ITEM 1 -- BUSINESS
OVERVIEW
Belco Oil & Gas Corp. and its subsidiaries ("Belco" or the "Company") is an independent energy company engaged in the exploration for and the acquisition, exploitation, development and production of natural gas and oil in the United States primarily in the Rocky Mountains, the Permian Basin, the Mid-Continent region and the Austin Chalk Trend. Since its inception in April 1992, the Company has grown its reserve base largely through a program of exploration and development drilling and through acquisitions. The Company concentrates its activities primarily in four core areas in which it has accumulated detailed geologic knowledge and has developed significant management and technical expertise. Additionally, the Company attempts to structure its participation in natural gas and oil exploration and development activities to minimize initial costs and risks, while permitting substantial follow-on investment.
The Company has achieved substantial growth in reserves, production, revenues and EBITDA (Earnings Before Interest, Taxes, Depreciation, Depletion and Amortization and other non-cash charges) since 1992. Belco's estimated proved reserves have increased at a compound annual growth rate of 44%, from 67 Bcfe as of December 31, 1992 to 604 Bcfe as of December 31, 1998 with a reserve life index of approximately 10 years based on 1998 production. Average daily production has increased from 4 MMcfe per day in 1992 to approximately 171 MMcfe per day in 1998. Similarly, the growth in the Company's EBITDA has been substantial, increasing from $2.9 million for the year ended December 31, 1992, to $104.7 million for the year ended December 31, 1998. The Company's low cost structure is evidenced by its general and administrative expenses of $0.08 per Mcfe and lease operating expenses of $0.66 per Mcfe in 1998.
The Company's operations are currently focused in the Rocky Mountains, primarily in the Green River (which includes the Moxa Arch Trend), Wind River and Big Horn Basins, the Permian Basin in west Texas, the Mid-Continent region in Oklahoma and north Texas, and the Austin Chalk Trend in both Texas and Louisiana. At December 31, 1998, the Company had estimated proved reserves of 604 Bcfe with a pre-tax PV10 value of $356.3 million (exclusive of a $4.3 million increase related to price risk management activities). The PV10 values were derived using substantially lower oil and gas prices as required by SEC rules when compared to the prices used at year-end 1997. As of December 31, 1998, Belco held or controlled approximately 1.9 million gross (822,000 net) undeveloped acres and had an interest in approximately 2,755 gross (1,769 net) oil and gas wells of which Belco operated 1,998.
The Company's Permian Basin and Mid-Continent activities concentrate on exploiting proved producing properties, including those with development potential, through secondary recovery operations, the drilling of development wells or infill wells, workovers, recompletions in other productive zones and other exploitation techniques. The Company has conducted or intends to conduct significant secondary recovery/infill drilling programs on many of the properties within these two core areas. Secondary recovery projects have been the primary development focus in these areas over the past five years. Generally, "secondary recovery" refers to methods of oil extraction in which fluid or gas (usually water, natural gas or CO(2)) is injected into a formation through input (injector) wells, and oil is removed from surrounding wells. "Waterflooding" is one proven method of secondary recovery in which water is injected into an oil reservoir for the purpose of forcing the oil out of the reservoir rock and into the bore of a producing well. Waterflood projects are engineered to suit the type of reservoir, depth and condition of the field. The Company has considerable experience with and actively employs waterflood techniques in many of its fields in order to stimulate production.
Certain terms relating to the oil and gas industry are defined in "-- Certain Definitions" below.
RECENT DEVELOPMENTS
In November 1997, the Company completed the acquisition of Coda Energy, Inc. ("Coda"), a Delaware corporation whose assets were concentrated in the Permian Basin of west Texas and the Mid-Continent region
of Oklahoma and north Texas. In February 1998, the Company merged Coda into Belco. As a result of the merger, Belco assumed the obligations under the 10 1/2% Senior Subordinated Notes due 2006 (the "10 1/2% Notes") originally issued by Coda. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." Immediately after such merger, the Company contributed all of Coda's assets and liabilities, except for the 10 1/2% Notes, into its wholly owned Nevada corporation Belco Energy Corp. The Company also restructured its operations creating a Northern Division, a Southern Division and a Western Division.
In February 1998, the Company acquired additional properties in its Permian Basin core area for $37.3 million (the "Permian Acquisition"). The properties consisted of approximately 65 Bcfe of estimated proved reserves at a cost of approximately $0.59 per Mcfe.
On March 10, 1998 the Company completed the sale of 4.37 million shares of its 6 1/2% Convertible Preferred Stock (the "Preferred Stock"). The Preferred Stock has a liquidation preference of $25 per share and is convertible at the option of the holder into shares of the Company's Common Stock at an initial conversion rate of 1.1292 shares of Common Stock for each share of Preferred Stock, equivalent to a conversion price of $22.14 per share of Common Stock. The Company received net proceeds from the sale of the Preferred Stock of $105.1 million, which was used to pay down bank indebtedness. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources."
In June 1998, the Company purchased, through its wholly owned Canadian subsidiary, approximately $10.5 million of 5% Convertible Preferred Shares of Big Bear Exploration Ltd., a Canadian oil and gas company ("Big Bear"), at a cost of approximately $0.85 per share with each such share convertible into one common share of Big Bear. The Company was also issued approximately $120 million of Special Acquisition Warrants at a price of approximately $0.72 per warrant. In November 1998, the Company entered into an agreement to cancel the Special Acquisition Warrants and to convert the 5% Convertible Preferred Shares into 21,428,571 shares of Big Bear common stock at an effective conversion price of $0.50 per share. On January 22, 1999 the Company consummated this agreement. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources."
Effective August 1, 1998, Diamond Energy Operating Company and Belco Operating Corp., both wholly owned subsidiaries of Belco, were merged into Belco Energy Corp., a wholly owned subsidiary of Belco.
Effective November 1, 1998, the Company acquired approximately 20 Bcfe (81% natural gas) of long-lived reserves on producing properties in Oklahoma and Kansas, as well as certain undeveloped acreage and 3-D seismic data for $14.8 million.
PRIMARY OPERATING AREAS
The Company's operations are currently focused in four core operating areas: (i) the Rocky Mountains, principally in Wyoming in the Green River (inclusive of the Moxa Arch Trend), Wind River and Big Horn Basins; (ii) the Permian Basin of west Texas; (iii) the Mid-Continent region in Oklahoma and north Texas; and (iv) the Austin Chalk Trend, primarily in Texas. In addition to these core areas, the Company conducts operations in the onshore Gulf Coast region and in several other minor areas.
The following table sets forth information, as of December 31, 1998, with respect to the Company's estimated net proved reserves by operating area. Approximately 83% of the quantities of proved reserves aggregating 92% of the pre-tax present value were estimated by the independent petroleum engineers Miller and Lents, Ltd. ("Miller & Lents"). See "Forward Looking Information and Risk Factors" below and "Properties."
PROVED RESERVES
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(1) Includes natural gas liquids.
Rocky Mountains
The Company maintains a significant acreage position in the Rocky Mountains of Wyoming where it conducts an ongoing exploration and development program. In June 1992, the Company commenced a development drilling program in the Moxa Arch Trend pursuant to a farmout from Amoco. In 1996, the Company significantly expanded its acreage and exploration activities by acquiring the rights to approximately 750,000 gross (250,000 net) acres in the Green River, Wind River and Big Horn Basins in Wyoming, which lie north and east of the Moxa Arch Trend. At December 31, 1998, the Company controlled approximately 894,916 gross (283,623 net) undeveloped acres in these three basins.
Moxa Arch Trend. One of the Company's primary operating areas is the Moxa Arch Trend located in the Green River Basin in southwestern Wyoming, principally in Lincoln, Sweetwater and Uinta Counties. Approximately 19% of the Company's estimated proved reserves at December 31, 1998 were located in this trend. The Company participates in vertical gas wells in this area which target the Frontier and/or Dakota formations at depths that range from approximately 10,000 to 12,500 feet. The Frontier formation is a relatively blanket "tight gas sand" formation, while the Dakota formation, beneath the Frontier, tends to be a more prolific, but less predictable, channel sand. Production from Moxa Arch wells, particularly from the Frontier formation, tends to be long-lived, with 25 to 30 year reserve lives not uncommon.
Through 1998, the Company had participated in 221 gross (69 net) wells in this field with 157 Frontier wells, 15 Dakota wells and 49 dual completions (both Frontier and Dakota completed in the same well bore). Average net production for the year ended December 31, 1998, was approximately 25.4 MMcfe per day. Forty-seven of the Company's gross wells drilled in 1992 qualified for the Section 29 Tax Credit of approximately $0.59 per Mcf, which is attributable to all qualified production from these wells through 2002. See "-- Section 29 Tax Credit." The Company drilled 13 wells (7 net) in 1998 and anticipates drilling another 12 wells in 1999. See "-- Regulation -- Environmental Regulation."
Green River, Wind River and Big Horn Basins. Effective November 1, 1996, the Company entered into an agreement with Andex Partners and Andover Partners to conduct exploratory operations in the Green River and Wind River Basins of Wyoming. Under the agreement, the Company has committed to spend a minimum of $20 million on seismic, leasing and exploratory activities through December 31, 2001 and will initially earn rights to a 50% interest in approximately 300,000 net acres after spending 50% of the committed amount. At December 31, 1998, the Company had spent approximately $10 million of its $20 million commitment with operations conducted by either Union Pacific Resources ("UPR") or Yates Petroleum Corporation ("Yates").
Effective December 31, 1996, the Company entered into two joint development agreements with Snyder Oil Company ("SOCO") pursuant to which the Company has acquired a 50% interest in approximately 87,321 net acres in the Wind River Basin of Wyoming and 110,859 net acres in the Big Horn Basin of Wyoming. Under such agreements, SOCO is the operator. The initial well on the Company's Wind River
acreage, the Tribal #46, was completed in August 1997 and was producing 1.1 MMcf per day gross on December 31, 1998. Four offset wells were drilled to the Tribal #46 in 1998 and two of the offsets were producing in the aggregate, approximately 2.4 MMcf per day gross in December 1998. The initial well in the Big Horn Basin, the Otto 16-4, was put on production in 1998 and was producing at a rate of 400 Mcfe per day as of December 31, 1998. One successful offset well to the Otto 16-4 has already been drilled in early 1999 and the Company currently anticipates drilling 4 additional offset wells in 1999.
In June 1997, the Company entered into a participation agreement with Tom Brown, Inc. ("Tom Brown") and Andover Partners covering an approximate one million acre AMI in the Big Horn Basin and acquired an interest in an initial 100,000 gross (25,000 net) acres. Based on interpretation of purchased 2-D seismic, the Company currently plans to drill two wells in 1999.
The Company expects to participate in a series of exploratory wells in these basins over the next 12 to 24 months with UPR, SOCO, Tom Brown and Yates serving as operators for most wells. The wells will target multiple formations, the most prevalent of which is the Frontier formation. If initial results are successful, these projects hold the potential for multi-well developmental drilling programs for the Company over the next several years.
Permian Basin
Approximately 38% of the Company's estimated proved reserves at December 31, 1998 were located in the Company's Permian Basin core area. These reserves are concentrated in five properties: the Andrews Unit, the Roundtop Unit, the Powell lease, the Shafter Lake San Andres Unit and the Nolley Wolfcamp Unit.
The Company's Permian Basin properties produce primarily from either the Grayburg/San Andres formation, at an average depth of 4,500 feet, or the Wolfcamp/Penn formation at an average depth of 9,000 feet. Most of the properties that produce from these horizons are under secondary recovery, and, based on analogous properties nearby, are potentially responsive to CO(2) miscible flooding. Given the existence of nearby CO(2) pipelines, the Company believes many of its properties in the Permian Basin region contain significant upside potential based on application of enhanced recovery methods and deeper drilling which could add to existing reserves.
A significant portion of the Company's total estimated proved reserves in the Permian Basin region lie in Andrews County, Texas. The Company produced approximately 2,630 gross BOPD in Andrews County, and realized significant advantages as a result of its large scale operation. The Company owns two electrical distribution systems and three saltwater gathering and disposal systems. The Company has several yards for both the storage of equipment and the staging of new development projects. Two of the Company's larger production facilities connect into a water supply system with excess capacity for expanding existing or initiating new secondary and enhanced recovery projects. The Company believes that these systems and facilities provide the Company with a competitive advantage in acquiring additional operated properties in Andrews County.
The Company's largest (by value) Permian Basin units are the Andrews Unit, the Roundtop Unit, the Powell lease and the Shafter Lake San Andres Unit.
Andrews Unit. The Andrews Unit produces from the Wolfcamp/Penn formation at approximately 8,600 feet. The Company has a 98.6% working interest in this 3,230 acre unit. Water injection began in late 1996 with some response occurring in late 1998. The Company anticipates additional response in 1999. Gross production in December 1998 was approximately 660 BOPD with injection of over 3,000 barrels of water per day. During 1998, the Company drilled one infill well which produced 102 BOPD in December 1998. The Company anticipates expanding its waterflood operations during 1999 by converting five wells to injection. The Company also believes that production from this waterflood unit can be enhanced with the use of CO(2) or surfactants.
Roundtop Unit. The Company owns a 61.6% working interest in this 4,559 acre unit in Fisher County, Texas. This Company operated secondary recovery unit produces from the Palo Pinto formation at approximately 4,700 feet. The Company became operator of this unit in March 1998. Gross oil production was
approximately 490 BOPD in December 1998. The unit was originally waterflooded with success on a peripheral injection pattern prior to changing to a five spot pattern. The Company began the process of returning the unit to a peripheral flood pattern in 1998. The Company plans to continue reconfiguring the injection pattern during 1999.
Powell Lease. The Powell lease is a 1,360 acre tract in Crockett County, Texas that produces from the Strawn and Ellenburger formations at 8,100 feet. The Company became the operator of this lease in March 1998 and owns a 50% working interest. Gross production in December 1998 was approximately 185 BOPD and 1,420 Mcf/d. During 1998, the Company drilled one well which produced approximately 80 BOPD and 500 Mcf/d in December 1998. The Company plans to drill three wells during 1999.
Shafter Lake San Andres Unit. The Shafter Lake San Andres Unit is a 12,880 acre unit in Andrews County, Texas that produces from the Grayburg/San Andres formation at approximately 4,500 feet. The Company has a 62.9% working interest in this secondary recovery unit. Gross oil production averaged 950 BOPD in 1998. The Company has drilled 42 infill 20 acre locations since becoming operator of the unit in early 1993. In 1998, the Company drilled 10 infill wells and anticipates continuing to develop this waterflood during 1999 by drilling an additional 10 infill wells. In addition, the Company believes a large part of this field has potential for 10 acre infill wells as well as CO(2) potential.
Recent Acquisition. In February 1998, the Company acquired additional properties in its Permian Basin core area for $37.3 million. The properties contained approximately 65 Bcfe of estimated proved reserves at a cost of approximately $0.59 per Mcfe to Belco. See "-- Recent Developments."
Mid-Continent Region
The Company's Mid-Continent operations are currently focused in Oklahoma, north Texas and Kansas, where approximately 27% of its total estimated proved reserves at December 31, 1998 were located.
Oklahoma. Six waterfloods collectively represent a majority of the Company's proved reserves in the region. These waterfloods are identified as the Oakdale Unit, the Calumet Unit, the Witcher Unit, the Crooked Creek Unit, the Cutter South Unit and the Rush Springs Unit. All six waterfloods were initiated and unitized by the Company.
Oakdale Red Fork Unit. The Company owns an 88.9% working interest in this 3,600 acre unit in northwestern Oklahoma. This Company operated secondary recovery unit produces from the Redfork formation at 6,400 feet. Gross oil production was approximately 1,250 BOPD in December 1998. The Company drilled 4 wells during 1998. Plans for 1999 include drilling infill production wells and fracture stimulating certain current producing wells.
Calumet Cottage Grove Unit. This Company operated secondary recovery unit consists of 11,400 acres in central Oklahoma. Production is from the Pennsylvanian Cottage Grove formation at 8,100 feet. Gross production in December 1998 was approximately 2,100 BOPD. The Company has a 44.1% working interest in this unit. 1999 plans include drilling several infill and re-entry wells and converting two wells to water injection.
Witcher Red Fork Unit. The 1,620 acre Company operated Witcher Red Fork Unit is located in Central Oklahoma. The Company has a 70.7% working interest in this 6,400 foot secondary recovery unit. December 1998 gross production was approximately 530 BOPD.
North Texas. The north Texas region stretches from the Chadbourne Ranch Field in Coke County in the west to several individual leases in Grayson County in the east. The Katz, Electra and Burkburnett Fields represent the properties of the most significant value in the north Texas region. The Company has drilled 289 wells in these fields. In addition to the Company's extensive inventory of oil and gas opportunities in the north Texas region, the Company owns three electrical distribution systems and has extensive field facilities.
Katz Field. The Katz Field consists of five secondary recovery leases located in King and Knox Counties, Texas. The Company became the operator in March 1998 and has a 100% working interest in
these leases. Production is from two Strawn sands at approximately 4,800 feet and 5,100 feet. Gross oil production was approximately 370 BOPD in December 1998. During 1998, the Company drilled three wells producing 50 BOPD total. In addition, the Company began reactivating the waterflood in the zone at 4,800 feet with response occurring in late 1998. The Company anticipates continuing reactivation of the waterflood by activating three shut-in injectors and five shut-in producers during 1999.
Electra Area. The Electra area produces from shallow Cisco sand at a depth of 150 to 2,100 feet. The Company operates 22 leases in this area with 233 active oil producing wells and 121 active water injectors. The Company has a 100% working interest in 21 of these leases and a 75% working interest in the other lease. Gross production for December 1998 was approximately 1,400 BOPD. In 1998 the Company drilled 16 producing wells and plans to drill an addition 7 wells in 1999.
Burkburnett Area. The Burkburnett area produces from the Gunsight Sand formation at a depth of 1,750 feet. The Company operates 12 leases in this area with 159 active oil producing wells and 116 active water injectors. The Company's working interest is 100% in all leases. Gross production for December 1998 was approximately 525 BOPD and the Company currently plans to drill six wells in 1999.
Recent Acquisition. Effective November 1, 1998, the Company acquired approximately 20 Bcfe (81% natural gas) of long-lived reserves on producing properties in Oklahoma and Kansas, as well as certain undeveloped acreage and 3-D seismic data for $14.8 million. See "-- Recent Developments."
Austin Chalk Trend
Texas -- Giddings Field. Approximately 14% of the Company's estimated total proved reserves at December 31, 1998 were located in the Giddings Field of east central Texas, principally in Grimes, Washington and Fayette Counties. The Giddings Field has been and still is one of the most actively drilled oil and gas fields in the United States. The primary producing zone in the Giddings Field is the Austin Chalk formation, a fractured carbonate formation that has been highly conducive to the application of horizontal drilling technology. The Austin Chalk formation is encountered in this field at depths ranging between approximately 7,000 and 17,000 feet.
