Item 1. Business
General
Louis Dreyfus Natural Gas Corp. (the "Company" or "Registrant") is one of the largest independent natural gas companies in the United States engaged in the acquisition, development, exploration, production and marketing of natural gas and crude oil. The Company's acquisition, development and exploration activities are primarily conducted in three geographically concentrated core areas: the Permian Region of West Texas, Southeast New Mexico and the San Juan Basin; the Mid-Continent Region of Oklahoma, Kansas and the Panhandle of Texas; and the Gulf Coast Region, which includes South Texas, Offshore Gulf of Mexico, East Texas, Southwest Arkansas and North Louisiana (collectively "Core Areas"). Approximately 94% of the Company's proved reserve value at December 31, 1998 is located within these Core Areas. Proved reserves as of December 31, 1998 totaled 1.3 Tcfe and had a Present Value (as hereinafter defined) of $979 million. The Company's operated properties contain more than 80% of its total proved reserves. Natural gas reserves comprised 89% of the Company's year-end proved reserve position and 86% of its reserves were proved developed. The Reserve Life of its proved reserves, as hereinafter defined, was 11.0 years.
The Company was acquired in 1990 by S.A. Louis Dreyfus et Cie to engage in oil and gas acquisition, development, production and marketing activities. At the time of acquisition, the Company's proved reserves totaled 61 Bcfe. Since that date, the Company has experienced significant growth in its production and reserves through a balanced strategy of proved reserve acquisitions and development and exploration drilling. The Company has accumulated interests in 3.6 million gross acres with 1,575 identified drilling locations. Of these locations, 394 had been assigned proved undeveloped reserves at December 31, 1998. The Company aggressively exploits the value in its properties through an active development drilling program. This program has resulted in the drilling of 1,439 wells with a completion success rate of 93% over the five-year period ended December 31, 1998. In recent years, exploratory drilling has been increasingly emphasized as an integral component of its business strategy and, consequently, the Company has incurred substantial up-front costs, including significant acreage, seismic and other geological and geophysical costs. During 1998, the Company invested $83 million in connection with exploration activities, $23 million of which was directed to acreage and seismic acquisition. The Company's exploration program has had a cumulative drilling success rate of 69% since its inception in 1995.
The Company's balanced growth strategy has enabled the Company to replace 296% of its production since 1993 at an average Finding Cost, as defined herein, of $1.07 per Mcfe, including the purchase accounting impact of its acquisition of American Exploration Company in 1997 ("American Acquisition"). Finding Costs excluding the effects of the American Acquisition, which Management believes are more representative of the Company's historical ability to replace reserves, were $.86 per Mcfe over this same five year period. The following table reflects the Company's growth since 1993:
Production, Proved Reserves, Earnings Per Share and Cash Flow Growth
(1) See "-- Certain Definitions."
(2) Earnings for 1998 were adversely affected by a $52.5 million non-cash impairment charge and a significant decline in oil and gas prices. Earnings for 1997 were adversely affected by a $75.2 million non-cash impairment charge, substantially all of which was recognized in connection with the American Acquisition. See "Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations."
The address of the Company's principal executive offices is 14000 Quail Springs Parkway, Suite 600, Oklahoma City, Oklahoma 73134, and its telephone number is (405) 749-1300.
Business Strategy
The Company's business strategy is to generate strong and consistent growth in reserves, production, operating cash flows and earnings. This strategy is implemented through the following:
Expanded Exploration Program. Increased exploration activity in the Company's Core Areas exposes the Company to higher production and reserve growth potential. The Company has a staff of 30 geoscientists and reservoir engineers who have extensive experience in the use of advanced technologies, including 3-D seismic analysis, computer aided mapping and reservoir simulation modeling. These technologies are combined with a considerable knowledge base gained through the Company's operating and development drilling activities in these Core Areas. The combination results in a disciplined approach to exploration growth. During 1998, $83 million was invested in connection with exploration activities, including drilling, seismic data collection and unproved lease acquisitions. Since the inception of the program in 1995, the Company has drilled 103 gross (63 net) exploratory wells with a completion success rate of 69%. The Company has allocated $61 million, or 36%, of its 1999 drilling budget to exploration activities.
Development Drilling. The Company aggressively exploits the value in its oil and gas property base through its active development drilling program. The development drilling program has been an important source of low-risk production growth and is conducted in areas where multiple productive oil and gas bearing formations are likely to be encountered, thus reducing dry hole risk. The Company has drilled 1,336 gross (851 net) development wells with a completion success rate of 94% over the five-year period ended December 31, 1998. For 1999, the Company plans to continue its aggressive development drilling program by investing $109 million, or 64% of its 1999 drilling budget.
Strategic Acquisitions. The Company has grown rapidly by investing $544 million to acquire 563 Bcfe of proved reserves over the five-year period ended December 31, 1998, an average acquisition cost of $.97 per Mcfe. The Company believes the cost of these acquisitions compares favorably to industry averages. These acquisitions have been geographically concentrated in its Core Areas where the Company possesses considerable operating expertise and realizes economies of scale. The Company principally targets acquisitions which have significant development potential, are in close proximity to existing properties, have a high degree of operatorship and can be integrated with minimal incremental administrative cost.
Large Property Base. The Company owns interests in approximately 9,200 wells located primarily in its Core Areas. As a result of this large property base, the opportunity to generate positive results through the application of improved production technologies and to achieve economies of scale is enhanced while the risk of material adverse financial consequences from unexpected production problems is minimized. The Company has five district offices in its Core Areas and employs approximately 140 pumpers and other field personnel to provide onsite management of its properties.
Price Risk Management. The Company manages a portion of the risks associated with decreases in prices of natural gas and crude oil through long-term fixed-price physical delivery contracts, energy swaps, collars, futures contracts and basis swaps (collectively "Fixed-Price Contracts"). Over the five-year period ended December 31, 1998, Fixed-Price Contracts have generated $55.1 million in additional revenues and operating cash flows and have resulted in additional cash proceeds of $76.8 million which have been used to fund the Company's drilling activities. The estimated fair value of the Company's Fixed-Price Contracts was $122.6 million at December 31, 1998, based on the difference between contract prices and forward market prices, as adjusted for basis, contract performance risk and counterparty credit risk. This contract value now resides on the Company's balance sheet as a result of adopting Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). The estimated undiscounted, unrisked future net revenues associated with these contracts was $226.4 million. Fixed-Price Contracts provide a base of predictable cash flows for a portion of the Company's gas and oil sales, enabling the Company to pursue its capital expenditures with a greater degree of assurance. The Company has not entered into Fixed-Price Contracts with a term in excess of 12 months since 1996 due to Management's belief that demand and supply fundamentals for natural gas imply the potential for prices in excess of those currently available in the long-term forward market. Forty-four percent of the Company's 1998 production was hedged by Fixed-Price Contracts.
Forward-Looking Statements
All statements in this document concerning the Company other than purely historical information (collectively "Forward-Looking Statements") reflect the current expectations of Management and are based on the Company's historical operating trends, its proved reserve and Fixed-Price Contract positions as of December 31, 1998, and other information currently available to Management. Such Forward-Looking Statements include among others, statements regarding the Company's future drilling plans and objectives, and related exploration and development budgets, and number and location of planned wells, and statements regarding the quality of the Company's properties and potential reserve and production levels. These statements assume, among other things, that no significant changes will occur in the operating environment for the Company's oil and gas properties and that there will be no material acquisitions or divestitures except as disclosed herein. The Company cautions that the Forward-Looking Statements are subject to all the risks and uncertainties incident to the acquisition, development and marketing of, and exploration for, oil and gas reserves. These risks include, but are not limited to, commodity price risks, counterparty risks, environmental risks, drilling risks, reserve risks, and operations and production risks. Certain of these risks are described elsewhere herein. See "Item 7 - -Management's Discussion and Analysis of Financial Condition
and Results of Operations--Outlook for Fiscal Year 1999." Moreover, the Company may make material acquisitions or divestitures, modify its Fixed-Price Contract positions by entering into new contracts or terminating existing contracts, or enter into financing transactions. None of these can be predicted with certainty and, accordingly, are not taken into consideration in the Forward-Looking Statements made herein. Statements concerning Fixed-Price Contract, interest rate swap and other financial instrument fair values and their estimated contribution to future results of operations are based upon market information as of a specific date. Such market information in certain cases is a function of significant judgment and estimation. Further, market prices for oil and gas and market money rates are subject to significant volatility. For all of the foregoing reasons, actual results may vary materially from the Forward-Looking Statements and there is no assurance that the assumptions used are necessarily the most likely. The Company expressly disclaims any obligation or undertaking to release publicly any updates regarding any changes in the Company's expectations with regard to the subject matter of any Forward-Looking Statements or any changes in events, conditions or circumstances on which any Forward-Looking Statements are based.
Recent Developments
The following information discusses certain of the more significant accomplishments of the Company during the year ended December 31, 1998.
1998 Drilling Program. The Company's drilling program for 1998 was the most extensive and the most successful in the Company's history. The program resulted in the drilling of 351 wells, of which 311 wells were completed as commercial producers for a drilling success rate of 89%. This well count included 27 exploratory wells, 52% of which were completed as producers, and 324 development wells, 92% of which were completed as producers. Through this program, the Company added 258 Bcfe of proved reserves to its reserve base at an all-in finding and development cost (total costs incurred to explore and develop oil and gas properties divided by proved reserves added through extensions and discoveries and revisions of previous estimates) of $.86 per Mcfe. 1998 marked the fifth consecutive year that the Company replaced its production through its drilling activities. See "Item 2
Item 2. Properties
General
The Company's oil and gas acquisition, exploration and development activities are conducted mainly in its Core Areas: the Permian Region of West Texas, Southeast New Mexico and the San Juan Basin; the Mid-Continent Region of Oklahoma, Kansas and the Panhandle of Texas; and the Gulf Coast Region which includes South Texas, Offshore Gulf of Mexico, East Texas, Southwest Arkansas and North Louisiana. Proved reserves as of December 31, 1998 consisted of 24 MMBbls of oil and 1.2 Tcf of natural gas, totaling 1.3 Tcfe. At this date, the Company had ownership interests in approximately 9,200 producing wells. The Company operates 3,500 of these wells which contain 81% of its total proved reserves. Net daily production during 1998 was 9.4 MBbls of oil and 276.9 MMcf of natural gas, or 333.3 MMcfe. The Company drilled 324 developmental oil and gas wells, 297 of which were completed as commercial producers, and 27 exploratory wells, 14 of which were successfully completed, during 1998.
The Company has allocated $170 million for its 1999 drilling program, subject to revision based upon oil and gas prices, proved reserve acquisitions and other factors. Approximately $61 million of this total, or 36%, has been allocated to exploration activities and $109 million, or 64%, has been allocated to development activities. It is expected that this drilling expenditure will result in the drilling of about 220 wells, including 30 exploratory wells and 190 development wells. See "Item 7 - -Management's Discussion and Analysis of Financial Condition and Results of Operations--Outlook for Fiscal Year 1999."
Core Areas
The following table sets forth certain information regarding the Company's activities in each of its principal producing areas as of December 31, 1998:
Core Areas
Permian Region
The Company is actively involved in development and exploration activities in several areas within the Permian Region. These areas include the Sonora Area, the Pitchfork Ranch and the Spraberry Trend of West Texas, and the Delaware Basin of Southeast New Mexico, among others. The Company's properties in the Permian Region contain 635 Bcfe of proved reserves, nearly one-half of the Company's total reserve base, in about 4,100 wells. The Company drilled 195 wells in the Permian Region in 1998 and daily production averaged 116 MMcfe per day. The Company has identified 850 undrilled locations in this region of which 202 have been assigned proved undeveloped reserves. Plans for this region in 1999 include the drilling of approximately 140 wells and a total investment of $57 million, including acreage and seismic acquisition.
Sonora Area
The Sonora area is located in the West Texas counties of Schleicher, Crockett, Sutton and Edwards. It is comprised of five fields: Sawyer, Shurley Ranch, MMW, Aldwell Ranch and Whitehead, which are located on the northeast side of the Val Verde Basin of West Central Texas. The Company has an average 93% working interest in 1,785 wells, most of which are Company operated. Production is predominately from the Canyon formation at depths ranging from 2,500 to 6,500 feet and the Strawn formation at depths ranging from 5,000 to 9,000 feet. The majority of the Company's interest in these properties was acquired in 1993 and 1995.
Canyon Formation. Natural gas in the Canyon formation is stratigraphically trapped in lenticular sandstone reservoirs and the typical Sonora Area well encounters numerous such reservoirs over the formation's gross thickness of approximately 1,500 feet. The Canyon reservoirs tend to be discontinuous and to exhibit low porosity and permeability, characteristics which reduce the area that can be effectively drained by a single well. These characteristics have encouraged operators in the area to undertake Canyon infill drilling programs. Initial wells were drilled on 640 acre drilling units, but well performance characteristics have indicated that denser well spacing is necessary for effective drainage. The Company continues to drill infill wells in these units and, in some areas, fields are now developed on 40 acre spacing.
Strawn Formation. The Strawn formation, a shallow-marine, fossiliferous limestone, produces natural gas from fractures and irregularly distributed porosity trends draped across anticlinal features. Original field development took place on 640 acre units, with subsequent infill programs downsizing some areas to 80 acre density. Testing of the Strawn formation in Sonora wells, for which the primary drilling objective was the Canyon formation, has been an attractive play for the Company because the Strawn lies less than 1,000 feet below the Canyon formation. Because of the closeness in depth, the incremental cost to evaluate the Strawn formation has been relatively minor. The Strawn production is generally commingled with the Canyon
production stream. During 1998, the Company completed a 19 square mile 3D seismic survey on the Buckhorn prospect, a northeast extension of Sonora. The 3D interpretation has identified several Strawn reef prospects and an Atoka play.
The Company has maintained an aggressive development drilling program in the Sonora Area since 1993, having drilled 580 Canyon and Strawn wells with only 20 dry holes. The 1998 drilling program resulted in the drilling of 126 wells which contributed to record production from the Sonora Area. Net production from Sonora reached the record rate of 93 MMcfe per day. The Company plans to drill approximately 110 wells in Sonora during 1999, the majority of which are relatively low risk locations. The Company has identified over 575 potential locations on its acreage, of which 179 have been assigned proved undeveloped reserves. Subject to further study and drilling results, the Company believes additional proved reserves will ultimately be attributed to many of the other locations. In addition to infill drilling potential, many of the Company's producing wells in the Sonora Area have recompletion possibilities in existing wellbores.
The Company is currently drilling and evaluating a Lower Canyon play south of the main producing area. More than 30,000 acres have been acquired along this Lower Canyon trend and two Lower Canyon wells have been drilled. The first of these two wells was dry, but the second well encountered potential Lower Canyon sands and is waiting on completion.
