Properties

 

AWP Olmos Area. Our largest contiguous operation is in the AWP Olmos area in south Texas. As of December 31, 1999, we owned approximately 33,530 net acres here. We have extensive expertise in this area and a long history of experience with low-permeability, tight-sand formations typical of this area, having acquired our first acreage here in 1988. These reserves are approximately 93% gas. At year-end 1999, we owned interests in and were the operator of 460 wells in this area producing gas from the Olmos Sand formation at a depth of approximately 10,000 to 11,500 feet. We, or entities we manage, own nearly 100% of the working interests in all wells in which we have an interest here.

In 1999, we drilled six development wells in the AWP Olmos area, five of which were successful. At year-end 1999, we had 141 proved undeveloped locations. Our planned 2000 capital expenditures of $14.3 million in this area will focus on drilling 12 wells and on wells currently on production, in which we will perform fracture extensions and install coiled tubing velocity strings.

Brookeland Area. As of December 31, 1999, we owned drilling and production rights in 134,400 gross acres, 84,000 net acres, and 15,000 fee mineral acres containing substantial proved undeveloped reserves. This area was part of the acquisition from Sonat in 1998. The Brookeland area is located in southeast Texas near the border of Louisiana in Jasper and Newton counties. This area primarily contains horizontal wells producing gas from the Austin Chalk formation. The reserves are approximately 66% gas. In 1999, we drilled or participated in the drilling of six development wells here, five of which were successful. At year-end 1999, we had 31 proved undeveloped locations. We plan to drill or participate in 10 development wells in 2000, five to be operated by us. Our planned 2000 capital expenditures in this area are $10.3 million.

Giddings Area. As of December 31, 1999, we owned drilling and production rights in 102,665 net acres in the Giddings area. This area is located in Washington, Colorado, Fayette, and Austin counties in southeast Texas, where we continue to selectively acquire acreage. Since 1992, we have participated in 82 horizontal wells in this area with an 87% success rate. The reserves are approximately 83% gas. In 1999, two development wells were drilled, both successfully. Also two exploratory wells were drilled, with one success. We attribute our success in this area, which primarily produces from the Austin Chalk formation, to our ability to identify hydrocarbon-bearing fractures through our expertise in geological and geophysical analyses and to our ability to drill and operate horizontal wells through advanced horizontal drilling techniques. In addition to the Austin Chalk formation, we have targeted exploration projects in the Edwards Lime formation. At year-end 1999, we had eight proved undeveloped locations. The drilling of two additional development wells and four exploratory wells are planned for 2000. Our planned 2000 capital expenditures in this area are $6.7 million.

We have established a number of joint ventures with industry partners to further develop and explore this area, including:

Chevron USA Production Company. This joint venture encompasses a development area of 144,000 gross acres in Fayette, Colorado, and Austin counties, with 77,000 net acres currently under lease. Swift and Chevron each own a 50% working interest, we serve as operator, and any additional leased acreage will be shared and operated on the same basis. To date, we have drilled two exploratory wells, one of which was successful, and one successful development well.

Union Pacific Resources.

• We have a 25% working interest in a joint development area covering approximately 17,000 gross acres in Washington County, Texas. Union Pacific acts as the operator in this venture.
• We own a 50% working interest in another joint development area, also in Washington County, covering approximately 6,300 gross acres. Union Pacific or we act as the operator in this venture, dependent upon the formation targeted.
• We own a 75% working interest and serve as operator for a joint venture covering approximately 8,100 gross acres in Washington and Austin counties.

Masters Creek Area. As of December 31, 1999, we owned drilling and production rights in 195,000 gross acres, 148,000 net acres, and 141,000 fee mineral acres in this area containing substantial proved undeveloped reserves. This area was also part of the acquisition from Sonat in 1998. It is located near the Texas-Louisiana border in the two parishes of Vernon and Rapides in Louisiana. The Masters Creek area contains horizontal wells producing both oil and gas from the Austin Chalk formation. The reserves are approximately 42% gas. In 1999, we drilled or participated in the drilling of five development wells, all of which were successful. At year-end 1999, we had 21 proved undeveloped locations. We plan to drill or participate in 12 development wells in 2000, with six to be operated by us. Two of these development wells to be drilled by us are in the S. Burr Ferry portion of this area. We also plan to drill one exploratory well to test the Saratoga formation. Our planned 2000 capital expenditures in this area are $23.7 million.