The Company first acquired interests in the Giddings Field in September 1992. During the year ended December 31, 1998, average net production from this field was approximately 60.2 MMcfe per day. Through December 31, 1998, the Company had drilled 256 gross (84 net) wells in this field and continues to control approximately 242,000 gross (85,000 net) undeveloped acres in this area. The Company currently divides the Giddings Field into three prospect areas: (i) Navasota River, primarily in Grimes County; (ii) Independence, primarily in Washington County; and (iii) River Bend, primarily in Fayette County. The Company expects to drill new wells, including infill wells, and re-enter older wells to drill additional laterals in the Giddings Field. Currently, a majority of the Company's interests in this field are held pursuant to agreements with and are operated by Chesapeake Energy Corporation ("CHK") and, to a lesser extent, UPR and Swift Energy Co. The Company serves as operator for portions of the River Bend prospect area.
The Company believes that its success in the Giddings Field is attributable to three principal factors: (i) continued technological advances in horizontal drilling have significantly lowered finding and development costs in the field; (ii) the geological setting of the deeper downdip areas of the field has created more extensive fracturing than in other areas of the Texas Austin Chalk Trend; and (iii) the Company's acquisition program in cooperation with other operators has permitted the creation of larger spacing units, thus reducing possible competition for reserves from offsetting wells. As a result of these factors, the Company's deeper downdip wells have, on average, produced greater reserves per well than average wells in other areas of the Texas Austin Chalk Trend.
The majority of the Company's acreage in the Giddings Field was classified as a tight formation or deep wells by the Texas Railroad Commission. Wells spud between May 1989 and September 1996 are exempt from the 7.5% state severance tax on high cost natural gas through August 2001. See "-- Texas Severance Tax Abatement."
Louisiana. The Louisiana Austin Chalk Trend is an extension of the 200-mile long Austin Chalk Trend of Texas and represents a continuation of the Company's exploration and development activities using deep-well horizontal drilling technology. At December 31, 1998, the Company owned or had the right to acquire approximately 217,363 net acres in this trend but, as previously reported, low oil prices prompted the postponement by the Company of substantially all oil prone Gulf Coast drilling, including drilling in the Louisiana extension of the Austin Chalk.
Other Operating Areas
Gulf Coast. In March 1996, the Company entered into an exploration agreement with Edge Petroleum Corporation ("Edge") pursuant to which the parties expected to jointly conduct a series of 3-D seismic programs onshore in the Gulf Coast region of Texas. Under the program, Edge and the Company initiated the first 50+ square mile 3-D seismic shoots targeting the shallower Frio and Yegua formations and potentially larger reserves in the deeper Yegua and Wilcox formations. Edge is the operator of any shallow zone wells drilled under the program and under certain circumstances the Company will operate prospects targeting deeper zones. At December 31, 1998, Belco and Edge had acquired seismic options on approximately 11,749 gross acres. As of December 31, 1998, the Company had a 50% working interest in twenty-five (25) productive Frio and Yegua wells (out of thirty-six (36) wells drilled). The Company participated in 17 Frio and 3 Yegua wells, respectively, in 1998. The Company anticipates concluding its drilling program in this area in 1999 with an additional 6 wells.
HLM Project. The Company has obtained 3-D seismic on approximately 140 square miles located mainly in Montgomery and Liberty Counties. This seismic is currently being interpreted with target objectives in the Frio, Yegua and Wilcox formations. The Company anticipates drilling up to 10 wells in this prospect area in 1999.
Michigan -- Central Basin. In June 1996, the Company entered into an exploration program with two private oil and gas companies pursuant to which the Company acquired an interest in acreage in the Central Basin of Michigan with the Company serving as operator. At December 31, 1998, the Company held or controlled interests in a total of approximately 106,299 gross and 17,841 net acres in this basin. As of year end 1998, the Company's drilling program in this basin has had limited success and the remaining prospects are currently being evaluated.
COSTS INCURRED AND DRILLING RESULTS
Drilling Activity
The following table sets forth the wells participated in by the Company during the periods indicated. In the table, "gross" refers to the total wells in which the Company has a working interest, and "net" refers to gross wells multiplied by the Company's working interest therein. The table includes results for Coda since November 26, 1997, the date Coda was acquired by the Company.
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(1) Includes 7 gross (4 net) wells in progress at December 31, 1998.
(2) Excludes 343 gross (175 net) productive wells acquired during 1998.
Volumes, revenue, prices and production costs
The following table sets forth certain information regarding the production volumes, revenue, average prices received (prior to any commodity price risk management activities) and average production costs associated with the Company's sale of oil and natural gas for the periods indicated. The table includes results for Coda since November 26, 1997.
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(1) Oil and gas sales exclude results related to commodity price risk management activities reported separately.
Development, Exploration and Acquisition Expenditures
The following table sets forth certain information regarding the costs incurred by the Company in its development, exploration and acquisition activities during the periods indicated. The table includes information for Coda since November 26, 1997, the date Coda was acquired by the Company.
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(1) Acquisition of proved properties includes $437.4 million (inclusive of $101.6 million of deferred taxes related to the difference between the book and tax basis of assets acquired) relative to the acquisition of Coda.
ACREAGE
The following table sets forth, as of December 31, 1998, the gross and net acres that the Company owned, controlled or had the right to acquire interests in both developed and undeveloped acreage. Developed acreage
refers to acreage within producing units and undeveloped acreage refers to acreage that has not been placed in producing units. "Gross" acres refers to the total number of acres in which the Company owns a working interest. "Net" acres refers to gross acres multiplied by the Company's fractional working interest.
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(1) Leases covering approximately half of the undeveloped acreage will expire within the next three years. However, the Company expects to evaluate this acreage prior to its expiration. The Company's leases generally provide that the leases will continue past their primary terms if oil or gas in commercial quantities is being produced from a well on such leases.
PRODUCTIVE WELL SUMMARY
The following table sets forth the Company's ownership in productive wells at December 31, 1998. Gross oil and gas wells include multiple completions. Wells with multiple completions are counted only once for purposes of the following table. Production from various formations in wells without multiple completions is commingled.
MARKETING
There are a variety of factors which affect the market for oil and natural gas, including the extent of domestic production and imports of oil and gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and gas, the marketing of competitive fuels and the effects of state and federal regulations on oil and gas production and sales. The Company has not experienced any difficulties in marketing its oil or gas. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual customers.
Although the Company seeks to moderate the impact of price volatility through its commodity price risk management activities, the Company remains subject to price fluctuations for natural gas sold in the spot
market due primarily to seasonality of demand and other factors beyond the Company's control. Domestic oil prices generally follow worldwide oil prices, which are subject to price fluctuations resulting from changes in world supply and demand.
PRODUCTION SALES CONTRACTS
In Wyoming, the Company sells all of its natural gas, natural gas liquids and condensate from its Moxa Arch wells under a market sensitive long term sales contract with Amoco Energy Trading Corporation (the "Amoco Gas Contract"). The price payable to the Company under the Amoco Gas Contract for gas is the Northwest Pipeline Rocky Mountain Index, plus $0.03 per MMBtu, less fuel charges and gathering fees and adjustments for Btu content. The Amoco Gas Contract was renewed effective January 1, 1999 for an additional three year period on the same terms.
All of the Company's current Moxa Arch Wyoming oil and condensate production is sold at market sensitive prices pursuant to an option held by Amoco.
The Company's Moxa Arch wells are subject to various gathering agreements with third parties. Wells drilled under the Amoco Farmout Agreement in the Wilson Ranch, Seven Mile Gulch and Bruff areas are subject to the Gas Gathering and Processing Agreement dated March 20, 1992 with Northwest Pipeline. Gathering fees under this agreement are currently $0.0762 per MMBtu and fuel charges are 0.5%. Gathering fees and fuel charges in the Cow Hollow/Shute Creek areas are $0.1386.
In Texas, Louisiana and Oklahoma, the Company sells its gas to purchasers under percentage of proceeds or index-based contracts. Under the percentage of proceeds contract, the Company receives a fixed percentage of the resale price received by the purchaser for sales of residue gas and natural gas liquids recovered after gathering and processing the Company's gas. The Company receives between 85% and 92% of the proceeds from residue gas sales and from 85% to 90% of the proceeds from natural gas liquids sales received by the Company's purchasers when the products are resold. The residue gas and natural gas liquids sold by these purchasers are sold primarily based on spot market prices. The revenue received by the Company from the sale of natural gas liquids is included in natural gas sales. Under indexed-based contracts, the price per MMBtu the Company receives for its gas at the wellhead is tied to indexes published in Inside FERC or Gas Daily, and in most cases is subject to a discount to the relevant index in lieu of a gathering fee.
All of the Company's oil production is sold under market sensitive or spot price contracts to various purchasers.
Sales to individual customers constituting 10% or more of total oil and gas sales in 1998 were made to Aquila Southwest Pipeline (14%) and Amoco Gas Trading Corp. (11%).
Management believes that the loss of any one of the above customers would not have a material adverse effect on the Company's results of operations or its financial position.
PRICE RISK MANAGEMENT TRANSACTIONS
Commodity Price Risk Management
With the objective of achieving more predictable revenues and cash flows and reducing the exposure to fluctuations in gas and oil prices, the Company has entered into price risk management transactions of various types with respect to both natural gas and oil, as described below. While the use of these arrangements limits the downside risk of adverse price movements to a certain extent, it may also limit future revenues from favorable price movements. The Company had entered into price risk management transactions with respect to a substantial portion of its production for 1997 and 1998 and with respect to a substantial portion of its estimated production for 1999 through 2000 and with respect to lesser portions thereafter. The Company continues to evaluate whether to enter into additional such transactions for 1999 and future years. In addition, the Company may determine from time to time to terminate its then existing hedging and other risk management positions.
All of the Company's price risk management transactions are carried out in the over-the-counter market and not on the New York Mercantile Exchange ("NYMEX"). These financial counterparties all have at least an investment grade credit rating. All of these transactions provide solely for financial settlements relating to closing prices on the NYMEX.
The following is a summary of the types of price risk management transactions in effect as of December 31, 1998.
Swaps. Since all of the Company's natural gas and oil is sold on "floating" or market related prices, the Company has entered into financial swap transactions which convert a floating price into a fixed price for a future month. For any particular swap transaction, the counterparty is required to make a payment to the Company in the event that the NYMEX Reference Price for any settlement period is less than the swap price for such hedge, and the Company is required to make a payment to the counterparty in the event that the NYMEX Reference Price for any settlement period is greater than the swap price for such hedge.
Reverse Swaps. When the Company determines it desires to reduce the amount of swaps because of an assumed favorable outlook for prices it enters into a reverse swap. Under such a transaction the role of the Company and the role of the counterparty are reversed.
Collars. A collar provides for an average floor price and an average ceiling price. For any particular collar transaction, the counterparty is required to make a payment to the Company if the average NYMEX Reference Price for the reference period is below the floor price for such transaction, and the Company is required to make payment to the counterparty if the average NYMEX Reference Price is above the ceiling price for such transaction.
Options, Puts and Straddles. When the Company believes that it will receive a sufficiently high cash premium (or other consideration) for granting the counterparty a call or put option, it may enter into such a transaction. If the Company sold a $16.00 call on oil for $0.40 a barrel in a given month and prices averaged $15.00 a barrel for such month, the Company would receive a net realization per barrel of $15.40 ($15.00 plus the $0.40 premium). However, if for that month the price of oil averaged $16.00 per barrel, the Company would receive a net realization of $16.40 (the call price, $16.00, plus $0.40). The Company regards this as a prudent transaction under certain circumstances provided that the Company always has more physical production for the periods involved than its related aggregate risk management transactions.
A limited number of these transactions contain negotiated knockout, extendable or leverage provisions. These provisions either limit price protection beyond a specific level, contain tiered pricing provisions, allow the option to be extended for a period of time, or provide for payment based upon a multiple of the underlying notional volume. The transactions described in this paragraph and any sold options are required to be marked to market as to their value on the last day of the accounting period.
Basis Swaps. Since a substantial portion of the Company's natural gas is sold under spot contracts with reference to East Texas hub prices and the Company's price risk management transactions are based on the NYMEX Reference Price relating to gas delivered to Henry Hub, Louisiana, the Company has entered into basis swaps that require the counterparty to make a payment to the Company in the event that the average NYMEX Reference Price per MMBtu for gas delivered to Henry Hub, Louisiana for a reference period exceeds the average price for gas delivered at the Houston Ship Channel (the most liquid East Texas hub) for such reference period by more than a stated differential, and requires the Company to make a payment to the counterparty in the event that the NYMEX Reference Price for Henry Hub exceeds the price for Houston Ship Channel gas by less than the stated differential (or in the event that the Houston Ship Channel price exceeds the Henry Hub price). The Company sells Wyoming natural gas at prices based on the Northwest Pipeline Rocky Mountain Index ("NPRMI") and the Colorado Interstate Gas Co. -- Rocky Mountain Index ("CIGCo. -- RMI") (indices of prices for gas delivered at various delivery points on the Northwest Pipeline and the CIGCo. pipeline in the Northern Rocky Mountain area). For natural gas sold against these indices, the Company has entered into basis swaps that require the counterparty to make a payment to the Company in the event that the average NYMEX Reference Price per MMBtu for gas delivered to Henry Hub, Louisiana for a reference period exceeds the average price for gas delivered to the Northwest Pipeline in the Rocky
Mountains as reflected in the NPRMI (the most liquid Rocky Mountain hub) for such reference period by more than a stated differential, and requires the Company to make a payment to the counterparty in the event that the NYMEX Reference Price for Henry Hub exceeds the price for NPRMI gas by less than the stated differential (or in the event that the NPRMI price exceeds the Henry Hub price).
TEXAS SEVERANCE TAX ABATEMENT
Production from natural gas wells that have been certified as tight formations or deep wells by the Texas Railroad Commission ("high cost gas wells") and that were spudded or completed during the period from May 24, 1989 to September 1, 1996 qualify for an exemption from the 7.5% severance tax in Texas on natural gas and natural gas liquids produced by such wells prior to August 31, 2001. The natural gas production from wells drilled on certain of the Company's properties in the Austin Chalk area qualify for this tax exemption. In addition, high cost gas wells that are spudded or completed during the period from September 1, 1996 to August 31, 2002 are entitled to receive a severance tax reduction upon obtaining a high cost gas certification from the Texas Railroad Commission within 180 days after first production. The tax reduction is based on a formula composed of the statewide "median" (as determined by the State of Texas from producer reports) and the producer's actual drilling and completion costs. More expensive wells will receive a greater amount of tax credit. This tax rate reduction remains in effect for 10 years or until the aggregate tax credits received equal 50% of the total drilling and completion costs.
SECTION 29 TAX CREDIT
The natural gas production from wells drilled on certain of the Company's properties in the Wyoming Moxa Arch Trend and Golden Trend Field in Oklahoma qualifies for the Section 29 Tax Credit. The Section 29 Tax Credit is an income tax credit against regular federal income tax liability with respect to sales of the Company's production of natural gas produced from tight gas sand formations, subject to a number of limitations. Fuels qualifying for the Section 29 Tax Credit must be produced from a well drilled or a facility placed in service after November 5, 1990 and before January 1, 1993, and be sold before January 1, 2003.
The basic credit, which is currently approximately $0.52 per MMbtu ($0.59 per Mcf) of natural gas produced from tight sand reservoirs and approximately $1.05 per MMbtu of natural gas produced from Devonian Shale, is computed by reference to the price of crude oil and is phased out as the price of oil exceeds $23.50 per Bbl in 1979 dollars (as adjusted for inflation) with complete phaseout if such price exceeds $29.50 per Bbl in 1979 dollars (as adjusted for inflation). Under this formula, the commencement of phaseout would be triggered if the average price for crude oil rose above approximately $48 per Bbl in current dollars. The Company generated approximately $0.7 and $0.9 million of Section 29 Tax Credits in 1998 and 1997, respectively. The Section 29 Tax Credit may not be credited against the alternative minimum tax, but under certain circumstances may be carried over and applied against regular tax liability in future years. Therefore, no assurances can be given that the Company's Section 29 Tax Credits will reduce its federal income tax liability in any particular year.
OTHER TAX RELIEF
Currently, Louisiana, Texas and Oklahoma are considering tax relief addressing persistent low oil and gas prices. Legislation related to the proposed relief is not final and as a result the Company cannot evaluate the potential impact.
REGULATION
General. The oil and gas industry is extensively regulated by federal, state and local authorities. In particular, oil and gas production operations and economics are affected by price controls, environmental protection statutes and regulations, tax statutes and other laws relating to the petroleum industry, as well as changes in such laws, changing administrative regulations and the interpretations and application of such laws, rules and regulations. Oil and gas industry legislation and agency regulation are under constant review for amendment and expansion for a variety of political, economic and other reasons.
Regulation of Natural Gas and Oil Exploration and Production. The Company's operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations. The Company's operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells which may be drilled and the unitization or pooling of oil and gas properties. In this regard, some states (such as Oklahoma) allow the forced pooling or integration of tracts to facilitate exploration while other states (such as Texas) rely on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units and, therefore, more difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount of oil and gas the Company can produce from its wells and may limit the number of wells or the locations at which the Company can drill. The regulatory burden on the oil and gas industry increases the Company's costs of doing business and, consequently, affects its profitability. Inasmuch as such laws and regulations are frequently expanded, amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with such regulations.
The Company has operations located on federal oil and gas leases, which are administered by the MMS. Such leases are issued through competitive bidding, contain relatively standardized terms and require compliance with detailed MMS regulations. In addition to permits required from other agencies (such as the Army Corps of Engineers and the Environmental Protection Agency (the "EPA")), lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS also has regulations restricting the flaring or venting of natural gas, liquid hydrocarbons and oil without prior authorization. The MMS generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met. The cost of such bonds or other surety can be substantial and there is no assurance that bonds or other surety can be obtained in all cases. Under certain circumstances, the MMS may require Company operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect the Company's financial condition and operations.
The Company does not anticipate that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect upon the capital expenditures, earnings or competitive position of the Company.
Environmental Regulation. Activities of the Company with respect to the exploration, development and production of oil and natural gas are subject to stringent environmental regulation by state and federal authorities. Such regulation has increased the cost of planning, designing, drilling, operating and in some instances, abandoning wells. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production waste products and waste created by water and air pollution control procedures. The risks of substantial costs and liabilities associated with such compliance are inherent in oil and gas operations, and there can be no assurance that significant costs and liabilities, including civil and criminal penalties, will not be incurred. Moreover, it is possible that other developments, such as stricter and more comprehensive environmental laws and regulations as well as claims for damages to property or persons resulting from the Company's operations could result in substantial costs and liabilities to the Company. The Company believes that it is in substantial compliance with existing environmental regulations, and that any noncompliance will not have a material adverse effect on operations or earnings.
OPERATING HAZARDS AND INSURANCE
Oil and gas drilling and production activities are subject to numerous risks, many of which are beyond the Company's control. These risks include the risk that no commercially productive oil or natural gas reservoirs will be encountered, that operations may be curtailed, delayed or canceled as a result of title problems, weather conditions, compliance with governmental requirements, mechanical difficulties or shortages or delays
in the delivery of equipment and that the availability or capacity of gathering systems, pipelines or processing facilities may limit the Company's ability to market its production. There can be no assurance that new wells drilled by the Company will be productive or that the Company will recover all or any portion of its investment. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. In addition, the Company's properties may be susceptible to hydrocarbon drainage from production by other operators on adjacent properties.
