(Mark One)
Commission File No. 0-16741
| NEVADA | 94-1667468 | ||||
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification Number) |
| Common Stock, $.50 Par Value | New York Stock Exchange | ||||
| Preferred Stock Purchase Rights | New York Stock Exchange | ||||
| (Title of class) | (Name of exchange on which registered) |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [ X ] No [ ].
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant ’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K. [ ]
As of March 9, 2001, there were 29,139,469 shares of common stock outstanding.
As of March 9, 2001, the aggregate market value of the voting stock held by non-affiliates of the registrant was approximately $370,574,000.
Proxy statement for the 2001 annual meeting of stockholders - Part III
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in this report, including without limitation, statements under “Business and Properties” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” regarding budgeted capital expenditures, increases in oil and natural gas production, the Company’s financial position, oil and natural gas reserve estimates, business strategy and other plans and objectives for future operations, are forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. Furthermore, the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary from one another. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revisions of such estimate and such revision, if significant, would change the schedule of any further production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and gas that are ultimately recovered. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, our actual results and plans for 2001 and beyond could differ materially from those expressed in forward-looking statements. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by such factors.
The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report. Natural gas equivalents and crude oil equivalents are determined using the ratio of six Mcf to one barrel.
“API” means American Petroleum Institute.
“Bbl” means a barrel of 42 U.S. gallons of oil.
“Bcf” means one billion cubic feet of natural gas.
“Bcfe” means one billion cubic feet of natural gas equivalent.
“Btu” means British thermal unit, which is the quantity of heat required to raise the temperature of one pound of water from 58.5 to 59.5 degrees Fahrenheit.
“Cash Margin per Mcfe” means the equivalent price per Mcfe less oil and gas operating expenses per Mcfe and general and administrative expenses per Mcfe.
“Completion” means the installation of permanent equipment for the production of oil or gas.
“Condensate” means a hydrocarbon mixture that becomes liquid and separates from natural gas when the gas is produced and is similar to crude oil.
“Development well” means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
“Dry hole” means a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
“Exploratory well” means a well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new productive reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.
“Gross” when used with respect to acres or wells, production or reserves refers to the total acres or wells in which the Company or other specified person has a working interest.
“MBbls” means one thousand barrels of oil.
“MMBbls” means one million barrels of oil.
“Mcf” means one thousand cubic feet of natural gas.
“Mcfe” means thousand cubic feet of natural gas equivalent.
“MMcf” means one million cubic feet of natural gas.
“MMcfe” means one million cubic feet of natural gas equivalent.
“Net” when used with respect to acres or wells, refers to gross acres of wells multiplied, in each case, by the percentage working interest owned by the Company.
“Net production” means production that is owned by the Company less royalties and production due others.
“Oil” means crude oil or condensate.
“Operator” means the individual or company responsible for the exploration, development, and production of an oil or gas well or lease.
“Present Value of Proved Reserves” means the present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with the Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to nonproperty related expenses such as general and administrative expenses, debt service, future income tax expense and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.
“Proved developed reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery will be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
“Proved reserves” means the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
| (i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. |
| (ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. |
| (iii) Estimates of proved reserves do not include the following: (a) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (b) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (c) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (d) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such resources. |
“Proved undeveloped reserves” means reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
“Recompletion” means the completion for production of an existing well bore in another formation from which the well has been previously completed.
“Reserve life” means the calculation derived by dividing year-end reserves by total production in that year.
“Reserve replacement” means the calculation derived by dividing additions to reserves from acquisitions, extensions, discoveries and revisions of previous estimates in a year by total production in that year.
“Royalty” means an interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
“3-D seismic” means an advanced technology method of detecting accumulations of hydrocarbons identified by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.
“Working interest” means an interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties. For example, the owner of a 100% working interest in a lease burdened only by a landowner’s royalty of 12.5% would be required to pay 100% of the costs of a well but would be entitled to retain 87.5% of the production.
“Workover” means operations on a producing well to restore or increase production.
Comstock Resources, Inc., together with its subsidiaries (the “Company” or “Comstock”), is an independent energy company engaged in the acquisition, development, production and exploration of oil and natural gas properties with an increasing focus on exploration. The Company’s oil and natural gas reserve base is entirely concentrated in the Gulf of Mexico, Southeast Texas and East Texas/North Louisiana regions. The Company’s reserve base is 74% natural gas and 68% proved developed on a Bcfe basis as of December 31, 2000. The estimated proved oil and natural gas reserves are 402.5 Bcfe with an estimated Present Value of Proved Reserves of $1.8 billion as of December 31, 2000 and the Company operates 73% of the Present Value of Proved Reserves of its properties. For the year ended December 31, 2000, the Company’s total revenues and EBITDA were $169.7 million and $136.5 million, respectively.
The Company's proved reserves at December 31, 2000 and its 2000 average daily production are summarized below:
Reserves at December 31, 2000 2000 Daily Production
---------------------------------- ---------------------------------
% of % of
Oil Gas Total Total Oil Gas Total Total
----- ----- ----- ----- ----- ----- ----- -----
(MMBbls) (Bcf) (Bcfe) (MBbls/d)(Mmcfe/d) (MMcfe/d)
Gulf of Mexico ........... 13.1 63.5 142.1 35.3% 3.2 15.4 34.8 33.6%
Southeast Texas .......... 3.7 110.4 132.5 32.9 1.5 35.5 44.7 43.1
East Texas/North Louisiana 0.6 123.5 127.3 31.6 0.2 22.7 23.6 22.8
Other .................... 0.1 0.4 0.6 0.2 0.1 0.3 0.6 0.5
----- ----- ----- ----- ----- ----- ----- -----
Total ................ 17.5 297.8 402.5 100.0% 5.0 73.9 103.7 100.0%
===== ===== ===== ===== ===== ===== ===== =====
Quality Properties. Comstock’s operations are located in three geographically concentrated areas, the Gulf of Mexico, Southeast Texas and East Texas/North Louisiana regions, which account for approximately 35%, 33% and 32% of its proved reserves, respectively. The Company has high price realizations relative to benchmark prices for natural gas and crude oil production. The Company also has favorable operating costs which gives it high cash margins. Finally, Comstock’s properties have an average reserve life of approximately 10.6 years and have extensive development and exploration potential.
Successful Exploration and Development Program. In 2000, Comstock continued to focus on the exploitation and development of its properties through development drilling, recompletions and workovers with expenditures of $46.9 million. Overall, the Company drilled 37 development wells (19.7 net) with an 100% success rate. The Company also had a successful exploratory drilling program in 2000, spending a total of $19.2 million to drill 12 wells (4.8 net) with a 58% success rate. The Company also spent $5.3 million in acquiring new acreage and seismic data in 2000 to support its exploration program.
Successful Acquisitions. The Company has historically grown through acquisitions. Since 1991, Comstock has added 502.4 Bcfe of proved oil and natural gas reserves from 25 acquisitions at an average cost of $0.85 per Mcfe. The Company’s application of strict economic and reserve risk criteria enables it to successfully evaluate and integrate acquisitions.
Efficient Operator. Comstock operates 73% of its Present Value of Proved Reserves as of December 31, 2000. This allows the Company to control operating costs, the timing and plans for future development, the level of drilling and lifting costs and the marketing of production. Because the Company owns interests in a fewer number of wells with higher production rates per well as compared to many of its peers and has relatively low corporate overhead, its general and administrative expenses per unit of production are generally lower than those of its peers.
High Price Realizations. The majority of the Company’s wells are located in areas which can access attractive natural gas and crude oil markets. In addition, the Company’s natural gas production has a relatively high Btu content (approximately 1,100 Btu) and its crude oil production has a favorable API gravity (approximately 40 degrees). Due to these factors, Comstock has relatively high price realizations compared to benchmark prices. In 2000 the Company’s average natural gas price was $4.26 per Mcf, which represented a $0.37 premium to the average 2000 NYMEX monthly settlement price. Also in 2000, the Company’s average crude oil price was $30.02 per barrel, which represented a $2.63 per barrel premium to the average monthly West Texas intermediate crude oil price for 2000 posted by Koch Industries, Inc.
High Cash Margins. As a result of its quality properties, higher price realizations and efficient operations, Comstock has higher cash margins. Consequently, the Company’s oil and natural gas reserves have a higher value per Mcfe than reserves that generate lower cash margins.
Business Strategy
Pursue Exploration Opportunities. Comstock conducts exploration activities to find additional reserves on its undeveloped acreage and in its core operating areas. In 2000, the Company spent approximately $19.2 million to drill 12 exploratory wells (4.8 net), of which seven (3.3 net) were successful, representing a success rate of 58%. The Company also spent $5.3 million in acquiring new acreage and seismic data in 2000 to support its exploration program. The Company has budgeted $45.0 million in 2001 for exploration activities which will be focused primarily in its Gulf of Mexico region.
Exploit Existing Reserves. Comstock seeks to maximize the value of its properties by increasing production and recoverable reserves through active workover, recompletion and exploitation activities. The Company utilizes advanced industry technology, including 3-D seismic data, improved logging tools, and formation stimulation techniques. During 2000, the Company spent approximately $35.0 million to drill 37 development wells (19.7 net), all of which were successful. In addition, the Company spent approximately $10.3 million for recompletion and workover activity during 2000 and $1.6 million for new production facilities. For 2001, the Company has budgeted $55.0 million for development drilling and for workover and recompletion activity.
Maintain Low Cost Structure. The Company seeks to increase cash flow by carefully controlling operating costs and general and administrative expenses. Comstock’s average oil and gas operating costs per Mcfe were $0.79 in 2000. In addition, the Company has been able to grow its reserves and production substantially over the past five years with minimal increase to general and administrative expenses. As a result, general and administrative expenses per Mcfe have decreased from $0.11 in 1995 to $0.09 in 2000.
Acquire High Quality Properties at Attractive Costs. Comstock has a successful track record of increasing its oil and natural gas reserves through opportunistic acquisitions. Since 1991, the Company has added 502.4 Bcfe of proved oil and natural gas reserves from 25 acquisitions at a total cost of $426.1 million, or $0.85 per Mcfe. The acquisitions were acquired at an average of 59% of their Present Value of Proved Reserves in the year the acquisitions were completed. The Company applies strict economic and reserve risk criteria in evaluating acquisitions. The Company targets properties in its core operating areas with established production and low operating costs that also have potential opportunities to increase production and reserves through exploration and exploitation activities.
Maintain Flexible Capital Expenditure Budget. The timing of most of the Company’s capital expenditures is discretionary with no material long-term capital expenditure commitments. Consequently, the Company has a significant degree of flexibility to adjust the level of such expenditures according to market conditions. Comstock anticipates spending approximately $100.0 million on development and exploration projects in 2001. The Company intends to use operating cash flow to fund its drilling expenditures in 2001 and to utilize any excess cash flow to reduce amounts outstanding under its bank credit facility or to make oil and gas property acquisitions. Comstock may also make property acquisitions in 2001 that would require additional sources of funding, which may include borrowings under its bank credit facility or sales of equity or debt securities.
Primary Operating Areas
The Company’s activities are concentrated in three primary operating areas: Gulf of Mexico, Southeast Texas and East Texas/North Louisiana. The following table summarizes the Company’s estimated proved oil and natural gas reserves by field as of December 31, 2000.