Exploration and Development Drilling Activities

 

We pursue a "controlled risk" approach to exploratory and development drilling, focusing our activities on specific U.S. regions in which our technical staff has considerable experience and which are located close to known producing horizons. We seek to minimize our exploration risk by investing in multiple prospects, farming out interests to third parties, using advanced technologies, and drilling in diverse types of geological formations, often in areas with multiple objectives. We use basin studies to analyze targeted formations based on their potential size, risk profile, and economic characteristics.

In 1991, we began an intensive effort to develop an inventory of exploration and development drilling prospects, identifying drilling locations through integrated geological and geophysical studies of our undeveloped acreage and other prospects. As a result, we added 120 Bcfe of proved reserves through drilling in 1997, 73.9 Bcfe in 1998, and 64.9 Bcfe in 1999. In the second half of 1998, in response to lower oil and gas prices, we deferred drilling projects scheduled for the second half of the year and continued into 1999 with a conservative drilling budget. Accordingly, reserves added by drilling were lower in 1998 and 1999 compared to 1997, when market conditions were more favorable to drilling. The 1999 additions were a result of our development success rate of 86%, as 19 of 22 development wells drilled were successful, and one of five exploratory wells was successful. An additional well, our New Zealand Rimu-A1 well, was classified as "under evaluation," as we were not able to estimate proved reserves at year-end. Therefore, the 64.9 Bcfe of reserves added through drilling in 1999 does not include any reserves added from the Rimu-A1 well in New Zealand. We believe that this discovery will result in proved reserves, and we will estimate reserves on this well after we feel we have sufficient sustained production testing data and other such analysis that we deem necessary in order to make a reasonable reserves estimate.

Our development strategy is designed to maximize the value and productivity of our existing properties through development drilling and recovery methods, enhancing production results through improved field production techniques, lowering production costs, and applying our technical expertise and resources to exploit producing properties efficiently. The Company utilizes various recovery techniques, which include employing water flooding and acid treatments, fracturing reservoir rock through the injection of high-pressure fluid, 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 Field.

Our exploration and development activities are conducted by our staff of professionals, including reservoir engineers, geologists, geophysicists, petrophysicists, landmen, and drilling and production engineers. We believe that one of the keys to our success has been our team approach, which integrates multiple disciplines to maximize efficient utilization of information leading to drillable projects.

We have increasingly used advanced 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. We have a number of computer workstations from which seismic data is analyzed and enhanced with advanced software programs, including Landmark, Geographix, and SMT workstations. As a result, we have maintained internal seismic expertise and have compiled an extensive database.

During 1997, we completed our first international seismic acquisition program in two key areas of our holdings in New Zealand. In the Rimu prospect, we acquired a 30-kilometer cross-swath, as well as 2-D seismic data in the Tawa prospect, complementing existing 2-D and 3-D data. We also acquired 21 miles of 2-D data in the AWP Olmos area in south Texas and 51 miles of data in the Fayette County portion of the Giddings area. Two more prospects in the North Louisiana Salt Basin were shot in the form of 2-D swaths of approximately 16 miles each. During 1998, we performed two additional 2-D acquisitions in Fayette County, Texas.

We are currently designing a New Zealand seismic acquisition project to develop the Rimu-A1 well discovery and a prospect target to the southeast of an adjacent offshore feature. This seismic program will straddle the coastline to acquire transition zone seismic data extending into the offshore area in order to tie into existing marine and onshore seismic data. This should enable us to answer a multitude of exploration and development questions. This project is scheduled for completion in the second quarter of 2000.

In addition to development and exploration activities in the AWP Olmos, Brookeland, Giddings, and Masters Creek areas, we are currently pursuing development and exploration activities in the Gulf Coast Basin and in New Zealand.

Gulf Coast Basin. This area includes all the Texas counties and Louisiana parishes along the Gulf Coast and extending into Mississippi and Alabama. In 1999, we drilled two successful development wells out of three and one unsuccessful exploratory well in this area. In 2000, four exploratory wells are scheduled for drilling in the Gulf Coast Basin, all in Texas. Our planned 2000 capital expenditures in this area are $3.6 million.