Industry operating risks include the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases, the occurrence of any of which could result in substantial losses to the Company due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Additionally, certain of the Company's oil and gas operations are located in an area that is subject to tropical weather disturbances, some of which can be severe enough to cause substantial damage to facilities and possibly interrupt production.
The Company maintains customary oil and gas related third party liability coverage, which it must renew annually, that insures the Company against certain sudden and accidental risks associated with drilling, completing and operating its wells. There can be no assurance that this insurance will be adequate to cover any losses or exposure to liability or that the Company will be able to renew its coverage annually. The Company and its subsidiaries carry workers' compensation insurance in all states in which they operate. While the Company believes this coverage is customary in the industry, it does not provide complete coverage against all operating risks.
TITLE TO PROPERTIES
Title to properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the oil and gas industry, as well as to liens for current taxes not yet due and to other encumbrances. As is customary in the industry in the case of undeveloped properties, little investigation of record title is made at the time of acquisition of leasehold interests (other than a preliminary review of local records). Investigations, including a title opinion of local counsel, are generally made before commencement of drilling operations. To the extent title opinions or other investigations reflect title defects, the Company, rather than the seller of the undeveloped property, is typically responsible to cure any such title defects at its expense. If the Company were unable to remedy or cure title defect of a nature such that it would not be prudent to commence drilling operations on the property, the Company could suffer a loss of its entire investment in the property. From time to time the Company's title to oil and gas properties is challenged through legal proceedings. Under the terms of certain of the Company's joint development, participation and farmout agreements, the Company's interest (other than interests acquired through holding of leasehold interests prior to spudding of the well) in each well is conveyed to the Company upon the successful completion of the well or satisfaction of other conditions.
EMPLOYEES
As of December 31, 1998, the Company had 189 full time employees, none of whom is represented by organized labor unions. The Company considers its employee relations to be good.
OFFICE AND EQUIPMENT
The Company maintains its executive offices at 767 Fifth Avenue, New York, New York. The Company pays Robert A. Belfer, Chairman of the Board and Chief Executive Officer, a fee of $250,000 per annum for office space and services provided through such office. This fee is indexed to the consumer price index. The fee is based on the actual cost of such office space prorated to the amount utilized in Company operations. The Company believes the fee compares favorably to the terms which might have been available from a non-affiliated party. See "Certain Relationships and Related Transactions." The Company owns a building in
Dallas, Texas, containing approximately 65,000 square feet which serves as the operations headquarters. The Company leases 5,796 square feet of office space in Tulsa, Oklahoma pursuant to a lease that terminates on August 31, 2000. The Company also leases 1,748 square feet of office space in Midland, Texas pursuant to a lease that terminates on February 28, 2001. Additionally, the Company owns a property in Granger, Wyoming consisting of a metal building and associated four acres, used by Belco as a production office and yard. The Company also maintains an inventory of field equipment and materials including tubular goods, compressors, pumping units and field vehicles.
FORWARD-LOOKING INFORMATION AND RISK FACTORS
This document includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements other than statements of historical facts included in this document (including the information incorporated by reference herein), including without limitation statements regarding planned capital expenditures, the availability of capital resources to fund capital expenditures, estimates of proved reserves, the number of anticipated wells to be drilled in 1999 and thereafter, the Company's financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the Company. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary from one another. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revisions of such estimate and such revisions, if significant, would change the schedule of any further production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Additional important factors that could cause actual results to differ materially from the Company's expectations are described elsewhere herein. All written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by such factors.
Volatility of Oil and Gas Prices; Marketability of Production
The Company's revenue, profitability and future rate of growth are substantially dependent upon the prevailing prices of, and demand for, oil and natural gas. The Company's ability to maintain or increase its borrowing capacity and to obtain additional capital on attractive terms is also substantially dependent upon oil and gas prices. Prices for oil and natural gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond the control of the Company. These factors include the level of consumer product demand, weather conditions, domestic and foreign governmental regulations, the price and availability of alternative fuels, political conditions in the Middle East, the foreign supply of oil and natural gas, the price of oil and gas imports and overall economic conditions. From time to time, oil and gas prices have been depressed by excess domestic and imported supplies. There can be no assurance that current price levels will be sustained. It is impossible to predict future oil and natural gas price movements with any certainty. Recent declines in oil and natural gas prices have reduced the amount of the Company's oil and natural gas that can be produced economically, and may adversely affect the Company's financial condition, liquidity and results of operations. Market prices for oil and gas have generally declined since December 1997. Additionally, substantially all of the Company's sales of oil and natural gas are made pursuant to contracts based on market indexes and not pursuant to long-term fixed price contracts. With the objective of reducing price risk, the Company enters into hedging transactions with respect to a portion of its expected future production. There can be no assurance, however, that such hedging transactions will reduce risk or mitigate the effect of any substantial or extended decline in oil or natural gas prices. Any substantial or extended decline in the prices of
oil or natural gas would have a material adverse effect on the Company's financial condition and results of operations.
In addition, the marketability of the Company's production depends upon the availability and capacity of gas gathering systems, pipelines and processing facilities. Federal and state regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand all could adversely affect the Company's ability to produce and market its oil and natural gas. If market factors were to change dramatically, the financial impact on the Company could be substantial. The availability of markets and the volatility of product prices are beyond the control of the Company and represent a significant risk. See "Marketing" and "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Overview."
Volatile oil and gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploration projects.
Uncertainty of Estimates of Oil and Gas Reserves
This 10-K contains estimates of the Company's proved oil and gas reserves and the estimated future net revenues therefrom based upon the Company's estimates and the reserve report prepared by Miller and Lents (the "Miller and Lents Report") that rely upon various assumptions, including assumptions required by the Securities and Exchange Commission (the "Commission") as to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. As a result, such estimates are inherently imprecise. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves may vary substantially from those estimated in the Company's estimates and the Miller and Lents Report. Any significant variance in these assumptions could materially affect the estimated quantity and value of reserves set forth in this 10-K. In addition, the Company's proved reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing oil and gas prices and other factors, many of which are beyond the Company's control. Actual production, revenues, taxes, development expenditures and operating expenses with respect to the Company's reserves will likely vary from the estimates used, and such variances may be material.
Approximately 23% of the Company's total proved reserves at December 31, 1998 were undeveloped, which are by their nature less certain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. The reserve data set forth in the Company's estimates and the Miller and Lents Report assumes that substantial capital expenditures by the Company will be required to develop such reserves. Although cost and reserve estimates attributable to the Company's oil and gas reserves have been prepared in accordance with industry standards, no assurance can be given that the estimated costs are accurate, that development will occur as scheduled or that the results will be as estimated. See "Properties -- Oil and Gas Reserves."
The present value of future net revenues referred to in this 10-K should not be construed as the current market value of the estimated oil and gas reserves attributable to the Company's properties. In accordance with applicable requirements of the Commission, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by increases or decreases in production, changes in governmental regulations or taxation. The timing of actual future net cash flows from proved reserves, and thus their actual present value, will be affected by the timing of both the production and the incurrence of expenses in connection with development and production of oil and gas properties. In addition, the 10% discount factor, which is required by the Commission to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor
based on interest rates in effect from time to time and risks associated with the Company or the oil and gas industry in general.
Reserve Replacement
As is customary in the oil and gas exploration and production industry, the Company's future success depends upon its ability to find, develop or acquire additional oil and gas reserves that are economically recoverable. Unless the Company replaces its estimated proved reserves (through development, exploration or acquisition), the Company's proved reserves will generally decline as they are produced.
Exploratory drilling and, to a lesser extent, development drilling involve a high degree of risk that no commercial production will be obtained or that the production will be insufficient to recover drilling and completion costs. The costs of drilling, completing and operating wells are uncertain. The Company's drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment. Furthermore, completion of a well does not assure a profit on the investment or a recovery of drilling, completion and operating costs. See "-- Costs Incurred and Drilling Results."
The Company's current strategy includes increasing its reserve base through acquisitions of leaseholds with drilling potential and by continuing to exploit its existing properties. There can be no assurance, however, that the Company's exploration and development projects will result in significant additional reserves or that the Company will have continuing success drilling productive wells at economically viable costs. Furthermore, while the Company's revenues may increase if prevailing oil and gas prices increase significantly, the Company's finding costs for additional reserves could also increase. For a discussion of the Company's reserves, see "Properties -- Oil and Gas Reserves."
Ceiling Limitation Writedowns
The Company reports its operations using the full cost method of accounting for oil and gas properties. Under the full cost accounting rules, the net capitalized costs of proved oil and gas properties may not exceed a "ceiling limit", calculated at the end of each quarter, which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%, plus the lower of cost or fair market value of unproved properties, net of related tax effects. If net capitalized costs of proved oil and gas properties exceed the ceiling limit, the Company is subject to a ceiling limitation writedown to the extent of such excess. A ceiling limitation writedown is a charge to earnings which does not impact cash flows. However, such writedowns impact the amount of the Company's stockholders' equity. The risk that the Company will be required to write down the carrying value of its oil and gas properties increases when oil and gas prices are depressed or volatile. Application of these rules during periods of relatively low oil or gas prices, even if temporary, may result in a ceiling writedown. In addition, writedowns may occur if the Company makes additional acquisitions or has substantial downward revisions in its estimated proved reserves. The recent significant declines in oil and gas prices increase the risk that the Company will be required to record a ceiling limitation writedown. See "-- Volatility of Oil and Natural Gas Prices; Marketability of Production." For the year 1998 the Company recorded approximately $229 million ($149 million after-tax) of non-cash ceiling test provisions after applying substantially lower commodity prices to estimated recoverable reserves. At year-end 1997, the Company recorded a non-cash writedown of approximately $150 million ($97.5 million after tax), a significant portion of which was attributable to the 1997 acquisition of Coda and lower year end reserve values due to lower year end oil and gas prices. No assurance can be given that the Company will not experience additional ceiling limitation writedowns in the future. See "Management's Discussion and Analysis of Financial Condition and Results of Operations."
Substantial Capital Requirements
The Company makes, and expects to continue to make, substantial expenditures for the development, exploration, acquisition and production of oil and natural gas reserves. The Company incurred capital expenditures of $141.0 million during 1997 and $133.0 million during 1998. The Company has budgeted $50
to $55 million, exclusive of potential acquisitions, for capital expenditures for producing properties and leasehold acquisitions and drilling operations in 1999. Management believes that the Company will have sufficient cash provided by operating activities and borrowings under its credit facility to fund capital expenditures in 1999. However, if revenues or cash flows from operations decrease as a result of lower oil and natural gas prices or operating difficulties, the Company may be limited in its ability to expend the capital necessary to undertake or complete its current drilling plans, or it may be forced to raise additional debt or equity proceeds to fund such expenditures in the future. The Company's credit facility currently limits the amounts the Company may borrow to $150 million, subject to increase or decrease based upon borrowing base adjustments. There can be no assurance that additional debt or equity financing or cash generated by operations will be available to meet all these requirements. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources."
Acquisition Risks
The Company continues to pursue the acquisition of oil and gas properties and businesses. Although no definitive agreements have been consummated regarding any such acquisitions, if consummated such acquisitions may have a material impact on the Company's business. Any acquisition by the Company must satisfy the applicable covenants set forth in the indenture governing the Company's 8 7/8% Senior Subordinated Notes due 2007 (the "8 7/8% Indenture"), the indenture governing the Company's 10 1/2% Senior Subordinated Notes due 2006 (the "10 1/2% Indenture") and the credit agreement (the "Credit Agreement") relating to the Company's Credit Facility (as defined herein).
The successful acquisition of producing properties generally requires accurate assessments of: (i) recoverable reserves; (ii) future oil and gas prices and operating costs; (iii) potential environmental and other liabilities; and (iv) other factors. Such assessments are necessarily inexact and their accuracy inherently uncertain. It generally is not feasible to review in detail every individual property involved in an acquisition. Ordinarily, review efforts are focused on the higher-valued properties. Nevertheless, even a detailed review of all properties and records may not reveal existing or potential problems nor will it permit the Company to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections are not always performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken.
Holding Company Structure
The Company conducts all of its operations through subsidiaries. Accordingly, the Company relies on dividends and cash advances from its subsidiaries to provide funds necessary to meet its obligations, and the Company will rely upon such sources of funds to pay interest on indebtedness and dividends on the Preferred Stock. The ability of any such subsidiary to pay dividends or make cash advances is subject to applicable laws and contractual restrictions as well as the financial condition and operating requirements of such subsidiary.
Restrictions Upon Ability to Pay Dividends
The ability of the Company to make dividend payments on the Preferred Stock will be dependent on the Company's future performance and liquidity. In addition, the Credit Agreement, the 8 7/8% Indenture and the 10 1/2% Indenture contain restrictions on the ability of the Company to pay cash dividends on its capital stock, including the Preferred Stock. The Credit Agreement permits the Company to pay cash dividends of up to $50 million in the aggregate and restricts additional dividends to 50% of the Company's cumulative consolidated net income (as defined in the Credit Agreement) (or if such consolidated net income is a deficit, 100% of such deficit) from October 1, 1997, subject to increases and decreases to such cumulative amount based on other adjustments specified in the Credit Agreement. The Credit Agreement also prohibits the Company from paying cash dividends if there is a default or event of default under the Credit Agreement. The 8 7/8% Indenture permits the Company to pay cash dividends of up to $25 million in the aggregate and restricts additional dividends to 50% of the Company's cumulative consolidated net income (as defined in the 8 7/8% Indenture) (or if such consolidated net income is a deficit, 100% of such deficit) from October 1, 1997, subject to increases and decreases to such cumulative amount based on other adjustments specified in the
8 7/8% Indenture. The 8 7/8% Indenture also prohibits the payment of cash dividends in the event that (i) the Company would not be permitted to incur $1.00 of additional indebtedness under the 8 7/8% Indenture at the time of a proposed dividend payment based on its inability to satisfy a fixed charge coverage ratio or (ii) there is a default or event of default under the 8 7/8% Indenture. The 10 1/2% Indenture permits the Company to pay cash dividends of up to $5 million in the aggregate and would restrict additional dividends to 50% of the Company's cumulative consolidated net income (as defined in the 10 1/2% Indenture) (or if such consolidated net income is a deficit, 100% of such deficit) from April 1, 1996, subject to increases and decreases to such cumulative amount based on other adjustments specified in the 10 1/2% Indenture. The Company believes that it will have capacity beyond the $5 million dividend limit under the 10 1/2% Indenture. The 10 1/2% Indenture would also prohibit the payment of cash dividends in the event that (i) the Company would not be permitted to incur $1.00 of additional indebtedness under the 10 1/2% Indenture at the time of a proposed dividend payment based on its inability to satisfy a fixed charge coverage ratio or (ii) there is a default or event of default under the 10 1/2% Indenture.
Operating Hazards and Uninsured Risks; Production Curtailments
Oil and gas drilling and production activities are subject to numerous risks, many of which are beyond the Company's control. These risks include the risk that no commercially productive oil or natural gas reservoirs will be encountered, that operations may be curtailed, delayed or canceled and that title problems, weather conditions, compliance with governmental requirements, mechanical difficulties or shortages or delays in the delivery of drilling rigs, work boats and other equipment may limit the Company's ability to market its production. There can be no assurance that new wells drilled by the Company will be productive or that the Company will recover all or any portion of its investment. In addition, the Company's properties may be susceptible to hydrocarbon drainage from production by other operators on adjacent properties.
Industry operating risks include the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases, the occurrence of any of which could result in substantial losses to the Company due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Additionally, certain of the Company's oil and gas operations are located in an area that is subject to tropical weather disturbances, some of which can be severe enough to cause substantial damage to facilities and possibly interrupt production. In accordance with customary industry practice, the Company maintains insurance against some, but not all, of the risks described above. There can be no assurance that any insurance will be adequate to cover losses or liabilities. The Company cannot predict the continued availability of insurance at premium levels that justify its purchase. Losses and liabilities arising from uninsured or under-insured events could have a material adverse effect on the financial condition and results of operations of the Company.
From time to time, due primarily to contract terms, pipeline interruptions or weather conditions, the producing wells in which the Company owns an interest may be subject to production curtailments. The curtailments may vary from a few days to several months. In most cases the Company will be provided only limited notice as to when production will be curtailed and the duration of such curtailments. The Company is currently not curtailed on any of its production.
Competition
The Company operates in a highly competitive environment. The Company competes with major and independent oil and gas companies for the acquisition of desirable oil and gas properties, as well as for the equipment and labor required to develop and operate such properties. Many of these competitors have financial and other resources substantially greater than those of the Company.
Risks of Price Risk Management Transactions
In order to manage its exposure to price risks in the marketing of its oil and natural gas, the Company has in the past and expects to continue to enter into oil and natural gas price risk management arrangements with respect to a portion of its expected production. These arrangements may include futures contracts on the NYMEX fixed price delivery contracts and financial swaps. While intended to reduce the effects of volatility of the price of oil and natural gas, such transactions may limit potential gains by the Company if oil and natural gas prices were to rise or fall substantially over the price established by the arrangement. In addition, such transactions may expose the Company to the risk of financial loss in certain circumstances, including instances in which: (i) production is less than expected; (ii) if there is a widening of price differentials between delivery points for the Company's production and the delivery point assumed in the arrangement; (iii) the counterparties to the Company's future contracts fail to perform under the contract; or (iv) a sudden, unexpected event materially impacts oil or natural gas prices. See "-- Price Risk Management Transactions" and "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources."
Governmental Regulation
Oil and gas operations are subject to various United States federal, state and local governmental regulations that change from time to time in response to economic or political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling and abandonment bonds, reports concerning operations, the spacing of wells, and unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas. In addition, the production, handling, storage, transportation and disposal of oil and gas, by-products thereof and other substances and materials produced or used in connection with oil and gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. The Company may also be subject to substantial clean-up costs for any toxic or hazardous substance that may exist under any of its current properties or properties that it has operated in the past. To date, expenditures related to complying with these laws and for remediation of existing environmental contamination have not been significant in relation to the results of operations of the Company.
Although the Company believes it is in substantial compliance with all applicable laws and regulations, the requirements imposed by such laws and regulations are frequently changed and subject to interpretation. In addition, the recent trend toward stricter standards in environmental legislation and regulation is likely to continue. For instance, legislation has been proposed in Congress from time to time that would reclassify certain crude oil and natural gas exploration and production wastes as "hazardous wastes" which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If such legislation were to be enacted, it could have a significant impact on the operating costs of the Company, as well as the oil and gas industry in general. The Company could incur substantial costs to comply with environmental laws and regulations, and the Company is unable to predict the ultimate cost of compliance with these requirements or their effect on its production. See "-- Regulation."
Reliance on Key Personnel
The Company depends, and will continue to depend in the foreseeable future, on the services of its officers and key employees with extensive experience and expertise in evaluating and analyzing producing oil and gas properties and drilling prospects, maximizing production from oil and gas properties and marketing oil and gas production. The ability of the Company to retain its officers and key employees is important to the continued success and growth of the Company.