Pitchfork Ranch
The Pitchfork Ranch is located in King and Dickens Counties, Texas, and covers approximately 140,000 acres. The Company is the operator and its ownership ranges from 45% to 78% in certain leases within this ranch. Target zones are the Tannehill sand at a depth of 4,500 feet and the Canyon/Strawn Reef at 5,500 feet. The Tannehill sands were deposited as northeast to southwest trending channel sands and extend over most of the acreage. Production is generally found within point bars on structural highs or in stratigraphic traps. Fields within this meandering channel system of the Tannehill can have potential reserves of up to 2 MMBbls, with the opportunity for numerous fields to exist on the ranch. The Canyon/Strawn produces from reefs in the area, some of which have produced more than 10 MMBbls. The first 30 square mile 3D seismic survey conducted in 1997 resulted in the completion of six oil wells in the Tannehill formation. In 1998, a second 3D seismic survey of 50 square miles was completed and drilling of Tannehill and Canyon/Strawn targets is expected to commence in the first quarter of 1999 based on this new seismic information.
Spraberry Trend
The Spraberry Trend is located in the West Texas counties of Martin, Midland, Glasscock, Upton, Reagan and Irion. The fields in the Spraberry Trend are characterized by the production of both oil and gas from productive zones ranging from the Lower Clearfork formation at a depth of 4,500 feet, to the Dean formation at a depth of 7,000 feet, with the majority of the production from the Spraberry formation at a depth of 5,500 to 6,500 feet. The Spraberry formation produces from fractured sandstones and siltstones and is characterized by low porosity and permeability. These formation characteristics have encouraged operators to develop the area on 80 acre spacing. Over the past few years, the Company has pursued an active infill drilling program in the Spraberry trend which will be pursued again when oil prices recover to provide more attractive economics.
Southeast New Mexico
The Company is also active in southeastern New Mexico in the Delaware Basin, where the primary objectives are the Morrow sands and Devonian carbonates. The Morrow sands are deposited in fluvial channels which trend from northwest to southeast. The Devonian carbonates occur as reefs that are as much as 600 feet thick. These reefs occur along a Devonian shelf edge that extends along a trend that is more than 250 miles long. These reservoirs exhibit excellent porosity and permeability at depths between 10,000 and 15,000 feet. These objectives also lend themselves to the use of modern technology including 3D seismic and computer aided mapping. In 1999 it is anticipated that approximately 10 wells may be drilled for these objectives.
Mid-Continent Region
The Company was actively involved in the Mid-Continent Region when it was acquired by S.A. Louis Dreyfus et Cie and has subsequently acquired substantial additional acreage and proved reserves in the area through multiple synergistic acquisitions. The Company operates approximately 1,280 wells in the Mid-Continent Region. The Company's properties are located in and along the northern shelf of the Anadarko Basin in western Oklahoma, in the deeper Anadarko Basin in the Texas Panhandle, and in Kansas. Development of the Company's Mid-Continent Region properties began in the late 1970's. Production is predominately natural gas from productive formations of Pennsylvanian and Pre-Pennsylvanian age rock. Productive depths range from 3,000 to 17,000 feet. Pre-Pennsylvanian reservoirs include the Chester, Mississippi and Hunton formations, with greater production from these formations occurring in highly fractured carbonate intervals. Pennsylvanian reservoirs include the Granite Wash, Red Fork, Atoka, Morrow and Springer sandstones. The stratigraphic nature of these reservoirs frequently provides for multiple targets in the same wellbores. Spacing in these formations is generally on 640 acres with extensive increased density drilling having occurred over the last 15 years. Two primary areas of focus in the Mid-Continent are the Watonga-Chickasha Trend in central Oklahoma and the Texas Panhandle.
The Company has pursued an active low-risk infill drilling program in the Mid-Continent area over the past five years, including the drilling of 77 wells in 1998. Average net daily production was 103 MMcfe per day for this region in 1998. The Company has ownership in about 3,500 wells with proved reserves of 406 Bcfe. The Company plans to drill approximately 60 wells in this area during 1999, with the primary development focus being the higher potential Morrow/Springer sand subcrop in the Watonga-Chickasha Trend. The Company has identified 400 undrilled locations in the Mid-Continent Region, of which 163 have been assigned proved undeveloped reserves.
Watonga-Chickasha Trend
These Morrow/Springer sands, located in central Oklahoma, were deposited as bars and channels along an ancient coast line more than 350 miles long. These sands exhibit excellent porosity and permeability at depths of 10,000 to 13,000 feet. Multiple objectives of up to a dozen sands have allowed increased drilling from one well per 640 acres to as many as four wells per 640 acres. The majority of the wells drilled in this trend are lower risk development wells. During 1999, the Company plans to drill four exploratory tests seeking to discover new bars or channels and approximately 40 development wells.
Texas Panhandle
In the Texas Panhandle, the primary objective is the Morrow sand which was deposited in fluvial channels. Previous experience has shown that 3D seismic can help identify these sand channels. In 1998, the Company completed a 40 square mile 3D seismic survey on the Munson Project. This data is currently being processed and is expected to produce drilling locations by the end of the first quarter of 1999. The Company has approximately 50% working interest in this 40,000 acre project.
Gulf Coast Region
The Company has been active in the Gulf Coast Region since its initial entry through an acquisition in 1991. Development drilling on these acquired properties began in 1992 and continued into 1998. Presently, the Company is actively involved in an exploration and development program in Lavaca County, Texas and offshore in the Gulf of Mexico. The Company's properties in this region number approximately 800 wells and include 250 Bcfe of proved reserves. The Company drilled 49 wells in the Gulf Coast Region during 1998 and daily production averaged 103 MMcfe per day. The Company has identified 75 undrilled locations in this region of which 26 have been assigned proved undeveloped reserves. Plans for this region in 1999 include the drilling of approximately 20 wells and a total investment of $70 million, including acreage and seismic acquisition.
Lavaca County Area
The Company began its involvement in Lavaca County joint venture projects in 1996 to explore and drill, primarily for the Lower Wilcox formation. Secondary targets include the shallower Upper Wilcox, Miocene, Frio and Yegua targets. Working interests in these projects, including the Yoakum Gorge and S.W. Speaks projects, initially ranged from 25% to 35%. Subsequent acquisitions in 1997 and 1998 have more than doubled the Company's interests in these projects. The Company has additionally expanded its position in the Wilcox trend further to the east to include the Provident City field.
The Company now holds working interests ranging from 30% to 87.5% in 60,000 gross acres in Lavaca County, Texas. Since this project began, the Company has participated in 30 Lower Wilcox wells, over 90% of which have successfully been completed as producers. Approximately 200 square miles of high-fold 3D seismic data was obtained in 1996 and 1997 which continues to be evaluated. An additional 50 square miles of 3D seismic was shot on the South Borchers prospect in late 1998 which is a southern extension to existing data. This data is being processed and interpreted with drilling expected to commence in mid-1999. The target zones are the Lower Wilcox sands from 10,000 to 17,000 feet and the shallow Miocene, Frio, Yegua and Upper Wilcox sands ranging in depth from 3,500 to 8,000 feet.
The Company's Lower Wilcox drilling program in 1998 resulted in the successful completion of 20 wells, including eight exploratory tests. The Lower Wilcox sands are part of an ancient deltaic system deposited across an unstable muddy continental shelf. The rapid subsidence of the underlying beds allowed accumulation of massive Wilcox sand packages with a high degree of structural complexity. These deep structures present higher risk but have significant potential, ranging up to 100 Bcf per field. The Company's Sibley #4 discovery in the Frost field logged approximately 300 feet of pay and had initial production of 10 MMcfe per day with 9,000 pounds of flowing tubing pressure from 60 feet of interval. Drilling plans for 1999 include approximately 20 Lower Wilcox wells in the Yoakum Gorge area, of which seven are expected to be exploratory.
Arklatex Area
Smackover Trend. The Company's operations in the Smackover Trend of Southwestern Arkansas are focused primarily in the Midway field, which is operated by the Company. The Midway field is located in Lafayette County, Arkansas and produces oil from the Smackover formation at an average depth of 6,500 feet. The Company owns an average of 79% working interest in this mature waterflood unit. Due to low oil prices, the Company does not plan to drill any wells in these fields in 1999.
East Texas. The Company has varying working interests in over 100,000 acres in the Oak Hill field and in the Cotton Valley Reef trend in Leon, Freestone, Smith, Anderson and Cherokee Counties of East Texas. During 1998, the Company
drilled several successful wells targeting the Taylor sand formation and one in the Cotton Valley Reef. The Company does not plan to drill any wells in the area in 1999.
During 1998, the Company drilled 42 wells onshore in the Gulf Coast Region and average net daily production was 56 MMcfe per day. The Company has identified 60 undrilled onshore locations of which 22 have been assigned proved undeveloped reserves.
Offshore Area
The Company owns working interests in twelve operated and eight outside-operated oil and gas production platforms and 164,000 acres, and owns over two thousand square miles of 3D seismic data in the Gulf of Mexico. Average net daily production from the Company's offshore properties was 47 MMcfe per day in 1998.
Texas State Waters. The Company owns an average 79% working interest in more than 38,000 gross acres in the Texas State Waters area. Two thousand square miles of 3D seismic data has been collected in the area. High-quality 3D seismic information for this offshore area previously was unavailable due to the inability of vessels towing seismic cables to operate in less than 60 feet of water without damaging the seismic equipment. The advent of ocean-bottom cabling has made the acquisition of high-quality 3D seismic information economically feasible. The Company drilled five exploratory tests offshore in 1998, successfully completing two for a combined gross rate of 22 MMcfe per day. The Company has identified several exploration prospects in the shallow waters offshore in the Gulf of Mexico.
High Island 116. High Island Block 116 is located in shallow federal waters, offshore Texas. The Company owns a 44% non-operated working interest in this block which produces from the Lower Miocene sands at an approximate depth of 10,000 feet. This block had average net daily production of 11 MMcfe during 1998.
East Cameron Block 328. East Cameron Block 328 is located in federal waters, offshore Louisiana, in approximately 240 feet of water. The block is on the flank of a large salt feature with multiple sands located in several fault blocks. Production is from the Trim A, Trim S and the HB-1 sands. The platform went on production in April 1998 and produced 16 MMcfe per day during 1998.
High Island 45. High Island Block 45 is located in shallow federal waters, offshore Texas. The Company is the operator and owns a 25% working interest in this block which produces from the Lower Miocene sands at an approximate depth of 11,000 feet. This platform had average net daily production of 4 MMcfe during 1998.
Reserves
The following table sets forth the estimated net quantities of the Company's proved and proved developed reserves as of December 31 for each year presented and the Estimated Future Net Revenues, as defined herein, and Present Values attributable to total proved reserves at such dates.
Proved Reserves
(1) The year-end prices used to estimate future net revenues include the effects of the Company's Fixed-Price Contracts which have escalating fixed prices. Estimated proved reserve quantities have been determined without regard to such contracts.
No estimates of the Company's proved reserves comparable to those included herein have been included in reports to any federal agency other than the Securities and Exchange Commission.
The Company's estimated proved reserves as of December 31, 1998 are based upon studies prepared by the Company's staff of engineers and reviewed by Ryder Scott Company, independent petroleum engineers. Estimated recoverable proved reserves have been determined without regard to any economic benefit that may be derived from the Company's Fixed-Price Contracts. Such calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with Securities and Exchange Commission guidelines. The Estimated Future Net Revenues and Present Value, as adjusted for Fixed-Price Contracts, were based on the engineers' production volume estimates with price adjustments based on the terms of the Company's Fixed-Price Contracts as of December 31, 1998. The amounts shown do not give effect to indirect expenses such as general and administrative expenses, debt service and future income tax expense or to depletion, depreciation and amortization.
The Company estimates that if all other factors (including the estimated quantities of economically recoverable reserves) were held constant, a $1.00 per Bbl change in oil prices and a $.10 per Mcf change in gas prices from those used in calculating the Present Value would change such Present Value by $14 million and $39 million, respectively.
The prices used in calculating the Estimated Future Net Revenues attributable to proved reserves are determined using the Company's Fixed-Price Contracts for the corresponding volumes and production periods adjusted for estimated location and quality differentials. These prices are on average higher than spot market prices at December 31, 1998. If such Fixed-Price Contracts were not in effect and the Company used December 31, 1998 wellhead prices, the Estimated Future Net Revenues attributable to proved reserves and the Present Value thereof would be $1.7 billion and $.8 billion, respectively.
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 information shown herein is estimated. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner, 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 of different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate. Accordingly, reserve estimates often differ from the quantities of oil and gas that are ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based.
For further information on reserves, future net revenues and the standardized measure of discounted future net cash flows, see Note 14 of the Notes to Consolidated Financial Statements appearing elsewhere herein.
Costs Incurred and Drilling Results
The following table sets forth certain information regarding the costs incurred by the Company in its acquisition, exploration and development activities during the periods indicated.
Costs Incurred
(1) Proved and unproved property acquisition costs for 1997 include $339.9 million and $98.0 million, respectively, of allocated American Acquisition purchase price.
The Company drilled or participated in the drilling of wells as set out in the table below for the periods indicated.
Wells Drilled
As of December 31, 1998, the Company was involved in the drilling, testing or completing of six gross (five net) development wells and two gross (one net) exploratory wells.
Acreage
The following table sets forth the Company's developed and undeveloped oil and gas lease and mineral acreage as of December 31, 1998. Excluded is acreage in which the Company's interest is limited to royalty, overriding royalty and other similar interests.
Acreage
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 176 wells with multiple completions. Wells with multiple completions are counted only once for purposes of the following table.
Productive Wells
Title to Properties
The Company believes that it has satisfactory title to its properties in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in the opinion of the Company, are not so material as to detract substantially from the use or value of its properties. The Company performs extensive title review in connection with acquisitions of proved reserves and has obtained title opinions on substantially all of its material producing properties. As is customary in the oil and gas industry, only a perfunctory title examination is performed in connection with acquisition of leases covering undeveloped properties. Generally, prior to drilling a well, a more thorough title examination of the drill site tract is conducted and curative work is performed with respect to significant title defects, if any, before proceeding with operations.
The Company's oil and gas properties are subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the oil and gas industry. Except as otherwise indicated, all information presented herein is presented net of such interests. The Company's properties are also subject to liens for current taxes not yet due and other encumbrances. The Company believes that such burdens do not materially detract from the value of such properties or from the respective interests therein or materially interfere with their use in the operation of the business. Approximately 29 Bcfe of the Company's oil and gas properties is mortgaged to a Fixed-Price Contract counterparty, securing the Company's performance under such contract.
Item 3.