Net Oil Net Gas Present Value of
(MBbls) (MMcf) MMcfe Proved Reserves Percentage
-------- ---------- ---------- ----------------- ----------
(In thousands)
Gulf of Mexico
South Timbalier/ South Pelto 2,002 31,452 43,462 $ 267,315
Ship Shoal ................. 7,687 13,758 59,882 176,790
Main Pass .................. 1,806 2,702 13,539 37,063
West Cameron ............... -- 4,755 4,755 30,009
East White Point ........... 827 3,611 8,570 14,587
El Campo ................... 192 2,971 4,122 14,157
Eugene Island .............. 17 1,777 1,879 13,863
Mustang Island ............. 46 1,718 1,996 11,246
Other ...................... 512 783 3,852 8,782
---------- ---------- ---------- ----------- ------
13,089 63,527 142,057 573,812 32.4%
---------- ---------- ---------- ----------- ------
Southeast Texas
Double A Wells ............. 3,557 100,912 122,257 579,878
Sugar Creek ................ 88 8,772 9,298 38,699
Other ...................... 54 712 1,036 4,527
---------- ---------- ---------- ---------- ------
3,699 110,396 132,591 623,104 35.2%
---------- ---------- ---------- ---------- ------
East Texas/ North Louisiana
Beckville .................. 128 47,370 48,139 203,436
Logansport ................. 39 17,988 18,220 88,747
Waskom ..................... 196 13,776 14,955 59,728
Blocker .................... 42 11,658 11,911 45,321
Box Church ................. 6 8,682 8,716 41,278
Longwood ................... 44 5,659 5,921 31,467
Lisbon ..................... 52 4,068 4,377 26,051
Hico-Knowles ............... 32 3,731 3,923 20,830
Ada ........................ 3 2,385 2,402 14,258
Sugar Creek ................ 49 2,226 2,519 11,296
Other ...................... 40 5,957 6,199 27,355
---------- ---------- ---------- ---------- ------
631 123,500 127,282 569,767 32.2%
---------- ---------- ---------- ---------- ------
Other Areas ................... 32 412 612 2,166 0.1%
---------- ---------- ---------- ---------- ------
Total ...................... 17,451 297,835 402,542 $1,768,849 100.0%
========== ========== ========== ========== =====
Gulf of Mexico
The Company’s largest operating region includes properties located offshore of Louisiana, in state and federal waters of the Gulf of Mexico and in fields along the Texas and Louisiana Gulf Coast. The Company owns interests in 108 producing wells (47.3 net) in eleven field areas, the largest of which are the South Timbalier/South Pelto area (South Timbalier Blocks 11, 16, 34, 50 and South Pelto Blocks 5 and 15), the Ship Shoal area (Ship Shoal Blocks 66, 67, 68, 69 and 99 and South Pelto Block 1) and the Main Pass area (Main Pass Blocks 21, 41, 43 and 58). The Company has 142.1 Bcfe of oil and natural gas reserves in the Gulf of Mexico region with a Present Value of Proved Reserves of $573.8 million as of December 31, 2000. The Company operates 29 of the wells (27.2 net) that it owns in this region. Production from the region averaged 15.4 MMcf of natural gas per day and 3.2 MBbls of oil per day during 2000. The Company spent $10.2 million in this region in 2000 drilling eight development wells (2.1 net) and $12.3 million drilling nine exploratory wells (3.1 net). Comstock also spent $3.8 million for acquiring leases and seismic data, $1.6 million to install production facilities and $6.2 million for recompletions and workovers in the Gulf of Mexico region in 2000. In 2001, the Company plans to spend $46.0 million for development and exploration activities in this region.
South Timbalier/South Pelto
The Company owns working interests ranging from 25% to 33% in Louisiana state waters and in federal waters in the South Timbalier/South Pelto area located offshore of Terrebonne and Lafourche Parishes in water depths ranging from 20 to 60 feet. The Company has estimated proved net reserves totaling 43.5 Bcfe (11% of total proved reserves) in this area as of December 31, 2000 with a Present Value of Proved Reserves of $267.3 million. Oil and natural gas are produced from numerous sands of Pliocene to Upper Miocene age, at depths ranging from 2,000 to 12,000 feet. The Company acquired a 33% working interest in seven producing wells as well as production facilities in 1998 and has drilled nine successful wells in the area in 1999 and 2000. Exploration in the area entered a new phase in early 2000 as a result of continued analysis of 3-D seismic data covering this area. Deep gas prospects were identified, targeting the geopressured Miocene section to depths below 16,000 feet. Three of these prospects were drilled and resulted in successful discoveries in 2000. In 2001, the Company plans to spend approximately $21.0 million to drill 13 exploratory wells (3.9 net) at South Timbalier/South Pelto.
Ship Shoal
The Ship Shoal area is located in Louisiana state waters and in federal waters, offshore of Terrebonne Parish and near the state/federal waters boundary. The Company owns a 99% to 100% working interest in Ship Shoal Blocks 66,67, and 68 and South Pelto Block, and operates these properties. Comstock has a 25% working interest in Ship Shoal Block 69 and a 60% working interest in Ship Shoal Block 99. In the Ship Shoal area, oil and natural gas are produced from numerous Miocene sands occurring at depths from 5,800 to 13,500 feet, and in water depths from 10 to 40 feet. The Company’s interest in the Ship Shoal area has estimated proved reserves of 59.9 Bcfe (15% of total proved reserves) with a Present Value of Proved Reserves of $176.8 million as of December 31, 2000. The Company owns interests in 29 wells in the Ship Shoal area which averaged 5.3 MMcf of natural gas per day and 1,957 barrels of oil per day during 2000. Comstock plans to spend $13.0 million to drill five exploratory wells (2.7 net) in the Ship Shoal area in 2001.
Main Pass
Main Pass Block 21 is located in Louisiana state waters, offshore of Plaquemines Parish in water with a depth of approximately 12 feet. The Company’s wells in this area produce from multiple Miocene sands at depths that range from 4,400 to 7,700 feet. The Company is the operator and owns interests in six wells at Main Pass Block 21. The Company also owns nonoperated interests at Main Pass Blocks 41, 43 and 58 in Federal waters with an average depth of 50 feet. Proved reserves for the total Main Pass area were 13.5 Bcfe (3% of total reserves at December 31, 2000). Comstock drilled five development wells (1.1 net) at Main Pass Blocks 41, 43 and 58 in 2000. The average production attributable to the Company’s interest from the Main Pass Area was approximately 3.5 Mmcf of natural gas and 751 barrels of oil per day in 2000.
Southeast Texas
Approximately one-third (132.6 Bcfe) of the Company’s proved reserves are located in Southeast Texas, where the Company owns interests in 57 producing wells (27.6 net) and operates 53 (25.8 net) of these wells. Reserves in Southeast Texas represent 35% of the Company’s Present Value of Proved Reserves as of December 31, 2000. Net daily production rates from the area averaged 35.5 MMcf of natural gas and 1.5 MBbls of oil during 2000. Comstock spent $13.8 million in the Southeast Texas region in 2000 drilling 12 development wells (7.0 net) and spent $6.9 million drilling two exploratory wells (1.6 net). Comstock also spent $8.1 million for acquisitions of additional interests in producing wells in the Double A Wells field, $2.9 million to acquire an additional 41,200 net acres in this region and $0.9 million for recompletions and workovers. In 2001, the Company plans to spend $25.0 million for development and exploration activities in this region.
Double A Wells
Substantially all of the reserves in this region are in the Double A Wells field area in Polk County, Texas. The Double A Wells field is the Company’s largest field area with total estimated proved reserves of 122.3 Bcfe (30% of total proved reserves) which have a Present Value of Proved Reserves of $579.9 million as of December 31, 2000. Net daily production from the 53 producing wells at Double A Wells field averaged 1,490 barrels of oil and 35.1 MMcf of natural gas during 2000. These wells typically produce from the Woodbine formation at an average depth of 14,300 feet. In 1999 the Company began a redevelopment program in this field based on the interpretation of 3-D seismic data. In 2000, Comstock drilled 11 wells (6.2 net) in this field. All of the wells were successful. The Company has budgeted $16.0 million to drill 11 wells (5.4 net) in the Double A Wells field in 2001.
Sugar Creek
The Sugar Creek field is located in Tyler County, Texas and was discovered in 1974. The field has produced 59 Bcfe from the Woodbine Formation at an average depth of 11,250 feet. A total of thirteen wells produced in the field, with all but one plugged and abandoned by 1989. The Company initiated a redevelopment program in November 2000 and successfully drilled two wells in 2000. These wells are currently awaiting pipeline connection. The Company has developed proved reserves in this older field by infill drilling between abandoned wells and completing the new wells with modern techniques. Comstock plans to drill four additional wells in this field in 2001.
East Texas/North Louisiana
Approximately 32% (127.3 Bcfe) of the Company’s proved reserves are located in East Texas and North Louisiana where the Company owns interests in 342 producing wells (196.7 net) in 20 field areas and operates 246 of these wells (176.4 net). The largest of the Company’s field areas in this region are the Beckville, Logansport, Waskom, Blocker and Box Church fields. Reserves in the region represented 32% of the Company’s Present Value of Proved Reserves as of December 31, 2000. Production from this region averaged 22.7 MMcf of natural gas per day and 156 barrels of oil per day during 2000. Most of the reserves in this area produce from the Cretaceous aged Travis Peak/Hosston formation and the Jurassic aged Cotton Valley formation. The total thickness of these formations range from 2,000 to 4,000 feet of sand and shale sequences in the East Texas Basin and the North Louisiana Salt Basin, at depths ranging from 6,000 to 10,500 feet. In 2000 the Company spent $11.1 million drilling 18 wells (10.7 net) and $3.1 million on workovers and recompletions in this region. Comstock has budgeted approximately $29.0 million in 2001 for this region to drill 30 development wells (23.7 net) and for recompletions.
Beckville
The Company’s properties in the Beckville field, located in Panola and Rusk Counties, Texas, represented approximately 12% (48.1 Bcfe) of the Company’s proved reserves as of December 31, 2000. The Company operates 63 wells in this field and owns interests in four additional wells. During 2000, the production attributable to the Company’s interest from this field averaged 6.2 MMcf of natural gas and 15 barrels of oil per day. The Beckville field produces from the Cotton Valley formation at depths ranging from 9,000 to 10,000 feet. The Company drilled 12 wells (9.4 net) in 2000 at Beckville and plans to spend approximately $21.0 million to drill 23 development wells (18.8 net) in this field in 2001.
Logansport
The Logansport field produces from multiple pay zones in the Hosston formation at an average depth of 8,000 feet and is located in DeSoto Parish, Louisiana. The Company’s proved reserves of 18.2 Bcfe in the Logansport field represented approximately 5% of the Company’s proved reserves as of December 31, 2000. The Company operates 49 wells in this field and owns interests in 31 additional wells. During 2000, net daily production attributable to the Company’s interest averaged 4.3 MMcf of natural gas and 19 barrels of oil. The Company drilled three wells (0.2 net) during 2000 and has budgeted $1.4 million to drill two development wells (1.4 net) in this field in 2001.