The Company is dependent upon Robert A. Belfer, the Company's Chairman and Chief Executive Officer, and Laurence D. Belfer, the Company's Vice Chairman and Chief Operating Officer, in addition to certain of its other executive officers. The unexpected loss of the services of one or more of these individuals
could have a detrimental effect on the Company. The Company does not maintain key man life insurance on any of its officers or key employees. See "Directors and Executive Officers of the Registrant."
Control by Certain Stockholders
Robert A. Belfer, his spouse, his children, his sisters, their spouses, their children and trusts for their children and grandchildren own approximately 77% of the outstanding shares of the Common Stock and approximately 15% of the outstanding shares of the Preferred Stock. As a result, such stockholders will be able to effectively control the outcome of certain matters requiring a stockholder vote, including the election of directors. Such ownership of Common Stock may have the effect of delaying, deferring or preventing a change of control of the Company and may adversely affect the voting and other rights of other stockholders.
Certain Potential Conflicts of Interests
Robert A. Belfer is a director of Enron Corp. ("Enron"). Enron, primarily through its majority owned subsidiary, Enron Oil & Gas Company ("EOG"), is involved in the exploration, development and production of oil and gas. Mr. Belfer is not a director of EOG. While the Company's activities have not historically overlapped with the activities of Enron or EOG, the Company may in the future compete for certain opportunities with Enron or EOG. To the extent any conflict from such future competition may arise, Mr. Belfer intends to excuse himself from participating in any decisions of the Board of Directors of Enron related to such opportunities.
EXECUTIVE OFFICERS OF THE REGISTRANT
Officers are elected each year by the Board of Directors following the Annual Meeting for a term of one year and until the election and qualification of their successors. The current executive officers of the Company and their ages, positions with the Company and business experience are presented below:
Robert A. Belfer, age 63, is Chairman of the Board and Chief Executive Officer of the Company. Mr. Belfer began his career at BPC in 1958 and became Executive Vice President in 1964, President in 1965 and Chairman of the Board in 1984. BPC was an independent oil and gas producer in the United States and abroad, which went public in 1959. It was one of the larger independent oil and gas companies in the United States and was included in Fortune's listing of the 500 largest industrial companies in the United States prior to merging with InterNorth, Inc. (now Enron Corp.) in 1983. Following the merger, Mr. Belfer became Chief Operating Officer of BelNorth Petroleum Corp., a combination of oil and gas producing operations of BPC and InterNorth. He resigned from his position with InterNorth in 1986 and pursued personal investments in oil and gas and other industries. In April 1992, Mr. Belfer founded the Company. In addition to his position at the Company, Mr. Belfer serves on the boards of Enron and NAC ReCorporation. Mr. Belfer received his undergraduate degree from Columbia College (A.B. 1955) and a law degree from the Harvard Law School (J.D. 1958).
Laurence D. Belfer, age 32, is Vice-Chairman and Chief Operating Officer of the Company. Mr. Belfer joined the Company as Vice President in September 1992. He was promoted to Executive Vice President in May 1995 and Chief Operating Officer in December 1995, was named President in April 1997 and Vice-Chairman in March, 1999. He is a founder and Chairman of Harvest Management, Inc., a money management firm. Mr. Belfer graduated from Harvard University (B.A. 1988) and from Columbia Law School (J.D. 1992).
Grant W. Henderson, age 40, is President of the Company. He was named President effective March 1, 1999 and prior to his promotion he served as Senior Vice President-Corporate Development. Mr. Henderson was formerly President and Chief Financial Officer of Coda and joined Coda in October 1993 as Executive Vice President and Chief Financial Officer. He was elected a director of Coda in 1995 and became President of Coda upon consummation of the merger with JEDI in February 1996. Mr. Henderson was previously employed by NationsBank, beginning 1981, last serving as Senior Vice President in its Energy Banking Group. Mr. Henderson is a graduate of Texas Tech University where he received a B.B.A. degree with a major in finance.
Dominick J. Golio, age 53, is Senior Vice President -- Finance, Chief Financial Officer, Treasurer and Secretary of the Company. Mr. Golio began his career at the New York City office of Arthur Andersen & Co. in 1972. In 1975, he joined Case, Pomeroy & Company and Felmont Oil Corporation, its publicly traded affiliate, where he rose to the position of Vice President Finance. Mr. Golio left Felmont in 1987 following a merger between Felmont and Homestake Mining Company. He served as Vice President Finance and Administration at both AEG Corporation, the U.S. electronics subsidiary of Daimler-Benz North America, until 1991 and at Millmaster Onyx Group, Inc. until September 1993 at which time he joined the Company. Mr. Golio is a Certified Public Accountant (NY). He holds undergraduate and graduate degrees from Pace University (B.B.A. Accounting, 1972, M.B.A. -- Taxation, 1978).
Shiv K. Sharma, age 57, is Senior Vice President -- Engineering of the Company. Mr. Sharma began his career in 1967 as a Reservoir Engineer with Shell Oil Company. In 1970, he joined BPC as a reservoir engineer and was subsequently elected to Vice President and Senior Vice President of Engineering, a position he held until his departure from that company in 1988. From 1988 to 1992, Mr. Sharma worked as a petroleum consultant for several New York companies. He served as a director and consultant to the Company commencing April 1992 and was elected to his present position in April 1994. Mr. Sharma received his degrees in petroleum technology from the Indian School of Mines (B.S. 1963) and petroleum engineering from Stanford University (M.S. 1966).
Steven L. Mueller, age 46, is Senior Vice President -- Exploration and Production of the Company. Mr. Mueller began his career in 1975 as a Geological Engineer at Tenneco Oil, Lafayette. He advanced at Tenneco Oil to Division Exploration Manager in 1987. In 1988, Mr. Mueller joined Fina Oil in Houston, Texas as Exploration Manager of South Louisiana, and in 1992 he joined American Exploration in Houston, Texas as Exploitation Vice President. He was with American Exploration until October of 1996 when he joined the Company. Mr. Mueller has over 23 years experience in exploring for and exploiting oil and gas fields both onshore and offshore. He holds a BS in Geological Engineering from the Colorado School of Mines (1975).
Gary Hampton, age 43, is Vice President -- Exploration of the Company. Mr. Hampton began his career in 1978 as a Reservoir Geologist for Texas Eastern (now PanEnergy). Mr. Hampton joined Champlin (currently UPR) in 1980 as a geologist and remained there until 1984. Mr. Hampton spent the next two years with Clayton Williams Energy generating prospects and developing acreage plays. In 1986, he became an independent consultant geologist providing geological assessments to the energy and environmental industry. Mr. Hampton rejoined Clayton Williams Energy in 1989 as the geologist responsible for, among other programs, geological planning associated with the company's Austin Chalk development program resulting in over 100 horizontal wells drilled in the Austin Chalk, Buda and Georgetown formations. Mr. Hampton was named Exploration Manager at Clayton Williams where he remained until February 1995, at which time he joined the Company as Manager -- Geology. Mr. Hampton was promoted to Vice President -- Exploration in January 1996. He received a B.S. in Geology from the University of Southern Mississippi in 1978.
George A. Sheffer, age 46, is Vice President -- Operations -- Western Division of the Company. Mr. Sheffer began his career in 1974 at Chevron USA where he served in the capacities of Reservoir Engineer, Drilling Representative and Production Engineer. Mr. Sheffer went on to serve in various engineering management positions with Meridian Oil and its predecessor Southland Royalty Company from 1979 to 1992. He joined the Company as Senior Petroleum Engineer in May 1994 after spending two years at Mearsk Energy, Inc. as Drilling Manager. He was promoted to Vice President -- Operations at the Company in November 1994. Mr. Sheffer has more than 20 years of diverse experience in all phases of petroleum engineering and operations management in the domestic oil and gas industry. Mr. Sheffer has specialized in horizontal drilling since 1987. He has extensive experience in the entire Austin Chalk Trend from South Texas to the Louisiana Border. Mr. Sheffer is a graduate of Pennsylvania State University (1974) from which he received a degree in Petroleum and Natural Gas Engineering.
CERTAIN DEFINITIONS
The definitions set forth below shall apply to the indicated terms as used in this 10-K. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.
AMI. Area of mutual interest.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
BOE. Barrel of oil equivalent (converting six Mcf of natural gas to one Bbl of oil).
BOPD. Barrels of oil per day.
Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Completion. The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Developed acreage. The number of acres that are allocated or assignable to producing wells or wells capable of production.
Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Exploratory well. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Finding costs. Total costs incurred in oil and gas acquisition, exploration and development activities and capitalized interest divided by total reserve additions, including purchases of minerals in place, extensions, discoveries, revisions and other additions.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Infill well. A well drilled between known producing wells to better exploit the reservoir.
Liquids. Crude oil, condensate and natural gas liquids.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet.
Mcf/d. One thousand cubic feet per day.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
MMS. Mineral Management Service of the United States Department of the Interior.
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMBOE. One million barrels of oil equivalent.
MMbtu. One million Btus.
MMcf. One million cubic feet.
MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.
Oil. Crude oil and condensate.
Operating cash inflows per Mcfe. Net operating cash inflows as listed in the Consolidated Statements of Cash Flows in the Consolidated Financial Statements divided by net gas equivalent production for the applicable periods.
Present Value or PV10. When used with respect to oil and natural gas reserves, the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Proved developed nonproducing reserves. Proved developed reserves expected to be recovered from zones behind casing in existing wells.
Proved developed producing reserves. Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production to market.
Proved 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.
Proved undeveloped location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
Proved undeveloped reserves. Proved 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.
Recompletion. The completion for production of an existing well bore in another formation from that in which the well has been previously completed.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Royalty interest. An interest in an oil and natural gas property entitling the owner to a share of oil or natural gas production free of costs of production.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Updip. A higher point in the reservoir.
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to a share of production.
Workover. Operations on a producing well to restore or increase production.
ITEM 2
ITEM 2 -- PROPERTIES
OIL AND GAS RESERVES
The following table sets forth information with respect to the Company's estimated net proved oil and gas reserves as of December 31, 1998. Information in this 10-K as of December 31, 1998 relating to properties with 83% of the Company's estimated net proved oil and gas reserves (92% of the PV10) and the estimated future net revenues attributable thereto is based upon the Miller and Lents, Ltd. Report, independent petroleum engineers. All calculations of estimated net proved reserves have been made in accordance with the rules and regulations of the Commission and, except as otherwise indicated, give no effect to federal or state income taxes otherwise attributable to estimated future net revenues from the sale of oil and gas. The present value of estimated future net revenues has been calculated using a discount factor of 10%. See "Business -- Forward-Looking Statements and Risk Factors -- Uncertainty of Estimates of Oil and Gas Reserves."
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(1) Estimated future net revenue before income taxes represents estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using average December 1998 prices, which were $2.20 per Mcf of gas and $10.85 per barrel of oil without giving effect to commodities price risk management activities accounted for as hedges. At December 31, 1998, the estimated future net revenue before income taxes and the present value of such estimated future net revenue before income taxes related to such price risk management activities were $4.6 million and $4.3 million, respectively (based on oil and gas prices in effect at December 31, 1998), which amounts have not been added to estimated future net revenue before income taxes and its present value as shown above. If such amounts were added, estimated future net revenue before income taxes would equal $609.4 million (Proved Developed) and $711.5 million (Total) and present values of such estimated future net revenues before income taxes would equal $322.5 million (Proved Developed) and $360.6 million (Total).
See also "Business."
ITEM 3
ITEM 3 -- LEGAL PROCEEDINGS
The Company is a named defendant in routine litigation incidental to its business. While the ultimate results of these proceedings cannot be predicted with certainty, the Company does not believe that the outcome of these matters will have a material adverse effect on the Company.
ITEM 4
ITEM 4 -- SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the quarter ended December 31, 1998, no matters were submitted by the Company to a vote of its security holders.
PART II
ITEM 5
ITEM 5 -- MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
As of March 15, 1999, the Company estimates there were approximately 142 record holders of its Common Stock. The Company's Common Stock is listed on the New York Stock Exchange ("NYSE") and traded under the symbol "BOG." As of March 15, 1999, the Company had 31,786,600 shares outstanding and its closing price on the NYSE was $5.9375 per share. The high and low sales prices for the Company's Common Stock during each quarter in the two years ended December 31, 1998 were as follows:
COMMON STOCK
The Company has never paid a dividend, cash or otherwise, on its Common Stock. Certain provisions of the Company's Credit Agreement, 8 7/8% Indenture and the 10 1/2% Indenture restrict the Company's ability to declare or pay cash dividends on its Common Stock. See "Forward-Looking Information and Risk Factors -- Restrictions Upon Ability to Pay Dividends". Other than payments of Preferred Stock dividends, the Company currently intends to maintain a policy of retaining cash for the continued expansion of its business.
ITEM 6
ITEM 6 -- SELECTED FINANCIAL DATA
The following table sets forth selected financial data regarding the Company as of and for each of the periods indicated. The following data should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Company's financial statements and notes thereto, which follow.
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(1) 1996 includes a one-time non-cash deferred tax charge of $30.1 million recognized as a result of the Combination consummated on March 29, 1996 in connection with the Company's Initial Public Offering.
(2) Earnings per share have been computed as if the 25,000,000 shares of Common Stock that were issued in connection with Combination had been outstanding for all years prior to 1996.
(3) Income before income taxes, depreciation, depletion and amortization, impairments and other non-cash mark-to-market accounting provisions is presented as a measure of the Company's ability to service its debt and to fund capital expenditures, not as a measure of operating results, and is not presented in the financial statements.
ITEM 7
ITEM 7 -- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist in the understanding of the Company's historical financial position and results of operations for the periods indicated. It is based on the Company's historical financial statements and related notes thereto which follow and contain detailed information that should be referred to in conjunction with Management's Discussion and Analysis.
OVERVIEW
Belco Oil & Gas Corp. (the "Company") is an independent energy company engaged in the exploration for and the acquisition, exploitation, development and production of natural gas and oil in the United States primarily in the Rocky Mountains, the Permian Basin, the Mid-Continent region and the Austin Chalk Trend. Since its inception in April 1992, the Company has grown its reserve base largely through a balanced program of exploration and development drilling and through acquisitions. The Company concentrates its activities primarily in four core areas in which it has accumulated detailed geologic knowledge and has developed significant management and technical expertise. Additionally, the Company structures its participation in natural gas and oil exploration and development activities to minimize initial costs and risks, while permitting substantial follow-on investment.
On November 26, 1997, the Company acquired all of the outstanding capital stock of Coda Energy, Inc. ("Coda"), an independent energy company that was principally engaged in the acquisition and exploitation of producing oil and natural gas properties. Coda's properties were principally located in the Permian Basin of west Texas and the Mid-Continent region of Oklahoma and north Texas. The acquisition approximately doubled the Company's reserve base to 604 Bcfe at December 31, 1997, extended the Company's reserve life index at that time and established a more balanced reserve mix of approximately 51% oil and 49% natural gas. Based on 1998 production, the Company's reserve life index is 9.7 years.
The Company's operations are currently focused in the Rocky Mountains, primarily in the Green River (which includes the Moxa Arch Trend), Wind River and Big Horn Basins of Wyoming, the Permian Basin in west Texas, the Mid-Continent region in Oklahoma and north Texas, and the Austin Chalk Trend, primarily in Texas. These areas accounted for approximately 99% of the Company's proved reserves at December 31, 1998.
The Company's revenue, profitability and future rate of growth are substantially dependent upon prevailing prices for natural gas, oil and condensate. These prices are dependent upon numerous factors beyond the Company's control, such as economic, political and regulatory developments and competition from other sources of energy. Energy markets have historically been very volatile, and there can be no assurance that oil and natural gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in oil and natural gas prices could have a material adverse effect on the Company's financial position, results of operations and access to capital, as well as the quantities of natural gas and oil reserves that the Company may economically produce. Natural gas produced is sold under contracts that primarily reflect spot market conditions for their particular area. The Company markets its oil with other working interest owners on spot price contracts and typically receives a small premium to the price posted for such oil. Currently, approximately 60% of the Company's production volumes relate to the sale of natural gas (based on six Mcf of gas being considered equivalent to one barrel of oil).
The Company utilizes commodity swaps and options and other commodity price risk management transactions related to a portion of its oil and natural gas production to achieve a more predictable cash flow, and to reduce its exposure to price fluctuations. The Company accounts for these transactions as hedging activities or uses mark-to-market accounting for those contracts that do not qualify for hedge accounting. As of December 31, 1998, the Company has various natural gas and oil price risk management contracts in place with respect to substantial portions of its estimated production for calendar year 1999 and with respect to lesser portions of its estimated production for 2000 and 2001. The Company expects from time to time to either add or reduce the amount of price risk management contracts that it has in place in keeping with its price risk management strategy.
The following table sets forth certain operations data of the Company for the periods presented:
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(1) Excluding non-cash ceiling test and securities impairment provisions, interest income and interest expenses.
RESULTS OF OPERATIONS -- 1998 COMPARED TO 1997
Revenues
Oil and gas sales revenues for the year 1998 (unhedged) declined 5% to $124.2 million when compared to the $130.0 million realized in 1997, due to substantially lower commodity prices. The year 1997 included only one month of Coda activities. In 1998 weighted average oil prices realized (unhedged) totaled $13.17 per barrel, a 32% decline when compared to the $19.28 realized in 1997. The natural gas weighted average prices realized (unhedged) declined 12% from $2.11 in 1997 to $1.86 in 1998. Average daily production volume in 1998 on an Mcfe basis increased 8% to 170,609 Mcfe.
Commodity price risk management activities resulted in a net pre-tax gain of $24.8 million for 1998 which included (1) realized hedging gains of $2.0 million, (2) net realized gains related to non-hedging transactions totaling $3.9 million, and (3) non-cash unrealized gains for mark-to-market accounting of $18.9 million. The impact of such activities on an Mcfe basis amounted to net gains of $0.40 ($0.10 cash and $0.30 non-cash). This compares to net losses of $0.11 ($0.13 cash losses and a non-cash gain of $0.02) per Mcfe for 1997.
Costs and Expenses
Production and Operating Expenses. Production and operating expenses increased to $40.8 million in 1998 when compared to the $12.8 million incurred during 1997. The increase is identified with the growth in oil production through secondary recovery techniques following the Coda acquisition and reflects the higher costs normally associated with such production when compared to natural gas. On a unit basis, operating costs were $0.66 per Mcfe for 1998 compared to $0.22 per Mcfe for 1997 which included only one month of Coda activities.
Depreciation, Depletion and Amortization. Recurring depreciation, depletion and amortization ("DD&A") costs for the year totalled $56.1 million when compared to the $46.7 million recorded for the prior year. The DD&A rate per Mcfe was $0.90 and $0.81 for 1998 and 1997, respectively. For the year 1998, the
Company also recorded $229 million ($149 million after-tax) in non-cash ceiling test provisions as required by full-cost accounting rules. The provisions were the result of applying substantially lower commodity prices to estimated recoverable reserves.
