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FORM 10-K FOR FISCAL YEAR ENDED DECEMBER 31, 1998Items 1 and 2. Business and Properties
See page 12 for explanations of abbreviations and terms used herein. General
Swift Energy Company (the "Company"), a Texas corporation organized in October 1979, is engaged in the exploration, development, acquisition, and operation of oil and gas properties, with a primary focus on U.S. onshore natural gas reserves. As of December 31, 1998, the Company had interests in over 1,750 oil and gas wells located in eight states, of which the Company operated 836 wells representing 91% of its proved reserves base. At such date, the Company had estimated proved reserves of 436.1 Bcfe, of which approximately 81% was natural gas, 55% was proved developed, and 97% was located in both Texas (84%) and Louisiana (13%). The Company’s primary focus is development and exploration drilling in its core areas, the AWP Olmos Field located in South Texas and the Austin Chalk trend in Texas and Louisiana. The AWP Olmos Field is characterized by long-lived reserves, while the Austin Chalk trend is characterized by more short-lived reserves with high initial production and rapid decline rates. These fields accounted for approximately 51% and 42%, respectively, of the Company’s proved reserves as of December 31, 1998, and approximately 40% and 48%, respectively, of the Company’s production during 1998. In the third quarter of 1998, the Company purchased the Toledo Bend Properties from Sonat Exploration Company ("Toledo Bend Properties") for approximately $87.0 million in cash, with approximately $56.8 million of the total spent for producing properties, approximately $15.0 million to purchase an interest in two gas processing plants, and approximately $15.2 million to acquire leasehold properties. This acquisition extended the Company’s properties in the Austin Chalk trend, and the Company expects to utilize its operating expertise in this area to successfully develop and exploit these properties. As of December 31, 1998, these properties consisted of 162 producing wells (115 of which were Company operated), 23 saltwater disposal wells, a 20% interest in two natural gas plants, associated production facilities, and interests in 200,875 gross (125,378 net) undeveloped acres and approximately 114,000 undeveloped fee mineral acres. At such date, the estimated proved reserves relating to these acquired properties were 130.5 Bcfe, of which approximately 58% was natural gas and 59% was proved undeveloped. The Company’s production on these properties, which began in the third quarter of 1998, amounted to approximately 11.6 Bcfe, of which 44% was natural gas. Such production comprised approximately 30% of the Company’s production during 1998. The Company pursues a balanced growth strategy that includes an active drilling program, strategic acquisitions, and the utilization of advanced technologies. The Company’s operating philosophy is to increase its reserves base through both drilling and acquisitions, shifting the balance between the two activities in response to market conditions. Over the last several years, the Company’s growth has resulted primarily from its increased acreage position and drilling activities in the AWP Olmos Field and the Austin Chalk trend. Capital expenditures for development and exploration drilling, primarily in the Company’s core areas, were $71.8 million and $101.0 million in 1996 and 1997, respectively, while capital expenditures for acquisitions were $1.5 million and $8.4 million. The downward pressure on commodity prices during 1998 caused the Company to decrease its originally targeted capital expenditures for drilling and to redirect a portion of those expenditures to the acquisition of producing properties, primarily the above mentioned Toledo Bend Properties. In 1998, development and exploration drilling expenditures for the year, concentrated in the first half of the year, totaled $67.4 million while $59.5 million was spent for the acquisition of producing properties, almost all in the third quarter of 1998. In response to market conditions, the Company has budgeted capital expenditures of only $54.2 million for 1999, of which $36.0 million is targeted for drilling, $31.3 million for development drilling, and $4.7 million for exploratory drilling. The remaining $18.2 million is targeted principally for leasehold, seismic, and geological costs of prospects. The Company plans to fund this budget primarily through the use of its internally generated cash flows and limited borrowings under its credit facility. Besides its core areas, the Company is also actively pursuing exploratory and development drilling opportunities in other basins in Texas, Arkansas, Louisiana, Wyoming, and New Zealand. The Company has increased its proved reserves from 90.1 Bcfe at year-end 1993 to 436.1 Bcfe at year-end 1998, which has resulted in the replacement of 449% of production during the same five-year period. In 1998, the Company increased its proved reserves by 21%, resulting in the replacement of 296% of its 1998 production. The Company’s five-year average reserves replacement costs were $0.88 per Mcfe. As a result of both acquisition and drilling activity, 1998 production increased 54% over 1997 production. Due to economies of scale, geographic concentration, and increased production, general and administrative expenses and production costs have fallen from $0.44 and $0.36 per Mcfe, respectively, in 1993 to $0.10 and $0.34 per Mcfe in 1998. The combination of increased production and decreased operating costs per Mcfe has resulted in average annual growth in net cash provided by operating activities of 50% per year from year-end 1993 to year-end 1998. |
Properties
The Company’s proved reserves are geographically concentrated, with approximately 93% of the Company’s proved reserves at December 31, 1998, attributable to its properties in the AWP Olmos Field and the Austin Chalk trend.