Waskom
The Waskom field, located in Harrison and Panola Counties in Texas, represented approximately 4% (15.0 Bcfe) of the Company’s proved reserves as of December 31, 2000. The Company operates 36 wells in this field and owns interests in 26 additional wells. During 2000, net daily production attributable to the Company’s interest averaged 1.7 MMcf of natural gas and 22 barrels of oil. The Waskom field produces from the Cotton Valley formation at depths ranging from 9,000 to 10,000 feet.
Blocker
The Blocker field in Harrison County, Texas produces primarily from the Cotton Valley formation from depths ranging from 8,600 feet to 10,000 feet. Wells also produce from the Pettit and Travis Peak formations from 6,000 feet to 7,800 feet in depth. At December 31, 2000, Comstock had 11.9 Bcfe of proved reserves in this field. Comstock operates two wells in this field which averaged 2 MMcf of natural gas and 8 barrels of oil per day in 2000 net to Comstock’s interest. Comstock plans to drill two wells in this field in 2001 at a cost of $2.5 million.
Box Church
The Company’s properties in the Box Church field, located in Limestone County, Texas, represented approximately 2% (8.7 Bcfe) of the Company’s proved reserves as of December 31, 2000. The Company operates nine wells in this field. During 2000, net daily production attributable to the Company’s interest from this field averaged 2.1 MMcf of natural gas and 4 barrels of oil. The Box Church field produces from the Cotton Valley formation at depths ranging from 10,200 to 10,500 feet. The Company drilled one well (0.9 net) at Box Church in 2000.
Acquisition Activities
Acquisition Strategy
The Company has concentrated its acquisition activity in the Gulf of Mexico, Southeast Texas and East Texas/North Louisiana regions. Using a strategy that capitalizes on management’s knowledge of and experience in these regions, the Company seeks to selectively pursue acquisition opportunities where the Company can evaluate the assets to be acquired in detail prior to completion of the transaction. The Company evaluates a large number of prospective properties according to certain internal criteria, including established production and the properties’ future development and exploration potential, low operating costs and the ability for the Company to obtain operating control.
Major Property Acquisitions
As a result of its acquisitions, the Company has added 502.4 Bcfe of proved oil and natural gas reserves since 1991.
The Company's largest acquisitions are the following:
Bois d’ Arc Acquisition. In December 1997, the Company acquired working interests in certain producing offshore Louisiana oil and gas properties as well as interests in undeveloped offshore oil and natural gas leases for approximately $200.9 million from Bois d’ Arc Resources and certain of its affiliates and working interest partners. The Company acquired interests in 43 wells (29.6 net) and eight separate production complexes located in the Gulf of Mexico offshore of Plaquemines and Terrebonne Parishes, Louisiana. The acquisition included interests in the Louisiana state and federal offshore areas of Main Pass Blocks 21 and 25, Ship Shoal Blocks 66, 67, 68 and 69 and South Pelto Block 1. The net proved reserves acquired were estimated at 14.3 MMBbls of oil and 29.4 Bcf of natural gas.
Black Stone Acquisition. In May 1996, the Company acquired 100% of the capital stock of Black Stone Oil Company and interests in producing and undeveloped oil and gas properties located in Southeast Texas for $100.4 million. The Company acquired interests in 19 wells (7.7 net) that are located in the Double A Wells field in Polk County, Texas and became the operator of most of the wells in the field. The net proved reserves acquired were estimated at 5.9 MMBbls of oil and 100.4 Bcf of natural gas.
Sonat Acquisition. In July 1995, the Company purchased interests in certain producing oil and gas properties located in East Texas and North Louisiana from Sonat Inc. for $48.1 million. The Company acquired interests in 319 producing wells (188.0 net). The acquisition included interests in the Beckville, Logansport, Waskom, and Hico-Knowles fields. The net proved reserves acquired were estimated at 0.8 MMBbls of oil and 104.7 Bcf of natural gas.
Oil and Natural Gas Reserves
The following table sets forth the estimated proved oil and natural gas reserves of the Company and the Present Value of Proved Reserves as of December 31, 2000:
Present
Value of
Proved
Oil Gas Total Reserves
(MBbls) (Mmcf) (Mmcfe) (000's)
---------- ---------- ---------- ----------
Proved Developed Producing ... 6,978 141,905 183,775 $ 874,470
Proved Developed Non-producing 5,311 58,444 90,312 315,840
Proved Undeveloped ........... 5,162 97,486 128,455 578,539
---------- ---------- ---------- ----------
Total Proved ........... 17,451 297,835 402,542 $1,768,849
========== ========== ========== ==========
There are numerous uncertainties inherent in estimating oil and natural gas reserves and their values, including many factors beyond the control of the producer. The reserve data set forth above represents estimates only. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. 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 may vary. In addition, estimates of reserves are subject to revision based on the results of drilling, testing and production subsequent to the date of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and gas reserves that are ultimately recovered.
In general, the volume of production from oil and natural gas properties declines as reserves are depleted. Except to the extent the Company acquires properties containing proved reserves or conducts successful exploration and development activities, the proved reserves of the Company will decline as reserves are produced. The Company’s future oil and natural gas production is, therefore, highly dependent upon its level of success in acquiring or finding additional reserves.
The market price for the Company’s oil production on December 31, 2000, after basis adjustments, was $26.34 per barrel as compared to $24.56 per barrel on December 31, 1999. The market price received for the Company’s natural gas production on December 31, 2000, after basis adjustments, was $10.51 per Mcf as compared to $2.51 per Mcf on December 31, 1999.
Drilling Activity Summary
During the three-year period ended December 31, 2000, the Company drilled development and exploratory wells as set forth in the table below.
Year Ended December 31,
----------------------------------------------
1998 1999 2000
------------- ------------- --------------
Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- ------
Development Wells:
Oil................... -- -- 1 .4 -- --
Gas................... 25 14.7 14 8.8 37 19.7
Dry................... 5 3.5 2 .8 -- --
----- ----- ----- ----- ----- ------
30 18.2 17 10.0 37 19.7
----- ----- ----- ----- ----- ------
Exploratory Wells:
Oil................... 6 2.3 2 .6 2 1.1
Gas................... 2 2.0 5 .9 5 2.2
Dry................... 6 2.9 4 .9 5 1.5
----- ----- ----- ----- ----- ------
14 7.2 11 2.4 12 4.8
----- ----- ----- ----- ----- ------
Total Wells........ 44 25.4 28 12.4 49 24.5
===== ===== ===== ===== ===== ======
In 2001 to the date of this report, the Company has drilled six development wells (2.9 net) and two exploratory wells (.5 net). All of these wells were successful. As of March 9, 2001, the Company was in the process of drilling two exploratory wells (1.3 net) and seven development wells (3.9 net).
Producing Well Summary
The following table sets forth the gross and net producing oil and natural gas wells in which the Company owned an interest at December 31, 2000.
Oil Gas
------------- --------------
Gross Net Gross Net
----- ----- ----- ------
Texas......................... 10 4.7 221 136.6
Louisiana..................... 8 4.5 180 83.8
Offshore Gulf of Mexico....... 39 22.4 49 19.6
Mississippi................... 1 0.1 1 0.2
----- ----- ----- ------
Total Wells......... 58 31.7 451 240.2
===== ===== ===== ======
The Company operates 322 of the 509 producing wells presented in the above table.
Acreage
The following table summarizes the Company's developed and undeveloped leasehold acreage at December 31, 2000. Excluded is acreage in which the Company's interest is limited to royalty or similar interests.
Developed Undeveloped
----------------- -----------------
Gross Net Gross Net
------- ------- ------- -------
Texas .................... 167,254 120,891 80,000 51,850
Louisiana ................ 77,792 57,109 6,114 349
State and Federal Offshore 41,386 17,863 21,230 14,450
Mississippi .............. 1,360 210 -- --
New Mexico ............... -- -- 172,336 59,456
------- ------- ------- -------
Total Wells .... 287,792 196,073 279,680 126,105
======= ======= ======= =======
Title to the Company’s oil and natural gas properties is subject to royalty, overriding royalty, carried and other similar interests and contractual arrangements customary in the oil and gas industry, liens incident to operating agreements and for current taxes not yet due and other minor encumbrances. All of the Company’s oil and natural gas properties are pledged as collateral under the Company’s bank credit facility. As is customary in the oil and gas industry, the Company is generally able to retain its ownership interest in undeveloped acreage by production of existing wells, by drilling activity which establishes commercial reserves sufficient to maintain the lease or by payment of delay rentals.
Markets and Customers
The market for oil and natural gas produced by the Company depends on factors beyond its control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.
Substantially all of the Company’s natural gas production is sold either on the spot natural gas market on a month-to-month basis at prevailing spot market prices or under long-term contracts based on current spot market gas prices. A portion of the natural gas production from the Company’s Double A Wells field is sold under a long-term contract to Houston Pipeline Company, a subsidiary of Enron Corporation (“HPL”). The agreement with HPL expires on October 31, 2004 with pricing based on spot gas prices for natural gas delivered to the Houston Ship Channel. The remaining gas production from the Double A Wells field is sold to El Paso Field Services Company, a business unit of El Paso Energy Corporation (“El Paso”), under a similar pricing arrangement. Total gas sales in 2000 to HPL and El Paso accounted for approximately 21% and 11%, respectively, of the Company’s total 2000 oil and gas sales.
All of the Company’s oil production is sold at the well site at prices tied to the spot oil markets. The Company sells its oil production from its offshore properties and from its Double A Wells field to Williams-Gulfmark Energy Company. Sales to Williams-Gulfmark Energy Company accounted for 29% of the Company’s total 2000 oil and gas sales.
Competition
The oil and gas industry is highly competitive. Competitors include major oil companies, other independent energy companies, and individual producers and operators, many of which have financial resources, personnel and facilities substantially greater than those of the Company. The Company faces intense competition for the acquisition of oil and natural gas properties.
Regulation
The Company’s operations are regulated by certain federal and state agencies. In particular, oil and natural gas production and related operations are or have been subject to price controls, taxes and other laws relating to the oil and natural gas industry. The Company cannot predict how existing laws and regulations may be interpreted by enforcement agencies or court rulings, whether additional laws and regulations will be adopted, or the effect such changes may have on its business or financial condition.
Sales of natural gas by the Company are not regulated and are made at market prices. However, the Federal Energy Regulatory Commission (“FERC”) regulates interstate and certain intrastate natural gas transportation rates and service conditions, which affect the marketing of natural gas produced by the Company, as well as the revenues received by the Company for sales of such production. Since the mid- 1980s, FERC has issued a series of orders, culminating in Order Nos. 636, 636-A and 636-B (“Order 636”), that have significantly altered the marketing and transportation of natural gas. Order 636 mandated a fundamental restructuring of interstate pipeline sales and transportation service, including the unbundling by interstate pipelines of the sales, transportation, storage and other components of the city-gate sales services such pipelines previously performed. One of FERC’s purposes in issuing the orders was to increase competition within all phases of the natural gas industry. Generally, Order 636 has eliminated or substantially reduced the interstate pipelines’ traditional role as wholesalers of natural gas and has substantially increased competition and volatility in natural gas markets.
Sales of oil and natural gas liquids by the Company are not regulated and are made at market prices. The price the Company receives from the sale of these products is affected by the cost of transporting the products to market.
The Company’s oil and natural gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state and local agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases the Company’s cost of doing business and affects its profitability. Because such rules and regulations are frequently amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with such laws.