General and Administrative Expenses. General and administrative ("G&A") costs increased by 33% during 1998 to $5.2 million when compared to the $3.9 million incurred in 1997. The increase is primarily due to the addition of personnel associated with the Coda transaction. The rate per Mcfe for such costs increased from $0.07 in 1997 to $0.08 in 1998. Exploration related G&A expenses for 1998 in the amount of $6.2 million have been capitalized to oil and gas property accounts. The increase of $0.4 million over the 1997 comparable capitalized amount of $5.8 million principally reflects additional personnel costs and seismic activities related to a number of exploration projects.
Interest expense is incurred on $150 million of the 8 7/8% Senior Subordinated Notes due 2007 (the "8 7/8% Notes") issued in September 1997, $109 million of the 10 1/2% Notes assumed in the Coda acquisition in November 1997 and bank debt incurred under the Revolving Credit Facility. Net interest costs incurred for the year 1998 totalled $26.1 million, with approximately $5.1 million of this total capitalized to property accounts.
As a result of the substantial decline in the market value of Chesapeake Energy Corp. ("CHK") securities acquired when Hugoton Energy Corp. ("Hugoton") was merged into CHK, the Company realized a loss of $14.4 million upon disposition of these securities during the first nine months of 1998. In addition, a $9.7 million non-cash impairment provision was recorded to recognize a decline in the value of Big Bear securities currently owned by the Company. See "Liquidity and Capital Resources" for additional details related to the Big Bear investment.
Income (Loss) Before Income Taxes
The Company's reported loss before income tax benefits for the year 1998 was $225.7 million. This compares to a loss of $88.3 million reported in 1997. The 1998 loss is primarily the result of the non-cash ceiling test impairment provisions totalling $229 million ($149 million after-tax) mandated by full-cost accounting rules. The 1997 loss was principally identified with purchase price allocations related to the Coda acquisition which resulted in a required ceiling test provision. Income before income taxes, excluding the effect of the non-cash impairments and purchase accounting provisions, was $3.0 million and $61.7 million for 1998 and 1997, respectively.
Income Taxes
Income tax benefits were recorded for 1998 in the amount of $78.1 million and $31.4 million for 1997 as a result of reported pre-tax losses.
RESULTS OF OPERATIONS -- 1997 COMPARED TO 1996
Revenues
Oil and gas sales revenues for the year 1997 (unhedged) increased 9% to $130.0 million when compared to the $119.7 million realized in 1996. The increase is principally identified with a 63% increase in oil production over the prior year, partially offset by lower prices. In 1997, weighted average oil prices realized (unhedged) totaled $19.28 per barrel, a 9% decline when compared to the $21.30 realized in 1996. The natural gas weighted average prices realized (unhedged) increased 6% from $2.00 in 1996 to $2.11 in 1997. Production volume in 1997 on an Mcfe basis increased 3% to 57,479 MMcfe.
Commodity price risk management activities resulted in a net pre-tax loss of $6.5 million for 1997 which included (1) realized hedging losses of $5.4 million, (2) net realized gains related to non-hedging transactions totaling $8.1 million, (3) net premiums received totaling $5.0 million and (4) a non-cash unrealized gain for mark-to-market accounting of $2.0 million. The impact of such activities on an Mcfe basis amounted to net losses of $0.11 ($0.13 cash losses and a non-cash gain of $0.02) and $0.11 ($0.06 cash gain and a non-cash loss of $0.17) per Mcfe for 1997 and 1996, respectively.
Interest income realized during 1997 was $3.3 million compared to $2.7 million for 1996 due to higher average cash balances principally attributable to the proceeds realized by the Company from the offering of its 8 7/8% Notes completed in September 1997.
Costs and Expenses
Production and Operating Expenses. Production and operating expenses, including associated taxes, totaled $12.8 million in 1997, an increase of 63% over the $7.9 million incurred in the prior year. Operating costs on a Mcfe basis increased 59% to $0.22 per Mcfe compared to $0.14 per Mcfe in 1996. The higher costs are directly associated with new oil wells placed into production during the year, which typically are more costly than gas wells to operate, and one month of Coda's production activity which is primarily secondary oil recovery. A substantial portion of the Company's natural gas production from wells drilled prior to September 1996 in the downdip Giddings Field qualifies for exemption from Texas state production taxes. This exemption will continue for production through August 31, 2001. The state of Louisiana offers a full year exemption from severance taxes for production from oil and gas wells that are returned to service after having been inactive for two or more years or having 30 days or less of production during the past two years.
Depreciation, Depletion and Amortization. DD&A costs related to oil and gas properties, excluding the non-cash ceiling test provision described below, totaled $46.7 million for 1997, a 14% increase over the $40.9 million incurred in the 1996 comparable period. The Company average DD&A rate per Mcfe for 1997 was $0.81 compared to a rate of $0.73 per Mcfe in 1996. The higher rate reflects increased levels of development and exploration drilling activities and higher costs paid for related third party services.
At year end 1997, the Company recorded a non-cash ceiling test provision of $150 million ($97.5 million after tax) based on year end 1997 estimated proved reserves. The ceiling test provision included the effect of the non-cash $101 million SFAS 109 "gross-up" attributable to the Coda acquisition on the Company's full cost pool at December 31, 1997 and the PV10 value of year end 1997 reserves, which were significantly impacted by lower product prices when compared to year end 1996 prices.
General and Administrative Expenses. G&A totaled $3.9 million for 1997, net of capitalized G&A costs directly related to the Company's oil and natural gas exploration and development efforts, a 28% increase over the prior year. The increase reflects the acquisition of Coda and one month of Coda's operations and related expenses. On an Mcfe basis, G&A costs were $0.07 for 1997 and $0.06 for 1996. Exploration related G&A expenses for 1997 in the amount of $5.8 million have been capitalized to oil and gas property accounts. The increase of $2.6 million over the 1996 comparable amount of $3.1 million principally reflects the addition of new personnel recruited to handle the Company's rapidly expanding exploration activities.
Income Before Income Taxes
The Company's pre-tax loss for 1997 was $88.3 million compared to $64.6 million of pre-tax income reported in 1996. The loss is principally the result of the $150 million non-cash ceiling test provision associated with SFAS 109 "gross-up" attributable to the acquisition of Coda and its impact on the full cost pool coupled with lower product prices at December 31, 1997 when compared to the prior year.
Income Taxes
Income tax benefits were recorded for 1997 totaling $31.4 million as a result of the reported pre-tax loss. The provision for taxes in 1996 included a one-time, non-cash charge in the amount of $30.1 million that was required as a result of the Combination which changed the tax status of the Company.
LIQUIDITY AND CAPITAL RESOURCES
General
On March 29, 1996, the Company successfully completed an initial public offering of 6.5 million shares of common stock (the "Offering"). The Offering provided the Company with approximately $113 million net of offering expenses. Proceeds from the Offering were used to repay approximately $35 million of indebtedness
under the Company's previous credit facility, fund capital expenditures and for other general corporate purposes. The remaining proceeds from the Offering, together with cash flows from operations, were used to fund planned capital expenditures, including lease acquisitions, commitments, other working capital requirements and general corporate purposes.
In September 1997, the Company entered into a five-year $150 million Credit Agreement dated September 23, 1997 (the "Credit Facility") with The Chase Manhattan Bank, N.A., as administrative agent (the "Agent") and other lending institutions (the "Banks"). The Credit Facility provides for an aggregate principal amount of revolving loans of up to the lesser of $150 million or the Borrowing Base (as defined) in effect from time to time, which includes a sub-facility from the Agent for letters of credit. The Borrowing Base at December 31, 1998 was set at $150 million with $29.5 million advanced to the Company at that date. The borrowing base is redetermined by the Agent and the Banks semi-annually based upon their usual and customary oil and gas lending criteria as such exist from time to time. In addition, the Company may request two additional redeterminations and the Banks may request one additional redetermination per year.
Indebtedness of the Company under the Credit Facility is secured by a pledge of the capital stock of each of the Company's material subsidiaries.
Indebtedness under the Credit Facility bears interest at a floating rate based (at the Company's option) upon (i) the ABR with respect to ABR Loans or (ii) the Eurodollar Rate (as defined) for one, two, three or six months (or nine or twelve months if available to the Banks) Eurodollar Loans (as defined), plus the Applicable Margin. The ABR is the greater of (i) the Prime Rate (as defined), (ii) the Base CD Rate (as defined) plus 1% or (iii) the Federal Funds Effective Rate (as defined) plus 0.50%. The Applicable Margin for Eurodollar Loans varies from 0.50% to 0.875% depending on the Borrowing Base usage. Borrowing Base usage is determined by a ratio of (i) outstanding Loans (as defined) and letters of credit to (ii) the then effective Borrowing Base. Interest on ABR Loans is payable quarterly in arrears and interest on Eurodollar Loans is payable on the last day of the interest period therefore and, if longer than three months, at three month intervals.
The Company is required to pay to the Banks a commitment fee based on the committed undrawn amount of the lesser of the aggregate commitments or the then effective Borrowing Base during a quarterly period equal to a percent that varies from 0.20% to 0.30% depending on the Borrowing Base usage.
In September 1997, the Company issued $150 million of the 8 7/8% Notes. Interest on the 8 7/8% Notes accrues at the rate of 8 7/8% per annum and is payable semi-annually in arrears on March 15 and September 15 of each year, commencing on March 15, 1998. The 8 7/8% Notes mature on September 15, 2007 unless previously redeemed. Except under limited circumstances, the 8 7/8% Notes are not redeemable at the Company's option prior to September 15, 2002. Thereafter, the 8 7/8% Notes will be subject to redemption at the option of the Company, in whole or in part, at specified redemption prices, plus accrued and unpaid interest, if any, thereon to the applicable redemption date. In addition, upon a change of control (as defined in the indenture pursuant to which the 8 7/8% Notes were issued) the Company is required to offer to redeem the 8 7/8% Notes for cash at 101% of the principal amount, plus accrued and unpaid interest, if any, thereon to the applicable date of repurchase.
The 8 7/8% Notes are general unsecured obligations of the Company and are subordinated in right of payment to all existing and future Senior Debt (as defined in the 8 7/8% Indenture) of the Company, which includes borrowings under the Credit Facility described above. The 8 7/8% Notes rank pari passu in right of payment with any existing or future senior subordinated debt of the Company and rank senior in right of payment to all other subordinated indebtedness of the Company.
In November 1997, the Company completed the acquisition of Coda. The Company paid an aggregate of $324 million including approximately $192 million in cash ($150 million plus a $42 million adjustment for proceeds from the disposition of Taurus Energy Corp. ("Taurus"), a subsidiary of Coda (which occurred on the day prior to closing of the Coda acquisition)), assumption of $110 million of Coda long-term debt outstanding and three year warrants to purchase 1,666,667 shares of Common Stock of the Company at $27.50 per share issued to the holders of the outstanding common stock, preferred stock and options to
purchase common stock of Coda. Concurrently with the closing of the acquisition of Coda, the Company contributed $23 million to Coda that Coda utilized, together with the funds from the disposition of Taurus, to repay all of the debt outstanding under Coda's revolving credit facility (approximately $65 million in principal amount), plus accrued interest thereon, and such credit facility was thereafter terminated. At closing, the Company funded the cash portion of the consideration and the cash contribution to Coda through cash on hand and borrowings of $84 million under its Credit Facility.
On February 25, 1998, the Company merged Coda into Belco and immediately thereafter transferred all of Coda's assets and liabilities, except for Coda's obligations under the 10 1/2% Notes to Belco Energy Corp., a Nevada corporation and a wholly owned subsidiary of the Company. As of December 31, 1998, the Company also had $109 million principal amount outstanding under the 10 1/2% Notes. Interest on the 10 1/2% Notes accrue at the rate of 10 1/2% per annum and is payable semi-annually in arrears on April 1 and October 1 of each year. Except under limited circumstances, the 10 1/2% Notes are not redeemable at the Company's option prior to April 1, 2001. Thereafter the 10 1/2% Notes will be subject to redemption at specified prices, plus accrued and unpaid interest, if any, thereon to the applicable redemption date.
The 10 1/2% Notes are general unsecured obligations of the Company and are subordinated in right of payment to all existing and future Senior Debt (as defined) of the Company, including any bank debt.
The Company entered into interest rate swap agreements converting two long-term debt fixed rate obligations to floating rate obligations as follows:
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(a) Floating rate is redetermined at each six month period following the expiration through September 15, 2007.
The agreements obligate the Company to actually pay the indicated floating rate rather than the original fixed rate. The floating rates are capped at 8 7/8% through September 15, 2001 and at 10% from March 15, 2002 through September 15, 2007 on the 8 7/8% Notes and capped at 10 1/2% through October 1, 1999 and 11.625% from April 1, 2000 through April 1, 2003 on the 10 1/2% Notes. The agreements reduced the Company's 1998 interest expense by approximately $1 million.
On March 10, 1998 the Company completed the sale of 4.37 million shares of its 6 1/2% Preferred Stock. The Preferred Stock has a liquidation preference of $25 per share and is convertible at the option of the holder into shares of the Company's Common Stock at an initial conversion rate of 1.1292 shares of Common Stock for each share of Preferred Stock, equivalent to a conversion price of $22.14 per share of Common Stock. The Company received net proceeds from the sale of the Preferred Stock of $105.1 million, which was used to pay down bank indebtedness.
On June 12, 1998, the Company, through its wholly-owned Canadian subsidiary, purchased approximately $10.5 million of 5% Convertible Preferred Stock of Big Bear, a Canadian oil and gas company, at approximately $0.85 per share with each share convertible into one common share of Big Bear. The Company was also issued approximately $120 million of Special Acquisition Warrants at a price of approximately $0.72 per warrant. In connection with the issuance of the Special Acquisition Warrants, the Company deposited a $60 million letter of credit and 3,436,000 shares of the Company's common stock into an escrow account. On November 10, 1998, the Company executed a restructuring agreement whereby (i) the Company agreed to convert the Big Bear 5% Convertible Preferred Stock into 21,428,571 shares of Big Bear Common Stock at a conversion price of approximately $0.50 per share (reduced from $0.85 per share), (ii) the Special Acquisition Warrants were canceled, (iii) the Belco representatives resigned from Big Bear's Board of Directors, (iv) the $60 million letter of credit was canceled, and (v) the 3,436,000 shares of Company common stock held in the escrow account were returned to the Company and designated as unissued. The
restructuring agreement closed on January 22, 1999. Additionally, following the acquisition of Blue Range Resource Corporation by Big Bear in December 1998 through the issuance of 381,689,000 shares of Big Bear common stock, directors of Big Bear determined that an 11 to 1 reverse split of Big Bear Common Shares would be in the corporation's best interests. The proposed Big Bear reverse split received the required approvals and Belco, through its wholly-owned Canadian subsidiary, now owns 1,948,052 common shares or approximately 4.6% ownership in Big Bear.
In February 1998, the Company acquired properties consisting of approximately 65 Bcfe of long-lived reserves in the Permian Basin of west Texas from EnerVest Texoma Acquisition L.P. for $37.3 million in cash.
In November 1998, the Company acquired approximately 20 Bcfe of long-lived reserves on producing properties in Oklahoma and Kansas, as well as certain undeveloped acreage and 3-D seismic data, for approximately $14.8 million.
Cash Flow
Operating cash flow, a measure of performance for exploration and production companies, is generally derived by adjusting net income to eliminate the effects of the non-cash components included in the net income calculation such as depreciation, depletion and amortization expense, provision for deferred income taxes, ceiling test provisions, and the non-cash effects of investing and commodity price risk management activities. Operating cash flow, before changes in working capital, was approximately $72.1 and $107.3 million for the years 1998 and 1997, respectively. The Company had working capital of $14.8 million as of December 31, 1998, a decrease of $22.0 million from the $36.8 million available as of December 31, 1997.
Capital Expenditures
For 1998, the Company incurred capital expenditures in the amount of $133.1 million, including property acquisitions totalling $52.2 million.
The Company intends to fund its future capital expenditures, commitments and working capital requirements through cash flows from operations, borrowings under the Credit Facility or other potential financings. The Company has a preliminary 1999 capital expenditure budget of approximately $75 million, with $25 million allocated to potential acquisitions. If there are changes in oil and natural gas prices, however, that correspondingly affect cash flows and the Borrowing Base under the Credit Facility, the Company has the discretion and ability to adjust its capital budget. The Company believes that it will have sufficient capital resources and liquidity to fund its capital expenditures and meet all of its financial obligations as they come due.
On December 15, 1998, the Company's Board of Directors authorized the purchase from time to time, in the open market or in privately negotiated transactions, shares of its Common and 6 1/2% Convertible Preferred Stock, in an aggregate amount not to exceed $10 million.
Commodity Price Risk Management Transactions
Certain of the Company's commodity price risk management arrangements require the Company to deliver cash collateral or other assurances of performance to the counterparties in the event that the Company's payment obligations with respect to its commodity price risk management transactions exceed certain levels.
With the primary objective of achieving more predictable revenues and cash flows and reducing the exposure to fluctuations in oil and natural gas prices, the Company has entered into commodity price risk management transactions of various kinds with respect to both oil and natural gas. While the use of certain of these price risk management arrangements limits the downside risk of adverse price movements, it may also limit future revenues from favorable price movements. The Company engages in transactions such as selling covered calls or straddles which are marked-to-market at the end of the relevant accounting period. Since the futures market historically has been highly volatile, these fluctuations may cause significant impact on the results of any given accounting period. The Company has entered into price risk management transactions
with respect to a substantial portion of its estimated production for 1999 and lesser portions of its estimated production thereafter. The Company continues to evaluate whether to enter into additional price risk management transactions for future years. In addition, the Company may determine from time to time to unwind its then existing price risk management positions as part of its price risk management strategy.
OTHER
Environmental Matters
The Company's operations are subject to various federal, state and local laws and regulations relating to the protection of the environment, which have become increasingly stringent. The Company believes its current operations are in material compliance with current environmental laws and regulations. There are no environmental claims pending or, to the Company's knowledge, threatened against the Company. There can be no assurance, however, that current regulatory requirements will not change, currently unforeseen environmental incidents will not occur or past noncompliance with environmental laws will not be discovered on the Company's properties.
Year 2000 Compliance
The year 2000 issue concerns the potential inability of information technology and non-information technology systems and processes to properly recognize and process date-sensitive information before, during, and after December 31, 1999.
The Company has a variety of operating systems, computer software program applications, computer hardware equipment and other equipment with embedded electronic circuits, including applications used in the Company's financial business systems, field operations, and administrative functions (collectively, the "systems").
Members of the Company's management group and financial department personnel have oversight of the information systems and personnel charged with implementing the Company's year 2000 compliance program.
The Company has upgraded hardware and software over the past year and believes that its internal financial and most of the operational systems are currently year 2000 compliant. The Company does not separately track the costs associated with the year 2000 compliance effort, as they have not been material and, further, no projects with any significant impact to the Company's operations have been deferred due to the year 2000 compliance effort. To date, the Company estimates that it has incurred less than $100,000 in upgrading a limited amount of hardware and does not expect to incur any significant additional cost in becoming year 2000 compliant. The Company does not know whether its significant vendors' and customers' systems are yet fully year 2000 compliant. If they are not, such failure could partially affect the Company's ability to sell its oil and gas and receive related payments. In addition, there could be disruptions in getting certain vendors to provide supplies and/or services in support of the Company's operations. While this is the most likely worst case scenario, the Company believes that its significant vendors and customers will be year 2000 compliant before that critical date.