Item 3. Legal Proceedings
Midcon. On December 22, 1995, the United States District Court for the Western District of Oklahoma entered a $10.8 million judgment in favor of the Company against Midcon Offshore, Inc. ("Midcon") in connection with non-performance by Midcon under an agreement to purchase a certain offshore oil and gas property. In January 1996, Midcon delivered a $10.8 million promissory note to the Company secured by first and second liens on assets of Midcon, payable in full on or before December 15, 1996 in settlement of disputes in connection with this litigation. During 1996, the Company received principal and interest payments on the promissory note totaling $1.7 million which have been reflected in the accompanying financial statements as other income. On December 16, 1996, Midcon filed for protection from its creditors under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court, Southern District of Texas, Corpus Christi Division. In January 1997, Midcon filed an action in the bankruptcy court alleging that Midcon's action in connection with the settlement constituted fraudulent transfers or avoidable preferences, and seeking a return of amounts paid and a release of the liens securing the payment obligation under the note. The complaint filed in the action also alleged certain affirmative claims against the Company including injury to reputation and loss of business opportunity. The complaint also seeks subordination of the Company's claim. The Court denied the Company's motion to dismiss the complaint. The Company considers the allegations of the complaint to be without merit and will vigorously defend against this action. Collection of unpaid interest and principal on the Midcon note is uncertain and no amounts have been recorded with respect thereto in the accompanying financial statements as of December 31, 1998. The Company will recognize income as any payments are received.
KNGSS. In February 1995, a lawsuit was filed in the United States District Court in Denver, Colorado, by KN Gas Supply Services, Inc. ("KNGSS"), requesting declaratory judgment that KNGSS had the right to reduce the contract price for gas produced from the Bowdoin Field, a property obtained in the American Acquisition, to market levels from October 1, 1993 forward. KNGSS alleges that it has overpaid American and seeks a refund of approximately $7.7 million for the period through September 1996. KNGSS has not updated its refund claim through the present date. A motion for summary judgment was filed by American in July 1996 and was argued before the court in February 1997. The Company assumed responsibility for this lawsuit in connection with the American Acquisition. In February 1998, the court ruled in favor of the Company's motion. KNGSS subsequently filed an appeal which has not been heard. Although the Company cannot predict the ultimate outcome of this proceeding, it will continue to vigorously defend its interests in this case and does not expect the outcome of the case to have a material adverse impact on its financial position or results of operations.
Other. American was a defendant in various other legal proceedings for which the Company also assumed responsibility in the American Acquisition. The largest of such legal claims was for an alleged underpayment of royalty of $5.5 million plus interest. In addition, American had received preliminary and final royalty underpayment determinations from the Minerals Management Service aggregating approximately $2.8 million plus interest in connection with certain gas contract settlements made in prior years. The Company is a defendant in additional pending legal proceedings which are routine and incidental to its business. While the ultimate results of all these proceedings and determinations cannot be predicted with certainty, the Company will vigorously defend its interests and 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
The Company's Common Stock is listed on the New York Stock Exchange ("NYSE") and traded under the symbol "LD." As of March 12, 1999, the Company estimates there were approximately 10,500 beneficial owners of its Common Stock. The high and low sales prices for the Company's Common Stock during each quarter in the years ended December 31, 1998 and 1997, were as follows:
Common Stock Market Prices
The Company has paid no dividends, cash or otherwise, subsequent to the date of the initial public offering of the Common Stock in November 1993. Certain provisions of the indenture agreement for the Company's 9-1/4% Senior Subordinated Notes due 2004 restrict the Company's ability to declare or pay cash dividends unless certain financial ratios are maintained. Although it is not currently anticipated that any cash dividends will be paid on the Common Stock in the foreseeable future, the Board of Directors may review the Company's dividend policy from time to time. In determining whether to declare dividends and the amount of dividends to be declared, the Board will consider relevant factors, including the Company's earnings, its capital needs and its general financial condition.
Item 6.
Item 6. Selected Financial Data
The selected financial data presented below as of December 31, 1998 and 1997, and for each of the three years ended December 31, 1998, 1997 and 1996, has been derived from, and is qualified by reference to, the Company's audited Consolidated Financial Statements, including the notes thereto, contained herein beginning at page. The selected financial data as of December 31, 1996, 1995 and 1994, and for the years ended December 31, 1995 and 1994, has been derived from audited consolidated financial statements previously filed with the Securities and Exchange Commission but not contained or incorporated herein. The selected financial data should be read in conjunction with the Consolidated Financial Statements of the Company, including the notes thereto, and "Item 7
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Overview
General. The Company's business strategy is to generate strong and consistent growth in reserves, production, operating cash flows and earnings through a balanced program of exploration and development drilling and strategic acquisitions of oil and gas properties. Over the five-year period ended December 31, 1998, this strategy has resulted in a 114% increase in proved reserves to 1.3 Tcfe, a 182% increase in oil and gas production to 122 Bcfe, and 180% growth in cash flows from operating activities to $147.4 million. Earnings for the year ended December 31, 1998 were adversely affected by a significant downturn in oil and gas prices, resulting in a net loss of $52.6 million.
The majority of the Company's growth has been the result of proved reserve acquisitions geographically concentrated in its Core Areas where the Company has significant expertise and where the Company benefits from operational synergies. During the five-year period ended December 31, 1998, the Company made proved reserve acquisitions aggregating 563 Bcfe, purchased for a total consideration of $544.5 million, or $.97 per Mcfe. Of particular significance was the American Acquisition which closed October 1997.
The Company's drilling program has played an increasingly important role in its growth strategy. During the five-year period ended December 31, 1998, the Company drilled 1,439 gross (914 net wells), with an overall drilling success rate of 93%, adding 610 Bcfe of reserves (including revisions of previous estimates) to its proved reserve base. The year ended December 31, 1998 marked the fifth consecutive year that the Company replaced its production through its drilling activities with 1998 representing the most successful year to date. Through its 1998 drilling program, the Company added 258 Bcfe of proved reserves at an all-in finding and development cost (total costs incurred to explore and develop oil and gas properties divided by proved reserves added through extensions and discoveries and revisions of previous estimates) of $.86 per Mcfe. These additions represent 212% production replacement for 1998. The Company has increasingly emphasized exploration as an integral component of its business strategy and in connection therewith, has incurred substantial up-front costs, including significant acreage positions, seismic costs and other geological and geophysical costs. During 1998, the Company invested $83 million in connection with exploration activities, resulting in the acquisition of $23 million of acreage and seismic information, and the drilling of 27 exploratory wells, of which 14 were completed as producers.
As of December 31, 1998, the Company's portfolio of Fixed-Price Contracts hedge 244 Bcfe of future production at escalating fixed prices, representing 18% of its estimated proved reserves. These fixed prices are presently significantly higher than the forward market prices for natural gas and oil. Over the past few years, competition in Fixed-Price Contracts has increased, opportunities for attractive Fixed-Price Contracts have diminished and year-to-year price escalations in the forward market are considerably lower. In response to these changes, a progressively smaller share of the Company's production and reserve growth has been hedged due to Management's belief that longer-term demand and supply fundamentals for natural gas imply the potential for prices in excess of those currently available in the long-term forward market. More recent hedging activity has been for shorter periods of time, generally less than 12 months, when market conditions have been viewed as favorable. The Company may decide to hedge a greater or smaller share of production in the future depending upon market conditions, capital investment considerations and other factors. See "Item 7A
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
General
The Company's results of operations and operating cash flows are impacted by changes in market prices for oil and gas and changes in market interest rates. To mitigate a portion of its exposure to adverse market changes, the Company has entered into Fixed-Price Contracts and interest rate swaps. All of the Company's Fixed-Price Contracts and interest rate swaps have been entered into as hedges of oil and gas price risk or interest rate risk and not for trading purposes. Information regarding the Company's market exposures, Fixed-Price Contracts, interest rate swaps and certain other financial instruments is provided below. All information is presented in U.S. Dollars.
Fixed-Price Contracts
Description of Contracts. The Company has entered into Fixed-Price Contracts to reduce its exposure to unfavorable changes in oil and gas prices which are subject to significant and often volatile fluctuation. The Company's Fixed-Price Contracts are comprised of long-term physical delivery contracts, energy swaps, collars, futures contracts and basis swaps. These contracts allow the Company to predict with greater certainty the effective oil and gas prices to be received for its hedged production and benefit the Company when market prices are less than the fixed prices provided in its Fixed-Price Contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in such contracts for its hedged production. For the years ended December 31, 1998, 1997 and 1996, Fixed-Price Contracts hedged 50%, 60% and 51%, respectively, of the Company's gas production and 16%, 33% and 67%, respectively, of its oil production. As of December 31, 1998, Fixed-Price Contracts are in place to hedge 244 Bcf of the Company's estimated future gas production.
For energy swap sales contracts, the Company receives a fixed price for the respective commodity and pays a floating market price, as defined in each contract (generally NYMEX futures prices or a regional spot market index), to the counterparty. For physical delivery contracts, the Company purchases gas in the spot market at floating market prices and delivers such gas to the contract counterparty at a fixed price. Under energy swap purchase contracts, the Company pays a fixed price for the commodity and receives a floating market price. The Company's natural gas collars contain a fixed floor price (put) and ceiling price (call). If the market price of natural gas exceeds the call strike price or falls below the put strike price, then the Company receives the fixed price and pays the market price. If the market price of natural gas is between the call and the put strike price, then no payments are due from either party. Under the Company's basis swaps, the Company receives the floating market price for NYMEX futures and pays the floating market price plus a fixed differential for a specified regional spot market index.
The following table summarizes the estimated volumes, fixed prices, fixed-price sales, fixed-price purchases and future net revenues (as defined below) attributable to the Company's Fixed-Price Contracts as of December 31, 1998.
(1) The Company expects the prices to be realized for its hedged production will vary from the prices shown due to location, quality and other factors which create a differential between wellhead prices and the floating prices under its Fixed-Price Contracts. See "-- Market Risk."
(2) Future net revenues for any period are determined as the differential between the fixed prices provided by Fixed-Price Contracts and forward market prices as of December 31, 1998, as adjusted for basis. Future net revenues change with changes in market prices and basis. See "-- Market Risk." Future net revenues as presented herein are undiscounted and have not been adjusted for contract performance risk or counterparty credit risk. See Note 12 of the Notes to Consolidated Financial Statements appearing elsewhere herein.
(3) Does not include basis swaps with notional volumes by year, as follows: 1999-19.0 TBtu; 2000-21.3 TBtu; 2001-9.4 TBtu; and 2002-5.5 TBtu.
The estimates of future net revenues from the Company's Fixed-Price Contracts are computed based on the difference between the prices provided by the Fixed-Price Contracts and forward market prices as of the specified date. The market for natural gas beyond a five year horizon is illiquid and published market quotations are not available. The Company has relied upon near-term market quotations, longer-term over-the-counter market quotations and other market information to determine its future net revenue estimates. Forward market prices for natural gas are dependent upon supply and demand factors in such forward market and are subject to significant volatility. The future net revenue estimates shown above are subject to change as forward market prices change.
The estimated fair value of the Company's Fixed-Price Contracts and the associated carrying value as of December 31, 1998 are provided below.
The fair value of Fixed-Price Contracts as of December 31, 1998 was estimated based on market prices of natural gas and crude oil for the periods covered by the contracts. The net differential between the prices in each contract and market prices for future periods, as adjusted for estimated basis, has been applied to the volumes stipulated in each contract to arrive at an estimated future value. In connection with the adoption of SFAS 133, this estimated future value was discounted on a contract-by-contract basis at rates commensurate with the Company's estimation of contract performance risk and counterparty credit risk. The terms and conditions of the Company's fixed-price physical delivery contracts and certain financial swaps are uniquely tailored to the Company's circumstances. In addition, the determination of market prices for natural gas beyond a five year horizon is subject to significant judgment and estimation. As a result, the Fixed-Price Contract fair value as reflected in the balance sheet as of December 31, 1998 does not necessarily represent the value a third party would pay to assume the Company's positions.
Accounting. In October 1998, the Company adopted SFAS 133 which establishes new accounting and reporting guidelines for derivative instruments and hedging activities. It requires that all derivative instruments be recognized as assets or liabilities in the statement of financial position, measured at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Designation is established at the inception of a derivative, but redesignation is permitted. For derivatives designated as cash flow hedges, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness, as defined by SFAS 133, is recognized immediately in earnings. Substantially all of the Company's Fixed-Price Contracts and interest rate swaps are designated as cash flow hedges. Changes in the fair value of derivative instruments which are not designated as hedges or are defined by SFAS 133 as being "fair value hedges" are recorded in earnings as the changes occur.
All of the Company's Fixed-Price Contracts have been executed in connection with its natural gas and crude oil hedging program and not for trading purposes. Further, all Fixed-Price Contracts have performed according to Management expectations in reducing the Company's exposure to adverse movements in commodity prices. However, SFAS 133 has very specific guidelines for measuring hedge effectiveness. Certain of the Company's contracts did not meet this criteria although they continue to perform as anticipated. For Fixed-Price Contracts qualifying as hedges pursuant to SFAS 133, the differential between the fixed price and the floating price for each contract settlement period multiplied by the associated contract volumes is the contract profit or loss. The realized contract profit or loss is included in oil and gas sales in the period for which the underlying commodity was hedged. Changes in market value for these contracts for volumes not yet settled are not reflected in the Company's income statements, but rather are shown as adjustments to other comprehensive income. For those contracts not qualifying as hedges, the associated fair value, as well as future changes in market value, are recognized in earnings. The fair value of all of its Fixed-Price Contracts are recorded as assets or liabilities in the Company's balance sheet.
If a Fixed-Price Contract which qualified for hedge accounting is liquidated or sold prior to maturity, the gain or loss is deferred and amortized into oil and gas sales over the original term of the contract. At December 31, 1998, the Company had pretax unamortized deferred gains of $61.3 million which were recorded net of deferred tax effects in accumulated other comprehensive income. Prior to the adoption of SFAS 133, the Company recorded gains and losses from contract terminations as deferred liabilities and assets, respectively. At December 31, 1997, the balance of deferred gains from price-risk management activities was $23.5 million. Prepayments received under Fixed-Price Contracts with continuing performance obligations are recorded as deferred revenue and amortized into oil and gas sales over the term of the underlying contract.
For the years ended December 31, 1998, 1997 and 1996, oil and gas sales included $23.1 million of net gains, $4.3 million of net losses and $2.1 million of net losses, respectively, associated with realized gains and losses under its Fixed-Price Contracts. Other income for the year ended December 31, 1998 included $2.5 million of gain attributable to contract hedge ineffectiveness and the change in fair value of contracts not qualifying as cash flow hedges.
Credit Risk. The terms of the Company's Fixed-Price Contracts generally provide for monthly settlements and energy swap contracts provide for the netting of payments. The counterparties to the contracts are comprised of independent power producers, pipeline marketing affiliates, financial institutions, a municipality and S.A. Louis Dreyfus et Cie, among others. In some cases, the Company requires letters of credit or corporate guarantees to secure the performance obligations of the contract counterparty. Should a counterparty to a contract default on a contract, there can be no assurance that the Company would be able to enter into a new contract with a third party on terms comparable to the original contract. The Company has not experienced non-performance by any counterparty.