New Zealand. After several years of preparation, including the acquisition and analyses of seismic data, an exploratory well commenced drilling in July 1999 and drilled to its total depth. The Rimu-A1 well was completed and a ten-day production draw-down/build-up test was performed. Also, on October 18, 1999, we expanded this permit to include approximately 12,800 adjacent offshore acres. This expanded permit now contains approximately 100,700 acres. We have committed to perform additional seismic acquisition and analysis on the permit area, are evaluating longer-term sustained testing of this well, and are analyzing further delineation activities on the Rimu block.

The following table sets forth the results of our drilling activities during the three years ended December 31, 1999:

¹Our New Zealand Rimu-A1 well is classified as "under evaluation" as we were not able to estimate proved reserves at year-end. We believe that this discovery will result in proved reserves, and we will estimate reserves on this well after we feel we have sufficient sustained production testing data and other such analysis that we deem necessary in order to make a reasonable reserves estimate.

Operations

 

We generally seek to be named as operator in wells in which we have 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 1999 ranged from $200 to $2,101 per well per month and totaled $6.0 million.

Marketing of Production

 

We typically sell our oil and gas production at market prices near the wellhead, although in some cases it must be gathered by us or other operators and delivered to a central point. Gas production is sold in the spot market on a monthly contract basis, while we sell our oil production at prevailing market prices at the time of sale. We do not refine any oil we produce. For the year ended December 31, 1999, one purchaser accounted for approximately 19% of our total revenues. Two oil or gas purchasers accounted for 10% or more of our total revenues during the year ended December 31, 1998, with those purchasers accounting for approximately 26% of revenues in the aggregate. 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 Hydrocarbon, LP, and PG&E Industrial, LP, both affiliates of Pacific Gas & Electric Corporation 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. Additionally, the gas processed and transported under these agreements may be sold to PG&E based upon current natural gas prices.

Much of our Giddings area production from Fayette and Washington counties, Texas, is currently dedicated under long-term gas purchase and gas processing contracts with Aquila Southwest Pipeline Corporation ("Aquila"). We believe that these contracts adequately provide for the gas purchase and processing needs of our Giddings area production, subject to practical limitations inherent in gas field operations. The prices received are redetermined monthly to reflect the current natural gas price.

Our oil production from the Brookeland and Masters Creek areas is sold to credit-worthy 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.

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, 1999. "Net" production is production that is owned by us either directly or indirectly through partnerships or joint venture interests and is produced to our interest after deducting royalty, limited partner, and other similar interests.

	Year Ended December 31,
	1999	1998	1997
	-----------------	-----------------	-----------------
Net Sales Volume:
Oil (Bbls)	2,564,924	1,800,676	672,385
Gas (Mcf)1	27,484,759	28,225,974	21,359,434
Gas equivalents (Mcfe)	42,874,303	39,030,030	25,393,744
Average Sales Price:
Oil (per Bbl)	$16.75	$11.86	$17.59
Gas (per Mcf)	$  2.40	$  2.08	$  2.68
Average Production Cost (per Mcfe)	$  0.46	$  0.34	$  0.35

¹Natural gas production for 1999, 1998, and 1997 includes 728,235, 866,232, and 1,015,226 Mcf, respectively, delivered under the volumetric production payment agreement pursuant to which we are obligated to deliver certain monthly quantities of natural gas (see Note 1 to the Consolidated Financial Statements).

 

Under the volumetric production payment entered into in 1992, as of December 31, 1999, we have a remaining commitment to deliver approximately 0.4 Bcf of gas meeting certain heating equivalent and quality standards through October 2000, when such agreement expires. Since entering into this agreement, these properties have produced in excess of the required monthly delivery requirements.

Acquisition Activities

 

We use a disciplined, market-driven approach to acquisitions. Generally we seek to acquire properties with the potential for additional reserves and production through development and exploration efforts. In 136 transactions since 1979, we have acquired approximately $556 million of producing oil and gas properties on behalf of ourselves and our co-investors. We acquired, for our own account, approximately $199.5 million of producing properties, with original proved reserves estimated at 300.0 Bcfe. Our producing property acquisition expenditures in the past three years were $18.5 million in 1999, $59.5 million in 1998, and $8.4 million in 1997. Our acquisition costs have averaged $0.57 per Mcfe over this three-year period.