Additionally, the Company fully understands that there are risks associated with year 2000 issues that it cannot directly control, primarily the readiness of its key suppliers and customers. The Company has had contact with a significant number of its customers and vendors and furnished information about how it is addressing the year 2000 issue. The Company is presently investigating contingency strategies primarily with existing internal resources in the event of any third party or internal system failure. Contingency plans contemplated include the use of alternative hardware and software vendors and customers as appropriate in the event that a presently unforeseen failure of a key vendor or customer is burdened with some non-controllable year 2000 compliance related failure.
The Company presently expects that its financial and related information systems, operations systems and other essential functions will be ready for the year 2000 transition, and that year 2000 issues would not have a material effect on the Company's business or financial condition.
New Accounting Standards
In June 1998, the Financial Accounting Standards Board issued Statement No. 133, Accounting for Derivative Instruments and Hedging Activities ("FAS 133"). FAS 133 is effective for fiscal years beginning after June 15, 1999. FAS 133 requires all derivatives to be recorded on the balance sheet at fair value and established "special accounting" for the following three different types of hedges: hedges of changes in the fair value of assets, liabilities, or firm commitments (referred to as fair value hedges); hedges of the variable cash flows of forecasted transactions (cash flow hedges); and hedges of foreign currency exposures of net investments in foreign operations. Though the accounting treatment and criteria for each of the three types of hedges is unique, they all result in offsetting changes in fair values or cash flows of both the hedge and the hedged item being recognized in earnings in the same period with no net impact on reported earnings. Changes in fair value of derivatives that do not meet the criteria of one of these three categories of hedges are included in income and reported as either gain or loss for the current period. Transition adjustments resulting from adoption must be recognized in income and comprehensive income, as appropriate, as a cumulative effect of an accounting change. Belco has not yet determined the effect of total compliance, but it is not expected to materially impact the financial statements of the Company.
ITEM 7A
ITEM 7A -- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's market risk exposures relate primarily to commodity prices, interest rates and marketable equity securities. The Company enters into various transactions involving commodity price risk management activities involving a variety of derivatives instruments to, in effect, hedge the impact of crude oil and natural gas price fluctuations. In addition, the Company entered into interest rate swap agreements to reduce current interest burdens related to its fixed long-term debt. The derivatives instruments are generally put in place to limit the risk of adverse oil and natural gas price movements, however, such instruments can limit future gains resulting from upward favorable oil and natural gas price movements. Recognition of both realized and unrealized gains or losses are reported currently in the Company's financial statements as required by existing generally accepted accounting principles. The cash flow impact of all derivative related transactions is reflected as cash flows from operating activities.
As a result of certain commodity price risk management transactions in effect for crude oil and natural gas, the Company's average realized crude oil and natural gas pricing has been impacted as follows:
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Note: All amounts approximate.
As of December 31, 1998, the Company had substantial derivative financial instruments outstanding and related to its price risk management program. See "Footnote 7" to the consolidated financial statements of the Company "Commodity Price Risk Management Activities and Fair Value of Financial Instruments" for complete details on the Company's oil and gas related transactions in effect as of December 31, 1998. Transactions subsequent to year-end 1998 were not significant.
The table below provides information related to the Company's interest rate swaps on long-term debt obligations. For interest rate swaps, the table presents notional amounts and approximate weighted average interest rates by contractual maturity dates. Notional amounts are used to calculate the contractual payments to be exchanged under the agreements in place.
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(1) Notes mature 2007
(2) Notes mature 2006
ITEM 8
ITEM 8 -- CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See the Consolidated Financial Statements and supplementary data listed in the accompanying Index to Financial Statements and Financial Statement Schedules on page herein. Information required by other schedules required under Regulation S-X is either not applicable or is included in the financial statements or notes thereto.
ITEM 9
ITEM 9 -- CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10
ITEM 10 -- DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information regarding Directors and Executive Officers required under Item 10 will be contained in the definitive Proxy Statement of the Company for its 1999 Annual Meeting of Shareholders (the "Proxy Statement") under the headings "Election of Directors", "Executive Compensation and Other Information" and "Section 16(a) Beneficial Ownership Compliance" and is incorporated herein by reference. The Proxy Statement will be filed pursuant to Regulation 14A with the Securities and Exchange Commission not later than 120 days after December 31, 1998. For information regarding Executive Officers not appearing in the Proxy Statement, see "Business -- Executive Officers of the Registrant".
ITEM 11
ITEM 11 -- EXECUTIVE COMPENSATION
The information required under Item 11 will be contained in the Proxy Statement under the heading "Executive Compensation and Other Information" and is incorporated herein by reference.
ITEM 12
ITEM 12 -- SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required under Item 12 will be contained in the Proxy Statement under the heading "Security Ownership of Management and Certain Beneficial Owners" and is incorporated herein by reference.
ITEM 13
ITEM 13 -- CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required under Item 13 will be contained in the Proxy Statement under the headings "Transactions with Management and Certain Shareholders" and "Executive Compensation and Other Information" and is incorporated herein by reference.
PART IV
ITEM 14
ITEM 14 -- EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
1. Financial Statements: See Index to Consolidated Financial Statements and Schedules immediately following the signature page of this report.
2. Financial Statement Schedules: See Index to Consolidated Financial Statements and Schedules immediately following the signature page of this report.
3. Exhibits: The following documents are filed as exhibits to this report.
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* Filed herewith
Certain of the exhibits to this filing contain schedules which have been omitted in accordance with applicable regulations. The Registrant undertakes to furnish supplementally a copy of any omitted schedule to the Securities and Exchange Commission upon request.
(b) Reports on Form 8-K.
Current Report on Form 8-K dated November 10, 1998.
Item 5. Other Events
Item 7. Financial Statements, Pro Forma Financial Information and Exhibits
(a) Financial Statements of Business Acquired.
Not applicable.
(b) Pro Forma Financial Information
Not applicable.
(c) Exhibits.
99.1 Press release dated November 11, 1998.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
BELCO OIL & GAS CORP.
By: /s/ LAURENCE D. BELFER ---------------------------------- Laurence D. Belfer Vice-Chairman, Chief Operating Officer and Director
Date: March 26, 1999
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
BELCO OIL & GAS CORP. AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
CONSOLIDATED FINANCIAL STATEMENT SCHEDULES
None
Financial Statement schedules pursuant to regulations of the Securities and Exchange Commission have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company's financial statements and related notes.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Belco Oil & Gas Corp.:
We have audited the accompanying consolidated balance sheets of Belco Oil & Gas Corp. (a Nevada Corporation) and subsidiaries as of December 31, 1998 and 1997, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1998. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Belco Oil & Gas Corp. and subsidiaries as of December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Dallas, Texas March 4, 1999
BELCO OIL & GAS CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
The accompanying notes to consolidated financial statements are an integral part of these statements.
BELCO OIL & GAS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
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(a) Does not include a one-time non-cash deferred tax charge of $30.1 million recognized as a result of the Combination consummated on March 29, 1996. See Note 1. Historical basic and diluted net income per share, including the deferred tax charge, was $0.61 for the year ended December 31, 1996. For 1996, the amounts present the Company as if it was a taxable corporation for the year then ended and earnings per share are based on the average number of shares outstanding assuming the shares issued in connection with the Combination were outstanding for the entire year.
The accompanying notes to consolidated financial statements are an integral part of these statements.
BELCO OIL & GAS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (IN THOUSANDS)
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(a) Includes a one-time non-cash deferred tax charge of $30.1 million recognized as a result of the Combination consummated on March 29, 1996. See Note 1.
(b) Represents a reclassification adjustment for $2.0 million gross ($1.32 million net of tax) unrealized loss recognized in comprehensive income in 1997, but recognized in net income during 1998.
The accompanying notes to consolidated financial statements are an integral part of these statements.
BELCO OIL & GAS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
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(a) Prior to March 29, 1996, the earnings of the Company were not subject to corporate income taxes as the Company, prior to the Combination, was a group of non-taxpaying entities. See Note 1.
The accompanying notes to consolidated financial statements are an integral part of these statements.
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- ORGANIZATION AND NATURE OF OPERATIONS
ORGANIZATION
Belco Oil & Gas Corp. was organized as a Nevada corporation in January 1996 in connection with the combination of assets (the "Combination") consisting of ownership interests (the "Combined Assets") in certain entities and direct interests in oil and gas properties and certain hedge transactions owned by the predecessors and entities related thereto. On March 29, 1996, Belco Oil & Gas Corp. completed its initial public offering (the "Offering") issuing 6,500,000 shares of Common Stock at $19 per share. Belco Oil & Gas Corp. and the owners of the Combined Assets entered into an Exchange and Subscription Agreement and Plan of Reorganization dated as of January 1, 1996 (the "Exchange Agreement") that provided for the issuance by the Company of an aggregate of 25,000,000 shares of Common Stock to such owners in exchange for the Combined Assets on March 29, 1996, the date the Offering closed. The owners of the Combined Assets received shares of Common Stock proportionate to the value of the Combined Assets underlying their ownership interests in the predecessors and the direct interests.
The Combination was accounted for as a reorganization of entities under common control because of the common control of the stockholders of Belco Oil & Gas Corp. and by virtue of their direct ownership of the entities and interests exchanged. Accordingly, the net assets acquired in the Combination have been recorded at the historical cost basis of the affiliated predecessor owners.
Belco Oil & Gas Corp. and its subsidiaries and prior to March 29, 1996, the combined predecessor entities, are referred to herein as "Belco" or the "Company".
NATURE OF CURRENT OPERATIONS
The Company is an independent energy company engaged in the exploration, development and production of natural gas and oil. The Company operates in this single industry segment, and all operations are presently conducted in the United States. The Company's operations are focused in four core areas including the Permian Basin (west Texas), the Mid-Continent (Oklahoma, north Texas and Kansas), the Rocky Mountains (Wyoming), and the Austin Chalk (Texas and Louisiana).
Substantially all of the Company's production is sold under market-sensitive contracts. The Company's revenue, profitability and future rate of growth are substantially dependent upon the price of, and demand for, oil, natural gas and natural gas liquids. Prices for oil and natural gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond the control of the Company. These factors include the level of consumer product demand, weather conditions, domestic and foreign governmental regulations, the price and availability of alternative fuels, political conditions in the Middle East, the foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. With the objective of reducing price risk, the Company has entered into hedging and related price risk management transactions with respect to a significant amount of its expected future production (See Note 7).
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements for the two years ended December 31, 1998 include the accounts of the Company and its wholly-owned subsidiaries including one month of Coda operations for 1997. The Company's interests in the Moxa Arch investment programs (the 1992 Moxa Arch Drilling Program, the 1993 Moxa Arch Drilling Program, the Moxa Arch 1992 Offset Drilling Program and the Moxa Arch 1993 Offset Drilling Program) (collectively, the "Programs") are accounted for using the proportionate consolidation method of accounting for investments in oil and gas property interests, whereby the Company's share of each program's assets, liabilities, revenues and expenses is included in the appropriate accounts of the consolidated
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
financial statements. All material intercompany balances and transactions have been eliminated. Through March 1996, the combined accounts were prepared using the historical costs and results of operations of the combined predecessor entities as if such entities had always been combined.
CASH EQUIVALENTS
The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
PROPERTY AND EQUIPMENT
The Company follows the full-cost method of accounting for oil and gas properties. Accordingly, all costs associated with acquisition, exploration and development of oil and gas reserves, including directly related internal costs, are capitalized. The Company capitalized $6,054,000, $5,769,000 and $3,065,000 of related internal costs during 1998, 1997 and 1996, respectively.
Oil and gas properties are amortized on the unit-of-production method using estimates of proved reserve quantities. Investments in unproved properties are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. The amortizable base includes estimated future development costs and, where significant, dismantlement, restoration and abandonment costs, net of estimated salvage values.
In addition, the capitalization costs of proved oil and gas properties are subject to a "ceiling test," which limits such costs to the estimated present value net of related tax effects, discounted at a 10 percent interest rate, of future net cash flows from proved reserves, based on current economic and operating conditions (PV10). If capitalized costs exceed this limit, the excess is charged to depreciation, depletion and amortization.
Based on the Company's year end 1998 estimated proved reserves, the Company recorded in the fourth quarter ended December 31, 1998 a non-cash impairment of oil and gas properties of approximately $75 million ($48.8 million after tax). The impairment provision is in addition to similar provisions booked at the end of the first and second quarters of 1998 due to low commodity prices. The 1997 provision included the effect of the non-cash $101 million Statement of Financial Accounting Standards ("SFAS") No. 109 deferred tax "gross up" attributable to the acquisition of Coda on the Company's full cost pool at December 31, 1997 and PV10 value of year end 1997 reserves, which were significantly also impacted by lower product prices when compared to year end 1996 prices.
Sales and other dispositions of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless significant reserves are involved. Abandonments of properties are accounted for as adjustments of capitalized costs with no loss recognized.
Buildings, equipment and gas processing facilities are depreciated on a straight-line basis over the estimated useful lives of the assets, which range from three to 20 years.
MANAGEMENT FEES
The Company manages three investment programs, which were formed during 1992-1994 to acquire and develop interests in certain drilling prospects located in the Moxa Arch trend in Wyoming. The Company offered, to certain qualified investors, the opportunity to invest in the prospects through participation in the Programs. In return for its management activities on behalf of the Programs, the Company earns an annual management fee of one percent of committed capital.
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
After elimination of management fees received from affiliated entities, including predecessor owners, the Company earned management fees totaling $305,000, $297,000 and $583,000 during 1998, 1997 and 1996, respectively.
CAPITALIZATION OF INTEREST
Interest costs related to the acquisition and development of unproved properties are capitalized to oil and gas properties. Interest costs capitalized for the years ended December 31, 1998, 1997 and 1996, totaled $5,123,000, $3,742,000 and $434,000, respectively.
ACCOUNTING FOR COMMODITY PRICE RISK MANAGEMENT ACTIVITIES
The Company periodically engages in price risk management activities in order to manage its exposure to oil and gas price volatility. Commodity derivatives contracts, which are usually placed with major financial institutions that the Company believes are minimal credit risks, may take the form of futures contracts, swaps or options. The oil and gas reference prices upon which these commodity derivatives contracts are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company. Gains and losses related to qualifying hedges of the Company's oil and gas production are deferred and are recognized as revenues as the associated production occurs. In the event of a loss of correlation between changes in oil and gas reference prices under a commodity derivatives contract and actual oil and gas prices, a gain or loss is recognized currently to the extent the commodity derivatives has not offset changes in actual oil and gas prices.
Estimates of future cash flows applicable to oil and gas commodity hedges are reflected in future cash flows from proved reserves in the supplemental oil and gas disclosures, with such estimates based on prices in effect as of the date of the reserve report (See Note 14).
Transactions that do not qualify for hedge accounting are accounted for using the mark-to-market method. Under such method, the financial instruments are reflected at market value at the end of the period with resulting unrealized gains and losses recorded as assets and liabilities in the consolidated financial statements. Changes in the market value of outstanding financial instruments are recognized as a gain or loss in the period of change.
In June 1998, the Financial Accounting Standards Board issued Statement No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("FAS 133"). FAS 133 is effective for fiscal years beginning after June 15, 1999. FAS 133 requires all derivatives to be recorded on the balance sheet at fair value and established "special accounting" for the following three different types of hedges: hedges of changes in the fair value of assets, liabilities, or firm commitments (referred to as fair value hedges); hedges of the variable cash flows of forecasted transactions (cash flow hedges); and hedges of foreign currency exposures of net investments in foreign operations. Though the accounting treatment and criteria for each of the three types of hedges is unique, they all result in offsetting changes in fair values or cash flows of both the hedge and the hedged item being recognized in earnings in the same period with no net impact on reported earnings. Changes in fair value of derivatives that do not meet the criteria of one of these three categories of hedges are included in income and reported as either gain or loss for the current period. Transition adjustments resulting from adoption must be recognized in income and comprehensive income, as appropriate, as a cumulative effect of an accounting change. Belco has not yet determined the effect of total compliance, but it is not expected to materially impact the financial statements of the Company.
GAS BALANCING/REVENUE RECOGNITION
The Company uses the sales method to account for natural gas imbalances. Under the sales method, the Company recognizes revenues based on the amount of gas sold to purchasers, which may differ from the
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
amounts to which the Company is entitled based on its interests in the properties. However, revenue is deferred and a liability is recorded for those properties where production sold by the Company exceeds its entitled share of remaining natural gas reserves. Gas balancing obligations as of December 31, 1998 and 1997 were not significant.
INCOME TAXES
The Company accounts for income taxes under the provisions of SFAS No. 109 -- "Accounting for Income Taxes," which provides for an asset and liability approach for accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences, using currently enacted tax laws, attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets are reduced by a valuation allowance when, based upon management's estimate, it is more likely than not that a portion of the deferred tax assets will not be realized in a future period.
The earnings for the three months ended March 29, 1996 were not subject to corporate income taxes as the Company through that date was a combination of non-taxpaying entities, including Subchapter S, limited liability corporations, partnership and joint venture entities and individual interests. Accordingly, earnings were directly taxable to the individual owners. The pro forma provision for income tax for 1996 is an estimate of the Company's income taxes that would have been provided in accordance with SFAS No. 109, if the Company were a taxable entity during the period (See Note 6).
NET INCOME (LOSS) PER COMMON SHARE
Basic and diluted net income (loss) per common share have been computed in accordance with SFAS No. 128, "Earnings Per Share," which the Company adopted at year end 1997. Net income per share amounts for prior periods have been restated to conform with the provisions of the new standard. Basic net income per common share is computed by dividing income available to common shareholders, after the payment of dividends to preferred stockholders, by the weighted average number of common shares outstanding for the periods. Diluted net income per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Calculations of basic and diluted net income (loss) per common share are illustrated in Note 12.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimated fair value of oil and gas commodity price risk management contracts and the estimate of proved oil and gas reserve volumes and the related discounted future net cash flows therefrom (See Notes 7 and 14).
NOTE 3 -- ACQUISITION OF CODA ENERGY, INC.
On November 26, 1997, Belco completed the Merger (the "Merger") of its subsidiary Belco Acquisition Sub, Inc. ("Belco Sub"), a Delaware corporation with and into Coda Energy, Inc., a Delaware corporation. The Merger was effected pursuant to the terms of an Agreement and Plan of Merger, dated as of October 31, 1997, by and among Belco, Belco Sub and Coda. In connection with the Merger, Belco paid $324 million, including $214 million in cash, assumption of $110 million in debt (face value), and the issuance of warrants to purchase 1,666,667 shares of common stock, par value $0.01 per share, of Belco (the "Belco Common Stock") to the holders of the outstanding common stock, preferred stock and options to purchase common
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
stock of Coda. The warrants are exercisable for a period of three years commencing on November 26, 1998 at an exercise price of $27.50 per share. The warrant exercise price and the number of shares of Belco Common Stock that may be issued pursuant to the exercise of the warrants will be adjusted to prevent dilution in the event of stock splits, stock dividends and certain other events affecting the capital structure of Belco.