AWP Olmos Field. The Company’s largest unified operation is located in the AWP Olmos Field in South Texas. The Company has extensive expertise in the AWP Olmos Field and a long history of experience with low-permeability, tight-sand formations typical of this field. Since acquiring its first AWP Olmos Field acreage in 1988, the Company has made detailed studies of drainage patterns in the formation and has introduced innovations in fracture design and implementation methods and coiled tubing technology that substantially reduce overall costs and improve recoveries.
Properties in the AWP Olmos Field represented approximately 51% of the Company’s proved reserves at December 31, 1998, and approximately 40% of the Company’s 1998 production. At December 31, 1998, the Company owned interests in and was the operator of 447 wells producing natural gas from the Olmos Sand formation at a depth of approximately 10,000 feet. The Company has engaged in extensive fracturing operations to increase the permeability of the formation and flow of gas from the wells. In addition, the Company has used coiled tubing velocity strings in numerous wells to improve production rates. Also, by utilizing a system of BJ Services, Inc., the Company is able to monitor fracturing operations from its Houston headquarters through direct computer access to the field.
In 1998, the Company drilled 33 (31 successful) development wells in the AWP Olmos Field and three unsuccessful exploratory wells northwest of the field. Of the properties operated by the Company in the AWP Olmos Field, the Company or entities managed by the Company own 100% of the working interests in all but 21 wells in this field, and in these 21 wells the smallest ownership interest is 99%. The Company increased its leasehold position in the field in 1998 by obtaining additional acreage and, if warranted, anticipates acquiring more acreage in the future. The Company’s planned 1999 capital expenditures of $12.0 million in this area will focus on fracture extensions and further use of coiled tubing velocity strings.
Austin Chalk Trend. At December 31, 1998, the Company owned drilling and production rights in 596,607 gross acres, 357,588 net acres, and 137,213 fee mineral acres in the Austin Chalk trend containing substantial proved undeveloped reserves. Of this acreage position, 402,560 gross acres, 244,662 net acres, and all 137,213 fee mineral acres were acquired in the Toledo Bend Properties acquisition described above. The Austin Chalk trend represented approximately 42% of the Company’s proved reserves at December 31, 1998 and 48% of the Company’s production in 1998. The wells in this trend are horizontal wells, primarily producing natural gas in the Texas portion of the trend and producing an approximately even split of oil and natural gas in the Louisiana portion. These wells deliver high initial flow rates and strong initial cash flows that decline rapidly. The Company believes the Austin Chalk reserves complement the Company’s long-lived reserves in the AWP Olmos Field. Since 1992, the Company has participated in 78 horizontal wells in the Austin Chalk trend with an 87% success rate, including 16 successful development wells out of 19 drilled and two successful exploratory wells out of four drilled in 1998. The Company believes its success in the Austin Chalk trend is attributable to its ability to identify hydrocarbon-bearing fractures, relying on its expertise in geological and geophysical analyses, and to its ability to drill and operate horizontal wells. The Company anticipates drilling 14 development wells and one exploratory well in the Austin Chalk trend during 1999. The acquisition of seismic data in the Cougar Run and Nimitz areas in Fayette County during 1998 has helped in upgrading locations to drill horizontal wells targeting the Austin Chalk formation determined from previous seismic data acquisitions and subsequent successful drilling in the Rocky Creek and North Fayetteville prospects.
Substantial portions of the Company’s property interests in the Austin Chalk trend have been acquired through joint development arrangements with industry partners who are active participants in exploration of the Austin Chalk trend. The first joint venture, with Chesapeake Energy Corporation in 1993 and now completed, covered approximately 8,800 acres in Fayette County, Texas, with the Company currently holding an average working interest of 25%. In September 1995, the Company entered into a joint development agreement with Union Pacific Resources providing for an area of mutual interest (AMI) covering 19,500 gross acres in Fayette County (the North Fayetteville Prospect), with the Company and UPR alternately serving as operator of any wells drilled on the acreage. During 1996, the Company purchased UPR’s interest in 9,500 of these gross acres, and the joint development arrangement was reduced to a 10,000 gross acre block in which the Company has an average working interest of 30% to 35%. This joint venture is now completed. The Company has a 100% working interest in the 9,500 acres it purchased and has drilled three wells on the property.
In 1996, the Company and UPR initiated another joint development arrangement covering approximately 8,000 acres in Washington County, Texas, in which the Company owns a 25% working interest. This joint development area was subsequently expanded to encompass approximately 17,000 gross acres in Washington County. Simultaneously, the Company and UPR entered into two additional joint development agreements, one covering an approximate 6,300 gross acre area in Washington County, in which the Company owns a 50% working interest, and another covering an approximate 8,100 gross acre area in Washington County and Austin County, in which the Company owns a 75% working interest and serves as operator.