The Company was a party to two Fixed-Price Contracts, both long-term physical delivery contracts, with independent power producers ("IPPs") which sold electrical power under firm, fixed-price contracts to Niagara Mohawk Corporation ("NIMO"), a New York state utility ("NIMO Contracts"). The ability of these IPPs to perform their obligations to the Company was dependent on the continued performance by NIMO of its power purchase obligations to the counterparties. NIMO has taken aggressive regulatory, judicial and contractual actions in recent years seeking to curtail power purchase obligations, including its obligations to the NIMO Contract counterparties, and had further stated that its future financial prospects were dependent on its ability to resolve these obligations, along with other matters. In July 1997, NIMO entered into a Master Restructuring Agreement (the "MRA") with 16 IPPs, including the NIMO Contract counterparties. Subsequently, one of the NIMO Contract counterparties withdrew from the MRA. The power purchase agreement between NIMO and the other counterparty was terminated. In connection therewith, the Company agreed to terminate its fixed-price contract to the counterparty in exchange for $40.1 million, the receipt of which has been recorded in accumulated other comprehensive income, net of tax effect. The remaining NIMO Contract which hedges 54 Bcf of natural gas as of December 31, 1998 remains in force and is reflected in the Company's balance sheet at a fair value of $72 million. The Company continues to deliver natural gas pursuant to the terms of this contract which expires in 2007. NIMO has continued to seek relief from its contractual obligations under this contract in the court system. Although there can be no assurance, Management does not expect that NIMO will ultimately succeed in these efforts.
Cancellation or termination of a Fixed-Price contract would subject a greater portion of the Company's gas production to market prices, which, in a low price environment, could have an adverse effect on the Company's future operating results. In addition, the associated carrying value of the contract would be removed from the Company's balance sheet. Any associated proceeds would be reflected in accumulated other comprehensive income, net of income tax effects, and amortized into earnings over the original contract term.
Market Risk. The Company's natural gas Fixed-Price Contracts at December 31, 1998 hedge 244 Bcf of proved natural gas reserves at fixed prices, representing 20% of its estimated proved natural gas reserves. If the Company's proved natural gas reserves are produced at rates less than anticipated, Fixed-Price Contract volumes could exceed production volumes. In such case, the Company would be required to satisfy its contractual commitments for any excess volumes at market prices in effect for each settlement period, which may be above the contract price, without a corresponding offset in wellhead revenue. The Company expects future production volumes to be equal to or greater than the volumes provided in its contracts.
The differential between the floating price paid under each energy swap contract, or the cost of gas to supply physical delivery contracts, and the price received at the wellhead for the Company's production is termed "basis" and is the result of differences in location, quality, contract terms, timing and other variables. The effective price realizations which result from the Company's Fixed-Price Contracts are affected by movements in basis. For the years ended December 31, 1998, 1997 and 1996, the Company received on an Mcf basis approximately 6%, 1% and 3% less than the prices specified in its natural gas Fixed-Price Contracts, respectively, due to basis. For its oil production hedged by crude oil Fixed-Price Contracts, the Company realized approximately 10%, 4% and 4% less than the specified contract prices for such years, respectively. Basis movements can result from a number of variables, including regional supply and demand factors, changes in the Company's portfolio of Fixed-Price Contracts and the composition of the Company's producing property base. Basis movements are generally considerably less than the price movements affecting the underlying commodity, but their effect can be significant.
A 1% move in price realization for hedged natural gas in 1999 represents a $1.0 million change in gas sales. The Company actively manages its exposure to basis movements and from time to time will enter into contracts designed to reduce such exposure.
Except for the effect of basis movements, the Company expects that any changes in Fixed-Price Contract fair value attributable to changes in market prices for natural gas will be offset by changes in the value of its natural gas reserves. This change in natural gas reserve value, however, is not reflected in the Company's balance sheet. Further, changes in future gains and losses to be realized in oil and gas sales upon future settlements of Fixed-Price Contracts resulting from changes in market prices for natural gas are expected to be offset by changes in the price received for the Company's hedged natural gas production. Because the majority of the Company's future estimated oil and gas production is unhedged, declining oil and gas prices could have a material adverse effect on the Company's future results of operations and operating cash flows.
Margin. The Company is required to post margin in the form of bank letters of credit or treasury bills under certain of its Fixed-Price Contracts. In some cases, the amount of such margin is fixed; in others, the amount changes as the market value of the respective contract changes, or if certain financial tests are not met. For the years ended December 31, 1998, 1997 and 1996, the maximum aggregate amount of margin posted by the Company was $23.7 million, $28.7 million and $28.4 million, respectively. If natural gas prices were to rise, or if the Company fails to meet the financial tests contained in certain of its Fixed-Price Contracts, margin requirements could increase significantly. The Company believes that it will be able to meet such requirements through the Credit Facility and such other credit lines that it has or may obtain in the future. If the Company is unable to meet its margin requirements, a contract could be terminated and the Company could be required to pay damages to the counterparty which generally approximate the cost to the counterparty of replacing the contract. At December 31, 1998, the Company had issued margin in the form of letters of credit and treasury bills totaling $17.0 million and $1.5 million, respectively. In addition, approximately 29 Bcf of the Company's proved gas reserves are mortgaged to a Fixed-Price Contract counterparty, securing the Company's performance under the associated contract.
Interest Rate Sensitivity
The Company has entered into interest rate swaps to hedge the interest rate exposure associated with borrowings under the Credit Facility. As of December 31, 1998, the Company had fixed the interest rate on average notional amounts of $158 million, $125 million, $125 million and $94 million for the years ended December 31, 1999, 2000, 2001 and 2002, respectively. Under the interest rate swaps, the Company receives the LIBOR three-month rate (5.1% at December 31, 1998) and pays an average rate of 5.3%, 5.0%, 5.0% and 5.0% for 1999, 2000, 2001 and 2002, respectively. The notional amounts are less than the maximum amount anticipated to be available under the Credit Facility in such years.
For each interest rate swap, the differential between the fixed rate and the floating rate multiplied by the notional amount is the swap gain or loss. Such gain or loss is included in interest expense in the period for which the interest rate exposure was hedged. If an interest rate swap is liquidated or sold prior to maturity, the gain or loss is recorded in accumulated other comprehensive income and amortized as interest expense over the original contract term. For the years ended December 31, 1998, 1997 and 1996, interest rate swaps increased interest expense by $.3 million, $.2 million and $.9 million, respectively.
As of October 1, 1998, the Company had one interest rate swap with a notional amount of $25 million, which pursuant to SFAS 133, was designated as a fair value hedge of a portion of the Subordinated Notes. As a result, cumulative effect of an accounting change in the statement of operations for the year ended December 31, 1998 included a gain of $2.7 million associated with the fair value of this interest rate swap and a loss of $1.6 million attributable to the fair value of the Subordinated Notes. This interest rate swap was terminated in the fourth quarter of 1998.
The following table provides information about the Company's interest rate swaps and certain other financial instruments as of December 31, 1998.
(1) Based on market quotations for interest rates as of December 31, 1998 plus the appropriate credit spread for the respective debt instrument. Does not include commitment fees. See "Item 7 - -Management's Discussion and Analysis of Financial Condition and Results of Operations--Capital Resources and Liquidity."
(2) Based on market quotations for interest rates as of December 31, 1998.
The estimated fair value of the Company's interest rate swaps and certain other financial instruments and the associated carrying value as of December 31, 1998 are provided below.
The Company's bank debt bears interest at rates which move with market interest rates. Accordingly, the fair value of such debt at December 31, 1998 was estimated to approximate the carrying amount. The fair values of the 6-7/8% Senior Notes due 2007 and the 9-1/4% Senior Subordinated Notes due 2004 were determined based on market quotations for such securities. The fair value of the Company's interest rate swaps was based on market interest rates as of such date.
The Company expects that changes in realized interest rate swap gains and losses attributable to future changes in market interest rates will be offset by changes in the interest payments hedged by such interest rate swaps. The fair value of such swaps until settlement will be subject to change as market interest rates change. Increases in market interest rates would have an adverse effect on the Company's results of operations since the majority of its bank debt interest rate exposure is unhedged.
Item 8.
Item 8. Financial Statements and Supplementary Data
The Consolidated Financial Statements and supplementary data of the Company are set forth on pages through inclusive, found at the end of this report.
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 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" and "Executive Compensation and Other Information" 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.
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 Certain Beneficial Owners and Management" 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 "Certain Transactions" and "Executive Compensation and Other Information--Compensation Committee Interlocks and Insider Participation" 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 Financial Statement Schedule immediately following the signature page of this report.
2. Financial Statement Schedule: See Index to Consolidated Financial Statements and Schedule immediately following the signature page of this report.
3. Exhibits: The following documents are filed as exhibits to this report.
Exhibit No. Description of Exhibit - -------------------------------------------------------------------------------- 2.1 Agreement and Plan of Reorganization dated as of June 24, 1997, as amended, between Louis Dreyfus Natural Gas Corp. and American Exploration Company (incorporated herein by reference to Annex A to Louis Dreyfus Natural Gas Corp.'s Joint Proxy Statement/Prospectus filed with the Securities and Exchange Commission on September 12, 1997 pursuant to Rule 424(b)(3) relating to Louis Dreyfus Natural Gas Corp.'s Registration Statement on Form S-4, Registration No. 333-34849).
3.1 Amended and Restated Certificate of Incorporation of the Registrant (incorporated by reference to Exhibit 3.1 of the Registrant's Registration Statement on Form S-1, Registration No. 33-69102).
3.2 Certificate of Merger of the Registrant dated September 9, 1993 (incorporated by reference to Exhibit 3.2 of the Registrant's Registration Statement on Form S-1, Registration No. 33-69102).
3.3 Amended and Restated Bylaws of the Registrant (incorporated by reference to Exhibit 3.3 of the Registrant's Registration Statement on Form S-1, Registration No. 33-69102).
3.4 Certificate of Merger of the Registrant dated November 1, 1993 (incorporated by reference to Exhibit 3.4 of the Registrant's Registration Statement on Form S-1, Registration No. 33-69102).
4.1 Indenture agreement dated as of June 15, 1994 for $100,000,000 of 9-1/4% Senior Subordinated Notes due 2004 between Louis Dreyfus Natural Gas Corp., as Issuer, and Bank of Montreal Trust Company, as Trustee (incorporated by reference to Exhibit 10.2 of the Registrant's Form 10-Q for the quarter ended September 30, 1994).
4.2 Indenture agreement dated as of December 11, 1997 for $200,000,000 of 6-7/8% Senior Notes due 2007 between Louis Dreyfus Natural Gas Corp. and LaSalle National Bank as Trustee (incorporated by reference to Exhibit 4.1 of the Registrant's Registration Statement on Form S-4, Registration No. 333-45773).
*10.1 Stock Option Plan of Louis Dreyfus Natural Gas Corp. as amended and restated effective December 1998.
Exhibit No. Description of Exhibit - ------------------------------------------------------------------------------- 10.2 Form of Indemnification Agreement with directors of the Registrant (incorporated by reference to Exhibit 10.2 of the Registrant's Registration Statement on Form S-1, Registration No. 33-69102).
10.3 Registration Rights Agreement between the Registrant and Louis Dreyfus Natural Gas Holdings Corp. (incorporated by reference to Exhibit 10.3 of the Registrant's Registration Statement on Form S-1, Registration No. 33-76828).
10.4 Amendment dated December 22, 1993 to Registration Rights Agreement between the Registrant, Louis Dreyfus Natural Gas Holdings Corp. and S.A. Louis Dreyfus et Cie (incorporated by reference to Exhibit 10.4 of the Registrant's Registration Statement on Form S-1, Registration No. 33-76828).
10.5 Services Agreement between the Registrant and Louis Dreyfus Holding Company, Inc. (incorporated by reference to Exhibit 10.5 of the Registrant's Registration Statement Form S-1, Registration No. 33-76828).
10.6 Credit Agreement dated as of October 14, 1997, among Louis Dreyfus Natural Gas Corp., as Borrower, Bank of Montreal, as Administrative Agent, Chase Manhattan Bank, as Syndication Agent, NationsBank of Texas, N.A., as Documentation Agent, and certain other lenders signatory thereto (incorporated by reference to Exhibit 10.1 of the Registrant's Form 8-K dated October 14, 1997).
10.7 Swap Agreement dated November 1, 1993 between the Registrant and Louis Dreyfus Energy Corp. (incorporated by reference to Exhibit 10.17 of the Registrant's Registration Statement on Form S-1, Registration No. 33-69102).
10.8 Memorandum of Agreement for a natural gas swap dated September 16, 1994, between Louis Dreyfus Natural Gas Corp. and Louis Dreyfus Energy Corp. (incorporated by reference to Exhibit 10.3 of the Registrant's Form 10-Q for the quarter ended September 30, 1994).
10.9 Memorandum of Agreement, effective January 10, 1996, for the cancellation of a natural gas swap between the Registrant and Louis Dreyfus Energy Corp. (incorporated by reference to Exhibit 10.16 of the Registrant's Form 10-K for the fiscal year ended December 31, 1995).
*10.10 Amendment to Option Agreement of Simon B. Rich, Jr. (incorporated by reference to Exhibit 10.14 of the Registrant's Form 10-K for the fiscal year ended December 31, 1996).
*10.11 Form of Amendment to Outstanding Option Agreements of Employees (incorporated by reference to Exhibit 10.15 of the Registrant's Form 10-K for the fiscal year ended December 31, 1996).
*10.12 Form of Amendment to Outstanding Option Agreements of Non-Employee Directors (incorporated by reference to Exhibit 10.16 of the Registrant's Form 10-K for the fiscal year ended December 31, 1996).
*10.13 Employment Agreement, dated as of June 24, 1997, between Louis Dreyfus Natural Gas Corp. and Mark Andrews (incorporated by reference to Exhibit 10.3 to Form 8-K dated June 24, 1997, of American Exploration Company).
*10.14 Form of Change in Control Agreements between Registrant and Messrs. Mark E. Monroe, Jeffrey A. Bonney, Richard E. Bross, Ronnie K. Irani and Kevin R. White (incorporated by reference to Exhibit 10.1 of the Registrant's Form 10-Q for the quarter ended March 31, 1998).
*10.15 Louis Dreyfus Natural Gas Corp. Deferred Stock Trust Agreement dated April 14, 1998 (incorporated by reference to Exhibit 10.2 of the Registrant's Form 10-Q for the quarter ended March 31, 1998).
*10.16 Deferred Stock Award Agreement dated March 31, 1998 between Registrant and Mark E. Monroe (incorporated by reference to Exhibit 10.3 of the Registrant's Form 10-Q for the quarter ended March 31, 1998).
*10.17 Deferred Stock Award Agreement dated March 31, 1998 between Registrant and Richard E. Bross (incorporated by reference to Exhibit 10.4 of the Registrant's Form 10-Q for the quarter ended March 31, 1998).
*10.18 Deferred Stock Award Agreement dated March 31, 1998 between Registrant and Ronnie K. Irani (incorporated by reference to Exhibit 10.5 of the Registrant's Form 10-Q for the quarter ended March 31, 1998).