Foreign Activities

 

New Zealand. Since October 1995, the New Zealand Minister of Energy has issued to Swift two petroleum exploration permits. The first permit covered approximately 65,000 acres in the Onshore Taranaki Basin of New Zealand’s North Island, and the second covered approximately 69,300 adjacent acres. A wholly owned subsidiary, Swift Energy New Zealand Limited, formed in late 1997, conducts our New Zealand activities and owns the interest in the permits. We conducted a 2-D seismic swath on our permit areas in 1997 that complemented approximately 120 kilometers of existing 2-D seismic data. Based on analysis of all of this data, in March 1998 we surrendered approximately 46,400 acres covered in the first permit, and the remaining acreage has been included as an extension of the area covered in the second permit, leaving us with only one expanded permit. On October 18, 1999, this expanded permit was again extended to include approximately 12,800 adjacent offshore acres. This permit now contains approximately 100,700 acres. Under the terms of the expanded permit, we were required to commence drilling one exploratory well prior to August 12, 1999.

That exploratory well commenced drilling in July 1999 and has been drilled to its total depth. The Rimu-A1 well was completed and a ten-day production draw-down/build-up test was performed. Our portion of the drilling, completion, and testing costs incurred at December 31, 1999, were approximately $6.9 million. We have committed to perform additional seismic acquisition and analysis on the permit area, are evaluating longer-term sustained testing of this well, and are analyzing further delineation activities on the Rimu block. While this further work is necessary in order for us to make a meaningful reserves estimate, we feel confident that the reserves are sufficient to recover our costs. All other obligations under the permit have been fulfilled.

On October 23, 1998, we entered into separate agreements with Marabella Enterprises Ltd., a subsidiary of Bligh Oil & Minerals N.L., an Australian company, under which we obtained from Marabella a 25% working interest in another New Zealand petroleum exploration permit and under which Marabella became a 5% participant in our permit. During the fourth quarter of 1998, Marabella drilled an unsuccessful exploration well on its permit. Accordingly, we charged $400,000 against earnings, representing our costs for the well. Additionally, Swift obtained a 7.5% working interest in another New Zealand permit from Antrim Oil and Gas Limited, a Canadian company, and Antrim became a 5% participant in our permit. An exploratory well was drilled and temporarily abandoned on Antrim’s permit during the second quarter of 1999, and we charged our $290,000 portion of the costs on this well against earnings in that quarter.

As of December 31, 1999, our investment in New Zealand totaled approximately $12.5 million. Approximately $0.7 million of these costs have been impaired while the remaining $11.8 million is included in the unproved properties portion of oil and gas properties.

Russia. On September 3, 1993, we signed a Participation Agreement with Senega, a Russian Federation joint stock company (in which we have an indirect interest of less than 1%), to assist in the development and production of reserves from two fields in Western Siberia, providing us with a minimum 5% net profits interest from the sale of hydrocarbon products from the fields. Additionally, we purchased a 1% net profits interest from Senega for $0.3 million. Senega is charged with the management and control of the field development. Our investment in Russia, prior to its impairment in the third quarter of 1998, was approximately $10.8 million and was previously included in the unproved properties portion of oil and gas properties. However, the economic and political uncertainty and currency concerns that arose during the third quarter of 1998 in Russia, combined with the price volatility and severe tightening of international capital markets, caused us to re-evaluate the timing of the recovery of our capitalized costs in that country. See Note 1 to the Consolidated Financial Statements for a more detailed discussion of the impairment.

Venezuela. We formed a wholly owned subsidiary, Swift Energy de Venezuela, C. A., for the purpose of submitting a bid on August 5, 1993, under the Venezuelan Marginal Oil Field Reactivation Program. We have entered into an agreement with Tecnoconsult, S. A., and Corporation EDC, S.A.C.A., Venezuelan companies, to jointly formulate and submit a proposal to Petroleos de Venezuela, S. A., for the construction and operation of a methane pipeline. Currently, the technical and economic feasibility of the project is under study. Our investment in Venezuela, prior to its impairment in the third quarter of 1998, was approximately $2.8 million and was previously included in the unproved properties portion of oil and gas properties. However, the economic uncertainty and currency concerns in Venezuela, combined with the price volatility and severe tightening of international capital markets, caused us to re-evaluate our prospects of participating in further Venezuelan exploration activities in the near-term and the prospects for recovery of our capitalized costs in that country. See Note 1 to the Consolidated Financial Statements for a more detailed discussion of the impairment.