The states of Texas and Louisiana require permits for drilling operations, drilling bonds and the filing of reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. These states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and gas wells and the regulation of spacing, plugging and abandonment of such wells. The statutes and regulations of certain states limit the rate at which oil and gas can be produced from the Company’s properties.
The Company is required to comply with various federal and state regulations regarding plugging and abandonment of oil and natural gas wells. The Company provides reserves for the estimated costs of plugging and abandoning its wells, to the extent such costs exceed the estimated salvage value of the wells, on a unit of production basis.
Environmental
Various federal, state and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment, health and safety, affect the Company’s operations and costs. These laws and regulations sometimes require governmental authorization before conducting certain activities, limit or prohibit other activities because of protected areas or species, create the possibility of substantial liabilities for pollution related to Company operations or properties and provide penalties for noncompliance. In particular, the Company’s drilling and production operations, its activities in connection with storage and transportation of crude oil and other liquid hydrocarbons and its use of facilities for treating, processing or otherwise handling hydrocarbons and related exploration and production wastes are subject to stringent environmental regulation. As with the industry in general, compliance with existing and anticipated regulations increases the Company’s overall cost of business. While these regulations affect the Company’s capital expenditures and earnings, the Company believes that such regulations do not affect its competitive position in the industry because its competitors are similarly affected by environmental regulatory programs. Environmental regulations have historically been subject to frequent change and, therefore, the Company cannot predict with certainty the future costs or other future impacts of environmental regulations on its future operations. A discharge of hydrocarbons or hazardous substances into the environment could subject the Company to substantial expense, including the cost to comply with applicable regulations that require a response to the discharge, such as containment or cleanup, claims by neighboring landowners or other third parties for personal injury, property damage or their response costs and penalties assessed, or other claims sought, by regulatory agencies for response cost or for natural resource damages.
The following are examples of some environmental laws that potentially impact the Company and its operations.
Water. The Oil Pollution Act (“OPA”) was enacted in 1990 and amends provisions of the Federal Water Pollution Control Act of 1972 (“FWPCA”) and other statutes as they pertain to the prevention of and response to major oil spills. The OPA subjects owners of facilities to strict, joint and potentially unlimited liability for removal costs and certain other consequences of an oil spill along shorelines or that enters navigable waters. In the event of an oil spill into such waters, substantial liabilities could be imposed upon the Company. Recent regulations developed under OPA require companies that own offshore facilities, including the Company, to demonstrate oil spill financial responsibility for removal costs and damage caused by oil discharge. States in which the Company operates have also enacted similar laws. Regulations are currently being developed under the OPA and similar state laws that may also impose additional regulatory burdens on the Company.
The FWPCA imposes restrictions and strict controls regarding the discharge of produced waters, other oil and gas wastes, any form of pollutant, and, in some instances, storm water runoff, into waters of the United States. The FWPCA provides for civil, criminal and administrative penalties for any unauthorized discharges and, along with the OPA, imposes substantial potential liability for the costs of removal, remediation or damages resulting from an unauthorized discharge. State laws for the control of water pollution also provide civil, criminal and administrative penalties and liabilities in the case of an unauthorized discharge into state waters. The cost of compliance with the OPA and the FWPCA have not historically been material to the Company’s operations, but there can be no assurance that changes in federal, state or local water pollution control programs will not materially adversely affect the Company in the future. Although no assurances can be given, the Company believes that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on the Company’s financial condition or results of operations.
Air Emissions. The Federal Clean Air Act and comparable state programs (the “Clean Air Act”) requires many industrial operations in the United States to incur capital expenditures in order to meet air emissions control standards developed by the United States Environmental Protection Agency (“EPA”) and state environmental agencies. Although no assurances can be given, the Company believes that compliance with the Clean Air Act will not have a material adverse effect on the Company’s financial condition or results of operations.
Solid Waste. The Company generates non-hazardous solid wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The EPA and the states in which the Company operates are considering the adoption of stricter disposal standards for the type of non-hazardous wastes generated by the Company. RCRA also governs the generation, management, and disposal of hazardous wastes. At present, the Company is not required to comply with a substantial portion of the RCRA requirements because the Company’s operations generate minimal quantities of hazardous wastes. However, it is possible that additional wastes, which could include wastes currently generated during the Company’s operations, could in the future be designated as “hazardous wastes.” Hazardous wastes are subject to more rigorous and costly disposal and management requirements than are non-hazardous wastes. Such changes in the regulations may result in additional capital expenditures or operating expenses by the Company.
Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as “Superfund”, imposes liability, without regard to fault or the legality of the original act, on certain classes of persons in connection with the release of a “hazardous substance” into the environment. These persons include the current owner or operator of any site where a release historically occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In the course of its ordinary operations, the Company may have managed substances that may fall within CERCLA’s definition of a “hazardous substance.” Therefore, the Company may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites where the Company disposed of or arranged for the disposal of these substances. This potential liability extends to properties that the Company previously owned or operated, as well as to properties owned and operated by others at which disposal of the Company’s hazardous substances occurred.
The Company may also fall into the category of the “current owner or operator.” The Company currently owns or leases numerous properties that for many years have been used for the exploration and production of oil and gas. Although the Company believes it has utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released by the Company on or under the properties owned or leased by the Company. In addition, many of these properties have been previously owned or operated by third parties who may have disposed of or released hydrocarbons or other wastes at these properties. Under CERCLA and analogous state laws, the Company could be subject to certain liabilities and obligations, such as being required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination.
Office and Operations Facilities
The Company’s executive offices are located at 5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034 and its telephone number is (972) 668-8800.
The Company leases office space in Frisco, Texas covering 20,046 square feet at a monthly rate of $34,706. The lease expires on May 31, 2006. The Company also owns production offices and pipe yard facilities near Marshall and Livingston, Texas and near Logansport, Louisiana.
Employees
As of December 31, 2000, the Company had 48 employees and utilized contract employees for certain of its field operations. The Company considers its employee relations to be satisfactory.
Directors, Executive Officers and Other Management
The following table sets forth certain information concerning the executive officers and directors of the Company.
Name Age Position with Company
------------------------ ------- --------------------------------------------
M. Jay Allison......... 45 President, Chief Executive Officer and
Chairman of the Board of Directors
Roland O. Burns........ 40 Senior Vice President, Chief Financial Officer,
Secretary, Treasurer and Director
Mack D. Good........... 50 Vice President of Operations
Stephen E. Neukom...... 51 Vice President of Marketing
Richard G. Powers...... 46 Vice President of Land
Daniel K. Presley...... 40 Vice President of Accounting and Controller
Michael W. Taylor...... 47 Vice President of Corporate Development
Franklin B. Leonard.... 73 Director
Cecil E. Martin, Jr.... 59 Director
David W. Sledge........ 44 Director
Executive Officers
M. Jay Allison has been a director of the Company since 1987, and President and Chief Executive Officer of the Company since 1988. Mr. Allison was elected Chairman of the Board of Directors in 1997. From 1987 to 1988, Mr. Allison served as Vice President and Secretary of the Company. From 1981 to 1987, he was a practicing oil and gas attorney with the firm of Lynch, Chappell & Alsup in Midland, Texas. In 1983, Mr. Allison co-founded a private independent oil and gas company, Midwood Petroleum, Inc., which was active in the acquisition and development of oil and gas properties from 1983 to 1987. He received B.B.A., M.S. and J.D. degrees from Baylor University in 1978, 1980 and 1981, respectively. Mr. Allison currently serves on the Board of Regents for Baylor University.
Roland O. Burns has been Senior Vice President of the Company since 1994, Chief Financial Officer and Treasurer since 1990 and Secretary since 1991. Mr. Burns was elected as a director of the Company in June 1999. From 1982 to 1990, Mr. Burns was employed by the public accounting firm, Arthur Andersen LLP. During his tenure with Arthur Andersen LLP, Mr. Burns worked primarily in the firm's oil and gas audit practice. Mr. Burns received B.A. and M.A. degrees from the University of Mississippi in 1982 and is a Certified Public Accountant.
Mack D. Good was appointed Vice President of Operations of the Company in March 1999. From August 1997 until his promotion, Mr. Good served as the Company's District Engineer for the East Texas/ North Louisiana region. From 1983 until 1997, Mr. Good was with Enserch Exploration, Inc. serving in various operations management and engineering positions. Mr. Good received a B.S. of Biology/Chemistry from Oklahoma State University in 1975 and a B.S. of Petroleum Engineering from the University of Tulsa in 1983. He is a Registered Professional Engineer in the State of Texas.
Stephen E. Neukom has been Vice President of Marketing of the Company since December 1997 and has served as Manager of Crude Oil and Natural Gas Marketing since December 1996. From October 1994 to 1996, Mr. Neukom served as Vice President of Comstock Natural Gas, Inc., the Company's wholly owned gas marketing subsidiary. Prior to joining the Company, Mr. Neukom was Senior Vice President of Victoria Gas Corporation from 1987 to 1994. Mr. Neukom received a B.B.A. degree from the University of Texas in 1972.
Richard G. Powers joined the Company as Land Manager in October 1994 and has been Vice President of Land since December 1997. Mr. Powers has over 20 years experience as a petroleum landman. Prior to joining the Company, Mr. Powers was employed for 10 years as Land Manager for Bridge Oil (U.S.A.), Inc. and its predecessor Pinoak Petroleum, Inc. Mr. Powers received a B.B.A. degree in 1976 from Texas Christian University.
Daniel K. Presley has been Vice President of Accounting since December 1997 and has been with the Company since December 1989 serving as Controller since 1991. Prior to joining the Company, Mr. Presley had six years of experience with several independent oil and gas companies including AmBrit Energy, Inc. Prior thereto, Mr. Presley spent two and one-half years with B.D.O. Seidman, a public accounting firm. Mr. Presley has a B.B.A. from Texas A & M University.
Michael W. Taylor has been Vice President of Corporate Development since December 1997 and has served the Company in various capacities since September 1994. Mr. Taylor has 26 years experience in the oil and gas business. For 15 years prior to joining the Company, he had been an independent oil and gas producer and petroleum consultant. Before that time, he worked in various engineering and executive capacities for a major oil company, a small independent producer and an international oil and gas consulting company. Mr. Taylor is a registered professional engineer in the state of Texas and he received a B.S. degree in Petroleum Engineering from Texas A & M University in 1974.
Outside Directors
Franklin B. Leonard has been a director of the Company since 1960. From 1961 to 1994, Mr. Leonard served as President of Crossley Surveys, Inc., a New York based company which conducted statistical surveys. Mr. Leonard's family's involvement in the Company spans four generations dating back to the 1880's when Mr. Leonard's great grandfather was a significant shareholder of the Company. Mr. Leonard holds a B.S. degree from Yale University.
Cecil E. Martin, Jr. has been a director of the Company since 1988. From 1973 to 1991 he served as Chairman of a public accounting firm in Richmond, Virginia. Mr. Martin also serves as a director for CareerShop.com. Mr. Martin holds a B.B.A. degree from Old Dominion University and is a Certified Public Accountant.
David W. Sledge was elected to the Board of Directors of the Company in 1996. Mr. Sledge served as President of Gene Sledge Drilling Corporation, a privately held contract drilling company based in Midland, Texas until its sale in October 1996. Mr. Sledge served Gene Sledge Drilling Corporation in various capacities from 1979 to 1996. Mr. Sledge is a past director of the International Association of Drilling Contractors and is a past chairman of the Permian Basin chapter of this association. He received a B.B.A. degree from Baylor University in 1979.