The acquisition of Coda has been accounted for using the purchase method of accounting and has been included in the financial statements of the Company since the date of acquisition. The purchase price has been allocated to the assets purchased and the liabilities assumed based upon the fair values on the date of acquisition as follows (in thousands):
NOTE 4 -- LONG TERM DEBT
Long term debt consists of the following at December 31, 1998 and 1997 (in thousands):
In September, 1997 the Company entered into a five-year $150 million Credit Agreement dated September 23, 1997 (as amended, the "Credit Facility") with The Chase Manhattan Bank, N.A., as administrative agent (the "Agent") and other lending institutions (the "Banks"). The Credit Facility provides for an aggregate principal amount of revolving loans of up to the lesser of $150 million or the Borrowing Base (as defined) as in effect from time to time, which includes a subfacility from the Agent for letters of credit of up to $25 million. The Borrowing Base at December 31, 1998 was set at $150 million with $29.5 million advanced to the Company at that date. The borrowing base will be redetermined by the Agent and the Banks semi-annually, determined solely at their discretion, predicated on the Company's oil and gas reserve value. In addition, the Company may request two additional redeterminations and the Banks may request one additional redetermination per year. During 1998, the weighted average interest rate was approximately 6%.
Indebtedness of the Company under the Credit Facility is secured by a pledge of the capital stock of each of the Company's material subsidiaries. Covenants contained in the Credit Facility require the Company to maintain minimum Interest Coverage Ratio (3:1), Current Ratio (1:1) and Leverage Ratio (Indebtedness to EBITDA) not to exceed (3.5:1). The Company and its subsidiaries may not incur any indebtedness other than indebtedness falling within the enumerated exceptions contained in the Credit Facility. In addition, the
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Company's various debt instruments contain certain restrictive covenants that, among other things, limit the ability of the Company to pay dividends.
Indebtedness under the Credit Facility bears interest at a floating rate based (at the Company's option) upon (i) the ABR (as defined below) with respect to ABR Loans or (ii) the Eurodollar Rate for one, two, three or six months (or nine or twelve months if available to the Banks) with respect to Eurodollar Loans, plus the Applicable Margin. The ABR is the greater of (i) the Prime Rate, (ii) the Base CD Rate plus 1% or (iii) the Federal Funds Effective Rate plus 0.50%. The Applicable Margin for Eurodollar Loans varies from 0.50% to 0.875% depending on the Borrowing Base usage. Borrowing Base usage is determined by a ratio of (i) outstanding Loans and letters of credit to (ii) the then effective Borrowing Base. Interest on ABR Loans will be payable quarterly in arrears and interest on Eurodollar Loans is payable on the last day of the interest period therefore and, if longer than three months, at three month intervals.
The Company is required to pay to the Banks a commitment fee based on the committed undrawn amount of the lesser of the aggregate commitments or the then effective Borrowing Base during a quarterly period equal to a percent that varies from 0.20% to 0.30% depending on the Borrowing Base usage.
In September 1997, the Company issued $150 million of the 8 7/8% Notes. Interest accrues at the rate of 8 7/8% per annum and is payable semi-annually in arrears on March 15 and September 15 of each year, commencing on March 15, 1998. The 8 7/8% Notes mature on September 15, 2007 unless previously redeemed. Except under limited circumstances, the 8 7/8% Notes are not redeemable at the Company's option prior to September 15, 2002. Thereafter, the 8 7/8% Notes will be subject to redemption at the option of the Company, in whole or in part, at specified redemption prices, plus accrued and unpaid interest, if any, thereon to the applicable redemption date. In addition, upon a change of control (as defined in the indenture pursuant to which the 8 7/8% Notes were issued (the "8 7/8% Indenture")) the Company is required to offer and redeem the 8 7/8% Notes for cash at 101% of the principal amount, plus accrued and unpaid interest, if any, thereon to the applicable date of repurchase.
The 8 7/8% Notes are general unsecured obligations of the Company and are subordinated in right of payment to all existing and future senior debt (as defined in the 8 7/8% Indenture) of the Company, which includes borrowings under the Credit Facility described above. The 8 7/8% Notes rank pari passu in right of payment with any existing or future senior subordinated debt of the Company and rank senior in right of payment to all other subordinated indebtedness of the Company.
As of December 31, 1998, the Company had outstanding $109 million face value of the 10 1/2% Notes. The debt was assumed in connection with the acquisition of Coda in 1997 and was recorded at $117.1 million, including premium, reflecting the fair value at the date of acquisition. The 10 1/2% Notes bear interest at an annual rate of 10 1/2% payable semiannually in arrears on April 1 and October 1 of each year. The Notes are general, unsecured obligations of the Company, are subordinated in right of payment to all Senior Debt (as defined in the Indenture governing the 10 1/2% Notes) of the Company, and are senior in right of payment to all future subordinated debt of the Company. On February 25, 1998, the Company merged Coda into Belco and Belco assumed the obligations under the Coda Indenture. Effective with the merger, the 10 1/2% Notes became pari passu in right of payment with the 8 7/8% Notes.
The 10 1/2% Notes were issued pursuant to an Indenture, which contains certain covenants that, among other things, limit the ability of Coda and its restricted subsidiaries (as defined in the Indenture) to incur additional indebtedness and issue Disqualified Stock (as defined in the Indenture), pay dividends, make distributions, make investments, make certain other restricted payments, enter into certain transactions with affiliates, dispose of certain assets, incur liens securing pari passu or subordinated indebtedness of the Company and engage in mergers and consolidations.
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The 10 1/2% Notes are not redeemable by the Company prior to April 1, 2001. After April 1, 2001, the 10 1/2% Notes will be subject to redemption at the option of the Company, in whole or in part, at the redemption prices set forth in the Indenture, plus accrued and unpaid interest thereon to the applicable redemption date. In addition, until March 12, 1999, up to $27.5 million in aggregate principal amount of Notes are redeemable, at the option of the Company on any one or more occasions from the net proceeds of an offering of common equity, at a price of 110.5% of the aggregate principal amount of the 10 1/2% Notes, together with accrued and unpaid interest thereon to the date of the redemption; provided, however, that at least $82.5 million in aggregate principal amount of Notes must remain outstanding immediately after the occurrence of such redemption; provided, further, that any such redemption shall occur within 75 days of the date of the closing of such offering of common equity.
In December 1997, the Company entered into two interest rate swap agreements converting two fixed rate obligations to floating rate obligations. The first agreement covers $100 million of 8 7/8% long-term debt (comparable to the interest rate on the 8 7/8% Notes) and obligates the Company to pay an initial rate of 8.175% through September 15, 1998. Thereafter, the rate is redetermined at each six month period through September 15, 2007. The floating rates are capped at 8 7/8% through September 15, 2001 and at 10% from March 15, 2002 through September 15, 2007. The second agreement covers $110 million of 10 1/2% long-term debt (comparable to the interest rate on the 10 1/2% Notes) and obligates the Company to pay an initial rate of 9.8881% through April 1, 1998. Thereafter, the rate is redetermined at each six month period through 2003. Floating rates on this agreement are capped at 10 1/2% through October 1, 1999 and 11.625% from April 1, 2000 through April 1, 2003.
NOTE 5 -- RELATED-PARTY TRANSACTIONS
The Company's executive offices are leased from its Chairman and $250,000 was paid under such lease in 1998, 1997 and 1996. The Company's remaining commitment related to the office space and service charge is $250,000 per year (adjusted for annual changes in the CPI) through 1999. Management believes the fee compares favorably to the terms which might have been available from a non-affiliated party.
Certain employees of the Company had an ownership interest in certain oil and gas properties held by the Company as of December 31, 1995. The Company had receivables of $894,000 and $775,000 as of December 31, 1998 and 1997, respectively, and related to amounts loaned to employees in connection with purchases of oil and gas interests from such employees. The notes receivable have been recorded as a reduction of equity in the consolidated balance sheets, as such interests were exchanged for Common Stock in the Combination (See Note 1).
NOTE 6 -- INCOME TAXES
Prior to March 29, 1996, the earnings of the Company were not subject to corporate income taxes as the Company, prior to the Combination, was a combination of non-taxpaying entities, including Subchapter S, limited liability corporations, partnership and joint venture entities and individual interests. Accordingly, taxable earnings were directly taxable to the individual owners through the date of the Combination. As a result of the Combination consummated on March 29, 1996, the Company became a taxpaying entity and recorded, in the first quarter of 1996, a $30.1 million one-time, non-cash charge to earnings to establish a deferred tax liability (discussed further below). The historical provision for income taxes for the year ended December 31, 1996 includes the one-time charge. The provision for income taxes reflected in the Consolidated Statements of Operations for the year ended December 31, 1996 has been presented to reflect the Company's income taxes under the assumption that the Company was a taxpaying entity since its inception.
Although the effective date of the Exchange Agreement is January 1, 1996, each owner of the Combined Assets was required under existing federal income tax rules and regulations to include in its taxable income, for all periods ended on the date of or prior to the completion of the Combination (March 29, 1996), its
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
allocable portion of the taxable income attributable to the Combined Assets and was entitled to all tax benefits related to the Combined Assets through the completion of the Combination on March 29, 1996.
Total provision (benefit) for income taxes consists of the following:
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(1) Provision includes combination related adjustments and excludes a one time non-cash deferred tax charge of $30.1 million.
The differences between the statutory federal income taxes and the Company's effective taxes is summarized as follows (in thousands):
The principal components of the Company's net deferred income tax liability at December 31, 1998 are as follows:
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As a result of the acquisition of Coda, the Company succeeded to net operating loss carryforwards ("NOLs") for income tax purposes that expire from 1999 through 2004. Due to a change of ownership (as defined by the Tax Reform Act of 1986) which occurred prior to the acquisition by the Company, the utilization of the Coda NOLs is severely restricted. At December 31, 1998, the Company estimates that approximately $12.0 million of the NOLs is available to offset future income. In addition to the NOLs, at December 31, 1998, the Company has approximately $14.4 million of capital loss carry forwards which may be used to offset capital gains realized over the next five years. A valuation allowance of $2.5 million was established against the capital loss carryforward since this amount is not expected to meet the realization test. The Company also has $0.6 million of alternative minimum tax ("AMT") credit carryovers. AMT credits may be carried forward indefinitely.
SECTION 29 TAX CREDIT
The natural gas production from wells drilled on certain of the Company's properties in the Moxa Arch Trend and Golden Trend Field qualifies for the Section 29 Tax Credit. The Section 29 Tax Credit is an income tax credit against regular federal income tax liability with respect to sales of the Company's production of natural gas produced from tight gas sand formations, subject to a number of limitations. Fuels qualifying for the Section 29 Tax Credit must be produced from a well drilled or a facility placed in service after November 5, 1990 and before January 1, 1993, and be sold before January 1, 2003.
The basic credit, which is currently approximately $0.52 per MMBtu of natural gas produced from tight sand reservoirs and approximately $1.05 per MMBtu of natural gas produced from Devonian Shale, is computed by reference to the price of crude oil and is phased out as the price of oil exceeds $23.50 in 1979 dollars (as adjusted for inflation) with complete phaseout if such price exceeds $29.50 in 1979 dollars (as adjusted for inflation). Under this formula, the commencement of phaseout would be triggered if the average price for crude oil rose above approximately $48 per Bbl in current dollars. The Company estimates that it generated approximately $0.7 million of Section 29 Tax Credits in 1998. The Section 29 Tax Credit may not be credited against the alternative minimum tax, but under certain circumstances may be carried over and applied against regular tax liability in future years. Therefore, no assurances can be given that the Company's Section 29 Tax Credits will reduce its federal income tax liability in any particular year. As production from qualified wells decline, the production based tax credit will also decline.
TEXAS SEVERANCE TAX ABATEMENT
Production from natural gas wells that have been certified as tight formations or deep wells by the Texas Railroad Commission ("high cost gas wells") and that are spudded or completed during the period from May 24, 1989 to September 1, 1996 qualify for an exemption from the 7.5% severance tax in Texas on natural gas and natural gas liquids produced by such wells prior to August 31, 2001. The natural gas production from wells drilled on certain of the Company's properties in the Austin Chalk area qualify for this tax reduction. In addition, high cost gas wells that are spudded or completed during the period from September 1, 1996 to August 31, 2002 are entitled to receive a severance tax reduction upon obtaining a high cost gas certification from the Texas Railroad Commission within 180 days after first production. The tax reduction is based on a formula composed of the statewide "median" (as determined by the State of Texas from producer reports) and the producer's actual drilling and completion costs. More expensive wells will receive a greater amount of tax credit. This tax rate reduction remains in effect for 10 years or until the aggregate tax credits received equal 50% of the total drilling and completion costs. The reduction in severance taxes for such wells is reflected as a reduction in oil and gas operating expenses and an increase in the standardized measure of discounted future net cash flows relating to proved oil and gas reserves (See Note 14).
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 7 -- COMMODITY PRICE RISK MANAGEMENT ACTIVITIES AND FAIR VALUE OF FINANCIAL INSTRUMENTS
OIL AND GAS HEDGING TRANSACTIONS
With the objective of achieving more predictable revenues and cash flows and reducing the exposure to fluctuations in gas and oil prices, the Company has entered into hedging transactions of various kinds with respect to both gas and oil. While the use of these hedging arrangements limits the downside risk of adverse price movements, it may also limit future revenues from favorable price movements. As of December 31, 1998, the Company had entered into hedging transactions with respect to a significant portion of its estimated oil and gas production for 1999 and 2000 and to a lesser extent its estimated production for the year 2001. The Company continues to evaluate whether to enter into additional hedging transactions for future years. In addition, the Company may determine from time to time to terminate its then existing hedging positions if market conditions warrant.
The following table and notes thereto cover the Company's pricing and notional volumes on open natural gas and oil commodity hedges as of December 31, 1998:
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(1) For any particular swap transaction, the counterparty is required to make a payment to the Company in the event that the NYMEX Reference Price for any settlement period is less than the swap price for such hedge, and the Company is required to make a payment to the counterparty in the event that the NYMEX Reference Price for any settlement period is greater than the swap price for such hedge.
(2) For any particular collar transaction, the counterparty is required to make a payment to the Company if the average NYMEX Reference Price for the reference period is below the floor price for such transaction, and the Company is required to make payment to the counterparty if the average NYMEX Reference Price is above the ceiling price for such transaction.
(3) In order to close certain commodity price hedge positions, the Company entered into various swap positions where the Company is the fixed-price payer on the swap. In these transactions, the counterparty is required to make a payment to the Company in the event that the NYMEX Reference Price for any settlement period is greater than the swap price, and the Company is required to make a payment to the counterparty in the event that the NYMEX Reference Price for any settlement period is less than the swap price.
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(4) Since most of the Company's gas is sold under spot contracts with reference to Houston Ship Channel prices and substantially all of the Company's hedge transactions are based on the NYMEX Reference Price, the Company has entered into basis swaps that require the counterparty to make a payment to the Company in the event that the average NYMEX Reference Price per MMBtu for a reference period exceeds the average price per MMBtu for gas delivered at the Houston Ship Channel for such reference period by a stated differential, and requires the Company to make a payment to the counterparty in the event that the NYMEX Reference Price exceeds the Houston Ship Channel price by less than a stated differential (or in the event that the Houston Ship Channel price exceeds the NYMEX Reference Price). The Company also sells its Wyoming gas at prices based on the Northwest Pipeline Rocky Mountain Index and has entered into basis swaps that require the counterparty to make a payment to the Company in the event that the NYMEX Reference Price per MMBtu for a reference period exceeds the Northwest Pipeline Rocky Mountain Index Price by more than a stated differential and requires the Company to make a payment to the counterparty in the event that the NYMEX Reference Price exceeds the Northwest Pipeline Rocky Mountain Index Price by less than a stated differential (or in the event that the Northwest Pipeline Rocky Mountain Index Price is greater than the NYMEX Reference Price).
(5) Does not include 3,665, 724, 6,410, and 4,555 thousand MMBtu of swaps in 1999 through 2002, respectively, that are extendable at the election of the counterparty. Also, does not include 3,660 and 10,950 thousand MMBtu of swaps in 2000 and 2001, which price will be fixed upon the close of the NYMEX Reference Price on a specified date less an average of $0.25.
(6) Does not include 1,825 thousand MMBtu of collars in 2000 that are extendable at the election of the counterparty.
(7) Does not include 429, 1,291 and 1,085 thousand Bbls of swaps in 1999 through 2001, respectively that are extendable at the option of the counterparty.
All of the above transactions were carried out in the over-the-counter market, and not on the NYMEX. These financial counterparties all have at least an investment grade credit rating. All of these transactions provide solely for financial settlements related to closing prices on the NYMEX.
A realized hedging gain (loss) of $1.9 million, $(13.1) million and $(0.1) million for 1998, 1997 and 1996, respectively, was included in Commodity Price Risk Management revenues. As of December 31, 1998, the Company had no accrued liabilities settled derivative contracts and as of December 31, 1997, had accrued liabilities of $0.6 million for settled derivative contracts. These amounts are included in Price Risk Management activities as assets or liabilities as appropriate.
NON-HEDGING TRANSACTIONS
As described in Note 2, the Company uses the mark-to-market method of accounting for instruments that do not qualify for hedge accounting. The 1998 results of operations included an aggregate pre-tax gain of $22.8 million related to these activities which included (1) net premiums received totaling $3.9 million and (2) the unrealized gain resulting from net change in the value of the Company's market-to-market portfolio of price risk management activities for the year ended December 31, 1998 of $18.9 million, all included in Commodity Price Risk Management revenues. At December 31, 1998, the Company's consolidated balance sheet reflects $21.1 million and $10.1 million of price risk management assets and liabilities, respectively.
The 1997 results of operations included an aggregate pre-tax gain of $6.6 million related to these activities which included (1) net premiums received totaling $11.5 million and (2) the unrealized loss resulting from net change in the value of the company's mark-to-market portfolio of price risk management activities for the year ended December 31, 1997 of $4.9 million, all included in Commodity Price Risk Management revenues. At December 31, 1997, the Company's consolidated balance sheet reflects $1.7 million and $9.6 million of price risk management assets and liabilities, respectively.
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table and notes thereto cover the Company's pricing and notional volumes on open natural gas and oil financial instruments at December 31, 1998, that do not qualify for hedge accounting:
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(1) A straddle is a combination of a put sold and a call sold. The Company is required to make a payment to the counterparty in the event that the NYMEX Reference Price for any settlement period is greater than the ceiling price or less than the floor price. The Company receives a significant premium upon entering into such contract.
(2) Calls sold or puts sold under written option contracts, in return for a significant premium received by the Company upon initiation of the contract. The Company is required to make a payment to the counterparty in the event that the NYMEX Reference Price for any settlement period is greater than the price of the call sold, or less than the price of the put sold. Conversely, calls or puts bought require the counterparty to make a payment to the company in the event that the NYMEX Reference Price on any settlement period is greater than the call price or less than the put price.