*10.19 Deferred Stock Award Agreement dated March 31, 1998 between Registrant and Kevin R. White (incorporated by reference to Exhibit 10.6 of the Registrant's Form 10-Q for the quarter ended March 31, 1998).
*10.20 Louis Dreyfus Natural Gas Corp. Non-employee Director Deferred Stock Trust Agreement dated December 1, 1998.
*10.21 Amendment No. 1 to Louis Dreyfus Natural Gas Corp. Deferred Stock Trust Agreement dated September 30, 1998.
Exhibit No. Description of Exhibit - -------------------------------------------------------------------------------- *10.22 Louis Dreyfus Natural Gas Corp. Non-Employee Director Deferred Stock Compensation Program as adopted effective July 23, 1998.
21.1 List of subsidiaries of the Registrant.
23.1 Consent of Independent Auditors.
24.1 Powers of Attorney.
27.1 Financial Data Schedule.
- ---------
* Constitutes a management contract or compensatory plan or arrangement required to be filed as an exhibit to this report.
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.
None.
Signatures
Pursuant to the requirements of Section 13 or 15(d) 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.
LOUIS DREYFUS NATURAL GAS CORP.
Date: March 12, 1999 By: /s/ JEFFREY A. BONNEY ------------------------------------- Jeffrey A. Bonney Executive Vice President and Chief Financial Officer
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.
LOUIS DREYFUS NATURAL GAS CORP. Index to Consolidated Financial Statements and Financial Statement Schedule
All other schedules for which provision is made in the applicable accounting regulations of the Securities and Exchange Commission are not required under the related instructions or are inapplicable and therefore have been omitted.
Report of Independent Auditors
The Board of Directors and Stockholders Louis Dreyfus Natural Gas Corp.
We have audited the accompanying consolidated balance sheets of Louis Dreyfus Natural Gas Corp. (the "Company") 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. Our audits also included the financial statement schedule listed in the Index to Item 14(a). These financial statements and the schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and the schedule 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 financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company at December 31, 1998 and 1997, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1998 in conformity with generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.
As discussed in Note 1 of the notes to the consolidated financial statements, effective October 1, 1998, the Company adopted Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities."
ERNST & YOUNG LLP
Oklahoma City, Oklahoma February 4, 1999
LOUIS DREYFUS NATURAL GAS CORP. Consolidated Balance Sheets
(dollars in thousands)
A S S E T S
See accompanying notes to consolidated financial statements.
LOUIS DREYFUS NATURAL GAS CORP. Consolidated Statements of Operations
(in thousands, except per share data)
See accompanying notes to consolidated financial statements.
LOUIS DREYFUS NATURAL GAS CORP. Consolidated Statements of Stockholders' Equity (in thousands)
See accompanying notes to consolidated financial statements.
LOUIS DREYFUS NATURAL GAS CORP. Consolidated Statements of Cash Flows (in thousands)
See accompanying notes to consolidated financial statements.
LOUIS DREYFUS NATURAL GAS CORP. Notes to Consolidated Financial Statements
Note 1. Significant Accounting Policies
General. Louis Dreyfus Natural Gas Corp. ("LDNG" or the "Company") is one of the largest independent natural gas companies in the United States engaged in the acquisition, development, exploration, production and marketing of natural gas and crude oil. At December 31, 1998, approximately 52% of the Company's Common Stock was owned by various subsidiaries of Societe Anonyme Louis Dreyfus & Cie (collectively "S.A. Louis Dreyfus et Cie"). See Note 6--Transactions with Related Parties. The accounting policies of LDNG reflect industry practices and conform to generally accepted accounting principles. The more significant of such policies are briefly described below.
Principles of Consolidation and Basis of Presentation. The accompanying consolidated financial statements include the accounts of LDNG and its wholly-owned subsidiaries after elimination of all material intercompany accounts and transactions. Certain reclassifications have been made in the financial statements for the years ended December 31, 1997 and 1996 to conform to the financial statement presentation for the year ended December 31, 1998.
Use of Estimates. The preparation of the financial statements in conformity with generally accepted accounting principles requires Management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.
Cash and Cash Equivalents. Cash and cash equivalents consist of all demand deposits and funds invested in short-term investments with original maturities of three months or less.
Concentration of Credit Risk. The Company sells oil and natural gas to various customers, participates with other parties in the drilling, completion and operation of oil and natural gas wells and enters into long-term energy swaps and physical delivery contracts. The majority of the Company's accounts receivable are due from purchasers of oil and natural gas and from fixed-price contract counterparties. Certain of these receivables are subject to collateral or margin requirements. The Company has established procedures to monitor credit risk and has not experienced significant credit losses in prior years. See Note 13--Fixed-Price Contracts--Credit Risk. As of December 31, 1998 and 1997, the Company's joint interest and other receivables are shown net of allowance for doubtful accounts of $1.2 million and $1.1 million, respectively.
Inventory. Inventory consists primarily of tubular goods and is carried at the lower of cost or market.
Property and Equipment. The Company utilizes the successful efforts method of accounting for oil and natural gas producing activities. Costs incurred in connection with the drilling and equipping of exploratory wells are capitalized as incurred. If proved reserves are not found, such costs are charged to expense. Other exploration costs, including delay rentals and seismic costs, are charged to expense as incurred. Development costs, which include the costs of drilling and equipping development wells, whether successful or unsuccessful, are capitalized as incurred. All general and administrative costs are expensed as incurred. Depreciation, depletion and amortization of capitalized costs of proved oil and gas properties is computed by the unit-of-production method on a field-by-field basis. The costs of unproved oil and gas properties are assessed quarterly on a property-by-property basis. If unproved properties are determined to be productive, the related costs are transferred to proved oil and gas properties. If unproved properties are determined not to be productive, or if the value of such properties has been otherwise impaired, the excess carrying value is charged to expense.
The Company's oil and gas properties are reviewed on a field-by-field basis for indications of impairment whenever events or circumstances indicate that the carrying value of its oil and gas properties may not be recoverable. In order to determine whether an impairment has occurred, the Company estimates the expected future net cash flows from its oil and gas properties as of the date of determination, and compares such future cash flows to the respective carrying amounts. Those oil and gas properties which have carrying amounts in excess of estimated future cash flows are deemed impaired. The carrying value of impaired properties is adjusted to an estimated fair value by discounting the estimated expected future cash flows attributable to such properties at a discount rate estimated to be representative of the market for such properties. The excess is charged to expense and may not be reinstated. For 1998, the Company recognized impairment charges aggregating $52.5 million. The associated impairment reviews were conducted as the result of declining oil and gas prices during the year which adversely affected the estimated future cash flows from the Company's oil and gas properties. Further weakening of oil and gas prices could result in future impairment recognition. In 1997, the Company recognized a $75.2 million impairment charge, substantially all of which was recorded in connection with the acquisition of American Exploration Company, a Houston-based exploration and production company ("American") in October 1997 (the "American Acquisition"). The allocation of the American Acquisition purchase price, based on the relative fair values of the acquired properties, was reviewed for indications of impairment. Such review resulted in the impairment charge recognition. See Note 3--Acquisitions.
LOUIS DREYFUS NATURAL GAS CORP. Notes to Consolidated Financial Statements (continued)
The Company provides for the estimated cost, at current prices, of dismantling and removing oil and gas production facilities. Such estimated costs are recorded at discounted values based on the estimated productive lives of the associated oil and gas property and amortized by the unit-of-production method. As of December 31, 1998 and 1997, estimated total future dismantling and restoration costs of $6.3 million and $5.8 million, respectively, were included in other liabilities in the accompanying balance sheets.
Depreciation of other property and equipment is provided by using the straight-line method over estimated useful lives of three to 20 years.
Debt Issuance Costs. Debt issuance costs are amortized over the term of the associated debt instrument using the straight-line method. The unamortized balance of such costs included in other assets as of December 31, 1998 and 1997, was $3.7 million and $4.1 million, respectively.
Oil and Gas Sales and Gas Imbalances. Oil and gas revenues are recognized as oil and gas is produced and sold. The Company uses the sales method of accounting for gas imbalances in those circumstances where the Company has underproduced or overproduced its ownership percentage in a property. Under this method, a liability is recorded to the extent that the Company's overproduced position in a reservoir cannot be recouped through the production of remaining reserves. At December 31, 1998 and 1997, the Company had recorded imbalance liabilities of $4.0 million and $3.2 million, respectively. Additionally, at December 31, 1998, the Company had imbalance receivables of $1.4 million.
Income Taxes. The Company files a consolidated United States income tax return which includes the taxable income or loss of its subsidiaries. Deferred federal and state income taxes are provided on all significant temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases.
Hedging. The Company reduces its exposure to unfavorable changes in oil and natural gas prices by utilizing fixed-price physical delivery contracts, energy swaps, collars, futures contracts, basis swaps and options (collectively "Fixed-Price Contracts"). The Company also enters into interest rate swap contracts to reduce its exposure to adverse interest rate fluctuations. In October 1998, the Company adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133") which establishes new accounting and reporting guidelines for derivative instruments and hedging activities. It requires that all derivative instruments be recognized as assets or liabilities in the statement of financial position, measured at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Designation is established at the inception of a derivative, but redesignation is permitted. For derivatives designated as cash flow hedges, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness, as defined by SFAS 133, is recognized immediately in earnings. Substantially all of the Company's Fixed-Price Contracts and interest rate swaps are designated as cash flow hedges. Changes in the fair value of derivative instruments which are not designated as hedges or are defined by SFAS 133 as being "fair value hedges" are recorded in earnings as the changes occur.
Adoption of the standard resulted in the reclassification of $62.2 million of deferred gains from price-risk management activities and $3.3 million of deferred hedging losses to accumulated other comprehensive income, recorded net of deferred income tax effects. In addition, adoption resulted in the recognition of $130.6 million of derivative assets and $7.6 million of derivative liabilities in the Company's balance sheet as of December 31, 1998. SFAS 133 precludes the consideration of future cash flows from derivative instruments in asset impairment determinations irrespective of any risk management intent for entering into such instruments. Adoption of the standard resulted in an additional impairment charge of $12.4 million which has been included in earnings as a cumulative effect of an accounting change. Also included in earnings as a cumulative effect of an accounting change are the following: $8.6 million of Fixed-Price Contract gains associated with the incremental impairment charge, $2.8 million of Fixed-Price Contract gains relating to contracts not qualifying as cash flow hedges, $1.5 million of Fixed-Price Contract gains relating to Fixed-Price Contract hedge ineffectiveness, and $1.1 million of net gain associated with a fair value hedge which hedged a portion of the Company's subordinated debt. See Note 4--Long-Term Debt, Note 10--Capital Stock and Stockholders' Equity Information, Note 12--Financial Instruments and Note 13--Fixed-Price Contracts. The Company does not hold or issue financial instruments with leveraged features.
Earnings per Share. The Company follows Statement of Financial Accounting Standards No. 128, "Earnings per Share" ("SFAS 128"), to compute earnings per share. Weighted average common shares outstanding used in the calculation of basic earnings per share for the years ended December 31, 1998, 1997, and 1996 (in thousands) were 40,107, 30,233 and 27,800, respectively. Dilutive potential common shares used in the calculation of diluted earnings per share for the years ended
LOUIS DREYFUS NATURAL GAS CORP. Notes to Consolidated Financial Statements (continued)
December 31, 1998, 1997 and 1996 (in thousands) were 40,107, 30,233 and 27,810, respectively. The increase in dilutive potential shares for 1996 is attributable to dilutive stock options. See Note 8--Employee Benefit Plans and Note 10--Capital Stock for a description of potentially dilutive securities of the Company.
Stock Options. The Company accounts for employee stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" and related interpretations. No compensation expense is recorded with respect to stock options granted at prices equal to the market value of the Company's Common Stock at the date of grant. Upon exercise, the excess of the proceeds over the par value of the shares issued is credited to additional paid-in capital. See Note 8--Employee Benefit Plans.
Note 2. Property and Equipment
Capitalized Costs. The Company's oil and gas acquisition, exploration and development activities are conducted primarily in Texas, Oklahoma, New Mexico and offshore in the Gulf of Mexico. The following table summarizes the capitalized costs associated with these activities:
Depreciation, depletion and amortization expense of oil and gas properties per Mcfe was $1.04, $.88 and $.82 for the years ended December 31, 1998, 1997 and 1996, respectively. Such amounts do not include impairment charges recorded in 1998 and 1997. See Note 1--Significant Accounting Policies. For the years ended December 31, 1998, 1997 and 1996, the Company capitalized $3.3 million, $1.0 million and $.4 million of interest, respectively, in connection with its exploration and development activities. Depreciation of other property and equipment was $4.1 million, $3.2 million and $2.6 million for the years ended December 31, 1998, 1997 and 1996, respectively.
Unproved properties at December 31, 1998 consist primarily of acreage positions obtained in the American Acquisition. The Company will evaluate such properties over their respective lease terms or as drilling results are determined.
Costs Incurred. The following table summarizes the costs incurred in the Company's acquisition, exploration and development activities for the years ended December 31, 1998, 1997 and 1996, respectively.
LOUIS DREYFUS NATURAL GAS CORP. Notes to Consolidated Financial Statements (continued)
Note 3. Acquisitions
In October 1997, the Company acquired 100% of the outstanding common stock of American for approximately 11.3 million shares of LDNG Common Stock valued at $17.15 per share and $47.2 million of cash. In addition, LDNG assumed $116 million of American long-term debt, $20 million liquidation value of American preferred stock and warrants and options valued at $10.3 million. The acquisition consisted of 217 Bcfe of proved reserves, approximately 3,500 producing wells, 1.0 million gross acres of developed leasehold, 2.0 million gross acres of undeveloped leasehold and other assets and liabilities. The purchase method was used to account for this acquisition.
The following unaudited pro forma results of operations data gives effect to the American Acquisition as if the transaction had occurred on January 1, 1996. The unaudited pro forma information is presented for illustrative purposes only and is not necessarily indicative of the actual results that would have occurred had these acquisitions closed on these respective dates or of future results of operations. The historic information has been adjusted for (1) oil and gas sales and related operating costs, (2) amortization of the oil and gas properties based on the purchase price, (3) incremental general and administrative expenses associated with the ownership of the properties, and (4) incremental interest expense resulting from the borrowings made under the Credit Facility, as hereinafter defined, in connection with each acquisition.
The pro forma information presented for 1997 and 1996 does not include a $73.1 million impairment charge recorded in connection with the American Acquisition, nor does it consider the effects of certain cost reduction plans, financing plans or the effects of certain purchase accounting adjustments (collectively "Pro Forma Adjustments"). The estimated combined financial impact of the Pro Forma Adjustments would be an increase in pro forma net income of $9.0 million, or $.23 per share, and $11.7 million, or $.30 per share, for the years ended December 31, 1997 and 1996, respectively.