ITEM 3. LEGAL PROCEEDINGS
The Company is not a party to any legal proceedings which management believes will have a material adverse effect on the Company’s consolidated results of operations or financial condition.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the Company’s security holders during the fourth quarter of 2000.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
The Company’s common stock is listed for trading on the New York Stock Exchange under the symbol “CRK”. The following table sets forth, on a per share basis for the periods indicated, the high and low sales prices by calendar quarter for the periods indicated as reported by the New York Stock Exchange.
High Low
--------- ---------
1999 First Quarter................. $ 3.88 $ 2.19
Second Quarter................ 5.13 2.44
Third Quarter................. 5.88 3.38
Fourth Quarter................ 4.50 2.63
2000 First Quarter................. $ 5.94 $ 2.44
Second Quarter................ 9.13 4.06
Third Quarter................. 13.13 6.13
Fourth Quarter................ 15.00 8.13
As of March 9, 2000, the Company had 29,139,469 shares of common stock outstanding, which were held by 526 holders of record and approximately 6,500 beneficial owners who maintain their shares in "street name" accounts.
The Company has never paid cash dividends on its common stock. The Company presently intends to retain any earnings for the operation and expansion of its business and does not anticipate paying cash dividends in the foreseeable future. Any future determination as to the payment of dividends will depend upon results of operations, capital requirements, the financial condition of the Company and such other factors as the Board of Directors of the Company may deem relevant. In addition, the Company is limited under its bank credit facility, its 1999 Series A Preferred Stock and the indenture for its senior notes due in 2007 from paying or declaring cash dividends.
ITEM 6. SELECTED FINANCIAL DATA
The historical financial data presented in the table below as of and for each of the years in the five-year period ended December 31, 2000 are derived from the Consolidated Financial Statements of the Company. The financial results are not necessarily indicative of the Company’s future operations or financial results. The data presented below should be read in conjunction with the Company’s Consolidated Financial Statements and the notes thereto included elsewhere herein and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Year Ended December 31,
-------------------------------------------------------------
1996 1997 1998 1999 2000
--------- --------- --------- --------- ---------
Statement of Operations Data: ($ in thousands, except per share data)
Revenues:
Oil and gas sales ......................... $ 68,915 $ 88,555 $ 92,961 $ 90,103 $ 169,350
Gain on sales of property ................. 1,447 85 -- 130 33
Other income .............................. 593 704 274 1,911 319
--------- --------- --------- --------- ---------
Total revenues .......................... 70,955 89,344 93,235 92,144 169,702
--------- --------- --------- --------- ---------
Expenses:
Oil and gas operating (1) ................. 13,838 17,919 24,747 23,714 29,707
Exploration ............................... 436 2,810 8,301 1,832 3,192
Depreciation, depletion and amortization .. 18,269 26,235 51,005 45,171 44,958
General and administrative, net ........... 2,239 2,668 1,617 2,399 3,537
Interest .................................. 10,086 5,934 16,977 23,361 24,611
Impairment of oil and gas properties ...... -- -- 17,000 -- --
--------- --------- --------- --------- ---------
Total expenses .......................... 44,868 55,566 119,647 96,477 106,005
--------- --------- --------- --------- ---------
Income (loss) from continuing operations
before income taxes ....................... 26,087 33,778 (26,412) (4,333) 63,697
Income tax benefit (expense) .............. -- (11,622) 9,244 1,517 (22,294)
--------- --------- --------- --------- ---------
Net income (loss) from continuing operations . 26,087 22,156 (17,168) (2,816) 41,403
Preferred stock dividends ................. (2,021) (410) -- (1,853) (2,471)
--------- --------- --------- --------- ---------
Net income (loss) from continuing operations
attributable to common stock ............... 24,066 21,746 (17,168) (4,669) 38,932
Income from discontinued operations ....... 1,866 -- -- -- --
--------- --------- --------- --------- ---------
Net income (loss) attributable to common stock $ 25,932 $ 21,746 $ (17,168) $ (4,669) $ 38,932
========= ========= ========= ========= =========
Weighted average shares outstanding:
Basic ..................................... 15,449 24,186 24,275 24,601 26,290
========= ========= ========= ========= =========
Diluted ................................... 21,199 26,008 34,219
========= ========= =========
Basic earnings per share:
Net income (loss) from continuing operations $ 1.56 $ 0.90 $ (0.71) $ (0.19) $ 1.48
Net income (loss)........................... 1.68 0.90 (0.71) (0.19) 1.48
Diluted earnings per share:
Net income (loss) from continuing operations $ 1.23 $ 0.85 $ 1.21
Net income (loss)........................... 1.32 0.85 1.21
Other Financial Data:
EBITDA(2)..................................... $ 54,878 $ 68,757 $ 66,871 $ 66,031 $ 136,458
Ratio of EBITDA to interest expense........... 5.4 11.3 3.5 2.8 5.5
As of December 31,
-------------------------------------------------------------
1996 1997 1998 1999 2000
--------- --------- --------- --------- ---------
Balance Sheet Data:
Cash and cash equivalents.................... $ 16,162 $ 14,504 $ 5,176 $ 7,648 $ 7,105
Property and equipment, net.................. 185,928 410,781 404,017 395,862 434,913
Total assets................................. 222,002 456,800 429,672 434,973 489,930
Total debt................................... 80,108 260,000 278,104 254,131 234,101
Stockholders' equity......................... 118,216 124,594 109,663 137,174 180,173
- -------
(1) Includes lease operating costs and production and ad valorem taxes.
(2) EBITDA means income (loss) from continuing operations before income taxes,
plus interest, depreciation, depletion and amortization, exploration
expense and impairment of oil and gas properties. EBITDA is a financial
measure commonly used in the Company's industry and should not be
considered in isolation or as a substitute for net income, cash flow
provided by operating activities or other income or cash flow data prepared
in accordance with generally accepted accounting principles or as a measure
of a company's profitability or liquidity.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Results of Operations
The following table reflects certain summary operating data for the periods presented:
Year Ended December 31,
----------------------------------------
1998 1999 2000
---------- ----------- -----------
Net Production Data:
Oil (Mbbls).................................. 2,571 2,128 1,807
Natural gas (Mmcf)........................... 26,713 23,872 26,990
Natural gas equivalent (Mmcfe)............... 42,141 36,642 37,833
Average Sales Price:
Oil (Mbbls).................................. $ 12.73 $ 17.35 $ 30.02
Natural gas (Mmcf)........................... 2.25 2.23 4.26
Average equivalent price (per Mcfe).......... 2.21 2.47 4.48
Expenses ($ per Mcfe):
Oil and gas operating(1)..................... $ 0.59 $ 0.65 $ 0.79
General and administrative................... 0.04 0.07 0.09
Depreciation, depletion and
amortization(2)........................... 1.20 1.20 1.15
Cash Margin ($ per Mcfe)(3)...................... $ 1.58 $ 1.75 $ 3.60
- ----
(1)Includes lease operating costs and production and ad valorem taxes.
(2)Represents depreciation, depletion and amortization of oil and gas properties only.
(3)Represents average equivalent price per Mcfe less oil and gas operating expenses per Mcfe and general
and administrative expenses per Mcfe.
Year Ended December 31, 2000 Compared to Year Ended December 31, 1999
Comstock’ s oil and gas sales increased $79.2 million (88%) in 2000 to a record level of $169.4 million from $90.1 million in 1999. The substantial increase in revenues is due to significantly higher oil and gas prices in 2000 combined with a 3% increase in production. In 2000, the Company’s average oil price increased by 73% and its average gas price increased by 92% from 1999. Oil production decreased by 15% and natural gas production increased by 13% in 2000 as compared to 1999. Comstock expects production to increase to approximately 45 Bcfe in 2001 as result of its drilling activities.
Other income for the year ended December 31, 2000 decreased $1.7 million to $352,000 from $1.9 million for the year ended December 31, 1999. Included in other income for 1999 was an insurance recovery in the amount of $1.7 million received by the Company.
Oil and gas operating expenses, including production taxes, increased $6.0 million (25%) to $29.7 million in 2000 from $23.7 million in 1999. Oil and gas operating expenses per equivalent Mcf produced increased $0.14 to $0.79 in 2000 from $0.65 for 1999. The increases are related to higher production taxes resulting from the higher oil and gas prices in 2000 as well as an increase of $3.6 million in Comstock’s lifting costs relating to new wells put into production in 2000.
In 2000, the Company had $3.2 million in exploration expense which represents the write-off of five offshore exploratory dry holes (1.5 net). Exploration expense for 1999 was $1.8 million which related to the write-off of four dry holes (0.9 net).
Depreciation, depletion and amortization ("DD&A") decreased $213,000 to $45.0 million in 2000 from $45.2 million in 1999. DD&A per equivalent Mcf produced was $1.15 for 2000, a decrease from the DD&A rate of $1.20 in 1999.
General and administrative expenses, which are reported net of overhead reimbursements, increased $1.1 million (47%) to $3.5 million in 2000 from $2.4 million in 1999. The increase was primarily due to higher compensation paid to the Company’s personnel in 2000.
Interest expenses increased $1.2 million (5%) to $24.6 million for 2000 from $23.4 million for 1999. The increase is related to a higher average interest rate on the Company’s debt. The interest rate on the Company’s senior notes (11.25%) issued to refinance $150.0 million of indebtedness under the bank credit facility on April 29, 1999 was significantly higher than the interest rates charged under the bank credit facility. The weighted average interest rate under the Company’s bank credit facility was 6.9% for 2000, a decrease from the weighted average rate of 7.2% in 1999.
For 2000 the Company reported net income of $38.9 million, after preferred stock dividends of $2.5 million, as compared to a net loss of $4.7 million for year ended December 31, 1999, after preferred stock dividends of $1.9 million. Net income per share for 2000 was $1.21 on diluted weighted average shares outstanding of 34.2 million as compared to net loss per share of $0.19 for 1999 on weighted average shares outstanding of 24.6 million.
Year Ended December 31, 1999 Compared to Year Ended December 31, 1998
The Company’s oil and gas sales decreased $2.9 million (3%) in 1999, to $90.1 million from $93.0 million in 1998 due to a decrease in oil and natural gas production largely offset by higher oil prices in 1999. In 1999, the Company’s average oil price increased by 36% and its average gas price decreased by 1%. The Company hedged 39% of its 1999 natural gas production at a fixed price of $2.03 per Mcf. Without the impact of the hedge, the Company would have realized $2.43 per Mcf in 1999. In 1999, the Company’s oil production decreased by 17% and natural gas production decreased by 11%. The production declines in 1999 were principally attributable to the significantly lower drilling activity in the first half of 1999.
Other income for the year ended December 31, 1999 increased $1.6 million to $1.9 million from $274,000 for the year ended December 31, 1998. Included in other income for 1999 is a $1.7 million insurance recovery received by the Company on an exploratory well drilled in 1998 which was written off when the well was abandoned due to encountering numerous well control problems.