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, 1999, 1998, and 1997. The information set forth in the table 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 based upon review of production histories and other geological, economic, ownership, and engineering data provided by us. In accordance with Securities and Exchange Commission guidelines, our 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 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. Proved reserves as of December 31, 1999, were estimated based upon prices in effect at year-end. The weighted averages of such year-end prices were $2.58 per Mcf of natural gas and $23.69 per barrel of oil, compared to $2.23 and $11.23 in 1998 and $2.78 and $15.76 in 1997. 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 proved reserves presented for all periods also exclude any reserves attributable to the volumetric production payment.

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 their PV-10 Value. Operating costs, development 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. In cases where producing properties are subject to gas purchase contracts and the amount of gas purchased thereunder was reduced during 1999, gas projections used to estimate future net revenues were based on the reduced gas purchases for the affected producing properties. The assumption was made that purchases in 2000 and thereafter will be made at an unrestricted level.

	Year Ended December 31,
	1999	1998	1997
	-----------------	-----------------	-----------------
Estimated Proved Oil and Gas Reserves
Net natural gas reserves (Mcf):
Proved developed	174,046,096	197,105,963	191,108,214
Proved undeveloped	155,913,654	155,294,872	123,197,455
	-----------------	-----------------	-----------------
Total	329,959,750	352,400,835	314,305,669
	==========	==========	==========
Net oil reserves (Bbl):
Proved developed	8,437,299	7,142,566	4,288,696
Proved undeveloped	12,368,964	6,815,359	3,570,222
	-----------------	-----------------	-----------------
Total	20,806,263	13,957,925	7,858,918
	==========	==========	==========
Estimated Present Value Proved Reserves
Estimated present value of future net cash flows from proved reserves discounted at 10%per annum:
Proved developed	$301,199,660	$243,124,194	$244,365,044
Proved undeveloped	262,854,849	97,660,811	105,979,738
	-----------------	-----------------	-----------------
Total	$564,054,509	$340,785,005	$350,344,782
	==========	==========	==========

 

At year-end 1999, 51% of the proved reserves were undeveloped reserves. This reflects the increased emphasis on development and exploration activities. In 1998, 45% of proved reserves were undeveloped and 55% were proved 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. While our total proved reserves quantities, on an equivalent Bcfe basis, at year-end 1999 increased by 4% over reserves quantities a year earlier, the PV-10 Value of those reserves increased 66% from the PV-10 Value at year-end 1997. This increase was due almost entirely to pricing increases at year-end 1999 as compared to year-end 1998. Product prices for natural gas increased 16% during 1999, from $2.23 per Mcf at December 31, 1998, to $2.58 per Mcf at year-end 1999, while oil prices increased 111% between the two dates, from $11.23 to $23.69 per barrel. Conversely, while our total proved reserves quantities at year-end 1998 increased by 21% over reserves quantities a year earlier, the PV-10 Value of those reserves decreased 3% from the PV-10 Value at year-end 1997. This decrease was due almost entirely to pricing declines at year-end 1998 as compared to year-end 1997, which more than offset the 21% Bcfe increase in reserves quantities. Product prices for natural gas declined 20% during 1998, from $2.78 per Mcf at December 31, 1997, to $2.23 per Mcf at year-end 1998, matched by a 29% decrease in the price of oil between the two dates, from $15.76 to $11.23 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 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, 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.

A portion of our proved reserves have been accumulated through our interests in the limited partnerships for which we serve as general partner. The estimates of future net cash flows and their present values, based on period end prices, assume that some of the limited partnerships in which we own interests will achieve payout status in the future. At December 31, 1999, 22 of the limited partnerships managed by us had achieved payout status.

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

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 Wells	Gas Wells	Total Wells1
	---------------	---------------	---------------
December 31, 1999
Gross	577	947	1,524
Net	105.5	449.2	554.7
December 31, 1998
Gross	657	1,060	1,717
Net	89.4	494.5	583.9
December 31, 1997
Gross	625	926	1,551
Net	48.1	381.7	429.8

¹Excludes 33 service wells in 1999, 36 service wells in 1998, and 16 service wells in 1997.

