exploration and exploitation of such properties. For example, the Lake Washington field was discovered in the 1930s. We acquired our properties in this area for $30.5 million in 2001. Since that time, we have increased our average daily net production from less than 700 BOE to 12,900 BOE for the quarter ended December 31, 2004. We have also increased our proved reserves in the area from 7.7 million BOE, or 46.2 Bcfe, to approximately 45.4 million BOE or 272.5 Bcfe, as of December 31, 2004. Additionally, 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 drilled 32 wells in New Zealand since 1999. When we first acquired our interests in AWP Olmos, Brookeland, and Masters Creek, these areas also had significant additional development potential. Our properties in the Bay de Chene and Cote Blanche Island fields hold mainly proved undeveloped reserves and we intend to begin our initial development activities of these properties in the second half of 2005. We intend to continue acquiring large acreage positions in under-explored and under-exploited areas, where we can apply modern technologies and our experience and knowledge in the areas to grow production from developed fields.

The Maui field in New Zealand currently supplies over 70% of the natural gas produced in New Zealand. The Maui field is expected to be depleted by 2007, which has caused significant upward pressure on prices for natural gas in the country. Due to currency exchange increases between the New Zealand Dollar and the U.S. Dollar, along with increases in our natural gas contract prices, our average natural gas price in New Zealand has increased 77% from the first quarter of 2003 to the fourth quarter of 2004. We expect the prices we receive for our natural gas in New Zealand to continue to remain strong in the foreseeable future. During 2005, we anticipate drilling seven to ten development wells and expect to drill three to five exploration tests, which includes our Tarata Thrust exploration activity. These 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 practice a disciplined approach to financial management and have historically maintained a disciplined capital structure to provide us with the ability to execute our business plan. As of December 31, 2004, our debt to capitalization was approximately 43%, debt per proved reserves was $0.45 per Mcfe, and our debt to PV-10 ratio was 18%. We plan to maintain a capital structure that provides financial flexibility through the prudent use of capital, aligning our capital expenditures to our cash flows, and an active hedging program. The combination of hedging with collars, floors, forward sales, and the sale of our New Zealand natural gas production under long-term, fixed-price contracts will provide for a more stable cash flow for the limited periods covered as described in the "Commodity Risk" section of this report.

We employ 42 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 us for an average of over eight years. In addition, we engage experienced and qualified consultants to perform various comprehensive seismic acquisitions, processing, reprocessing, interpretation, and other services. We continually apply our extensive in-house experience and current technologies to benefit our drilling and production operations.

We have increasingly used seismic technology to enhance the results of our drilling and production efforts, including two and three-dimensional seismic acquisition, post-stack image enhancement reprocessing, amplitude versus offset datasets, correlation cubes, and detailed formation depletion studies. In 2004, we completed our three dimensional seismic survey covering our Lake Washington area and at least four of our 2005 wells in this area will be exploration wells with targets derived from this three-dimensional seismic data.

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

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

We have developed an 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 also employ measurement-while-drilling techniques extensively in our Lake Washington area, which allows us to guide the drill bit during the drilling process. This technology allows Swift Energy to steer the well bore path parallel to the salt face and to intersect multiple targeted sands in a single well bore.

Operating Areas

The following table sets forth information regarding our proved reserves and production in our six core areas:

AWP Olmos Area. As of December 31, 2004, we owned 27,534 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 69% natural gas. At year-end 2004, we owned interests in and operated 512 wells in this area producing natural 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 2004, we completed 13 development wells in this area, and performed four fracture enhancements. At year-end 2004, we had 112 proved undeveloped locations. Our planned 2005 capital expenditures in this area will focus on drilling 12 to 15 wells in this area.

Brookeland Area. As of December 31, 2004, we owned drilling and production rights in 79,040 net acres and 3,500 fee mineral acres in the Brookeland area, which contains substantial proved undeveloped reserves. This area is located in East Texas near the border of Louisiana in Jasper and Newton counties. We primarily drill horizontal wells and produce from the Austin Chalk formation. The reserves are approximately 56% oil and natural gas liquids. At year-end 2004, we had 11 proved undeveloped locations. Our planned 2005 capital expenditures in this area include drilling one to two development wells.

Lake Washington Area. As of December 31, 2004, we owned drilling and production rights in 15,199 net acres in the Lake Washington area located in Plaquemines Parish in South Louisiana, along with lease and seismic options covering another 6,645 acres. Approximately 92% of our proved reserves of 45.4 million BOE in this area at December 31, 2004 were oil and NGLs. To date, we have primarily produced from multiple Miocene sands ranging in depth from greater than 1,700 feet to less 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 109 producing wells is gathered from three platforms located in water depths from two to 12 feet, with drilling and workover operations performed with rigs on barges.