During 1998, 1997 and 1996, the Company made numerous other acquisitions of proved oil and gas properties, the net purchase price of which aggregated $4.1 million, $9.1 million and $36.1 million, respectively. The results of operations related to such acquisitions have been included in the accompanying statements of operations and cash flows for the periods subsequent to the closing of each transaction.
Note 4. Long-Term Debt
Long-term debt consists of the following:
$450 Million Revolving Credit Facility. The Company has a revolving credit facility (the "Credit Facility") with a syndicate of banks which provides up to $450 million in borrowings (the "Commitment"). Letters of credit under the Credit Facility are limited to $75 million of such availability. The Credit Facility allows the Company to draw on the full $450 million credit line without restrictions tied to periodic revaluations of its oil and gas reserves provided the Company continues to maintain an investment grade credit rating from either Standard & Poor's Ratings Service or Moody's Investors Service. A borrowing base can be required only upon the vote by a majority in interest of the lenders after the loss of an investment grade credit rating. No principal payments are required under the Credit Facility prior to maturity on October 14, 2002.
LOUIS DREYFUS NATURAL GAS CORP. Notes to Consolidated Financial Statements (continued)
The Company has relied upon the Credit Facility to provide funds for acquisitions and to provide letters of credit to meet the Company's margin requirements under Fixed-Price Contracts. See Note 13--Fixed-Price Contracts. As of December 31, 1998, the Company had $295.0 million of principal and $17.8 million of letters of credit outstanding under the Credit Facility.
The Company has the option of borrowing at a LIBOR-based interest rate or the Base Rate (approximating the prime rate). The LIBOR interest rate margin and the facility fee payable under the Credit Facility are subject to a sliding scale based on the Company's senior debt credit rating. At December 31, 1998, the applicable interest rate was LIBOR plus 30 basis points. The Credit Facility also requires the payment of a facility fee equal to 15 basis points of the Commitment. At December 31, 1998, the effective interest rate for borrowings under the Credit Facility was 5.9%, including the effect of interest rate swaps.
The Credit Facility contains various affirmative and restrictive covenants which, among other things, limit total indebtedness to $700 million ($625 million of senior indebtedness) and require the Company to meet certain financial tests. Borrowings under the Credit Facility are unsecured.
Other Lines of Credit. The Company has certain other unsecured lines of credit available to it, which aggregated $45.0 million as of December 31, 1998. Such short-term lines of credit are primarily used to meet margin requirements under Fixed-Price Contracts and for working capital purposes. At December 31, 1998, the Company had $2.2 million of indebtedness and $.1 million of letters of credit outstanding under these credit lines. Repayment of indebtedness thereunder is expected to be made through Credit Facility availability.
6-7/8% Senior Notes due 2007. In December 1997, the Company issued $200 million principal amount, $198.8 million net of discount, of 6-7/8% Senior Notes due 2007 (the "Senior Notes"). Interest is payable semi-annually on June 1 and December 1. The associated indenture agreement contains restrictive covenants which place limitations on the amount of liens and the Company's ability to enter into sale and leaseback transactions.
9-1/4% Senior Subordinated Notes due 2004. In June 1994, the Company issued $100 million principal amount, $98.5 million net of discount, of 9-1/4% Senior Subordinated Notes due 2004 (the "Subordinated Notes"). Interest is payable semi-annually on June 15 and December 15. The associated indenture agreement contains restrictive covenants which limit, among other things, the prepayment of the Subordinated Notes, the incurrence of additional indebtedness, the payment of dividends and the disposition of assets.
The amount of required principal payments for the next five years and thereafter as of December 31, 1998 are as follows: 1999--$0; 2000--$0; 2001--$0; 2002--$297.2 million; 2003--$0; thereafter--$300 million.
Interest Rate Swaps. The Company has entered into interest rate swaps to hedge the interest rate exposure associated with borrowings under the Credit Facility. As of December 31, 1998, the Company had fixed the interest rate on average notional amounts of $158 million, $125 million, $125 million and $94 million for the years ended December 31, 1999, 2000, 2001 and 2002, respectively. Under the interest rate swaps, the Company receives the LIBOR three-month rate (5.1% at December 31, 1998) and pays an average rate of 5.3%, 5.0%, 5.0% and 5.0% for 1999, 2000, 2001 and 2002, respectively. The notional amounts are less than the maximum amount anticipated to be available under the Credit Facility in such years.
For each interest rate swap, the differential between the fixed rate and the floating rate multiplied by the notional amount is the swap gain or loss. Such gain or loss is included in interest expense in the period for which the interest rate exposure was hedged. If an interest rate swap is liquidated or sold prior to maturity, the gain or loss is recorded in accumulated other comprehensive income and amortized as interest expense over the original contract term. For the years ended December 31, 1998, 1997 and 1996, interest rate swaps increased interest expense by $.3 million, $.2 million and $.9 million, respectively.
As of October 1, 1998, the Company had one interest rate swap with a notional amount of $25 million, which pursuant to SFAS 133, was designated as a fair value hedge of a portion of the Subordinated Notes. As a result, cumulative effect of an accounting change in the statement of operations for the year ended December 31, 1998 included a gain of $2.7 million associated with the fair value of this interest rate swap and a loss of $1.6 million attributable to the fair value of the Subordinated Notes. This interest rate swap was terminated in the fourth quarter of 1998.
LOUIS DREYFUS NATURAL GAS CORP. Notes to Consolidated Financial Statements (continued)
Note 5. Income Taxes
The significant components of income tax expense (benefit) before cumulative effect of accounting change for the years ended December 31, 1998, 1997 and 1996 are as follows:
The provision for income taxes before cumulative effect of accounting change differed from the computed "expected" income tax provision using statutory rates on income before income taxes for the following reasons:
LOUIS DREYFUS NATURAL GAS CORP. Notes to Consolidated Financial Statements (continued)
Deferred tax assets and liabilities, resulting from differences between the financial statement carrying amounts and the tax bases of assets and liabilities, consist of the following:
At December 31, 1998, the Company had U.S. Federal net operating loss carryforwards of $202.5 million that expire beginning in 1999 and alternative minimum tax credit carryforwards of $5.9 million that can be carried forward indefinitely but which can be used only to reduce regular tax liabilities in excess of alternative minimum tax liabilities. Net operating loss carryforwards of $95.8 million are expected to expire without utilization due to the change of control provisions of Section 382 of the Internal Revenue Code. Such expirations have been fully reserved through the valuation allowance.
Note 6. Transactions With Related Parties
Fixed-Price Contract Activity. In 1993, the Company entered into a fixed-price sales contract with S.A. Louis Dreyfus et Cie hedging 33 Bcf of natural gas over a five-year period beginning in 1996, at a weighted-average fixed price of $2.49 per Mcf. For the years ended December 31, 1998 and 1996, the Company realized hedging gains of $2.9 million and $.8 million, respectively, in results of operations related to this contract. For 1997, the contract resulted in the recognition of a $.6 million hedging loss.
The Company uses the commodity trading resources of S.A. Louis Dreyfus et Cie when purchasing natural gas futures contracts on the New York Mercantile Exchange ("NYMEX"). In that regard, the Company reimburses S.A. Louis Dreyfus et Cie for margin posted on behalf of the Company. At December 31, 1998 and 1997, margin of $1.5 million and $4.5 million, respectively, had been posted on the Company's behalf by S.A. Louis Dreyfus et Cie under this arrangement.
In 1994, the Company entered into a Fixed-Price Contract with S.A. Louis Dreyfus et Cie which hedged 20 Bcf of natural gas production commencing January 1, 1996. This natural gas swap provided a weighted-average fixed price of approximately $2.18 per Mcf. In January 1996, the Company canceled this contract and received $1.6 million upon termination. The proceeds were deferred and amortized into oil and gas sales over the original 19-month term of the contract.
General and Administrative Expense. The Company is a party to a services agreement with S.A. Louis Dreyfus et Cie pursuant to which the Company is billed for certain administrative and support services (principally insurance costs and services) provided by S.A. Louis Dreyfus et Cie at amounts approximating cost. General and administrative expenses for the years ended December 31, 1998, 1997 and 1996 include $1.4 million, $.9 million and $.9 million, respectively, for such services.
Other. At December 31, 1998 and 1997, the Company owed S.A. Louis Dreyfus et Cie approximately $.1 million and $.7 million, respectively, principally for posted margin and miscellaneous general and administrative expenses. Such amounts are included in accounts payable in the accompanying balance sheets.
LOUIS DREYFUS NATURAL GAS CORP. Notes to Consolidated Financial Statements (continued)
Note 7. Commitments and Contingencies
Litigation. On December 22, 1995, the United States District Court for the Western District of Oklahoma entered a $10.8 million judgment in favor of the Company against Midcon Offshore, Inc. ("Midcon") in connection with non-performance by Midcon under an agreement to purchase a certain offshore oil and gas property. In January 1996, Midcon delivered a $10.8 million promissory note to the Company secured by first and second liens on assets of Midcon, payable in full on or before December 15, 1996 in settlement of disputes in connection with this litigation. During 1996, the Company received principal and interest payments on the promissory note totaling $1.7 million which have been reflected in the accompanying financial statements as other income. On December 16, 1996, Midcon filed for protection from its creditors under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court, Southern District of Texas, Corpus Christi Division. In January 1997, Midcon filed an action in the bankruptcy court alleging that Midcon's action in connection with the settlement constituted fraudulent transfers or avoidable preferences, and seeking a return of amounts paid and a release of the liens securing the payment obligation under the note. The complaint filed in the action also alleged certain affirmative claims against the Company including injury to reputation and loss of business opportunity. The complaint also seeks subordination of the Company's claim. The Court denied the Company's motion to dismiss the complaint. The Company considers the allegations of the complaint to be without merit and will vigorously defend against this action. Collection of unpaid interest and principal on the Midcon note is uncertain and no amounts have been recorded with respect thereto in the accompanying financial statements as of December 31, 1998. The Company will recognize income as any payments are received.
In February 1995, a lawsuit was filed in the United States District Court in Denver, Colorado, by KN Gas Supply Services, Inc. ("KNGSS"), requesting declaratory judgment that KNGSS had the right to reduce the contract price for gas produced from the Bowdoin Field, a property obtained in the American Acquisition, to market levels from October 1, 1993 forward. KNGSS alleges that it has overpaid American and seeks a refund of approximately $7.7 million for the period through September 1996. KNGSS has not updated its refund claim through the present date. A motion for summary judgment was filed by American in July 1996 and was argued before the court in February 1997. The Company assumed responsibility for this lawsuit in connection with the American Acquisition. In February 1998, the court ruled in favor of the Company's motion. KNGSS subsequently filed an appeal which has not been heard. Although the Company cannot predict the ultimate outcome of this proceeding, it will continue to vigorously defend its interests in this case and does not expect the outcome of the case to have a material adverse impact on its financial position or results of operations.
American was a defendant in various other legal proceedings for which the Company also assumed responsibility in the American Acquisition. The largest of such legal claims was for an alleged underpayment of royalty of $5.5 million plus interest. In addition, American had received preliminary and final royalty underpayment determinations from the Minerals Management Service aggregating approximately $2.8 million plus interest in connection with certain gas contract settlements made in prior years. The Company is a defendant in additional pending legal proceedings which are routine and incidental to its business. While the ultimate results of all these proceedings and determinations cannot be predicted with certainty, the Company will vigorously defend its interests and does not believe that the outcome of these matters will have a material adverse effect on the Company.
Rental Commitments. Minimum annual rental commitments as of December 31, 1998 under noncancelable office space leases are as follows: 1999--$3.1 million; 2000--$3.0 million; 2001--$2.2 million; 2002 and thereafter--$2.2 million. Approximately $3.8 million of such rental commitments is included in other long-term liabilities as of December 31, 1998, presented net of estimated future rental income to be received of $1.0 million. Rent expense included in results of operations for the three years ended December 31, 1998, 1997 and 1996 was $2.1 million, $1.1 million and $.9 million, respectively.
Note 8. Employee Benefit Plans
401(k) Plan. The Company's employees who have completed a specified term of service are eligible for participation in the Louis Dreyfus Natural Gas Profit Sharing and 401(k) Plan and Trust Agreement (the "401(k) Plan"). Pursuant to the plan provisions, employee contributions can be made up to 17% of compensation. Company contributions are discretionary. Employees vest in Company contributions at 20% per year of service. For the years ended December 31, 1998, 1997 and 1996, the Company contributed $1.2 million, $.9 million and $.9 million, respectively, to the 401(k) Plan.
Stock Compensation Plans. Certain executive officers of the Company were participants in the Louis Dreyfus Deferred Compensation Stock Equivalent Plan sponsored by S.A. Louis Dreyfus et Cie ("Stock Equivalent Plan"). Under this plan, participants were awarded stock equivalent rights ("SERs") expressed as a number of stock equivalent units. At December 31, 1997 and 1996, SERs totaling 83,500 and 85,000 stock equivalent units, respectively, were outstanding. Recorded compensation expense attributable to the SERs was approximately $.4 million for each of the years ended December 31, 1997 and 1996. In 1998, the Stock Equivalent Plan was terminated and replaced with the Louis Dreyfus Natural Gas Corp. Deferred
LOUIS DREYFUS NATURAL GAS CORP. Notes to Consolidated Financial Statements (continued)
Stock Trust Agreement ("Trust Agreement"). The Trust Agreement establishes a trust which serves as a depositary for restricted stock awards granted pursuant to the Trust Agreement. An aggregate of 55,000 shares previously earned under the Stock Equivalent Plan were purchased by the Company and contributed to the trust for distribution upon termination of employment or other specified events, thus eliminating the Company's obligations under the Stock Equivalent Plan. These transactions resulted in a net reduction to compensation expense of $.6 million after consideration for amounts previously recorded in connection with the Stock Equivalent Plan. Also during 1998, a separate deferred stock trust agreement was established to create a compensation program for the services of non-employee directors of the Company. In connection therewith, the Company purchased and contributed 8,000 shares of restricted stock during 1998.
Officers, directors and certain key employees have been granted options to purchase the Company's Common Stock under its 1993 Stock Option Plan (the "Option Plan"). Under the Option Plan, the Company may grant both incentive stock options intended to qualify under Section 422 of the Internal Revenue Code and options which are not qualified as incentive stock options. The maximum number of shares of Common Stock issuable under the Option Plan is 3.0 million shares, subject to appropriate equitable adjustment in the event of a reorganization, stock split, stock dividend, reclassification or other change affecting the Company's Common Stock. As of December 31, 1998 and 1997, options to purchase 875,420 shares and 291,670 shares of Common Stock, respectively, were available for grant under the Option Plan. Options granted under the Option Plan vest over a period of time based on the nature of the grants and as defined in the individual grant agreements, but generally over a four to five-year period. The exercise price of each option, with certain exceptions, equals the market price of the Company's stock on the date of grant and an option's expiration date is ten years from the date of issuance.