In 1997, in a joint venture with Belco Oil and Gas Corporation, the Company acquired a 50% working interest in 20,000 net acres adjoining the North Fayetteville Prospect area, for which Swift serves as operator. Several wells were drilled on this acreage in 1998. Also in 1997, in an adjoining area covering 8,000 gross acres in Fayette County, the Company entered a joint venture with Chesapeake Energy Corporation with a 68% working interest for which the Company serves as the operator. Two wells were drilled on this acreage in 1997, and three wells were drilled in 1998.
In 1998, the Company signed a joint development agreement with Chevron USA Production Company encompassing 144,000 gross acres in central Texas, where the Company and Chevron are participating in the drilling of a number of wells targeted for the Edwards Limestone, Sligo, Austin Chalk, and other formations in the counties of Fayette, Colorado, and Austin. Swift’s interests originally covered 68,000 net acres but were subsequently expanded to 70,000 net acres. The Company and Chevron each own an undivided 50% working interest within the AMI, with the Company serving as operator. To date, the Company has drilled two exploratory wells targeting the Austin Chalk trend in this AMI, one of which was successful, and is continuing to acquire acreage in selective areas within the AMI.
Exploration and Development Drilling Activities
In 1991, the Company began an intensive effort to develop an inventory of exploration and development drilling prospects, identifying drilling locations through integrated geological and geophysical studies of the Company’s undeveloped acreage and other prospects. As a result, the Company added 118 Bcfe of proved reserves through drilling in 1996 and 120 Bcfe in 1997. In 1998, the Company deferred drilling projects scheduled for the second half of the year in response to market conditions and, accordingly, reserves added by drilling decreased to 73.9 Bcfe. The 1998 additions were a result of the Company’s success rate of 87% for development wells (53 out of 61 drilled) and 36% for exploratory wells (5 out of 14 drilled).
The Company’s successful drilling program has led to the acquisition of additional acreage during 1997 and 1998 in the areas of its principal operations in the AWP Olmos Field in South Texas and in the Austin Chalk trend, the latter covering several Texas counties and, as of 1998, two Louisiana parishes.
The Company pursues a "controlled risk" approach to exploratory drilling, focusing its exploration activities on specific U.S. regions in which its technical staff has considerable experience and which are in close proximity to known producing horizons where the potential for significant reserves exists. The Company seeks to minimize its exploration risk by investing in multiple prospects, farming out interests to industry partners and Company-managed drilling funds, utilizing advanced technologies, and drilling in different types of geological formations. The Company utilizes basin studies to analyze targeted formations based on their potential size, risk profile, and economic parameters.
The Company’s development strategy is designed to maximize the value and productivity of its existing properties through development drilling and recovery methods, enhancing production results through improved field production techniques, lowering production costs, and applying the Company’s 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 speed gas flow. The Company believes that the application of fracturing technology and coiled tubing has resulted in significant increases in production and decreases in drilling and operating costs, particularly in the Company’s AWP Olmos Field.
The Company’s exploration and development activities are conducted by its in-house exploration staff, assisted by professionals from other departments, including reservoir engineers, geologists, geophysicists, petrophysicists, landmen, and drilling and production engineers. The Company believes that one of the keys to its success has been its team approach, which integrates multiple disciplines to maximize efficient utilization of information leading to drillable projects.
The Company has increasingly utilized advanced seismic technology to enhance the quality of its drilling efforts, including two-dimensional (2-D) and three-dimensional (3-D) seismic analyses and amplitude versus offset (AVO) studies. During 1997, the Company completed its first international seismic acquisition program in two key areas of its holdings in New Zealand. In the Rimu prospect, Swift 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. It also acquired 21 miles of 2-D data in the AWP Olmos Field in South Texas and 51 miles of data in the Fayette County portion of the Austin Chalk trend. 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, the Company performed two additional 2-D acquisitions in Fayette County, Texas. It also conducted a 2-D cross swath that yielded 3-D data in Point Coupee Parish, Louisiana, which resulted in the Company’s release of acreage in the area.
In addition to development and exploration activities in the AWP Olmos Field and the Austin Chalk trend, the Company is currently focusing its exploration activities in three main domestic geographical areas: the Gulf Coast Basin, the Wyoming Powder River Basin, and the North Louisiana Salt Basin. It has also initiated an exploration program in New Zealand.
Gulf Coast Basin. The Company defines this area as including all the Texas counties and Louisiana parishes along the Gulf Coast and extending into Mississippi and Alabama and including all target formations present except the Austin Chalk trend and the Olmos sand. In 1998, three successful development wells (out of six) and two successful exploratory wells (out of three) were drilled in the Gulf Coast Basin, following four successful exploratory wells and one successful development well drilled in 1997. In 1999, two exploratory wells and one development well are scheduled for drilling in the Gulf Coast Basin.