Oil and gas operating expenses, including production taxes, decreased $1.0 million (4%) to $23.7 million in 1999 from $24.7 million in 1998. Oil and gas operating expenses per equivalent Mcf produced increased $0.06 to $0.65 for the year ended December 31, 1999 from $0.59 for the year ended 1998 due to the 13% decrease in oil and natural gas production (on an equivalent Mcf basis) and the fixed nature of most of the Company’s lifting costs.
In 1999, the Company had $1.8 million in exploration expense which represents the write off of four offshore exploratory dry holes (.9 net). Exploration expense for 1998 of $8.3 million relates to the write off of the six dry holes (2.9 net) drilled in the Gulf of Mexico during 1998.
DD&A decreased $5.8 million (11%) to $45.2 million in 1999 from $51.0 million in 1998 due to the 13% decrease in oil and natural gas production. DD&A per equivalent Mcf produced was $1.20 for the year ended December 31, 1999 which remained unchanged from 1998‘s DD&A rate. Included in DD&A in 1999 is $538,000 relating to the amortization of costs associated with the issuance of the Company’s senior notes in April 1999.
General and administrative expenses, which are reported net of overhead reimbursements, increased $782,000 (48%) to $2.4 million in 1999 from $1.6 million in 1998. The increase relates to a $225,000 litigation settlement paid in 1999, a decrease in drilling overhead reimbursements received by the Company in 1999 due to the lower level of drilling in 1999 and higher personnel costs incurred in 1999.
Interest expense increased $6.4 million (38%) to $23.4 million for the year ended December 31, 1999 from $17.0 million for the year ended December 31, 1998. The Company capitalized interest expense of $2.3 million in 1998 on its unevaluated properties, while in 1999, no interest expense was capitalized. The remaining increase is related to a higher average interest rate on the Company’s debt. The weighted average annual interest rate under the Company’s bank credit facility was 7.2% for 1999, the same as the weighted average rate in 1998. The interest rate on the Company’s senior notes issued to refinance $150.0 million of amounts outstanding under the bank credit facility on April 29, 1999 (11.25%) was significantly higher than the 7.2% rate charged under the bank credit facility in 1998.
The Company reported a net loss of $4.7 million after preferred stock dividends of $1.9 million for the year ended December 31, 1999, as compared to a net loss of $17.2 million for year ended December 31, 1998. Net loss per share for 1999 was $0.19 on weighted average shares outstanding of 24.6 million as compared to net loss per share of $0.71 for 1998 on weighted average shares outstanding of 24.3 million.
Liquidity and Capital Resources
Funding for the Company’s activities has historically been provided by operating cash flow, debt and equity financings and asset dispositions. In 2000, the Company’s net cash flow provided by operating activities totaled $112.1 million before changes to other working capital accounts. The other primary funding source in 2000 was borrowings of $18.0 million under the Company’s revolving bank credit facility.
The Company’s primary needs for capital, in addition to funding of ongoing operations, relate to the acquisition, development and exploration of oil and gas properties and the repayment of debt. In 2000, the Company incurred capital expenditures of $83.4 million primarily for development, exploration and acquisition activities and reduced amounts outstanding under its bank credit facility by $38.0 million.
The Company’s annual capital expenditure activity is summarized as follows:
Year Ended December 31,
----------------------------
1998 1999 2000
------- ------- -------
Acquisitions of oil and gas properties... $ 2,453 $ 4,458 $ 9,684
Other leasehold costs ................... 3,622 2,258 6,964
Workovers and recompletions ............. 10,198 4,472 10,252
Offshore production facilities .......... -- 4,462 1,629
Development drilling .................... 20,361 11,521 35,047
Exploratory drilling .................... 30,423 8,126 19,202
Other ................................... 330 684 616
------- ------- -------
Total ............................... $67,387 $35,981 $83,394
======= ======= =======
The timing of most of the Company’s capital expenditures is discretionary with no material long-term capital expenditure commitments. Consequently, the Company has a significant degree of flexibility to adjust the level of such expenditures as circumstances warrant. The Company spent $64.6 million, $30.8 million and $73.1 million on development and exploration activities in 1998, 1999 and 2000, respectively. The Company currently anticipates spending approximately $100.0 million on development and exploration projects in 2001. The Company intends to primarily use internally generated cash flow to fund capital expenditures other than significant acquisitions.
The Company spent $2.5 million, $4.5 million and $9.7 million on acquisition activities in 1998, 1999 and 2000 respectively. The Company does not have a specific acquisition budget for 2001 as a result of the unpredictability of the timing and size of forthcoming acquisition activities. The Company intends to use borrowings under its bank credit facility, or other debt or equity financings to the extent available, to finance significant acquisitions. The availability and attractiveness of these sources of financing will depend upon a number of factors, some of which will relate to the financial condition and performance of the Company, and some of which will be beyond the Company’s control, such as prevailing interest rates, oil and gas prices and other market conditions.
The Company has a bank credit facility consisting of a $250.0 million revolving credit commitment provided by a syndicate of banks for which Bank One, NA serves as administrative agent. Indebtedness under the bank credit facility is secured by substantially all of the Company’s assets and is subject to borrowing base availability which is generally redetermined semiannually based on the banks’ estimates of the future net cash flows of the Company’s oil and gas properties. The borrowing base under the bank credit facility is currently $205.0 million. Such borrowing base may be affected from time to time by the performance of the Company’s oil and gas properties and changes in oil and gas prices. The determination of the Company’s borrowing base is at the sole discretion of the administrative agent and the bank group. The revolving credit line under the bank credit facility bears interest at the option of the Company, based on the utilization of the borrowing base, at either (i) LIBOR plus 1.25% to 2.0% or (ii) the “corporate base rate” plus 0.25% to 1.0%. The Company incurs a commitment fee, based on the utilization of the borrowing base, of 0.25% to 0.5% per annum on the unused portion of the borrowing base. As of December 31, 2000, $84.0 million was outstanding under the bank credit facility. The revolving credit line matures on December 9, 2002 or such earlier date as the Company may elect. The bank credit facility contains covenants which, among other things, restrict the payment of cash dividends, limit the amount of consolidated debt, and limit the Company’s ability to make certain loans and investments. Significant financial covenants include the maintenance of a current ratio, as defined, (1.0 to 1.0), maintenance of tangible net worth ($105.0 million), and maintenance of an interest coverage ratio (2.5 to 1.0).
The Company believes that cash flow from operations and available borrowings under the Company’s bank credit facility will be sufficient to fund its operations and future growth as contemplated under its current business plan. However, if the Company’s plans or assumptions change or if its assumptions prove to be inaccurate, the Company may be required to seek additional capital. Management cannot be assured that the Company will be able to obtain such capital or, if such capital is available, that the Company will be able to obtain it on acceptable terms.
Federal Taxation
At December 31, 2000, the Company had federal income tax net operating loss (“NOL”) carryforwards of approximately $38.0 million. The NOL carryforwards expire from 2009 through 2019. The value of these carryforwards depends on the ability of the Company to generate federal taxable income and to utilize the carryforwards to reduce such income.
Year 2000
“Year 2000,” or the ability of computer systems to process dates with years beyond 1999, affects almost all companies and organizations. Computer systems that were not Year 2000 compliant by January 1, 2000 may cause an adverse effect to companies and organizations that rely upon those systems. The Company assessed and corrected computer systems that were unable to properly process dates beyond 1999. The Company’s significant financial information systems are outsourced and the Company is relying on assurances from the providers that they are Year 2000 compliant. The Company’s costs related to Year 2000 have not been significant. The Company has not experienced any significant problems or delays related to Year 2000 subsequent to January 1, 2000. In addition, the Company does not expect any future material effects to arise from Year 2000.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS
The Company’s operations are impacted by fluctuations in crude oil and natural gas commodity prices and interest rates. The following discussion is intended to identify the nature of these market risks, describe the Company’s strategy for managing such risks, and to quantify the potential affect of market volatility on the Company’s financial condition and results of operations.
Oil and Natural Gas Prices
The Company’s financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond the control of the Company. These factors include the level of global demand for petroleum, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect the Company’s financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that the Company can produce economically. Any reduction in oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse affect on the Company’s ability to obtain capital for its exploration and development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on the Company’s financial condition, results of operations and capital resources. Based on the Company’s oil and natural gas production in 2000, before taking into account any hedging transactions, a $1.00 change in the price per barrel of oil would result in a change in the Company’s cash flow for such period of approximately $1.9 million and a $1.00 change in the price per Mcf of natural gas would result in a change in the Company’s cash flow of approximately $28.3 million.
The Company periodically has utilized hedging transactions with respect to a portion of its oil and natural gas production to mitigate its exposure to price fluctuations. While the use of these hedging arrangements limits the downside risk of price declines, such use may also limit any benefits which may be derived from price increases. The Company has primarily used price swaps, whereby monthly settlements are based on differences between the prices specified in the instruments and the settlement prices of certain futures contracts quoted on the NYMEX or certain other indices. Generally, when the applicable settlement price is less than the price specified in the contract, the Company receives a settlement from the counterparty based on the difference. Similarly, when the applicable settlement price is higher than the specified price, the Company pays the counterparty based on the difference. During 2000, the Company did not hedge any of its oil and natural gas production. As of December 31, 2000, the Company had no open derivative financial instruments held for price risk management.
Interest Rates
At December 31, 2000, the Company had long-term debt of $234.0 million; of this amount, $150.0 million bears interest at a fixed rate of 11.25%. The fair market value of the fixed rate debt as of December 31, 2000 was $155.3 million based on the market price of 103.5 of the face amount as of the closing day of 2000. The remaining outstanding long-term debt of $84.0 million is under the Company’s bank credit facility which is subject to floating market rates of interest. Borrowings under the bank credit facility bear interest at a fluctuating rate that is linked to LIBOR or the corporate base rate, at the Company’s option. Any increases in these interest rates can have an adverse impact on the Company’s results of operations and cash flow. The Company entered into interest rate swap agreements to hedge the impact of interest rate changes on a large portion of its floating rate debt for part of 2000. As a result of the interest rate swaps in place, the Company realized gains of $1.0 million in 2000. As of December 31, 2000, the Company had no open derivative financing instruments held for interest rate management.
New Accounting Pronouncement
In September 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133") which has been amended by SFAS 137 and SFAS 138. The Statement establishes accounting and reporting standards that are effective for fiscal years beginning after June 15, 2000 which require that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. The Statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Such derivatives are reported at cost, if any, and gains and losses on such derivatives are reported when the hedged transaction occurs. Accordingly, if the Company uses derivatives in the future, SFAS 133 will have an impact on the reported financial position and comprehensive income of the Company.
ITEM 8. FINANCIAL STATEMENTS
The Consolidated Financial Statements for Comstock Resources, Inc. and Subsidiaries are included on pages F-1 to F-20 of this report.
The financial statements have been prepared by the management of the Company in conformity with generally accepted accounting principles. Management is responsible for the fairness and reliability of the financial statements and other financial data included in this report. In the preparation of the financial statements, it is necessary to make informed estimates and judgments based on currently available information on the effects of certain events and transactions.
The Company maintains accounting and other controls which management believes provide reasonable assurance that financial records are reliable, assets are safeguarded, and that transactions are properly recorded in accordance with management’s authorizations. However, limitations exist in any system of internal control based upon the recognition that the cost of the system should not exceed benefits derived.