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 domestic leasehold acreage held by us at December 31, 1999:

	Developed1			Undeveloped1
	Gross	Net		Gross	Net
	--------------	--------------		--------------	--------------
Alabama	4,495.38	616.70		292.00	72.90
Arkansas	1,242.35	699.71		6,420.87	2,418.89
Kansas	---	---		4,520.00	1,908.80
Louisiana	99,799.02	57,987.62		127,795.19	100,145.95
Mississippi	2,395.39	1,527.99		2,807.42	744.78
Oklahoma	29,925.90	13,600.59		2,589.04	590.21
Texas	232,571.92	142,625.49		247,041.48	124,600.34
Wyoming	2,338.15	1,233.04		116,881.90	79,721.63
All other states	---	---		5,928.45	981.43
	--------------	--------------		--------------	--------------
Total	372,768.11	218,291.14		514,276.35	311,184.93
	=========	=========		=========	=========

¹Fee minerals acquired in the Brookeland and Master Creek areas acquisition are not included in the above leasehold acreage table. We acquired 25,430 developed fee mineral acres and 115,570 undeveloped fee mineral acres for a total of 141,000 fee mineral acres..

In New Zealand, petroleum exploration permits that we own or participate in contain 188,836 gross undeveloped acres and 101,052 net undeveloped acres.

Partnerships

 

For many years, we relied on limited partnerships as our principal vehicle to fund our operations. We have formed 109 limited partnerships that raised a total of approximately $509.5 million. However, as we have increasingly shifted our emphasis to development and exploration activities and our reserves base has grown, we have significantly reduced our reliance on limited partnership financing.

Between 1984 and 1995, we formed 88 limited partnerships for the purpose of acquiring interests in producing oil and gas properties and, since 1993, 13 partnerships engaged in drilling for oil and gas reserves. We serve as managing general partner of these entities. We acquired producing oil and gas properties for the production purchase partnerships and transferred those properties to the partnership entities that invested in producing oil and gas properties. Various producing property partnerships have been in existence for periods ranging from four to thirteen years. Most of these partnerships have produced a majority of their reserves and, having been in existence for long periods of time, have entered the stage where consideration of liquidation proposals is appropriate.

During 1997 and 1998, 21 of these partnerships were liquidated following a vote of the limited partners in each of those partnerships to do so. Ten of these 21 partnerships were the earliest public income partnerships formed by Swift. As of early March 2000, an additional 10 partnerships voted to sell substantially all of their assets and liquidate, and the efforts to sell their assets have just commenced. Also in February and early March 2000, proxy statements were sent to the investors in 55 of the 57 remaining production purchase partnerships soliciting their votes upon proposals to sell their assets and liquidate. The proxy statements for the remaining two partnerships will be mailed shortly. If these proposals are approved, it is anticipated that these liquidations will be substantially completed during 2000 and, if necessary, 2001.

Commencing in September 1993, we began offering, on a private placement basis, general and limited partnership interests in limited partnerships to be formed to drill for oil and gas. As managing general partner, we pay a percentage of the continuing costs and we paid for all front-end costs incurred in connection with these offerings, for which we received an interest in the partnerships. Through December 31, 1999, approximately $66.1 million had been raised in thirteen partnerships, one each formed in 1993 and 1994; three each in 1995, 1996, and 1997; and two in 1998. During 1997, eight private drilling partnerships formed between 1979 and 1985 were liquidated following limited partner votes to do so.

Risk Management

 

Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and gas, including blowouts, cratering, pipe failure, casing collapse, oil spills, and fires, each of which could result in severe damage to or destruction of oil and gas wells, production facilities or other property, or individual injuries. The oil and gas exploration business is also subject to environmental hazards, such as oil spills, gas leaks, and ruptures and discharges of toxic substances or gases that could expose us to substantial liability due to pollution and other environmental damage. Additionally, as managing general partner of limited partnerships, we are solely responsible for the day-to-day conduct of the limited partnerships’ affairs and accordingly have liability for expenses and liabilities of the limited partnerships. We maintain comprehensive insurance coverage, including general liability insurance in an amount not less than $35.0 million, as well as general partner liability insurance. We believe that our insurance is adequate and customary for companies of a similar size engaged in comparable operations, but losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage.

Competition

 

The oil and gas industry is highly competitive in all its phases. We encounter strong competition from many other oil and gas producers, including many that possess substantial financial resources, in acquiring economically desirable producing properties and exploratory drilling prospects, and in obtaining equipment and labor to operate and maintain our properties.