(3) For any particular swap transaction, the counterparty is required to make a payment to the Company in the event that the NYMEX Reference Price for any settlement period is less than the swap price for such instrument and the Company is required to make a payment to the counterparty in the event that the NYMEX Reference Price for any settlement period is greater than the swap price for such instrument. All of these swaps listed will double the volumes swapped when the NYMEX Reference Price is above the swap price for such instrument.
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(4) On these trades, protection of 9,125, 3,650 and 1,825 thousand MMbtu per day disappear in any month that the respective NYMEX Reference Price is below $2.00, $1.80 and $1.70 in 1999.
(5) Does not include 600 and 360 MBbls of oil swaps for 1999 and 2000, respectively, which have tiered pricing at which the swap is canceled when the NYMEX Reference Price falls below $16.50 per Bbl as to 50% of the volumes and $18.00 for the remaining volume and the volumes double when the NYMEX Reference Price rises above $23.05 per Bbl as to 50% of the volumes and above $22.85 for the remaining volume. These provisions either limit price protection beyond a specific level, contain tiered pricing provisions, allow the option to be extended for a period of time, or provide for payment based upon a multiple of the underlying notional volume.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The following table presents the carrying amounts and estimated fair values of the Company's financial instruments at December 31, 1998 and 1997. SFAS No. 107 defines the fair value of a financial instrument as the amount at which the instrument could be exchanged in a current transaction between willing parties.
The following methods and assumptions were used to estimate the fair value of the financial instruments summarized in the above table. The carrying values of trade receivables and trade payables included in the accompanying consolidated balance sheets approximated market value at December 31, 1998 and 1997.
CASH AND CASH EQUIVALENTS
The carrying amounts approximate fair value because of the short maturity of those instruments.
MARKETABLE EQUITY SECURITIES
In June 1997 the Company purchased 2,940,000 shares of common stock of Hugoton Energy Corp. ("Hugoton") at $10.50 per share for a total investment of $30.9 million. At December 31, 1997 a non-cash investment valuation provision in the amount of $2 million was charged to stockholder's equity to reflect the value of this investment at that date. In March 1998, Hugoton was acquired by Chesapeake Energy Corporation ("CHK"). In the merger each share of Hugoton common stock was converted into 1.3 shares of CHK common stock. During 1998 the Company disposed of its holdings in CHK and realized a loss of $14.4 million.
On June 12, 1998, the Company, through its wholly-owned Canadian subsidiary, purchased approximately $10.5 million of 5% Convertible Preferred Stock of Big Bear Exploration, Ltd. ("Big Bear"), a Canadian oil and gas company, at approximately $0.85 per share with each share convertible into one common share of Big Bear. Through a subsequent restructuring agreement, Belco's preferred stock holdings were converted to common stock and then subject to an 11:1 reverse stock split.
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As a result of the substantial decline in the market value of Big Bear securities currently owned by the Company, a $9.7 million impairment provision was recorded during the fourth quarter of 1998.
LONG-TERM DEBT
The fair value of the Company's revolving credit facility debt of $29.5 million is assumed to be the same as the carrying value because the interest rate is variable and is reflective of market rates. The fair value of the 10 1/2% Notes is based upon the quoted market prices for that issue. The fair value of the 8 7/8% Notes is based upon estimates provided to the Company by independent banking firms.
INTEREST RATE SWAPS AND OIL AND GAS COMMODITY FINANCIAL INSTRUMENTS
The estimated fair values of interest rate swaps and oil and gas commodity financial instruments have been provided by responsible third parties and determined by using available market data and applying certain valuation methodologies. In some cases, quotes of termination values were available. Judgment is usually required in interpreting market data, and the use of different market assumptions or estimation methodologies could result in different estimates of fair value.
NOTE 8 -- COMMITMENTS AND CONTINGENCIES
FUTURE CONTINGENCIES RELATED TO THE MOXA ARCH PROGRAMS
From 1992 to 1994, the Company established three Moxa Arch investment programs: the 1992 Moxa Arch Drilling Program, the 1993 Moxa Arch Drilling Program, and the Moxa Arch 1992 Offset Drilling Program. The Programs were established to develop certain drilling prospects acquired as a result of a farmout agreement with Amoco Production Company and others. The Company offered certain qualified investors (the Investors) the opportunity to invest in the prospects through participation in the Programs. As of December 31, 1998, the Programs have invested approximately $130 million in connection with the development of the Moxa Arch Trend of Southwest Wyoming. Through October 30, 1996, the Company owned approximately 55.20 percent of the 1992 Moxa Arch Drilling Program, 32.45 percent of the 1993 Moxa Arch Drilling Program, and 58.21 percent of the Moxa Arch 1992 Offset Drilling Program. On October 31, 1996 the Company purchased from certain third-party investors interests (the "Acquired Interests") in the Belco Oil & Gas Corp. 1992, 1993 and 1992 Offset Moxa Arch Drilling Programs. The effective date of the purchase was October 31, 1996 for financial reporting purposes. The Acquired Interests represent incremental working interests in the Company's natural gas wells in the Moxa Arch trend located in Lincoln, Sweetwater and Uinta Counties, Wyoming. The Company paid aggregate cash consideration of $9.9 million plus an 80% participation in potential natural gas price increases (net of incremental production costs) associated with production from the wells through July 31, 1999 (the "Price Participation Right"). After the purchase, the Company's interest in these programs was increased to 81.5% of the 1992 Moxa Arch Drilling Program, 74.0% of the 1993 Moxa Arch Drilling Program, and 80.5% of the Moxa Arch 1992 Offset Drilling Program. The transaction was accounted for using the purchase method of accounting.
The remaining third-party investors in the Programs may "put" their interest to Belco annually through 2003, based upon a valuation by a nationally recognized independent petroleum engineering firm of the discounted net present value of the future net revenues from production of proved reserves attributable to the interests. The put amount is to be calculated based upon certain specified parameters including prices, discount factors and reserve life. No investor under the Programs exercised the put right through December 31, 1998. The Company is not obligated to repurchase in any one calendar year more than 30% of the interests originally acquired by the program investors (including, for purposes of this calculation, the Company's interest). The Company's purchase price under the put right has not been calculated given that no investors have exercised such right. However, using reserve values presented in Note 14, Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (SEC basis using
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
year end prices and a 10% discount rate), the maximum purchase price if all remaining investors exercised the put option would not be material to the Company as of December 31, 1998.
LEASE COMMITMENTS
At December 31, 1998, the Company had operating leases covering office space. Minimum rental commitments under such operating leases are as follows (in thousands):
For the years ended December 31, 1998, 1997 and 1996, total rental expense was approximately $512,000, $438,000 and $329,000, respectively.
LEGAL PROCEEDINGS
The Company is a named defendant in routine litigation incidental to its business. While the ultimate results of these proceedings cannot be predicted with certainty, the Company does not believe that the outcome of these matters will have a material adverse effect on the Company.
ENVIRONMENTAL MATTERS
The Company's operations are subject to various federal, state and local laws and regulations relating to the protection of the environment, which have become increasingly stringent. The Company believes its current operations are in material compliance with current environmental laws and regulations. There are no environmental claims pending or, to the Company's knowledge, threatened against the Company. There can be no assurance, however, that current regulatory requirements will not change, currently unforeseen environmental incidents will not occur or past noncompliance with environmental laws will not be discovered on the Company's properties.
NOTE 9 -- CASH FLOW INFORMATION
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
In November 1997, the company acquired Coda for cash, warrants and the assumption of certain liabilities. See Note 3.
NOTE 10 -- CUSTOMER INFORMATION
CONCENTRATIONS OF CREDIT RISK
The Company's revenues are derived from uncollateralized sales to customers in the oil and gas industry. The concentration of credit risk in a single industry affects the Company's overall exposure. The Company has not experienced significant credit losses on such sales.
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
MAJOR CUSTOMERS
Oil and gas sales for 1998 include $28.9 million and $16.9 million in revenues received from two customers. Also, 1998 revenues included net gains in the amount of $24.8 million related to Commodity Price Risk Management Activities. Oil and gas sales for 1997 include $40.6 million, $27.9 million, $25.5 million in revenues received from three customers. Also, 1997 revenues include Commodity Price Risk Management net losses totaling $6.5 million. Oil and gas sales for 1996 include $44.6 million, $37.7 million and $11.7 million in revenues received from three customers and Commodity Price Risk Management losses of $5.9 million. No other customers individually accounted for 10 percent or more of revenues.
NOTE 11 -- EMPLOYEE BENEFIT PLANS
RETIREMENT PLAN
The Company provides a 401(k) and savings plan for all its full-time employees. The plan qualifies under Section 401(k) of the Internal Revenue Code as a salary reduction plan. Under the plan, but subject to certain limitations imposed under the Internal Revenue Code, eligible employees are permitted to (a) defer receipt of up to 15 percent of their compensation on a pre-tax basis (salary deferral contributions) or (b) contribute up to 10 percent of their compensation to the plan on an after-tax basis. The plan provides for a Company matching contribution in an amount equal to 50 percent (75% for employees with more than three years of service) of a participant's salary deferral contributions that are not in excess of 6 percent of such participant's compensation. The plan also permits the Company, in its sole discretion, to make a contribution that is allocated on the last day of each calendar year to certain eligible participants. Company matching and discretionary contributions are vested over a period of five years at the rate of 20 percent per year.
During 1998 and 1997, the Company incurred contribution expenses of $398,000 and $99,000, respectively, in connection with this plan.
PERFORMANCE UNIT PLAN
In 1996, Belco adopted a performance unit plan which is a long-term incentive compensation plan to be administered by the Stock Option Committee of the Board of Directors. All employees of the Company are eligible to receive an award of performance units under the plan. A performance unit has a performance period that is four consecutive calendar years beginning with and including the calendar year in which the performance unit is granted. The value of a performance unit will be determined based on the ranking of the Company's return on Common Stock during an applicable performance period compared to the return on the shares of Common Stock of certain companies with which the Company competes; however, the maximum value is $2.00 per unit. While payments with respect to performance units will normally be made at the end of the four-year performance period, pro-rated payments may also be made at an earlier time in the event a participant's employment with the Company is involuntarily terminated without cause or is terminated by reason of retirement, death or disability. Payments with respect to performance units will be made in a single sum and may be made in cash, Common Stock or a combination thereof as the Stock Option Committee in its sole discretion may determine. The Company did not grant any units during 1998. The Company granted 320,000 and 250,000 performance units during 1997 and 1996, respectively. As of December 31, 1998 the Company has made no cash payments in connection with this plan.
NOTE 12 -- CAPITAL STOCK
On March 10, 1998 the Company completed the sale of 4.37 million shares of its 6 1/2% Convertible Preferred Stock (the "Preferred Stock"). The Preferred Stock has a liquidation preference of $25 per share and is convertible at the option of the holder into shares of the Company's Common Stock at an initial conversion rate of 1.1292 shares of Common Stock for each share of Preferred Stock, equivalent to a
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
conversion price of $22.14 per share of Common Stock. The Company received net proceeds from the sale of the Preferred Stock of $105.1 million, which was used to pay down bank indebtedness.
NET INCOME (LOSS) PER COMMON SHARE
A reconciliation of the components of basic and diluted net income (loss) per common share for the years ended December 31, 1998, 1997 and 1996 is presented in the table below (in thousands, except per share amounts):
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(1) Includes shares issued and outstanding plus the restricted stock vested. A total of 80,628 shares of restricted stock grants were not vested as of December 31, 1998.
(2) Calculated using the treasury stock method, including unearned compensation of restricted stock as proceeds.
(3) Amounts are not included in the computation of diluted net income (loss) per share in 1998 and 1997 because to do so would have been antidilutive.
(4) The computation assumes that the Company was incorporated during the periods presented and presents the 25 million shares issued in connection with the Combination as outstanding for all periods.
EXCHANGE AGREEMENT AND PUBLIC EQUITY OFFERING
On March 29, 1996, the Exchange Agreement was consummated resulting in the issuance of 25,000,000 shares to the Predecessor Owners (See Note 1). In addition, on March 29, 1996, the Company completed its initial public offering issuing 6,500,000 shares at $19 per share. Net proceeds totaled $113.1 million after offering costs of $10.4 million.
STOCK INCENTIVE PLANS
On March 25, 1996, the Company adopted a Stock Incentive Plan (the Plan) under which options for shares of Belco's Common Stock may be granted to officers and employees for up to 2,250,000 shares of Common Stock. Under the Plan, options granted may either be incentive stock options or non-qualified stock options with a maximum term of 10 years and are granted at no less than the fair market of the stock at the date of grant. Options vest 20% per year until fully vested five years from the date of grant.
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
A separate plan has been established under which options for shares of Belco's Common Stock may be granted to non-employee directors for up to approximately 158,000 shares of Common Stock. The plan provides that each non-employee director be granted stock options for 3,000 shares annually as of the date of the Annual Meeting. The option price of shares issued is equal to the fair market value of the stock on the date of grant. All options vest 33 1/3% per year, beginning one year from date of grant, until fully vested and expire ten years after the date of grant.
A summary of the status of the Company's plans (the Plans) as of December 31, 1998 and 1997 and the changes during the year then ended is presented below:
The following table summarizes information about stock options outstanding at December 31, 1998.
As permitted by SFAS No. 123, the Company applies APB Opinion No. 25 and related Interpretations in accounting for its stock option plans. Accordingly, no compensation expense has been recognized for the Plans. Had compensation costs been determined based on the fair value at the grant dates consistent with the method of SFAS No. 123, the Company's pro forma net income (loss) for calendar years 1998 and 1997 would have been reduced to the pro forma amounts indicated below (in thousands, except for per share amounts):
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The fair value of grants was estimated on the date of grant using the Black-Scholes options pricing model with the following weighted average assumptions used in 1998 and 1997, respectively: risk-free interest rate of 5.60 and 6.35 percent, expected volatility of 49.0 and 46.6 percent, expected lives of 6.0 and 5.7 years and no dividend yield.
Under the Stock Incentive Plan, participants may be granted stock without cost (restricted stock). During 1998 and 1997, the Company granted 34,700 and 5,100 shares, respectively, of restricted stock with a weighted average fair value based on the price of the Company's stock on the date of grant of $15.69 and $24.44 per share, respectively. At December 31, 1998, 80,828 shares remained unvested, net of 11,700 shares forfeited. The weighted average fair value of shares forfeited was $21.31. The restrictions on disposition lapse 20% each year and non-vested shares must be forfeited in the event employment ceases. Unearned compensation was charged for the market value of the restricted shares at the date the shares were issued. The unearned compensation is shown as a reduction of stockholders' equity in the accompanying consolidated balance sheet and is being amortized ratably as the restrictions lapse. During 1998 and 1997, $344,100 and $192,000, respectively, was charged to costs and expenses relating to the Plan.
NOTE 13 -- SUPPLEMENTAL QUARTERLY FINANCIAL DATA (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS):
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The sum of the individual quarterly pro forma basic and diluted net income (loss) per share amounts may not agree with year-to-date pro forma basic and diluted net income per share as each period's computation is based on the weighted average number of common shares outstanding during that period. In addition, certain potentially dilutive securities were not included in certain of the quarterly computations of diluted net income per common share because to do so would have been antidilutive.
NOTE 14 -- SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCING ACTIVITIES (UNAUDITED):
CAPITALIZED COSTS
The following table sets forth the capitalized costs and related accumulated depreciation, depletion and amortization relating to the Company's oil and gas production, exploration and development activities as of December 31, 1998 and 1997 (in thousands):
COSTS NOT BEING AMORTIZED
The following table sets forth a summary of unproved oil and gas property costs not being amortized at December 31, 1998, by the year in which such costs were incurred (in thousands):
COSTS INCURRED
The following table sets forth the costs incurred in oil and gas acquisition, exploration and development activities as of December 31, 1998, 1997 and 1996 (in thousands):
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(1) Acquisition of proved properties in 1997 includes $437.4 million relative to the acquisition of Coda of which $50 million was allocated to unproved property costs.
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
The following table sets forth revenue and direct cost information relating to the Company's oil and gas exploration and production activities as of December 31, 1998, 1997 and 1996 (in thousands):
OIL AND GAS RESERVE INFORMATION
The following summarizes the policies used by the Company in preparing the accompanying oil and gas reserves and the standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes in such standardized measure from period to period.
Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods.
Proved oil and gas reserve quantities and the related discounted future net cash flows (without giving effect to hedging activities) as of December 31, 1998, 1997 and 1996 are based on estimates prepared by Miller & Lents, independent petroleum engineers. Such estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission (SEC). Reserve estimates for periods prior to December 31, 1995 were not prepared by an independent petroleum engineer. While reserve reports for years ended prior to December 31, 1995 were not prepared contemporaneously, they have been prepared by an in-house engineer on a basis generally consistent with the Miller & Lents report. The Company used the December 31, 1995 Miller & Lents estimates as an initial basis and adjusted such data for actual production and extensions, discoveries and other additions in 1994 to determine the relevant data for each of these periods. The Company also calculated the reserve economics at the end of 1994 using oil and gas prices in effect as of the end of the year.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the Company. The reserve data set forth herein represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates, and such revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The standardized measure of discounted future net cash flows from production of proved reserves was developed by first estimating the quantities of proved reserves and the future periods during which they are expected to be produced based on year end economic conditions. The estimated future cash flows from proved reserves were then determined based on year end prices, except in those instances where fixed contracts provide for a higher or lower amount. Estimates of future cash flows applicable to oil and gas commodity hedges have been prepared by the Company and are reflected in future cash flows from proved reserves with such estimates based on prices in effect as of the date of the reserve report. Additionally, future cash flows were reduced by estimated production costs, costs to develop and produce the proved reserves, and when significant, certain abandonment costs, all based on year end economic conditions. Future net cash flows have been discounted by 10 percent in accordance with SEC guidelines.
The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company's oil and gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
Under SEC rules, companies that follow full-cost accounting methods are required to make quarterly "ceiling test" calculations. Under this test, proved oil and gas property costs may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10 percent, as adjusted for related tax effects and deferred tax reserves. Application of these rules during periods of relatively low oil and gas prices, even if of short-term duration, may result in write-downs.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED OIL AND GAS RESERVES
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(1) The earnings of the Company were not subject to corporate income taxes prior to March 29, 1996 as the Company was a combination of nontaxpaying entities. Concurrent with the March 1996 Exchange Agreement (see Note 1), the Company became a taxable corporation. The estimated pro forma income taxes as of December 31, 1995, discounted at 10%, have been presented assuming the Company was a taxable entity for all periods. In addition, the estimated undiscounted future income taxes related to future net inflows were $32.6, $146.4 and $245.9 million for the years 1998, 1997 and 1996, respectively.
(2) Oil and gas commodity hedges included in future cash inflows totaled $4.6 million, $5.9 million and ($60.8) million at December 31, 1998, 1997, and 1996, respectively, and such hedges included in discounted future net cash flows before income taxes totaled $4.3 million, $5.5 million and ($55.2) million at December 31, 1998, 1997 and 1996, respectively.
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RESERVE QUANTITY INFORMATION
PROVED RESERVES
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(1) Revisions include the reduction of previously recoverable quantities, primarily of oil and to a lesser extent natural gas resulting from the use of lower oil and gas prices.
EXHIBIT INDEX
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* Filed herewith