During 1997, the Company acquired 1,920 gross acres in Jim Hogg County, in which the Company owns a minimum 75% working interest. A successful exploratory well drilled by the Company to the Queen City formation in 1997 was followed by three successful development wells and a successful exploratory well in 1998. Further work in the area is awaiting a fracture extension program to be carried out in 1999 to assess the field’s full potential.
Wyoming Powder River Basin. The Minnelusa trend has been the subject of extensive study over several years by the Company’s multidisciplinary teams in order to identify the location of stratigraphic hydrocarbon traps. In recent years, the Company has shifted its emphasis to pursue the Cretaceous trend in southern Campbell County and northern Converse County in Wyoming, as well as north into the Williston Basin in Daniels County, Montana. This shift is due to the Company’s commitment to find larger reserve accumulations at a lower risk by drilling in areas with multiple producing zones and larger field sizes. In 1997, the Company successfully drilled one out of two exploratory wells in the Minnelusa trend in Campbell County, Wyoming. In 1998, the Company participated in a successful exploratory well in Converse County, Wyoming. A second exploratory well drilled in Daniels County, Montana, was unsuccessful.
North Louisiana Salt Basin. The North Louisiana Salt Basin covers the neighboring corners of Arkansas, Louisiana, and Texas ("Ark-La-Tex region"). In this area, the Jurassic Smackover formation, a prolific hydrocarbon producer from multiple levels and from a variety of structures, including fault traps, salt anticlines, basement structures, and stratigraphic traps, is the primary target, and the Haynesville formation is the secondary target. Both formations have been the subject of intense geophysical and geological analyses by the Company for a number of years. During 1998, analyses were completed for two 2-D seismic swaths, each covering 12 miles, that were acquired in 1997 in Lafayette County, Arkansas, and Bossier Parish, Louisiana. Since 1996, Swift has had four successes out of five exploratory wells drilled in the area (the unsuccessful well was drilled in 1998). The Company plans to drill an additional exploratory well in the area in 1999.
New Zealand. After several years of preparation, including the acquisition and analyses of seismic data, the Company will drill an exploratory well on its permit to the Mangahewa formation in the Taranaki Basin on the North Island of New Zealand in 1999. In 1998, the Company participated in an unsuccessful exploratory well on a permit in which the Company obtained an interest through Marabella Enterprises Ltd. See "Foreign Activities – New Zealand."
The following table sets forth the results of the Company’s drilling activities during the three fiscal years ended December 31, 1998:
| Gross Wells | Net Wells | ||||||||
| Year | Type of Well | Total | Producing | Dry | Total | Producing | Dry | ||
| 1996 | Exploratory | 11 | 7 | 4 | 5.9 | 3.7 | 2.2 | ||
| Development | 142 | 134 | 8 | 110.5 | 106.7 | 3.8 | |||
| 1997 | Exploratory | 15 | 7 | 8 | 7.2 | 2.7 | 4.5 | ||
| Development | 167 | 159 | 8 | 127.5 | 123.6 | 3.9 | |||
| 1998 | Exploratory | 14 | 5 | 9 | 8.7 | 2.7 | 6.0 | ||
| Development | 61 | 53 | 8 | 37.7 | 32.8 | 4.9 | |||
Operations
The Company generally seeks to be named as operator for wells in which it or its affiliated limited partnerships and joint ventures have acquired a significant interest, although this typically occurs only when they own the major portion of the working interest in a particular well or field. The Company acts as operator of 836 wells at December 31, 1998, which comprise approximately 91% of the Company’s total proved reserves.
As operator, the Company is able to exercise substantial influence over development and enhancement of a well and to supervise operation and maintenance activities on a day-to-day basis. The Company does not own the drilling rigs used to drill on properties it operates. Drilling rigs are contracted from independent contractors and supervised by the Company. The Company employs drilling, production, and reservoir engineers, geologists, and other operations and production specialists who strive to improve production rates, increase reserves, and/or lower the cost of operating its oil and gas properties.
Oil and gas properties are customarily operated under the terms of a joint operating agreement, which provides for reimbursement of the operator’s direct expenses and monthly per-well supervision fees. Per-well supervision fees vary widely depending on the geographic location and depth of the well, whether the well produces oil or gas, and other factors. Such fees received by the Company in 1998 ranged from $200 to $1,632 per well per month.
Marketing of Production
The Company typically sells its gas production at or near the wellhead, although in some cases it must be gathered by the Company or other operators and delivered to a central point. Gas production is sold in the spot market at prevailing prices. The Company sells its oil production at prevailing market prices. The Company does not refine any oil it produces. During the year ended December 31, 1998, two purchasers accounted for approximately 16% and 10% of the Company’s revenues. Three oil or gas purchasers accounted for 10% or more of the Company’s revenues during the year ended December 31, 1997, with those purchasers accounting for approximately 42% of revenues in the aggregate. Because of the availability of other purchasers, the Company does not believe that the loss of any single oil or gas purchaser or contract would materially affect its sales.
The Company has entered into gas processing and gas transportation agreements with respect to its natural gas production in the AWP Olmos Field with Pacific Gas & Electric Corporation and its affiliates ("PG&E") for up to 75,000 Mcf per day. These contracts were recently amended, effective May 1, 1998, to provide for an initial ten-year term, with automatic one-year extensions unless earlier terminated. In addition, the amended contracts provided for more favorable terms benefiting the Company. The Company believes that these arrangements adequately provide for its gas transportation and processing needs in the AWP Olmos Field for the foreseeable future. Additionally, at the discretion of the Company and PG&E, the gas processed and transported under these agreements may be sold to PG&E at monthly indexed prices based upon the current natural gas price.
Much of the Company’s Austin Chalk 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"). The Company believes that these contracts adequately provide for the gas purchase and processing needs of its Austin Chalk production, subject to practical limitations inherent in gas field operations. The prices received are redetermined monthly to reflect the current natural gas price.
The Company’s oil production from the Toledo Bend Properties is sold to credit-worthy purchasers at prevailing market prices. The Company’s gas production from the Toledo Bend Properties is processed under long-term gas processing contracts with Union Pacific Resources Company ("UPR"). Processed liquids and residue gas production are sold in the spot market at prevailing prices. Recently UPR signed a definitive agreement with Duke Energy Field Services, Inc. ("Duke") for the acquisition by Duke of UPR’s gas gathering processing and marketing subsidiary, Union Pacific Fuels, Inc. ("UPFI"). Through a merger, UPFI will become a wholly owned subsidiary of Duke. The transaction is expected to close by the end of March 1999. This merger will not affect the contractual obligations between the Company and UPR.
The following table summarizes sales volumes, sales prices, and production cost information for the Company’s net oil and gas production for the three-year period ended December 31, 1998. "Net" production is production that is owned by the Company either directly or indirectly through partnerships or joint venture interests and produced to its interest after deducting royalty, limited partner, and other similar interests.
Year Ended December 31,
1998 1997 1996 ----------------- ----------------- ----------------- Net Sales Volume: Oil (Bbls) 1,800,676 672,385 623,386 Gas (Mcf)1 28,225,974 21,359,434 15,696,798 Gas equivalents (Mcfe) 39,030,030 25,393,744 19,437,114 Average Sales Price: Oil (per Bbl) $11.86 $17.59 $19.82 Gas (per Mcf) $ 2.08 $ 2.68 $ 2.57 Average Production Cost (per Mcfe) $ 0.34 $ 0.35 $ 0.32
1Natural gas production for 1998, 1997, and 1996 includes 866,232, 1,015,226, and 1,156,361 Mcf, respectively, delivered under the volumetric production payment agreement pursuant to which the Company is obligated to deliver certain monthly quantities of natural gas (see Note 1 to the Company’s financial statements).
Under the volumetric production payment entered into in 1992, as of December 31, 1998, the Company has a remaining commitment to deliver approximately 1.1 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.
Price Risk Management
The Company’s revenues are primarily the result of sales of its oil and natural gas production. Market prices of oil and natural gas may fluctuate and adversely affect operating results. To mitigate some of this risk, the Company engages periodically in certain limited hedging activities, but only to the extent of buying protection price floors for portions of its and the Company-managed limited partnerships’ oil and gas production. Costs and/or benefits derived from these price floors are accordingly recorded as a reduction or increase, as applicable, in oil and gas sales revenue and have not been significant for any year presented. The costs to purchase put options are amortized over the option period.
During 1998, the Company entered into oil and natural gas price hedging contracts covering a portion of the Company’s and its affiliated partnerships’ oil and natural gas production. For January, 1,500,000 MMBtu of the natural gas production was covered, and February was covered for 3,000,000 MMBtu of natural gas, each at a minimum price of $2.00 per MMBtu. March was covered for 2,000,000 MMBtu of natural gas at a minimum price of $1.80 per MMBtu and 500,000 MMBtu at $1.90 per MMBtu. For the months of April, May, June, and July, 1,000,000 MMBtu were covered, providing for a minimum price of $1.80, $1.90, $2.10, and $2.10 per MMBtu, respectively.
For the months of January and February 1998, 60,000 Bbls of oil production were covered each month, providing for a minimum price of $18.00 per Bbl. Costs related to 1998 hedging activities totaled approximately $377,000, with benefits of approximately $101,000 being received, resulting in a net cash outlay of approximately $276,000 or $0.007 per Mcfe.
The Company had entered into four put option contracts for 1999 production by December 31, 1998, three of which remained open at year-end. January was covered for 2,000,000 MMBtu of natural gas at $2.00 per MMBtu, with a net profit of approximately $154,000. The three open contracts at December 31, 1998, covered 1,000,000 MMBtu and 1,800,000 MMBtu of natural gas production for February at minimum prices of $1.80 and $1.70 per MMBtu, respectively, and 2,800,000 MMBtu of natural gas for March at a minimum price of $1.60 per MMBtu. The costs related to these 1999 contracts totaled $317,016 and had a fair market value of $486,680 as of December 31, 1998.
Acquisition Activities
Since 1979, the Company has acquired approximately $537.5 million of producing oil and gas properties on behalf of itself and its co-investors in 133 separate transactions. In recent years, the Company’s acquisition activities have declined, as it has fulfilled its obligation to buy producing properties for the remaining partnerships which invested in such properties and as industry conditions brought a redirection of the Company’s strategy towards increasing reserves through drilling. As of December 31, 1997, all such partnerships investing in producing properties had spent their available capital resources on producing properties. Therefore, the Company anticipates all future acquisition activity will be on its own behalf. The Company has acquired for its own account approximately $181.0 million of producing properties, with original proved reserves estimated at 279.9 Bcfe. The Company’s producing property acquisition expenditures in the past three years were approximately $1.5 million in 1996, $8.4 million in 1997, and $59.5 million in 1998. The Company’s acquisition costs have averaged $0.52 per Mcfe over this three-year period.
The Company uses a disciplined, market-driven approach to acquisitions, generally seeking to acquire properties in close proximity to its current reserves with the potential to add reserves and production through additional development and exploration efforts.
Foreign Activities
New Zealand. Since October 1995, the Company has been issued two Petroleum Exploration Permits by the New Zealand Minister of Energy. 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 its New Zealand activities and owns the interest in the permits. In March 1998, the Company 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. Under the terms of the expanded permit, the Company is obligated to drill one exploratory well prior to August 12, 1999. All other obligations under the permit have been fulfilled, including the reinterpretation of existing seismic data and the acquisition and processing of new seismic data.
On October 23, 1998, the Company entered into separate agreements with Marabella Enterprises Ltd. (Marabella), a subsidiary of Bligh Oil & Minerals N.L., an Australian company, to obtain from Marabella a 25% working interest in another New Zealand Petroleum Exploration Permit and for Marabella to become a 5% participant in the Company’s permit. An exploration well on the Marabella permit commenced drilling on October 16, 1998, the results of which were unsuccessful. Accordingly, the $400,000 cost of such well was charged against earnings. The Company has also agreed in principle to participate with Marabella in an additional permit as a 17.5% working interest owner.
At December 31, 1998, the Company’s investment in New Zealand was approximately $5.4 million and is included in the unproved properties portion of oil and gas properties. Approximately $0.4 million of such costs have been impaired.
Russia. On September 3, 1993, the Company signed a Participation Agreement with Senega, a Russian Federation joint stock company (in which the Company has an indirect interest of less than 1%), to assist in the development and production of reserves from two fields in Western Siberia, providing the Company with a minimum 5% net profits interest from the sale of hydrocarbon products from the fields for providing managerial, technical, and financial support to Senega. Additionally, the Company purchased a 1% net profits interest from Senega for $0.3 million.
On December 10, 1997, the Company amended and restated the Participation Agreement. Under the amended and restated Participation Agreement, the Company retains its 6% net profits interest in the Samburg Field and agreed to assist Senega in obtaining investments necessary to develop the field. Senega is charged with the management and control of the field development. The Company’s 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 the Company to re-evaluate the timing of the recovery of its capitalized costs in that country. See Note 1 to the Company’s financial statements for a more detailed discussion of the impairment. Subsequent to such impairment, any costs incurred in Russia have been reported as a charge to earnings.
Venezuela. The Company 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. Although the Company did not win the bid, it has continued to gather information relating to reserves and geological and geophysical data in Venezuela and continued to pursue cooperative ventures involving other fields and opportunities in Venezuela. The Company evaluated a number of blocks being offered by Petroleos de Venezuela, S. A., under the Third Operating Agreement Round in 1997 but decided against submitting any bid on these blocks. The Company has 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. The Company’s 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 the Company to re-evaluate its prospects of participating in further Venezuelan exploration activities in the near-term and the recovery of its capitalized costs in that country. See Note 1 to the Company’s financial statements for a more detailed discussion of the impairment. Subsequent to such impairment, any costs incurred in Venezuela have been reported as a charge to earnings.
Oil and Gas Reserves
The following table presents information regarding proved reserves of oil and gas attributable to the Company’s interests in producing properties as of December 31, 1998, 1997, and 1996. The information set forth in the table is based on proved reserves reports prepared by the Company and audited by H. J. Gruy and Associates, Inc., Houston, Texas, independent petroleum engineers. Gruy’s estimates were based upon review of production histories and other geological, economic, ownership, and engineering data provided by the Company. In accordance with Securities and Exchange Commission guidelines, the Company’s estimates of future net revenues from the Company’s 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, 1998, were estimated based upon weighted average prices of $2.23 per Mcf of natural gas and $11.23 per barrel of oil, compared to $2.78 and $15.76 in 1997 and $4.47 and $23.75 in 1996, respectively. The Company has 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 the Company's 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 1998, 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 1999 and thereafter will be made at an unrestricted level.
| Year Ended December 31, | |||
| 1998 | 1997 | 1996 | |
| ----------------- | ----------------- | ----------------- | |
| Estimated Proved Oil and Gas Reserves | |||
| Net natural gas reserves (Mcf): | |||
| Proved developed | 197,105,963 | 191,108,214 | 135,424,880 |
| Proved undeveloped | 155,294,872 | 123,197,455 | 90,333,321 |
| ----------------- | ----------------- | ----------------- | |
| Total | 352,400,835 | 314,305,669 | 225,758,201 |
| =========== | =========== | =========== | |
| Net oil reserves (Bbl): | |||
| Proved developed | 7,142,566 | 4,288,696 | 3,622,480 |
| Proved undeveloped | 6,815,359 | 3,570,222 | 1,861,829 |
| ----------------- | ----------------- | ----------------- | |
| Total | 13,957,925 | 7,858,918 | 5,484,309 |
| =========== | =========== | =========== | |
| Estimated Present Value Proved Reserves | |||
| Estimated present value of future net cash flows from proved reserves discounted at 10%per annum: | |||
| Proved developed | $243,124,194 | $244,365,044 | $310,408,949 |
| Proved undeveloped | 97,660,811 | 105,979,738 | 160,776,008 |
| ----------------- | ----------------- | ----------------- | |
| Total | $340,785,005 | $350,344,782 | $471,184,957 |
| =========== | =========== | =========== | |
The Company’s total proved developed and undeveloped reserves increased 21% at December 31, 1998, over amounts at December 31, 1997, as shown above and in Supplemental Information to the Company’s financial statements. At year-end 1998, 45% of the reserves were proved undeveloped reserves. This reflects the increased emphasis on development and exploration activities. In 1997, 40% of proved reserves were undeveloped and 60% 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 the Company’s total proved reserves quantities (on an equivalent Bcfe basis) 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 the Company’s proved reserves has been accumulated through the Company’s interests in the limited partnerships for which it serves 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 the Company owns interests will achieve payout status in the future. At December 31, 1998, 17 of the limited partnerships managed by the Company had achieved payout status.
No other reports on the Company’s reserves have been filed with any federal agency.
Oil and Gas Wells
The following table sets forth the gross and net wells in which the Company owned an interest at the following dates:
Oil Wells Gas Wells Total Wells1 --------------- --------------- --------------- 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 December 31, 1996 Gross 734 1,068 1,802 Net 59.5 222.9 282.4
1Excludes 36 service wells in 1998, 16 service wells in 1997, and 26 service wells in 1996.
Oil and Gas Acreage
As is customary in the industry, the Company generally acquires oil and gas acreage without any warranty of title except as to claims made by, through, or under the transferor. Although the Company has 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 the Company’s judgment it would be uneconomical or impractical to do so.
The following table sets forth the developed and undeveloped domestic leasehold acreage held by the Company at December 31, 1998:
Developed1 Undeveloped1
Gross Net Gross Net -------------- -------------- -------------- -------------- Alabama 4,495.38 616.70 292.00 72.90 Arkansas 3,339.49 1,736.30 8,092.80 5,022.95 Kansas --- --- 4,600.00 1,988.80 Louisiana 100,233.66 50,356.48 159,555.53 101,109.80 Mississippi 4,186.10 2,240.85 3,693.84 910.69 Montana --- --- 4,411.28 4,411.28 Oklahoma 33,240.59 14,197.02 3,209.04 886.50 Texas 260,232.49 146,577.24 301,336.20 161,354.21 Wyoming 4,713.90 1,969.49 120,253.29 104,579.29 All other states --- --- 6,317.48 1,286.06 -------------- -------------- -------------- -------------- Total 410,441.61 217,694.08 611,761.46 381,622.48 ========= ========= ========= =========
1Fee minerals acquired in the Toledo Bend Properties acquisition are not included in the above leasehold acreage table. The Company acquired 23,178.56 developed fee mineral acres and 114,034.44 undeveloped fee mineral acres for a total of 137,213 fee mineral acres.
Partnerships
For many years, the Company relied on limited partnerships as its principal vehicle to fund its activities. The Company has formed 109 limited partnerships which had raised a total of approximately $509.5 million at December 31, 1998. However, as the Company has increasingly shifted its emphasis to development and exploration activities and its reserves base has grown, the Company has significantly reduced its reliance on limited partnership financing.
During 1996, the limited partners in 18 partnerships, which had been in operation over nine years and had produced a substantial majority of their reserves, voted to sell their remaining properties and liquidate the limited partnerships. Of these partnerships, 10 were the earliest public income partnerships formed in 1984 to 1986. In early 1997, eight private drilling partnerships formed in 1979 to 1985 were liquidated. During 1997, the limited partners in an additional 11 partnerships, formed in 1990 and 1991, voted to sell their properties and liquidate the limited partnerships, which liquidation occurred in June 1998.
From 1984 to 1995, the Company formed limited partnerships and joint ventures for the purpose of acquiring interests in producing oil and gas properties. Since 1993, the Company also has offered private partnerships formed to engage in the drilling for oil and gas reserves. The Company serves as the managing general partner of these entities. As of December 31, 1998, thirteen private drilling partnerships had been formed (one formed in each of 1993 and 1994, three in each of 1995, 1996, and 1997, and two in 1998) with aggregate investor contributions of approximately $66.1 million.
The private drilling partnerships have been offered on a no-load basis under which the Company pays all selling and offering expenses of the offering. Amounts paid by the Company are treated as a capital contribution to each partnership. The Company also is entitled to a general and administrative overhead allowance and an incentive amount. In certain partnerships, the Company does not bear any of the costs incurred in acquiring or drilling properties. The Company pays approximately 20% of all continuing costs (approximately 30% after payout and 35% after 200% payout), and the Company is entitled to receive 20% of net revenues distributed by each such partnership prior to payout, 30% distributed after payout, and 35% distributed after 200% payout. As managing general partner of certain other partnerships, the Company pays out of its own corporate funds the capital costs, consisting of all prospect costs and the non-deductible, tangible portion of drilling and completion costs. The Company pays approximately 40% of all continuing costs (approximately 45% after payout and 50% after 200% payout), and the Company is entitled to receive 40% of net revenues distributed by each such partnership prior to payout, 45% distributed after payout, and 50% distributed after 200% payout.
In October 1998, the Company notified investors in 63 Swift-managed production partnerships formed between 1986 and 1994 that it had delayed calling investor meetings to consider its purchase of all of the oil and gas properties owned by these partnerships, which was proposed in March 1998. This decision principally reflected significant market changes that had occurred during the long period necessary for regulatory review of soliciting materials, the age of the third-party appraisals of these partnership properties, and the much publicized weakness in both the equity and debt markets for energy companies. During the last six months, the weakness in oil and natural gas prices has deepened, creating concern over the appropriateness of selling properties at this time. The Company expects to continue to re-evaluate the status and operation of these partnerships, whether to propose some form of liquidating transaction, and if so when and in what form.
Risk Management
The Company’s 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 the Company to substantial liability due to pollution and other environmental damage. Additionally, as managing general partner of limited partnerships, the Company is solely responsible for the day-to-day conduct of the limited partnerships’ affairs and accordingly has liability for expenses and liabilities of the limited partnerships. The Company maintains comprehensive insurance coverage, including general liability insurance in an amount not less than $35.0 million, as well as general partner liability insurance. The Company believes that its 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. The Company encounters 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 its properties. Continued decreases in natural gas and oil prices have had an effect on the Company’s cash flow, capital expenditures, and drilling schedule. In light of the extreme volatility of prices, it is impossible to predict the length of time that prices may remain at such levels or may move to higher or lower levels.
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 to the Company of compliance with existing and future environmental regulations cannot be predicted with certainty.
Federal Regulation of Natural Gas
The transportation and certain sales of natural gas in interstate commerce are heavily regulated by agencies of the federal government. The following discussion is intended only as a brief summary of agency rules and regulations that may affect the production and sale of the Company’s natural gas. This summary should not be relied upon as a complete review of applicable natural gas regulatory provisions.
In April 1992, the Federal Energy Regulatory Commission ("FERC") issued Order No. 636 pertaining to pipeline restructuring. This rule requires interstate pipelines to unbundle transportation and sales services by separately stating the price of each service and by providing customers only the particular service desired, without regard to the source for purchase of the gas. The rule also requires pipelines to (i) provide nondiscriminatory "no-notice" service allowing firm commitment shippers to receive delivery of gas on demand up to certain limits without penalties, (ii) establish a basis for release and reallocation of firm upstream pipeline capacity and (iii) provide non-discriminatory access to capacity by firm transportation shippers on a downstream pipeline. The rule requires interstate pipelines to use a straight fixed variable rate design.
In addition, interstate pipelines that transport gas for others must provide transportation service to producers, distributors and all other shippers of natural gas on a nondiscriminatory, "first-come, first-served" basis ("open access transportation"), so that producers and other shippers can sell natural gas directly to end-users.
Gas produced normally will be sold to intermediaries who have entered into transportation arrangements with pipeline companies. These intermediaries typically accumulate gas purchased from a number of producers and sell the gas to end-users through open access transportation.
State Regulations
Production of any oil and gas by the Company will be affected to some degree by state regulations. Many states in which the Company operates 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 the Company’s 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, 1998, the Company employed 203 persons. None of the Company’s employees are represented by a union. Relations with employees are considered to be good.
Facilities
The Company and SEMCO 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 $95,000 per month. The Company has field offices in various locations from which Company employees supervise local oil and gas operations.
-------------------------------------
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 the Company financed the purchase of certain oil and natural gas interests and committed to deliver certain monthly quantities of natural gas.
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