The Company’s independent public accountants, Arthur Andersen LLP, are engaged to audit the financial statements of the Company and to express an opinion thereon. Their audit is conducted in accordance with generally accepted auditing standards to enable them to report whether the financial statements present fairly, in all material respects, the financial position and results of operations of the Company in accordance with generally accepted accounting principles.
The Audit Committee of the Board of Directors of the Company, composed of three directors who are not employees, meets periodically with the independent public accountants and management. The independent public accountants have full and free access to the Audit Committee to meet, with and without management being present, to discuss the results of their audits and the quality of financial reporting.
ITEM 9. CHANGES
IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING
AND FINANCIAL DISCLOSURE
Not applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item is incorporated herein by reference to the Company's definitive proxy statement which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2000.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is incorporated herein by reference to the Company's definitive proxy statement which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2000.
ITEM 12. SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT
The information required by this item is incorporated herein by reference to the Company's definitive proxy statement which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2000.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is incorporated herein by reference to the Company's definitive proxy statement which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2000.
PART IV
ITEM 14. EXHIBITS AND REPORTS ON FORM 8-K
Exhibits:
The following exhibits are included on pages E-1 to E-4 of this report.
Exhibit No. Description
- ------------- ------------------------------------------------------------
3.1(a) Restated Articles of Incorporation of the Company
(incorporated by reference to Exhibit 3.1 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1995).
3.1(b) Certificate of Amendment to the Restated Articles of
Incorporation dated July 1, 1997 (incorporated herein by
reference to Exhibit 3.1 to the Company's Quarterly Report
on Form 10-Q for the quarter ended June 30, 1997).
3.2 Bylaws of the Company (incorporated by reference to Exhibit
3.2 to the Company's Registration Statement on Form S-3,
dated October 25, 1996).
4.1 Rights Agreement dated as of December 14, 2000, by and
between the Company and American Stock Transfer and Trust
Company, as Rights Agent (incorporated herein by reference
to Exhibit 1 to the Company's Registration Statement on Form
8-A dated January 11, 2001).
4.2 Certificate of Voting Powers, Designations, Preferences, and
Relative, Participating, Optional or Other Special Rights of
the Series A 1999 Convertible Preferred Stock and Series B
1999 Non-Convertible Preferred Stock (incorporated herein by
reference to Exhibit 4.1 to the Company's Current Report on
Form 8-K dated April 29, 1999).
4.3 Stock Purchase Agreement dated April 29, 1999 between the
Company and certain purchasers (incorporated herein by
reference to Exhibit 10.1 to the Company's Current Report on
Form 8-K dated April 29, 1999).
4.4 Certificate of Designation, Preferences and Rights of Series
B Junior Participating Preferred Stock (incorporated herein
by reference to Exhibit 2 to the Company Registration
Statement on Form 8-A dated January 11, 2001.
4.5 Indenture dated as April 29, 1999 between the Company and
U.S. Trust Company of Texas, N.A., Trustee for the
$150,000,000 11 1/4% Senior Notes due 2007 (incorporated
herein by reference to Exhibit 10.5 to the Company's Current
Report on Form 8-K dated April 29, 1999).
10.1 Amended and Restated Credit Agreement dated as of November
7, 2000, between the Company, the Banks Party thereto and
Bank One, NA, as Administrative Agent, Toronto Dominion
(Texas), Inc., as Syndication Agent and Paribas, as
Documentation Agent (incorporated herein by reference to
Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q
for the quarter ended September 30, 2000).
10.2# Employment Agreement dated May 16, 2000, by and between the
Company and M. Jay Allison (incorporated herein by reference
to Exhibit 10.4 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 2000).
10.3# Employment Agreement dated May 16, 2000, by and between the
Company and Roland O. Burns (incorporated herein by
reference to Exhibit 10.5 to the Company's Quarterly Report
on Form 10-Q for the quarter ended June 30, 2000).
10.4# Comstock Resources, Inc. 1999 Long-term Incentive Plan
(incorporated herein by reference to Exhibit 10.1 to the
Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 1999).
10.5# Form of Nonqualified Stock Option Agreement between the
Company and certain officers and directors of the Company
(incorporated herein by reference to Exhibit 10.2 to the
Company's Quarterly Report on Form 10-Q for the year ended
June 30, 1999).
10.6# Form of Restricted Stock Agreement between the Company and
certain officers of the Company (incorporated herein by
reference to Exhibit 10.3 to the Company's Quarterly Report
on Form 10-Q for the quarter ended June 30, 1999).
10.7 Warrant Agreement dated December 9, 1997 by and between the
Company and Bois d' Arc Resources (incorporated herein by
reference to Exhibit 10.10 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1997).
10.8 Joint Exploration Agreement dated December 8, 1997 by and
between the Company and Bois d' Arc Resources (incorporated
herein by reference to Exhibit 10.11 to the Company's Annual
Report on Form 10-K for the year ended December 31, 1997).
10.9 Office Lease Agreement dated August 12, 1997 between the
Company and Briar Center LLC (incorporated by reference to
Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q
for the quarter ended September 30, 1997).
21* Subsidiaries of the Company.
23* Consent of Arthur Andersen LLP.
- ----------------
*Filed herewith.
# Management contract or compensatory plan document.
Reports on Form 8-K:
Form 8-K Reports filed subsequent to September 30, 2000 are as follows:
Date Item Description
- --------------------- ------- -------------------------
December 8, 2000 5 Stock Repurchase Plan
December 18, 2000 5 Stockholder Rights Plan
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.
| COMSTOCK RESOURCES, INC By:/s/M. JAY ALLISON M. Jay Allison President and Chief Executive Officer (Principal Executive Officer) |
Date: March 9, 2001
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.
| /s/M. JAY ALLISON M. Jay Allison |
President, Chief Executive Officer and Chairman of the Board of Directors (Principal Executive Officer) |
March 9, 2001 | |
| /s/ROLAND O. BURNS Roland O. Burns |
Senior Vice President, Chief Financial Officer, Secretary, Treasurer and Director (Principal Financial and Accounting Officer) |
March 9, 2001 | |
| /s/FRANKLIN B. LEONARD Franklin B. Leonard |
Director | March 9, 2001 | |
| /s/CECIL E. MARTIN, JR. Cecil E. Martin, Jr. |
Director | March 9, 2001 | |
| /s/DAVID W. SLEDGE David W. Sledge |
Director | March 9, 2001 |
To the Board of Directors and Stockholders of Comstock Resources, Inc.:
We have audited the accompanying consolidated balance sheets of Comstock Resources, Inc. (a Nevada corporation) and subsidiaries as of December 31, 1999 and 2000, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. 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 financial position of Comstock Resources, Inc. and subsidiaries as of December 31, 1999 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Dallas, Texas,
February 16, 2001
ASSETS
December 31,
----------------------
1999 2000
--------- ---------
(In thousands)
Cash and Cash Equivalents .................................. $ 7,648 $ 7,105
Accounts Receivable:
Oil and gas sales ........................................ 18,200 34,637
Joint interest operations ................................ 5,415 4,574
Other Current Assets ....................................... 909 2,842
--------- ---------
Total current assets .............................. 32,172 49,158
Property and Equipment:
Unevaluated oil and gas properties ....................... 2,231 5,206
Oil and gas properties, successful efforts method ........ 581,247 659,505
Other .................................................... 2,163 2,589
Accumulated depreciation, depletion and amortization ..... (189,779) (232,387)
--------- ---------
Net property and equipment ........................ 395,862 434,913
Other Assets ............................................... 6,939 5,859
--------- ---------
$ 434,973 $ 489,930
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Portion of Long-Term Debt .......................... $ 131 $ 101
Accounts Payable and Accrued Expenses ...................... 35,587 45,544
--------- ---------
Total current liabilities ......................... 35,718 45,645
Long-Term Debt, less current portion ....................... 254,000 234,000
Deferred Taxes Payable ..................................... 261 22,555
Reserve for Future Abandonment Costs ....................... 7,820 7,557
Stockholders' Equity:
Preferred stock--$10.00 par, 5,000,000 shares
authorized, 3,000,000 and 1,757,310 shares
outstanding at December 31, 1999 and 2000, respectively.. 30,000 17,573
Common stock--$0.50 par, 50,000,000 shares
authorized, 25,375,197 and 28,837,755 shares
outstanding at December 31, 1999 and 2000, respectively.. 12,688 14,419
Additional paid-in capital ................................ 114,855 129,896
Retained earnings (deficit) ............................... (19,603) 19,329
Deferred compensation-restricted stock grants ............. (766) (1,044)
--------- ---------
Total stockholders' equity .......................... 137,174 180,173
--------- ---------
$ 434,973 $ 489,930
========= =========
The accompanying notes are an integral part of these statements.
1998 1999 2000
--------- --------- ---------
(In thousands, except per share amounts)
Revenues:
Oil and gas sales ....................... $ 92,961 $ 90,103 $ 169,350
Gain on sales of property ............... -- 130 33
Other income ............................ 274 1,911 319
--------- --------- ---------
Total revenues ................. 93,235 92,144 169,702
--------- --------- ---------
Expenses:
Oil and gas operating ................... 24,747 23,714 29,707
Exploration ............................. 8,301 1,832 3,192
Depreciation, depletion and amortization 51,005 45,171 44,958
General and administrative, net ......... 1,617 2,399 3,537
Interest ................................ 16,977 23,361 24,611
Impairment of oil and gas properties .... 17,000 -- --
--------- --------- ---------
Total expenses ................. 119,647 96,477 106,005
--------- --------- ---------
Income (loss) before income taxes ............ (26,412) (4,333) 63,697
Income tax benefit (expense) ................. 9,244 1,517 (22,294)
--------- --------- ---------
Net income (loss) ............................ (17,168) (2,816) 41,403
Preferred stock dividends .................... -- (1,853) (2,471)
--------- --------- ---------
Net income (loss) attributable to common stock $ (17,168) $ (4,669) $ 38,932
========= ========= =========
Net income (loss) per share:
Basic........................... $ (0.71) $ (0.19) $ 1.48
========= ========= =========
Diluted......................... $ 1.21
=========
Weighted average shares outstanding:
Basic........................... 24,275 24,601 26,290
========= ========= =========
Diluted......................... 34,219
=========
The accompanying notes are an integral part of these statements.
Deferred
Additional Retained Compensation-
Preferred Common Paid-In Earnings Restricted
Stock Stock Capital (Deficit) Stock Grants Total
---------- ---------- ---------- ---------- ---------- ----------
(In thousands)
Balance at December 31, 1997........ $ -- $ 12,104 $ 110,273 $ 2,234 $ (17) $ 124,594
Issuance of common stock.......... -- 71 664 -- -- 735
Value of stock options issued
for exploration prospects...... -- -- 1,495 -- -- 1,495
Restricted stock grants........... -- -- -- -- 7 7
Net loss attributable to
common stock................... -- -- -- (17,168) -- (17,168)
---------- ---------- ---------- ---------- ---------- ----------
Balance at December 31, 1998........ -- 12,175 112,432 (14,934) (10) 109,663
---------- ---------- ---------- ---------- ---------- ----------
Issuance of preferred stock....... 30,000 -- -- -- -- 30,000
Issuance of common stock.......... -- 400 1,166 -- -- 1,566
Value of stock options issued
for exploration prospects...... -- -- 498 -- -- 498
Restricted stock grants........... -- 113 759 -- (756) 116
Net loss attributable to
common stock................... -- -- -- (4,669) -- (4,669)
---------- ---------- ---------- ---------- ---------- ----------
Balance at December 31, 1999........ 30,000 12,688 114,855 (19,603) (766) 137,174
---------- ---------- ---------- ---------- ---------- ----------
Conversion of preferred stock..... (12,427) 1,553 10,874 -- -- --
Issuance of common stock.......... -- 150 706 -- -- 856
Value of stock options issued
for exploration prospects...... -- -- 2,990 -- -- 2,990
Restricted stock grants........... -- 28 471 -- (278) 221
Net income attributable to
common stock................... -- -- -- 38,932 -- 38,932
---------- ---------- ---------- ---------- ---------- ----------
Balance at December 31, 2000........ $ 17,573 $ 14,419 $ 129,896 $ 19,329 $ (1,044) $ 180,173
========== ========== ========== ========== ========== ==========
The accompanying notes are an integral part of these statements.