The following pro forma information, as required by Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"), presents net income and earnings per share information as if the Company had accounted for stock options issued after December 31, 1994 using the fair value method prescribed by that statement. The fair value of issued stock options was estimated at the date of grant using a Black-Scholes option pricing model. Valuation assumptions for option grants in 1998, 1997 and 1996 included the following: risk-free interest rates of 4.9%, 5.7% and 6.6%, respectively; no dividends over the option term; stock price volatility factors of .36, .32 and .31, respectively, and a weighted average expected option life of five years. The estimated fair value as determined by the model is amortized to expense over the respective vesting period. The SFAS 123 pro forma information presented below is not necessarily indicative of the pro forma effects to be presented in future periods. Additionally, option awards made prior to 1995 have been excluded.
The SFAS 123 pro forma information is as follows:
The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in Management's opinion, the existing models do not necessarily provide a reliable single measure of fair value of its stock options.
LOUIS DREYFUS NATURAL GAS CORP. Notes to Consolidated Financial Statements (continued)
Stock option transactions for 1998, 1997 and 1996 are summarized as follows:
(1) Excludes for 1997 the fair value of options to purchase 53,330 shares issued in connection with the American Acquisition and recorded as part of the corresponding purchase price. See Note 3--Acquisitions.
Outstanding options to acquire .9 million shares of stock at December 31, 1998 had exercise prices ranging from $18.00 to $23.16 per share and had a weighted-average remaining contractual life of 6.9 years. The balance of options outstanding at December 31, 1998 had exercise prices ranging from $12.63 to $17.71 per share and a weighted-average remaining contractual life of 8.8 years.
Note 9. Significant Customers
The Company's oil and gas sales at the wellhead are sold under contracts with various purchasers. For the year ended December 31, 1998, gas sales to PG&E Texas Industrial Energy, L.P. and Enron Capital and Trade Resources approximated 21% and 10% of total revenues, respectively. For the year ended December 31, 1997, gas sales to PG&E Texas Industrial Energy, L.P., Enron Capital and Trade Resources and GPM Gas Corporation approximated 22%, 15% and 10% of total revenues, respectively. For the year ended December 31, 1996, gas sales to Valero Industrial Gas, L.P., HPL Resources Corp. and GPM Gas Corporation approximated 18%, 13% and 11% of total revenues, respectively. The Company believes that alternative purchasers are available, if necessary, to purchase its production at prices substantially similar to those received from these significant purchasers in 1998.
Note 10. Capital Stock and Stockholders' Equity Information
Common Stock. The following table sets forth the Company's Common Stock activity for the periods presented:
Preferred Stock. In October 1997, in connection with the American Acquisition, the Company issued 800,000 depositary shares representing a 1/200 interest in a share of $450 Cumulative Convertible Preferred Stock ("Preferred Stock") to the holders of American preferred stock. In December 1997, in connection with the Company's redemption offer for the Preferred Stock at $26.35 per depositary share, holders of 783,675 depositary shares elected to convert into 940,649 shares of Common Stock and $3.9 million of cash. The remaining depositary shares were redeemed on December 31, 1997 for an aggregate cash payment of $.4 million.
Warrants. At December 31, 1998, the Company had outstanding warrants to purchase 1.6 million shares of Common Stock, all of which are currently exercisable, issued in connection with the American Acquisition for the outstanding
LOUIS DREYFUS NATURAL GAS CORP. Notes to Consolidated Financial Statements (continued)
warrants of American. The associated exercise prices range from $17.47 to $23.06 per share. Warrants to purchase .4 million shares expire April 1999; the balance expire December 2004.
Other Comprehensive Income. The components of other comprehensive income and related tax effects for the year ended December 31, 1998 are shown as follows:
Note 11. Supplemental Statement of Cash Flows Information
In October 1997, LDNG issued Common Stock, Preferred Stock, warrants and options and cash in connection with the American Acquisition. The accompanying financial statements include the following amounts attributable to the acquired assets and liabilities of American:
For the years ended December 31, 1998, 1997 and 1996, the Company paid interest of $38.3 million, $25.8 million and $25.3 million, respectively, net of capitalized interest, and paid income taxes of $.3 million, $1.0 million and $1.4 million, respectively.
Note 12. Financial Instruments
The following information is provided regarding the estimated fair value of the financial instruments, including derivative assets and liabilities as defined by SFAS 133, employed by the Company as of December 31, 1998 and 1997, and the methods and assumptions used to estimate the fair value of such financial instruments:
LOUIS DREYFUS NATURAL GAS CORP. Notes to Consolidated Financial Statements (continued)
(1) The Company adopted the provisions of SFAS 133 as of October 1, 1998 pursuant to which the fair value of the Company's derivative instruments are recorded as assets and liabilities in the balance sheet. See Note 1 -- Significant Accounting Policies -- Hedging.
(2) Carrying amounts do not include capitalized debt issuance costs. See Note 1--Significant Accounting Policies -- Debt Issuance Costs.
Cash and cash equivalents, accounts receivable, deposits, accounts payable, revenues payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount due to the short maturity of those instruments or to the criteria used to determine carrying value in the financial statements.
The fair value of Fixed-Price Contracts as of December 31, 1998 and 1997 was estimated based on market prices of natural gas and crude oil for the periods covered by the contracts. The net differential between the prices in each contract and market prices for future periods, as adjusted for estimated basis, has been applied to the volumes stipulated in each contract to arrive at an estimated future value. As of December 31, 1998, in connection with the adoption of SFAS 133, this estimated future value was discounted on a contract-by-contract basis at rates commensurate with the Company's estimation of contract performance risk and counterparty credit risk. For December 31, 1997 (prior to the adoption of SFAS 133), the Company discounted the future value at a rate of 10%, the discount factor prescribed by the Securities and Exchange Commission for discounting future net cash flows from its oil and gas properties. See Note 14--Supplemental Information--Oil and Gas Reserves. The terms and conditions of the Company's fixed-price physical delivery contracts and certain financial swaps are uniquely tailored to the Company's circumstances. In addition, certain of the Company's contracts hedge gas production for periods beyond five years into the future. The market for natural gas beyond the five year horizon is illiquid and published market quotations are not available. The Company has relied upon near-term market quotations, longer-term over-the-counter market quotations and other market information to determine its fair value estimates. The Fixed-Price Contract fair value as reflected in the balance sheet as of December 31, 1998 does not necessarily represent the value a third party would pay to assume the Company's positions.
The Company's bank debt bears interest at rates which move with market interest rates. Accordingly, the fair value of such debt at December 31, 1998 and 1997 was estimated to approximate the carrying amount. The fair values of the 6-7/8% Senior Notes due 2007 and the 9-1/4% Senior Subordinated Notes due 2004 were determined based on market quotations for such securities. The fair value of the Company's interest rate swaps for each of the years presented was based on market interest rates as of such dates.
Note 13. Fixed-Price Contracts
Description of Contracts. The Company has entered into Fixed-Price Contracts to reduce its exposure to unfavorable changes in oil and gas prices which are subject to significant and often volatile fluctuation. The Company's Fixed-Price Contracts are comprised of long-term physical delivery contracts, energy swaps, collars, futures contracts and basis swaps. These contracts allow the Company to predict with greater certainty the effective oil and gas prices to be received for its hedged production and benefit the Company when market prices are less than the fixed prices provided in its Fixed-Price Contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in such contracts for its hedged production. For the years ended December 31, 1998, 1997 and 1996, Fixed-Price Contracts hedged 50%, 60% and 51%, respectively, of the Company's gas production and 16%, 33% and 67%, respectively, of its oil production. As of December 31, 1998, Fixed-Price Contracts are in place to hedge 244 Bcf of the Company's estimated future gas production.
For energy swap sales contracts, the Company receives a fixed price for the respective commodity and pays a floating market price, as defined in each contract (generally NYMEX futures prices or a regional spot market index), to the counterparty. For physical delivery contracts, the Company purchases gas in the spot market at floating market prices and delivers such gas to the contract counterparty at a fixed price. Under energy swap purchase contracts, the Company pays a fixed price for the commodity and receives a floating market price. The Company's natural gas collars contain a fixed floor price (put) and ceiling price (call). If the market price of natural gas exceeds the call strike price or falls below the put strike price, then the Company receives the fixed price and pays the market price. If the market price of natural gas is between the call and the put strike price, then no payments are due from either party. Under the Company's basis swaps, the Company receives the floating market price for NYMEX futures and pays the floating market price plus a fixed differential for a specified regional spot market index.
The following table summarizes the estimated volumes, fixed prices, fixed-price sales, fixed-price purchases and future net revenues (as defined below) attributable to the Company's Fixed-Price Contracts as of December 31, 1998.
LOUIS DREYFUS NATURAL GAS CORP. Notes to Consolidated Financial Statements (continued)
(1) The Company expects the prices to be realized for its hedged production will vary from the prices shown due to location, quality and other factors which create a differential between wellhead prices and the floating prices under its Fixed-Price Contracts. See "Market Risk."
(2) Future net revenues for any period are determined as the differential between the fixed prices provided by Fixed-Price Contracts and forward market prices as of December 31, 1998, as adjusted for basis. Future net revenues change with changes in market prices and basis. See "Market Risk." Future net revenues as presented herein are undiscounted and have not been adjusted for contract performance risk or counterparty credit risk. See Note 12--Financial Instruments.
(3) Does not include basis swaps with notional volumes by year, as follows: 1999-19.0 TBtu; 2000-21.3 TBtu; 2001-9.4 TBtu; and 2002-5.5 TBtu.
LOUIS DREYFUS NATURAL GAS CORP. Notes to Consolidated Financial Statements (continued)
The estimates of future net revenues from the Company's Fixed-Price Contracts are computed based on the difference between the prices provided by the Fixed-Price Contracts and forward market prices as of the specified date. The market for natural gas beyond a five year horizon is illiquid and published market quotations are not available. The Company has relied upon near-term market quotations, longer-term over-the-counter market quotations and other market information to determine its future net revenue estimates. Forward market prices for natural gas are dependent upon supply and demand factors in such forward market and are subject to significant volatility. The future net revenue estimates shown above are subject to change as forward market prices change. See Note 12--Financial Instruments for estimated fair value information.
Accounting. All of the Company's Fixed-Price Contracts have been executed in connection with its natural gas and crude oil hedging program and not for trading purposes. Further, all Fixed-Price Contracts have performed according to Management expectations in reducing the Company's exposure to adverse movements in commodity prices. However, SFAS 133 has very specific guidelines for measuring hedge effectiveness. Certain of the Company's contracts did not meet this criteria although they continue to perform as anticipated. For Fixed-Price Contracts qualifying as hedges pursuant to SFAS 133, the differential between the fixed price and the floating price for each contract settlement period multiplied by the associated contract volumes is the contract profit or loss. The realized contract profit or loss is included in oil and gas sales in the period for which the underlying commodity was hedged. Changes in market value for these contracts for volumes not yet settled are not reflected in the Company's income statements, but rather are shown as adjustments to other comprehensive income. For those contracts not qualifying as hedges, the associated fair value, as well as future changes in market value, are recognized in earnings. The fair value of all of its Fixed-Price Contracts are recorded as assets or liabilities in the Company's balance sheet.
If a Fixed-Price Contract which qualified for hedge accounting is liquidated or sold prior to maturity, the gain or loss is deferred and amortized into oil and gas sales over the original term of the contract. At December 31, 1998, the Company had pretax unamortized deferred gains of $61.3 million which were recorded net of deferred tax effects in accumulated other comprehensive income. Prior to the adoption of SFAS 133, the Company recorded gains and losses from contract terminations as deferred liabilities and assets, respectively. At December 31, 1997, the balance of deferred gains from price-risk management activities was $23.5 million. Prepayments received under Fixed-Price Contracts with continuing performance obligations are recorded as deferred revenue and amortized into oil and gas sales over the term of the underlying contract. See Note 1--Significant Accounting Policies--Hedging.
For the years ended December 31, 1998, 1997 and 1996, oil and gas sales included $23.1 million of net gains, $4.3 million of net losses and $2.1 million of net losses, respectively, associated with realized gains and losses under its Fixed-Price Contracts. Other income for the year ended December 31, 1998 included $2.5 million of gain attributable to contract hedge ineffectiveness and the change in fair value of contracts not qualifying as cash flow hedges.
Credit Risk. The terms of the Company's Fixed-Price Contracts generally provide for monthly settlements and energy swap contracts provide for the netting of payments. The counterparties to the contracts are comprised of independent power producers, pipeline marketing affiliates, financial institutions, a municipality and S.A. Louis Dreyfus et Cie, among others. In some cases, the Company requires letters of credit or corporate guarantees to secure the performance obligations of the contract counterparty. Should a counterparty to a contract default on a contract, there can be no assurance that the Company would be able to enter into a new contract with a third party on terms comparable to the original contract. The Company has not experienced non-performance by any counterparty.
The Company was a party to two Fixed-Price Contracts, both long-term physical delivery contracts, with independent power producers ("IPPs") which sold electrical power under firm, fixed-price contracts to Niagara Mohawk Corporation ("NIMO"), a New York state utility ("NIMO Contracts"). The ability of these IPPs to perform their obligations to the Company was dependent on the continued performance by NIMO of its power purchase obligations to the counterparties. NIMO has taken aggressive regulatory, judicial and contractual actions in recent years seeking to curtail power purchase obligations, including its obligations to the NIMO Contract counterparties, and had further stated that its future financial prospects were dependent on its ability to resolve these obligations, along with other matters. In July 1997, NIMO entered into a Master Restructuring Agreement (the "MRA") with 16 IPPs, including the NIMO Contract counterparties. Subsequently, one of the NIMO Contract counterparties withdrew from the MRA. The power purchase agreement between NIMO and the other counterparty was terminated. In connection therewith, the Company agreed to terminate its fixed-price contract to the counterparty in exchange for $40.1 million, the receipt of which has been recorded in accumulated other comprehensive income, net of tax effect. The remaining NIMO Contract which hedges 54 Bcf of natural gas as of December 31, 1998 remains in force and is reflected in the Company's balance sheet at a fair value of $72 million. The Company continues to deliver natural gas pursuant to the terms of this contract which expires in 2007. NIMO has continued to seek relief from its contractual
LOUIS DREYFUS NATURAL GAS CORP. Notes to Consolidated Financial Statements (continued)
obligations under this contract in the court system. Although there can be no assurance, Management does not expect that NIMO will ultimately succeed in these efforts.
Cancellation or termination of a Fixed-Price contract would subject a greater portion of the Company's gas production to market prices, which, in a low price environment, could have an adverse effect on the Company's future operating results. In addition, the associated carrying value of the contract would be removed from the Company's balance sheet. Any associated proceeds would be reflected in accumulated other comprehensive income, net of income tax effects, and amortized into earnings over the original contract term.