In 2004, we drilled 23 development wells and seven exploratory wells, of which 19 development and two exploratory wells were completed. At year-end 2004, we had 85 proved undeveloped locations in this field. Our planned 2005 capital expenditures in this area will focus on drilling at least 30 wells, of these at least four will be exploratory wells with targets derived from recently acquired three-dimensional data. Additional facility work is planned to further improve the deliverability and efficiency in this area.

Masters Creek Area. As of December 31, 2004, we owned drilling and production rights in 48,810 net acres and 91,994 fee mineral acres in the Masters Creek area, which contains substantial proved undeveloped reserves. This area 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 68% oil and NGLs. In 2004, we drilled and successfully completed one development well in this area. At year-end 2004, we had nine proved undeveloped locations. Our planned 2005 capital expenditures include drilling one to two development wells.

Garcia Ranch Area. We have been focusing on the deep sands of the Frio formation (10,000 to 16,000 feet) in an area known as Garcia Ranch, which straddles the border of Kenedy County and Willacy County in the southern tip of Texas. Three exploratory wells and one development well were drilled in this area in 2004, of which two exploratory wells were completed.

Bay de Chene and Cote Blanche Island. In December 2004, we acquired approximately 14,200 gross acres in the Bay de Chene field and approximately 6,200 gross acres in the Cote Blanche Island field, both of which are in South Louisiana in close proximity to Lake Washington. Bay de Chene is located in Jefferson Parish and Lafourche Parish, while Cote Blanche Island is located in St. Mary Parish. These fields hold predominantly undeveloped reserves. We plan to spend $15 million to $20 million to begin developing these fields in the later part of 2005. These fields were shut-in following the acquisition for facility enhancements and to repair a gas supply line.

Our activity in New Zealand began in 1995. As of December 31, 2004, our exploration permit 38719, which we operate, included approximately 72,769 acres in the Taranaki Basin of New Zealand’s north island. In April 2004, two other permits (38756 and 38759) within the Taranaki Basin were consolidated with our permit 38719 to form one permit area. This acreage includes our Rimu/Kauri area, our Rimu mining permit area, and our Tawa prospect.

Rimu/Kauri Area. Since 2002, we have held a 100% working interest in petroleum mining permit 38151 covering approximately 5,500 acres in the Rimu area for a primary term of 30 years. We began commercial production from the Rimu area in May 2002. During 2004, we completed ten of 11 wells in the Kauri area. Five of these wells successfully targeted the Kauri sands, and five were completed in the Manutahi sand. We have applied for a 30-year primary term mining permit covering approximately 8,714 acres in the Kauri area. Our natural gas production from this area 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.

TAWN Area. Our interest in TAWN consists of a 100% working interest in four petroleum mining permits, 38138 through 38141, covering producing oil and gas fields and extensive associated hydrocarbon-processing facilities and pipelines. The properties are collectively identified as the TAWN properties, an acronym derived from the first letters of the field names — the Tariki field, the Ahuroa field, the Waihapa field, and the Ngaere field. The four fields include 18 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. In 2004, we completed the Tariki-D1 well in this area. The TAWN assets are located approximately 17 miles north of the Rimu/Kauri area.

Our infrastructure at TAWN includes two hydrocarbon-processing plants with significant excess capacity. We also own the pipelines connecting the fields and facilities to export terminals and interior markets.

The Tawa prospect, which is scheduled for drilling in 2005, is located in permit 38719 northwest of the Rimu area. Its main targets are the Kauri, Tariki, and Kapuni sands. Consisting of a combination of structural and stratigraphic traps, this prospect was developed based upon our analysis of existing two and three-dimensional seismic data. The Tawa prospect may also include a shallower prospect located on the southeast flank of the prospect.

Two prospects, also scheduled for drilling in 2005, are located in our TAWN area and are identified as the Goss prospect (Goss A1 well), and the Trapper prospect (Trapper A1 well). Both 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 producing sands in the basin .We have entered into a series of farm-out agreements with Mighty River Power ("MRP"), a state owned New Zealand utility, that provide for a 50% working interest in relation to the Goss A1 well, the Trapper A1 well, and a well on our Tawa prospect. Under the farm-out agreement, MRP will provide the funding for the drilling of the three exploration wells to earn a 50% working interest in any commercial discoveries resulting from these prospects. Once MRP has earned its 50%, we will equally share any future development costs subject to the terms of the agreements. Swift will continue to maintain its 100% working interest in the existing producing horizons and facilities in both the TAWN and Rimu/Kauri areas.

Swift also holds a 71% interest in exploration permit 38718, covering approximately 28,600 gross acres northeast of our TAWN area, and a 21% interest in exploration permit 38716, covering approximately 33,000 gross acres southeast of our TAWN area. In December 2004, we entered into a farm-in agreement with Ballance Agri-Nutrients Limited of New Zealand for 60% of their exploration permit 38742. The approximately 16,800 gross acre permit is located onshore in the north-central Taranaki Basin. Under the terms of the contract we became the operator of the permit and anticipate drilling an exploratory well in this area in the second half of 2005.