Regulations

     Environmental Regulations

 

The federal government and various state and local governments have adopted laws and regulations regarding the protection of human health and the environment. These laws and regulations may require the acquisition of a permit by operators before drilling commences, prohibit drilling activities on certain lands lying within wilderness areas, wetlands, or where pollution might cause serious harm, and impose substantial liabilities for pollution resulting from drilling operations, particularly with respect to operations in onshore and offshore waters or on submerged lands. These laws and regulations may increase the costs of drilling and operating wells. Because these laws and regulations change frequently, the costs of compliance with existing and future environmental regulations cannot be predicted with certainty.

     Federal and State Regulation of Oil and Natural Gas

 

The transportation and certain sales of natural gas in interstate commerce are heavily regulated by agencies of the federal government. Production of any oil and gas by us will be affected to some degree by state regulations. Many states in which we operate have statutory provisions regulating the production and sale of oil and gas, including provisions regarding deliverability. Such statutes, and the regulations promulgated in connection therewith, are generally intended to prevent waste of oil and gas and to protect correlative rights to produce oil and gas between owners of a common reservoir. Certain state regulatory authorities also regulate the amount of oil and gas produced by assigning allowable rates of production to each well or proration unit.

     Federal Leases

 

Some of our properties are located on federal oil and gas leases administered by various federal agencies, including the Bureau of Land Management. Various regulations and orders affect the terms of leases, exploration and development plans, methods of operation, and related matters.

Employees

 

At December 31, 1999, we employed 173 persons. None of our employees are represented by a union. Relations with employees are considered to be good.

Facilities

 

We occupy approximately 75,000 square feet of office space at 16825 Northchase Drive, Houston, Texas, under a ten year lease expiring in 2005. The lease requires payments of approximately $96,000 per month. We have field offices in various locations from which our employees supervise local oil and gas operations.

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Glossary of Abbreviations and Terms

 

The following abbreviations and terms have the indicated meanings when used in this report:

Bbl — Barrel or barrels of oil.

Bcf — Billion cubic feet of natural gas.

Bcfe — Billion cubic feet of natural gas equivalent (see Mcfe).

Development Well — A well drilled within the presently proved productive area of an oil or natural gas reservoir, as indicated by reasonable interpretation of available data, with the objective of completing in that reservoir.

Discovery Cost — With respect to proved reserves, a three-year average (unless otherwise indicated) calculated by dividing total incurred exploration and development costs (exclusive of future development costs) by net reserves added during the period through extensions, discoveries, and other additions.

Dry Well — An exploratory or development well that is not a producing well.

Exploratory Well — A well drilled either in search of a new, as yet undiscovered oil or natural gas reservoir or to greatly extend the known limits of a previously discovered reservoir.

Gross Acre — An acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

Gross Well — A well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned.

MBbl — Thousand barrels of oil.

Mcf — Thousand cubic feet of natural gas.

Mcfe — Thousand cubic feet of natural gas equivalent, which is determined using the ratio of one barrel of oil, condensate, or natural gas liquids to 6 Mcf of natural gas.

MMBbl — Million barrels of oil.

MMBtu — Million British thermal units, which is a heating equivalent measure for natural gas and is an alternate measure of natural gas reserves, as opposed to Mcf, which is strictly a measure of natural gas volumes. Typically, prices quoted for natural gas are designated as price per MMBtu, the same basis on which natural gas is contracted for sale.

MMcf — Million cubic feet of natural gas.

MMcfe — Million cubic feet of natural gas equivalent (see Mcfe).

Net Acre — A net acre is deemed to exist when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Net Well — A net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.

Producing Well — An exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Proved Developed Oil and Gas Reserves — Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved Oil and Gas Reserves — The estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, that is, prices and costs as of the date the estimate is made.

Proved Undeveloped Oil and Gas Reserves — Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

PV-10 Value — The estimated future net revenue to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%. These amounts are calculated net of estimated production costs and future development costs, using prices and costs in effect as of a certain date, without escalation and without giving effect to non-property related expenses, such as general and administrative expenses, debt service, future income tax expense, or depreciation, depletion, and amortization.

Reserves Replacement Cost — With respect to proved reserves, a three-year average (unless otherwise indicated) calculated by dividing total incurred acquisition, exploration, and development costs (exclusive of future development costs) by net reserves added during the period.

Volumetric Production Payment — The 1992 agreement pursuant to which we financed the purchase of certain oil and natural gas interests and committed to deliver certain monthly quantities of natural gas.

This page was last updated on Saturday, February 08, 2003, at 07:46:30 PM.

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