Market Risk. The Company's natural gas Fixed-Price Contracts at December 31, 1998 hedge 244 Bcf of proved natural gas reserves at fixed prices, representing 20% of its estimated proved natural gas reserves. If the Company's proved natural gas reserves are produced at rates less than anticipated, Fixed-Price Contract volumes could exceed production volumes. In such case, the Company would be required to satisfy its contractual commitments for any excess volumes at market prices in effect for each settlement period, which may be above the contract price, without a corresponding offset in wellhead revenue. The Company expects future production volumes to be equal to or greater than the volumes provided in its contracts.
The differential between the floating price paid under each energy swap contract, or the cost of gas to supply physical delivery contracts, and the price received at the wellhead for the Company's production is termed "basis" and is the result of differences in location, quality, contract terms, timing and other variables. The effective price realizations which result from the Company's Fixed-Price Contracts are affected by movements in basis. For the years ended December 31, 1998, 1997 and 1996, the Company received on an Mcf basis approximately 6%, 1% and 3% less than the prices specified in its natural gas Fixed-Price Contracts, respectively, due to basis. For its oil production hedged by crude oil Fixed-Price Contracts, the Company realized approximately 10%, 4% and 4% less than the specified contract prices for such years, respectively. Basis movements can result from a number of variables, including regional supply and demand factors, changes in the Company's portfolio of Fixed-Price Contracts and the composition of the Company's producing property base. Basis movements are generally considerably less than the price movements affecting the underlying commodity, but their effect can be significant. A 1% move in price realization for hedged natural gas in 1999 represents a $1.0 million change in gas sales. The Company actively manages its exposure to basis movements and from time to time will enter into contracts designed to reduce such exposure.
Except for the effect of basis movements, the Company expects that any changes in Fixed-Price Contract fair value attributable to changes in market prices for natural gas will be offset by changes in the value of its natural gas reserves. This change in natural gas reserve value, however, is not reflected in the Company's balance sheet. Further, changes in future gains and losses to be realized in oil and gas sales upon future settlements of Fixed-Price Contracts as a result of changes in market prices for natural gas are expected to be offset by changes in the price received for the Company's hedged natural gas production.
Margin. The Company is required to post margin in the form of bank letters of credit or treasury bills under certain of its Fixed-Price Contracts. In some cases, the amount of such margin is fixed; in others, the amount changes as the market value of the respective contract changes, or if certain financial tests are not met. For the years ended December 31, 1998, 1997 and 1996, the maximum aggregate amount of margin posted by the Company was $23.7 million, $28.7 million and $28.4 million, respectively. If natural gas prices were to rise, or if the Company fails to meet the financial tests contained in certain of its Fixed-Price Contracts, margin requirements could increase significantly. The Company believes that it will be able to meet such requirements through the Credit Facility and such other credit lines that it has or may obtain in the future. If the Company is unable to meet its margin requirements, a contract could be terminated and the Company could be required to pay damages to the counterparty which generally approximate the cost to the counterparty of replacing the contract. At December 31, 1998, the Company had issued margin in the form of letters of credit and treasury bills totaling $17.0 million and $1.5 million, respectively. In addition, approximately 29 Bcf of the Company's proved gas reserves are mortgaged to a Fixed-Price Contract counterparty, securing the Company's performance under the associated contract.
Note 14. Supplemental Information--Oil and Gas Reserves (unaudited)
The following information summarizes the Company's net proved reserves of crude oil and natural gas and the present values thereof for the three years ended December 31, 1998, 1997 and 1996. Reserve estimates for these years have been prepared by the Company's petroleum engineers and reviewed by an independent engineering firm. All studies have been prepared in accordance with regulations prescribed by the Securities and Exchange Commission. Future net revenue is estimated by such engineers using oil and gas prices in effect as of the end of each respective year with price escalations permitted only for those properties which have wellhead contracts allowing specific increases. Future operating costs estimated in each study
LOUIS DREYFUS NATURAL GAS CORP. Notes to Consolidated Financial Statements (continued)
are based on historical operating costs incurred. Reserve quantity estimates are calculated without regard to prices in the Company's Fixed-Price Contracts.
The reliability of any reserve estimate is a function of the quality of available information and of engineering interpretation and judgment. Such estimates are susceptible to revision in light of subsequent drilling and production history or as a result of changes in economic conditions.
Estimated Quantities of Oil and Gas Reserves (unaudited). The following table sets forth the Company's estimated proved reserves, all of which are located in the United States, for the years ended December 31, 1998, 1997 and 1996:
(1) The crude oil volume revision for 1998 was primarily the result of a significant reduction in year-end 1998 crude oil prices compared to the prior year-end.
Standardized Measure of Discounted Future Net Cash Flows (unaudited). The following table reflects the standardized measure of discounted future net cash flows relating to the Company's interests in proved oil and gas reserves. The future net cash inflows were developed as follows:
(1) Estimates were made of quantities of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions.
(2) The estimated cash flows from future production of proved reserves were prepared on the basis of prices received at December 31, 1998, 1997 and 1996, as adjusted for the effects of the Company's existing Fixed- Price Contracts, as follows: 1998--$9.46 per Bbl, $2.30 per Mcf; 1997--$16.77 per Bbl, $2.73 per Mcf; and 1996--$24.66 per Bbl, $3.55 per Mcf.
(3) The resulting future gross revenue streams were reduced by estimated future costs to develop and to produce the proved reserves and estimated abandonment costs for offshore properties, based on year-end estimates.
(4) Future income taxes were computed by applying the appropriate statutory tax rates to the future pretax net cash flows less the current tax basis of the properties involved and related carryforwards, giving effect to permanent differences and tax credits.
(5) The resulting future net revenue streams were reduced to present value amounts by applying a 10% discount factor.
LOUIS DREYFUS NATURAL GAS CORP. Notes to Consolidated Financial Statements (continued)
(1) Future cash inflows and the standardized measure of discounted future net cash flows include the expected cash flow contribution of the Company's Fixed-Price Contracts based on year-end oil and gas prices. Such future cash inflows have not been adjusted for contract performance risk or counterparty credit risk. See Note 12--Financial Instruments.
(2) The standardized measure of discounted future net cash flows excluding the effect of the Company's Fixed-Price Contracts was $719.7 million, $873.5 million and $922.6 million as of December 31, 1998, 1997 and 1996, respectively.
(3) The SEC PV10% amounts give no effect to federal or state income taxes attributable to estimated future net revenues.
The standardized measure information in the preceding table was derived from estimates of the Company's proved oil and gas reserves contained in studies prepared by petroleum engineers. Neither the standardized measure calculation, prepared pursuant to the provisions of Statement of Financial Accounting Standards No. 69, nor the SEC PV10% amounts, purport to represent the fair market value of the Company's oil and gas reserves. The foregoing information is presented for comparative purposes as of the Company's year-end and is not intended to reflect any changes in value which may result from future price fluctuations.
Changes Relating to the Standardized Measure of Discounted Future Net Cash Flows (unaudited). The principal changes in the standardized measure of discounted future net cash flows attributable to the Company's oil and gas reserves for the years ended December 31, 1998, 1997 and 1996, were as follows:
LOUIS DREYFUS NATURAL GAS CORP. Notes to Consolidated Financial Statements (continued)
Note 15. Quarterly Results (unaudited)
(1) The revenue increase in the fourth quarter of 1997 is largely attributable to the American Acquisition. Revenue increases in the first quarter of 1997 and the fourth quarter of 1997 were also favorably impacted by higher oil and gas prices.
(2) The decrease in operating profit in the second quarter of 1998 is attributable to a $9.9 million impairment charge. Also, operating losses in the fourth quarters of 1998 and 1997 were attributable to impairment charges of $42.6 million and $75.2 million, respectively. See Note 1--Significant Accounting Policies.
(3) Net losses in 1998 resulted from lower oil and gas prices and impairment charges previously discussed.
LOUIS DREYFUS NATURAL GAS CORP. Schedule II--Consolidated Valuation and Qualifying Accounts (in thousands)
(1) Additions relate to provisions for doubtful accounts charged to general and administrative expense.
(2) Deductions relate to the write-off of accounts receivable deemed uncollectible.
INDEX TO EXHIBITS
Exhibit No. Description of Exhibit --- ----------------------
2.1 Agreement and Plan of Reorganization dated as of June 24, 1997, as amended, between Louis Dreyfus Natural Gas Corp. and American Exploration Company (incorporated herein by reference to Annex A to Louis Dreyfus Natural Gas Corp.'s Joint Proxy Statement/Prospectus filed with the Securities and Exchange Commission on September 12, 1997 pursuant to Rule 424(b)(3) relating to Louis Dreyfus Natural Gas Corp.'s Registration Statement on Form S-4, Registration No. 333-34849).
3.1 Amended and Restated Certificate of Incorporation of the Registrant (incorporated by reference to Exhibit 3.1 of the Registrant's Registration Statement on Form S-1, Registration No. 33-69102).
3.2 Certificate of Merger of the Registrant dated September 9, 1993 (incorporated by reference to Exhibit 3.2 of the Registrant's Registration Statement on Form S-1, Registration No. 33-69102).
3.3 Amended and Restated Bylaws of the Registrant (incorporated by reference to Exhibit 3.3 of the Registrant's Registration Statement on Form S-1, Registration No. 33-69102).
3.4 Certificate of Merger of the Registrant dated November 1, 1993 (incorporated by reference to Exhibit 3.4 of the Registrant's Registration Statement on Form S-1, Registration No. 33-69102).
4.1 Indenture agreement dated as of June 15, 1994 for $100,000,000 of 9-1/4% Senior Subordinated Notes due 2004 between Louis Dreyfus Natural Gas Corp., as Issuer, and Bank of Montreal Trust Company, as Trustee (incorporated by reference to Exhibit 10.2 of the Registrant's Form 10-Q for the quarter ended September 30, 1994).
4.2 Indenture agreement dated as of December 11, 1997 for $200,000,000 of 6-7/8% Senior Notes due 2007 between Louis Dreyfus Natural Gas Corp. and LaSalle National Bank as Trustee (incorporated by reference to Exhibit 4.1 of the Registrant's Registration Statement on Form S-4, Registration No. 333-45773).
10.1 Stock Option Plan of Louis Dreyfus Natural Gas Corp. as amended and restated effective December 1998.
10.2 Form of Indemnification Agreement with directors of the Registrant (incorporated by reference to Exhibit 10.2 of the Registrant's Registration Statement on Form S-1, Registration No. 33-69102).
10.3 Registration Rights Agreement between the Registrant and Louis Dreyfus Natural Gas Holdings Corp. (incorporated by reference to Exhibit 10.3 of the Registrant's Registration Statement on Form S-1, Registration No. 33-76828).
10.4 Amendment dated December 22, 1993 to Registration Rights Agreement between the Registrant, Louis Dreyfus Natural Gas Holdings Corp. and S.A. Louis Dreyfus et Cie (incorporated by reference to Exhibit 10.4 of the Registrant's Registration Statement on Form S-1, Registration No. 33-76828).
10.5 Services Agreement between the Registrant and Louis Dreyfus Holding Company, Inc. (incorporated by reference to Exhibit 10.5 of the Registrant's Registration Statement Form S-1, Registration No. 33-76828).
10.6 Credit Agreement dated as of October 14, 1997, among Louis Dreyfus Natural Gas Corp., as Borrower, Bank of Montreal, as Administrative Agent, Chase Manhattan Bank, as Syndication Agent, NationsBank of Texas, N.A., as Documentation Agent, and certain other lenders signatory thereto (incorporated by reference to Exhibit 10.1 of the Registrant's Form 8-K dated October 14, 1997).
10.7 Swap Agreement dated November 1, 1993 between the Registrant and Louis Dreyfus Energy Corp.
(incorporated by reference to Exhibit 10.17 of the Registrant's Registration Statement on Form S-1, Registration No. 33-69102).
10.8 Memorandum of Agreement for a natural gas swap dated September 16, 1994, between Louis Dreyfus Natural Gas Corp. and Louis Dreyfus Energy Corp. (incorporated by reference to Exhibit 10.3 of the Registrant's Form 10-Q for the quarter ended September 30, 1994).
10.9 Memorandum of Agreement, effective January 10, 1996, for the cancellation of a natural gas swap between the Registrant and Louis Dreyfus Energy Corp. (incorporated by reference to Exhibit 10.16 of the Registrant's Form 10-K for the fiscal year ended December 31, 1995).
10.10 Amendment to Option Agreement of Simon B. Rich, Jr. (incorporated by reference to Exhibit 10.14 of the Registrant's Form 10-K for the fiscal year ended December 31, 1996).
10.11 Form of Amendment to Outstanding Option Agreements of Employees (incorporated by reference to Exhibit 10.15 of the Registrant's Form 10-K for the fiscal year ended December 31, 1996).
10.12 Form of Amendment to Outstanding Option Agreements of Non-Employee Directors (incorporated by reference to Exhibit 10.16 of the Registrant's Form 10-K for the fiscal year ended December 31, 1996).
10.13 Employment Agreement, dated as of June 24, 1997, between Louis Dreyfus Natural Gas Corp. and Mark Andrews (incorporated by reference to Exhibit 10.3 to Form 8-K dated June 24, 1997, of American Exploration Company).
10.14 Form of Change in Control Agreements between Registrant and Messrs. Mark E. Monroe, Jeffrey A. Bonney, Richard E. Bross, Ronnie K. Irani and Kevin R. White (incorporated by reference to Exhibit 10.1 of the Registrant's Form 10-Q for the quarter ended March 31, 1998).
10.15 Louis Dreyfus Natural Gas Corp. Deferred Stock Trust Agreement dated April 14, 1998 (incorporated by reference to Exhibit 10.2 of the Registrant's Form 10-Q for the quarter ended March 31, 1998).
10.16 Deferred Stock Award Agreement dated March 31, 1998 between Registrant and Mark E. Monroe (incorporated by reference to Exhibit 10.3 of the Registrant's Form 10-Q for the quarter ended March 31, 1998).
10.17 Deferred Stock Award Agreement dated March 31, 1998 between Registrant and Richard E. Bross (incorporated by reference to Exhibit 10.4 of the Registrant's Form 10-Q for the quarter ended March 31, 1998).
10.18 Deferred Stock Award Agreement dated March 31, 1998 between Registrant and Ronnie K. Irani (incorporated by reference to Exhibit 10.5 of the Registrant's Form 10-Q for the quarter ended March 31, 1998).
10.19 Deferred Stock Award Agreement dated March 31, 1998 between Registrant and Kevin R. White (incorporated by reference to Exhibit 10.6 of the Registrant's Form 10-Q for the quarter ended March 31, 1998).
10.20 Louis Dreyfus Natural Gas Corp. Non-employee Director Deferred Stock Trust Agreement dated December 1, 1998.
10.21 Amendment No. 1 to Louis Dreyfus Natural Gas Corp. Deferred Stock Trust Agreement dated September 30, 1998.
10.22 Louis Dreyfus Natural Gas Corp. Non-Employee Director Deferred Stock Compensation Program as adopted effective July 23, 1998.
21.1 List of subsidiaries of the Registrant.
23.1 Consent of Independent Auditors.
24.1 Powers of Attorney.
27.1 Financial Data Schedule.