Our acreage in New Zealand is licensed from the New Zealand government under production exploration permits (PEP), production mining licenses (PML), and production mining permits (PMP). These licenses and permits are summarized in the following table:

The New Zealand government’s Crown Minerals website has details of these licenses at http://crownminerals.med.govt.nz/index.asp. 

Oil and Natural Gas Reserves

The following tables present information regarding proved reserves of oil and natural gas attributable to our interests in producing properties as of December 31, 2004, 2003, and 2002. The information set forth in the tables 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 has audited 100% of our proved reserves. 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 all available production histories and other geological, economic, and engineering data, all of which was provided by us.

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, for that year’s reserve calculation, 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 2004 consisted mainly of crude oil and natural gas price floors with strike prices lower than the period-end price and thus did not materially affect prices used in these calculations. The weighted averages of such year-end 2004 prices domestically were $5.87 per Mcf of natural gas, $42.21 per barrel of oil, and $26.49 per barrel of NGL, compared to $5.53, $30.88, and $21.81 at year-end 2003 and $4.23, $29.36, and $17.30 at year-end 2002, respectively. The weighted averages of such year-end 2004 prices for New Zealand were $3.07 per Mcf of natural gas, $33.60 per barrel of oil, and $20.48 per barrel of NGL, compared to $2.04, $26.78, and $14.10 in 2003 and $1.48, $28.80, and $12.24 in 2002, respectively. The weighted averages of such year-end 2004 prices for all our reserves, both domestically and in New Zealand, were $5.16 per Mcf of natural gas, $41.07 per barrel of oil, and $25.48 per barrel of NGL, compared to $4.56, $30.16, and $20.61 in 2003 and $3.49, $29.27, and $16.54 in 2002, 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 tables.

The following tables set forth estimates of future net revenues presented on the basis of unescalated prices and costs in accordance with criteria prescribed by the SEC and its PV-10 Value as of December 31, 2004, 2003, and 2002. 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. We combine NGLs with oil for reserve reporting purposes.

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 required to be filed, nor have any been filed with any federal agency.

Proved Undeveloped Reserves

The following table sets forth the aging and PV-10 value of our proved undeveloped reserves as of December 31, 2004:

Sensitivity of Reserves to Pricing

As of December 31, 2004, a 5% increase in crude oil and NGL pricing would increase our total estimated proved reserves of 799.8 Bcfe by approximately 0.6 Bcfe, and increase the total PV-10 value of $2.0 billion by approximately $89 million. Similarly, a 5% decrease in crude oil and NGL pricing would decrease our total estimated proved reserves by approximately 0.7 Bcfe and decrease the total PV-10 value by approximately $89 million.

As of December 31, 2004, a 5% increase in natural gas pricing (exclusive of fixed contract volumes) would increase our total estimated proved reserves by approximately 0.6 Bcfe and increase the total PV-10 value by approximately $33 million. Similarly, a 5% decrease in natural gas pricing (exclusive of fixed contract volumes) would decrease our total estimated proved reserves by approximately 0.6 Bcfe and decrease the total PV-10 value by approximately $34 million.

Oil and Gas Wells

The following table sets forth the gross and net wells in which we owned an interest at the following dates:

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, 2004:

Drilling Activities

The following table sets forth the results of our drilling activities during the three years ended December 31, 2004:

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 natural gas. The fees for these activities in 2004 totaled $5.8 million and ranged from $600 to $2,155 per well per month.

Marketing of Production

Domestically, we typically sell our oil and natural gas production at market prices near the wellhead or at a central point after gathering and/or processing. We typically sell our natural gas in the spot market on a monthly basis, while we sell our oil at prevailing market prices. We do not refine any oil we produce. Shell, both domestically and in New Zealand accounted for 10% or more of our total revenues during the year ended December 31, 2004, with purchases accounting for approximately 48% of total oil and gas sales. For the year-ended December 31, 2003, Shell, both domestically and in New Zealand, and Contact Energy in New Zealand together accounted for approximately 26% of our total oil and gas sales. 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 natural 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, and then assumed by Enterprise Hydrocarbons L.P. in September 2004, 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 natural 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 transported on barges for sales to various purchasers at prevailing market prices or at fixed prices tied to the then current Nymex crude oil contract for the applicable month(s) Our natural 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 natural gas production from our TAWN fields is sold under a long-term fixed price contract with Contact Energy. Our natural gas production from the Rimu field is sold to Genesis Power Ltd. under a long-term fixed price contract that was modified in 2003 and covers approximately 7.2 Bcfe per year for a three-year period. During 2004, additional production volumes from our fields, over the contract maximum, were sold to Contact Energy or Genesis Power Ltd. at prevailing market rates.

Production of NGLs in New Zealand 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 natural gas production for the three-year period ended December 31, 2004: