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1997 ANNUAL REPORT |
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Form 10-K Excerpts |
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1997 ANNUAL REPORT |
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Form 10-K Excerpts |
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PART 1
Items 1 and 2. Business and Properties
See page 48 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, 1997, the Company had interests in over 1,500 oil and gas wells located in 10 states, with 93% of its proved reserves base concentrated in Texas. At the same date, the Company had estimated proved reserves of 361.5 Bcfe, approximately 87% of which were natural gas, and operated 650 wells representing 91% of its proved reserves base.
The Company’s primary focus is exploration and development drilling in its core areas, the AWP Olmos Field located in South Texas and the Texas Austin Chalk trend. 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 74% and 15%, respectively, of the Company’s proved reserves as of December 31, 1997, and approximately 61% and 19%, respectively, of the Company’s production during 1997. The Company has substantially accelerated its drilling activities during the last several years, drilling 42, 116, and 135 net wells in 1995, 1996, and 1997, respectively, primarily in these areas. During 1996, the Company doubled its acreage position in the AWP Olmos Field and quadrupled it in the Austin Chalk trend. In 1997, the Company increased slightly its acreage position in the AWP Olmos Field and increased its acreage position in the Austin Chalk trend by approximately 50%. The Company has budgeted capital expenditures of $154.8 million for 1998, of which approximately 73% is targeted for these two fields. The Company is also actively pursuing exploratory and development drilling opportunities in other basins in Texas, Arkansas, Louisiana, and Wyoming. As a complement to these domestic activities, the Company is participating in several high potential international projects with limited capital exposure to the Company in New Zealand, Russia, and Venezuela.
The Company has increased its proved reserves from 59.0 Bcfe at year end 1992 to 361.5 Bcfe at year end 1997, primarily from additions through the drillbit, which has resulted in the replacement of 554% of production during the same five-year period. In 1997, the Company increased its proved reserves by 40%, resulting in the replacement of 522% of 1997 production. The Company’s five-year average reserves replacement costs were $0.76 per Mcfe. As a result of increased drilling activity, 1997 production increased 31% over 1996 production. Due to economies of scale, geographic concentration, and increased production, general and administrative expenses and production costs have fallen from $0.88 and $0.69 per Mcfe in 1992 to $0.24 and $0.45 per Mcfe, respectively, for 1997. 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 54% per year from year end 1992 to year end 1997. For 1997, due to these same production and operating cost factors, net cash provided by operating activities increased to $55.3 million or 49% over the same period in 1996.
The Company’s proved reserves are geographically concentrated, with approximately 89% of the Company’s proved reserves at December 31, 1997, attributable to its two largest properties, the AWP Olmos Field and the Austin Chalk trend.
AWP Olmos Field. The Company’s most significant property 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.
The AWP Olmos Field represented approximately 74% of the Company’s proved reserves at December 31, 1997, and approximately 61% of the Company’s 1997 production. At December 31, 1997, the Company owned interests in and was the operator of approximately 400 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 several 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.
During 1997, the Company purchased, for approximately $3.8 million, Olmos producing properties strategically located in the heart of its existing leasehold in the AWP Olmos Field. The purchase included 35 producing wells, 35 new development drilling locations, and a related 20-mile pipeline. Net proved reserves attributable to the purchase are approximately 25 Bcfe, with current production of approximately 2,000 Mcfe per day.
In 1997, the Company drilled 142 (137 successful) development wells in this field and one unsuccessful exploratory well northwest of the field. The Company or entities managed by the Company own 100% of the working interest in this field. During 1997, the Company maintained its leasehold position in this area. The Company anticipates continuing its acquisition of acreage in this area in the future, if warranted. The Company plans to drill approximately 57 additional development wells and four exploratory wells to the Olmos formation in 1998.
Austin Chalk Trend. At December 31, 1997, the Company owned drilling and production rights in 175,022 gross acres and 112,918 net acres in the Austin Chalk trend containing substantial proved undeveloped reserves. The Austin Chalk trend represented approximately 15% of the Company’s proved reserves at December 31, 1997. Production from this field constituted 19% of oil and gas production in 1997. The wells in this trend are all horizontally produced wells, primarily natural gas, that deliver high initial flow rates and strong initial cash flows which decline rapidly. The Company believes these reserves complement its long-lived reserves in the AWP Olmos Field. Since 1992, the Company has participated in 55 horizontal wells in the trend with a 91% success rate, including in 1997 16 successful development wells out of 17 drilled and two successful exploratory wells out of five drilled. The Company believes its success is attributable to its ability to identify hydrocarbon-bearing fractures, relying on its expertise in seismic data analysis, and its ability to drill and operate horizontal wells. The Company anticipates drilling 30 development wells and three exploratory wells in the Austin Chalk during 1998. The acquisition of seismic data in the Cougar Run and Nimitz areas in Fayette County has helped in upgrading locations to drill numerous 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 its 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, beginning in 1993 in an arrangement that covered approximately 8,800 acres in which the Company currently has an average working interest of 25%. In September 1995, the Company entered into another joint development agreement providing for an area of mutual interest covering 19,500 gross acres and pursuant to which that industry partner and the Company alternate serving as operator of any wells drilled on the acreage. During 1996, the Company purchased its partner’s interest in 9,500 of these gross acres, and the joint development arrangement now covers a 10,000 gross acre block in which the Company expects to have an average working interest of 30% to 35% based on certain assumptions relating to elections with respect to the drilling of various wells. The Company has a 100% working interest in the 9,500 acres.
In 1996, a joint development arrangement covering approximately 8,000 acres in Washington County, Texas, in which the Company owns a 25% working interest, was reached with an industry partner. This joint development area has been further expanded to encompass approximately 17,000 gross acres. Simultaneously, the Company entered into two additional joint development agreements covering an approximate 6,300 gross acre area, in which the Company owns a 50% working interest, and an approximate 8,100 gross acre area, in which the Company owns a 75% working interest and serves as operator.
Also in 1997, the Company acquired a 50% working interest in 20,000 net acres adjoining the N. Fayetteville Prospect area for which it will serve as operator. The initial test well was spudded in December 1997.
Exploration and Development Drilling Activities
In 1991, the Company began to develop an inventory of exploration and development drilling prospects. Drilling locations were selected through intensive geological and geophysical studies of the Company’s undeveloped acreage and other prospects. During 1995, the Company added 72 Bcfe of proved reserves through drilling, and in 1996, reserves added by drilling increased to 118 Bcfe. In 1997, reserves added by drilling increased to 120 Bcfe, with the Company’s success rate 47% for exploratory wells (7 out of 15 drilled) and 95% for development wells (159 out of 167 drilled). These successful drilling results have led to acquisition of additional acreage during 1997 in the area of its two core properties, the AWP Olmos Field in South Texas and the Austin Chalk trend in Austin, Colorado, Fayette, Walker, and Washington counties in central and eastern Texas.
The Company pursues a "controlled risk" approach to exploratory drilling. The Company focuses its exploration activities on specific U.S. regions where 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 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, economic parameters, and activity in the trend.
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 employs various recovery techniques, which include water flooding, fracturing reservoir rock through the injection of high-pressure fluid, inserting coiled tubing velocity strings to speed gas flow, and acid treatments. 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 largest single property, the 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 operations 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 analysis and amplitude versus offset (AVO) studies. During 1997, the Company completed its first international seismic acquisition program in two key areas of its holding 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 Wheeler Ranch Olmos trend in South Texas and 51 miles of data in the Fayette County Austin Chalk trend. Two more prospects in the Ark-La-Tex region were shot in the form of 2-D swaths of approximately 16 miles each.
In addition to exploration and development activities in the AWP Olmos Field and the Austin Chalk trend, the Company is currently focusing its exploration activities in three main geographical areas: the Gulf Coast Basin, the Wyoming Powder River Basin, and the North Louisiana Salt Basin.
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, which includes all target formations present except the Austin Chalk trend and the Olmos sand. In 1997, one successful development well (out of three) and four successful exploratory wells (out of six) were drilled in the Gulf Coast Basin, following one successful exploratory well and two successful development wells drilled in 1996. In 1998, seven exploratory wells and 18 development wells are scheduled for drilling in the Gulf Coast Basin. The locations were selected utilizing traditional geologic studies combined with analyses of available seismic data.
During 1997, the Company acquired 1,920 gross acres in Jim Hogg County in which the Company owns a minimum 75% working interest. Additionally, the Company has an oil and gas lease option on an additional 8,500 gross acres until August 1, 1998. A well drilled by the Company to the Queen City formation, the Chapparral #1, in 1997 was highly successful. Of the 18 development wells expected to be drilled in the Gulf Coast Basin in 1998, 10 will be drilled on this acreage. Further work in the area through licensing additional 2-D data and acquiring 3-D data jointly with a third party will help complete the analysis and the interpretation of the acreage for future development in 1998.
In the North Creole prospect in southern Louisiana, the Company has worked 2-D and 3-D seismic data in conjunction with the Vertical Seismic Profile it shot in early 1997 to identify development and exploratory locations of deep high-potential targets to be drilled in the first quarter of 1998. Additional 3-D seismic grids are being quality checked for eventual licensing in the area to help in the interpretation of the complex geologic features.
In the Sherburne prospect in south central Louisiana, the Company has been working with 2-D seismic data to identify the location of a Sparta formation test slated for the first quarter of 1998 and has designed a 2-D seismic cross-swath to be acquired commencing in March 1998 to identify deeper high-yield structures in the Wilcox trend.
Wyoming Powder River Basin. The Company intends to drill three exploratory wells and eight development wells in 1998. In 1997, the Company successfully drilled one out of two exploratory wells in the Minnelusa trend in Campbell County, Wyoming. In 1996, the Company successfully drilled one out of three exploratory wells and one out of three development wells in this trend. The Minnelusa trend has been the subject of extensive study by the Company’s multidisciplinary teams in order to identify the location of stratigraphic hydrocarbon traps. Recently, 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. The Company has licensed various existing 2-D seismic data to help map the structural and stratigraphic traps that have been identified for drilling in 1998.
North Louisiana Salt Basin. The North Louisiana Salt Basin covers the neighboring corners of Arkansas, Louisiana, and Texas (Ark-La-Tex region). In 1997, the Company drilled two wells, one exploratory and one development, with the development well being successful, following five successful wells drilled in 1996, four of which were exploratory. The Company plans to drill four exploratory wells in the region in 1998. In this area, the Smackover formation is a prolific hydrocarbon producer from multiple levels and from a variety of structures, including fault traps, salt anticlines, basement structures, and stratigraphic traps. In northern Louisiana and southern Arkansas in the Smackover trend, in 1997 the Company acquired and completed processing two sets of 2-D seismic swaths that have been interpreted to yield numerous exploratory locations slated for testing in the first half of 1998. Additional seismic acquisitions are planned in Bossier Parish, Louisiana, to delineate a prospect pending the drilling of a test well to determine the presence of hydrocarbon sands in the area.
The following table sets forth the results of the Company’s drilling activities during the three fiscal years ended December 31, 1997:
| Gross Wells | Net Wells | ||||||||
| Year | Type of Well | Total | Producing | Dry | Total | Producing | Dry | ||
| 1995 | Exploratory | 8 | 4 | 4 | 3.5 | 1.5 | 2.0 | ||
| Development | 68 | 65 | 3 | 38.7 | 38.0 | 0.7 | |||
| 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 | |||
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 approximately 650 wells at December 31, 1997, 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 conduct the actual drilling of wells on properties for which it acts as operator. Drilling operations are conducted by independent contractors engaged and supervised by the Company. The Company employs petroleum 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 producing formation of the well, whether the well produces oil or gas, and other factors. Such fees received by the Company in 1997 ranged from $200 to $1,481 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 generally sold in the spot market at prevailing prices. The Company generally sells its oil production at prevailing market prices. The Company does not refine any oil it produces. During the year ended December 31, 1997, three oil or gas purchasers each accounted for 10% or more of the Company’s revenues, with those purchasers together accounting for 42%. Three oil or gas purchasers accounted for 10% or more of the Company’s revenues during the year ended December 31, 1996, with those purchasers accounting for approximately 51%. 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 Valero Transmission, L.P. and its affiliates ("Valero") for up to 75,000 Mcf per day. These contracts have initial six-year terms, with automatic one-year extensions unless earlier terminated. 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 Valero, the gas processed and transported under these agreements may be sold to Valero at monthly indexed prices based upon the current natural gas price. Effective July 31, 1997, Valero was merged with Pacific Gas & Electric Corporation ("PG&E"). This merger did not affect the contractual obligations between the Company and Valero.
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 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, 1997. "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, | |||
| 1997 | 1996 | 1995 | |
| ----------------- | ----------------- | ----------------- | |
| Net Sales Volume: | |||
| Oil (Bbls) | 672,385 | 623,386 | 545,435 |
| Gas (Mcf)1 | 21,359,434 | 15,696,798 | 7,913,963 |
| Gas equivalents (Mcfe) | 25,393,744 | 19,437,114 | 11,186,573 |
| Average Sales Price: | |||
| Oil (per Bbl) | $17.59 | $19.82 | $15.66 |
| Gas (per Mcf) | $ 2.68 | $ 2.57 | $ 1.77 |
| Average Production Cost (per Mcfe) | $ 0.45 | $ 0.43 | $ 0.61 |
1Natural gas production for 1997, 1996, and 1995 includes 1,015,226, 1,156,361, and 1,211,255 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, 1997, the Company has a remaining commitment to deliver approximately 2.0 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 does engage periodically in certain limited hedging activities, but only to the extent of buying protection price floors for portions of its and the 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 were not significant for any year presented. The costs to purchase put options are amortized over the option period.
During 1997, 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, 1,400,000 MMBtu of the natural gas production was covered, providing for a minimum price of $1.90 per MMBtu. February was covered for 2,000,000 MMBtu of natural gas, and March and April were covered for 1,500,000 MMBtu of natural gas, each at a minimum price of $2.00. For the months of May, June, July, and August, 1,500,000 MMBtu was covered, providing for a minimum price of $1.80. September, October, and November had two contracts each month with each separate contract covering 1,500,000 MMBtu of natural gas, providing for minimum prices of $1.80 and $1.90 in September, $1.85 and $1.90 in October, and $1.90 and $2.00 in November.
For the months of January, February, and March, 140,000 Bbls of oil production were covered, with 70,000 Bbls each month providing for a minimum price of $17.00 and the other 70,000 Bbls each month providing for a minimum price of $20.00 per Bbl. April, May, and June were covered for 140,000 Bbls of oil production at a minimum price of $20.00 in April and May, while June provided for a minimum price of $19.00. July was covered for 60,000 Bbls of production at a minimum price of $18.00 and for 60,000 Bbls at a minimum price of $19.00. August was covered for 120,000 Bbls of production, providing for a minimum price of $19.00. For the months of September through December, 60,000 Bbls of oil production were covered, providing for a minimum price of $18.00. Costs related to 1997 hedging activities totaled approximately $1,052,000 with benefits of approximately $439,000 being received, resulting in a net cash outlay of approximately $613,000 or $0.014 per Mcfe.
The Company had three open contracts at December 31, 1997, covering 1,500,000 MMBtu of the natural gas production for February 1998 at a minimum price of $2.00, 500,000 MMBtu of gas in March 1998 at a minimum price of $1.90, and 60,000 Bbls of oil production for February providing for a minimum price of $18.00 per Bbl. The costs related to the open contracts totaled $95,308 and had a market value of $121,600 as of December 31, 1997.
Acquisition Activities
Since 1979, the Company has acquired approximately $478.0 million of producing oil and natural gas properties on behalf of itself and its co-investors in 129 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. 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 for its own behalf. The Company has acquired for its own account approximately $121.5 million of producing properties, with original proved reserves estimated at 182.2 Bcfe. The Company’s acquisition expenditures the past three years were approximately $3.5 million, $1.5 million, and $8.4 million of properties acquired in 1995, 1996, and 1997, respectively. The Company’s acquisition costs have averaged $0.31 per Mcfe over this three-year period.
The Company uses a disciplined, market-driven approach to acquisitions. The Company generally seeks acquisition of properties for its own account that are in close proximity to its current reserves and provide the potential to add reserves and production through additional development efforts.
Foreign Activities
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 $300,000. In May 1995, the Company executed a Management Agreement with Senega, under which, in return for undertaking to obtain financing for development of these fields, Swift would be entitled to receive a 49% interest in production income derived by Senega from this project after repayment of costs.
On December 10, 1997, the Company agreed to terminate the Management Agreement with Senega and to amend and restate the Participation Agreement. Under the amended and restated Participation Agreement, the Company retains its 6% net profits interest in the Samburg Field and has agreed to assist Senega in obtaining investments necessary to develop the field. Senega is charged with the management and control of the field development. At December 31, 1997, the Company’s investment in Russia was approximately $10,190,000 and is included in the unproved properties portion of oil and gas properties.
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 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. a Venezuelan company, 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. At December 31, 1997, the Company’s investment in Venezuela was approximately $2,435,000 and is included in the unproved properties portion of oil and gas properties, net of impairments of $45,668.
New Zealand. Since October 1995, the Company has been issued two Petroleum Exploration Permits by the New Zealand Minister of Energy. The first permit covers approximately 65,000 acres in the Onshore Taranaki Basin of New Zealand’s North Island, and the second covers approximately 69,300 adjacent acres. Under the terms of these permits, the Company is obligated to analyze and interpret certain seismic data, acquire certain new seismic data and drill one exploratory well, to be followed by a development well or additional seismic work, all of which is to be performed on a staged basis in order to maintain the permits, over periods extending through July 2000 for the first permit and August 1999 for the second permit. The Company formed a wholly-owned subsidiary, Swift Energy New Zealand Limited, for the purpose of conducting its New Zealand activities and assigned its interest in the permits to that subsidiary during the third quarter of 1997. At December 31, 1997, the Company’s investment in New Zealand was approximately $2,480,000 and is included in the unproved properties portion of oil and gas properties.
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, 1997, 1996, and 1995. 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, 1997, were estimated based upon weighted average prices of $2.78 per Mcf of natural gas and $15.76 per barrel of oil, compared to $4.47 and $2.41 per Mcf of natural gas and $23.75 and $18.07 per barrel of oil as of December 31, 1996 and 1995, 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.
| Year Ended December 31, | |||
| 1997 | 1996 | 1995 | |
| ----------------- | ----------------- | ----------------- | |
| Estimated Proved Oil and Gas Reserves | |||
| Net natural gas reserves (Mcf): | |||
| Proved developed | 191,108,214 | 135,424,880 | 81,532,025 |
| Proved Undeveloped | 123,197,455 | 90,333,321 | 62,035,495 |
| ----------------- | ----------------- | ----------------- | |
| Total | 314,305,669 | 225,758,201 | 143,567,520 |
| ============ | ============ | ============ | |
| Net oil reserves (Bbl): | |||
| Proved developed | 4,288,696 | 3,622,480 | 3,313,226 |
| Proved Undeveloped | 3,570,222 | 1,861,829 | 2,108,755 |
| ----------------- | ----------------- | ----------------- | |
| Total | 7,858,918 | 5,484,309 | 5,421,981 |
| ============ | ============ | ============ | |
| Estimated Present Value Proved Reserves | |||
| Estimated present value of future net cash flows from proved reserves discounted at 10%per annum: | |||
| Proved developed | $244,365,044 | $310,408,949 | $85,536,873 |
| Proved Undeveloped | 105,979,738 | 160,776,008 | 61,501,536 |
| ----------------- | ----------------- | ----------------- | |
| Total | $350,344,782 | $471,184,957 | $147,038,409 |
| ============ | ============ | ============ | |
The table also 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 Consolidated Financial Statements of the Company, 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 1997, 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 1998 and thereafter will be made at an unrestricted level.
The Company’s total proved developed and undeveloped reserves have increased substantially (40%) at December 31, 1997, when compared to December 31, 1996, as shown above and in Supplemental Information to the Company’s financial statements. A substantial portion (40%) of the reserves are proved undeveloped reserves. This reflects the increased emphasis on exploration and development activities. This was consistent with the proportions in 1996 of 39% proved undeveloped and 61% proved developed and reflects the continued emphasis on exploration and development activities.
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 1997 increased by 40% over reserves quantities a year earlier, the PV-10 Value of those reserves decreased 26% from the PV-10 Value at year end 1996. This decrease was almost totally due to high product prices at year end 1996, with the price of gas declining 38% during 1997 from $4.47 at December 31, 1996, to $2.78 at year end 1997, matched by a 34% decrease in the price of oil between the two dates, from $23.75 to $15.76. If the PV-10 Value as of year end 1997 had been calculated using the same prices in effect a year earlier, there would have been an increase in the PV-10 Value from year end 1996 to year end 1997 comparable to the 40% increase in the Company’s total proved reserves quantities during that same period.
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. Four of the limited partnerships had achieved payout status at December 31, 1997.
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, 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 |
| December 31, 1995 | |||
| Gross | 3,049 | 995 | 4,044 |
| Net | 88.5 | 121.6 | 210.1 |
1Excludes 16 service wells in 1997, 26 service wells in 1996, and 39 service wells in 1995.
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, 1997:
| Developed | Undeveloped | ||||
| Gross | Net | Gross | Net | ||
| -------------- | -------------- | -------------- | -------------- | ||
| Alabama | 4,495.38 | 616.70 | 292.00 | 41.17 | |
| Arkansas | 4,139.49 | 2,070.92 | 9,608.55 | 6,858.86 | |
| Kansas | --- | --- | 4,600.00 | 1,988.80 | |
| Louisiana | 44,481.57 | 13,610.37 | 20,085.44 | 11,750.85 | |
| Mississippi | 5,236.49 | 3,379.84 | 1,828.22 | 489.42 | |
| Montana | --- | --- | 4,851.28 | 4,851.28 | |
| Nebraska | --- | --- | 1,707.04 | 1,029.53 | |
| Oklahoma | 38,554.53 | 14,976.93 | 3,733.90 | 1,251.50 | |
| Texas | 117,016.60 | 64,543.20 | 173,589.65 | 124,198.13 | |
| Wyoming | 7,859.27 | 2,060.84 | 69,278.53 | 53,824.64 | |
| All other states | 157.64 | 6.80 | 4,850.44 | 285.33 | |
| -------------- | -------------- | -------------- | -------------- | ||
| Total | 221,940.97 | 101,265.60 | 294,425.05 | 206,569.51 | |
| ========= | ========= | ========= | ========= | ||
Partnerships
For many years, the Company relied on limited partnerships as its principal financing vehicle to fund its activities. The Company has formed 107 limited partnerships which have raised a total of approximately $502.0 million at December 31, 1997. However, as the Company has increasingly shifted its emphasis to exploration and development 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) and were liquidated in 1996, and 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 is expected in early 1998. As the public income partnerships formed since 1986 grow older, it is anticipated that proposals will continue to be made to the investors in those partnerships to sell their properties and liquidate the partnerships.
From 1991 to 1995 (and for prior periods), 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, 1997, eleven partnerships had been formed (one formed in each of 1993 and 1994, and three in each of 1995, 1996, and 1997) with aggregate investor contributions of approximately $58.6 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.
Under the terms of the Company’s limited partnership programs, the Company generally retains the right to engage in oil and gas exploration and production for its own account. The partnership agreement for each limited partnership contains detailed provisions regarding the terms upon which a variety of transactions between the Company and the limited partnerships may be carried out. These restrictions, which may limit the ability of the Company to take certain actions, are intended to ensure that transactions between the Company and the limited partnerships are fair to such limited partnerships.
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 $25.0 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.
Employees
At December 31, 1997, the Company employed 194 persons. None of the Company’s employees are represented by a union. Relations with employees are considered to be good.
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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 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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Those portions of the Form 10-K Report for the year ended December 31, 1997, not included in this Annual Report to Shareholders (including certain portions of Item 1–Business pertaining to "Competition" and "Regulations," Item 3–Legal Proceedings, Item 4–Submission of Matters to a Vote of Security Holders, Item 5–Market for Common Equity and Related Stockholder Matters pertaining to certain common stock matters, Item 7A–Quantitative and Qualitative Disclosures About Market Risk, Item 9–Changes in and Disagreements with Accountants on Accounting and Financial Disclosure, and Item 14–Exhibits, Financial Statement Schedules, and Reports on Form 8-K), with no disclosures having been made as to Items 3, 4, 7A, and 9, will be provided without charge to shareholders making a written request to John R. Alden, Secretary, Swift Energy Company, 16825 Northchase Drive, Suite 400, Houston, Texas 77060-6098. Exhibits filed as part of the Form 10-K will be provided to shareholders making a written request as set forth above at a reasonable charge sufficient to cover the Company’s cost in providing such exhibits.
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