1998 1999 2000
--------- --------- ---------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) ....................................... $ (17,168) $ (2,816) $ 41,403
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Compensation paid in common stock ..................... 269 247 314
Depreciation, depletion and amortization .............. 51,005 45,171 44,958
Impairment of oil and gas properties .................. 17,000 -- --
Deferred income taxes ................................. (9,244) (1,517) 22,294
Exploration ........................................... 8,301 1,832 3,192
Gain on sales of property ............................. -- (130) (33)
--------- --------- ---------
Working capital provided by operations .............. 50,163 42,787 112,128
Decrease (increase) in accounts receivable .............. 13,380 (5,754) (15,596)
Decrease (increase) in other current assets ............. (1,285) 548 (1,933)
Increase (decrease) in accounts payable and
accrued expenses ...................................... (21,532) 935 9,957
--------- --------- ---------
Net cash provided by operating activities ........... 40,726 38,516 104,556
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sales of properties ....................... -- 778 33
Capital expenditures and acquisitions ................... (67,387) (35,981) (83,394)
--------- --------- ---------
Net cash provided by operating activities ........... (67,387) (35,203) (83,361)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings .............................................. 23,238 10,378 18,408
Proceeds from senior notes offering ..................... -- 149,221 --
Debt issuance costs ..................................... (1,059) (5,671) --
Principal payments on debt .............................. (5,134) (184,351) (38,438)
Proceeds from preferred stock offering .................. -- 30,000 --
Proceeds from common stock issuances .................... 288 296 763
Stock issuance costs .................................... -- (714) --
Dividends paid on preferred stock ....................... -- -- (2,471)
--------- --------- ---------
Net cash provided by financing activities ............... 17,333 (841) (21,738)
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents (9,328) 2,472 (543)
Cash and cash equivalents, beginning of year ........ 14,504 5,176 7,648
--------- --------- ---------
Cash and cash equivalents, end of year .............. $ 5,176 $ 7,648 $ 7,105
========= ========= =========
The accompanying notes are an integral part of these statements.
Comstock Resources, Inc., a Nevada corporation (together with its subsidiaries, the “Company”), was formed in 1919 as Comstock Tunnel and Drainage Company. In 1987, the Company’s name was changed to Comstock Resources, Inc. The Company is primarily engaged in the acquisition, development, production and exploration of oil and natural gas properties in the United States.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Concentrations of Credit Risk
Although the Company’s cash equivalents and accounts receivable are exposed to credit loss, the Company does not believe such risk to be significant. Cash equivalents are high-grade, short-term securities, placed with highly rated financial institutions. Most of the Company’s accounts receivable are from a broad and diverse group of oil and gas companies and, accordingly, do not represent a significant credit risk.
Oil and Gas Properties
The Company follows the successful efforts method of accounting for its oil and gas operations. Under this method, costs of productive wells, development dry holes and productive leases are capitalized and amortized on a unit-of-production basis over the life of the remaining related oil and gas reserves. Cost centers for amortization purposes are determined on a field area basis. The estimated future costs of dismantlement, restoration and abandonment are accrued as part of depreciation, depletion and amortization expense and included in the accompanying Consolidated Balance Sheets as Reserve for Future Abandonment Costs.
Oil and gas leasehold costs are capitalized. Unproved oil and gas properties with significant acquisition costs are periodically assessed and any impairment in value is charged to expense. The costs of unproved properties which are determined to be productive are transferred to proved oil and gas properties. Exploratory expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties, are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property but charged to expense if and when the well is determined not to have found proved oil and gas reserves.
In accordance with the Statement of Financial Accounting Standards 121 “Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of”, the Company assesses the need for an impairment of capitalized costs of oil and gas properties on a property by property basis. If an impairment is indicated based on undiscounted expected future cash flows, then an impairment is recognized to the extent that net capitalized costs exceed discounted expected future cash flows. No impairment was required in 1999 or 2000. Due to the substantial drop in oil and gas prices during 1998, the Company provided an impairment of $17.0 million in 1998.
Other Property and Equipment
Other property and equipment of the Company consists primarily of work boats, gas gathering systems, computer equipment and furniture and fixtures which are depreciated over estimated useful lives on a straight-line basis.
Other Assets
Other assets of the Company primarily consists of deferred costs associated with issuance of the Company’s 11¼% senior notes and borrowings under the Company’s bank credit facility. These costs are amortized over the lives of the respective debt instruments on a straight-line basis.
Income Taxes
Deferred income taxes are provided to reflect the future tax consequences of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates.
Earnings Per Share
Basic and diluted earnings per share for 1998, 1999 and 2000 were determined as follows:
Year Ended December 31,
--------------------------------------------------------------------------------------------
1998 1999 2000
----------------------------- ------------------------------ ----------------------------
Income Per Income Per Income Per
(Loss) Shares Share (Loss) Shares Share (Loss) Shares Share
-------- -------- -------- --------- --------- -------- -------- --------- -------
Basic Earnings Per Share:
Income (Loss)............. $(17,168) 24,275 $ (2,816) 24,601 $ 41,403 26,290
Less Preferred Stock
Dividends................ -- -- (1,853) -- (2,471)
-------- -------- --------- --------- -------- -------- --------- -------
Net Income (Loss) Available
to Common Stockholders... $(17,168) 24,275 $ (0.71) $ (4,669) 24,601 $ (0.19) 38,932 26,290 $ 1.48
======== ======== ======== ========= ========= ======== ======== ========= =======
Diluted Earning Per Share:
Effect of Dilutive Securities:
Stock Options............ -- 1,184
Convertible Preferred Stock 2,471 6,745
-------- ---------
Net Income Available to
Common Stockholders and
Assumed Conversions.... $ 41,403 34,219 $ 1.21
======== ======== =======
Statements of Cash Flows
For the purpose of the consolidated statements of cash flows, the Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
The following is a summary of all significant noncash investing and financing activities and cash payments made for interest and income taxes:
------------------------------
1998 1999 2000
--------- --------- ---------
Noncash activities -
Common stock issued for compensation .................. $ 269 $ 131 $ 93
Value of vested stock options under exploration venture 1,495 498 2,990
Common stock issued in payment of preferred
stock dividends .............................. -- 1,853 --
Cash payments -
Interest payments ..................................... 19,898 20,840 24,731
Income tax payments ................................... -- -- --
Comprehensive Income
The Company had no comprehensive income components in each of the three years ended December 31, 2000; therefore, comprehensive income/ loss is the same as net income/ loss for all periods presented.
Segment Reporting
The Company presently operates in one business segment.
Derivative Instruments and Hedging Activities
In September 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”) which has been amended by SFAS 137 and SFAS 138. The Statement establishes accounting and reporting standards that are effective for fiscal years beginning after June 15, 2000 which require that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. The Statement requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met.
The Company periodically uses derivatives to hedge floating interest rates and oil and gas price risks. Such derivatives are reported at cost, if any, and gains and losses on such derivatives are reported when the hedged transaction occurs. Accordingly, if the Company uses derivatives in the future, SFAS 133 will have an impact on the reported financial position and comprehensive income of the Company. The Company adopted SFAS 133 on January 1, 2001, and since the Company had no outstanding derivatives, there was no effect on the Company’s financial statements as a result of such adoption.
Set forth below is certain information regarding the aggregate capitalized costs of oil and gas properties and costs incurred in oil and gas property acquisition, development and exploration activities:
Capitalized Costs
As of December 31,
----------------------
1999 2000
--------- ---------
(In thousands)
Proved properties .............. $ 581,247 $ 659,505
Unproved properties ............ 2,231 5,206
Accumulated depreciation,
depletion and amortization.... (189,270) (231,667)
--------- ---------
$ 394,208 $ 433,044
========= =========
Costs Incurred
For the Year Ended December 31,
----------------------------
1998 1999 2000
------- ------- -------
(In thousands)
Property acquisitions
Proved properties.... $ -- $ 4,458 $11,302
Unproved properties.. 6,075 2,258 5,346
Development costs ....... 30,559 20,455 46,928
Exploration costs ....... 30,423 8,126 19,202
------- ------- -------
$67,057 $35,297 $82,778
======= ======= =======
The following presents the results of operations of oil and gas producing activities:
For the Year Ended December 31,
-----------------------------------
1998 1999 2000
--------- --------- ---------
(In thousands)
Oil and gas sales ............................. $ 92,961 $ 90,103 $ 169,350
Production costs .............................. (24,747) (23,714) (29,707)
Exploration ................................... (8,301) (1,832) (3,192)
Depreciation, depletion and amortization ...... (50,738) (44,118) (43,478)
Impairment of oil and gas properties .......... (17,000) -- --
--------- --------- ---------
Operating income (loss) ....................... (7,825) 20,439 92,973
Income tax benefit (expense)................... 2,739 (7,154) (32,541)
--------- --------- ---------
Results of operations (excluding general
and administrative and interest expenses) $ (5,086) $ 13,285 $ 60,432
========= ========= =========
Long-term debt is comprised of the following:
As of December 31,
1999 2000
--------- ---------
(In thousands)
Revolving Bank Credit Facility $ 104,000 $ 84,000
11 1/4% Senior Notes due 2007 150,000 150,000
Other ........................ 131 101
--------- ---------
254,131 234,101
Less current portion ......... (131) (101)
--------- ---------
$ 254,000 $ 234,000
========= =========
On April 29, 1999, the Company closed the sale of $150.0 million in aggregate principal amount of 11¼% Senior Notes due in 2007 (the “Notes”). Interest on the Notes is payable semiannually on May 1 and November 1, commencing on November 1, 1999. Proceeds from the sale of the Notes were used to reduce amounts outstanding under the Company’s bank credit facility. The Notes are unsecured obligations of the Company and are guaranteed by all of the Company’s principal operating subsidiaries. The Company can redeem the Notes beginning on May 1, 2004. The fair market value of the Notes as of December 31, 2000 was $155.3 million based on the market price of 103.5 of the face amount as of the closing day of 2000.
The Company’s bank credit facility consists of a $250.0 million revolving credit commitment provided by a syndicate of banks for which Bank One, NA serves as administrative agent. The borrowing base under the bank credit facility is $205.0 million. Such borrowing base may be affected from time to time by the performance of the Company’s oil and gas properties and changes in oil and gas prices. The determination of the Company’s borrowing base is at the sole discretion of the administrative agent and the bank group. The revolving credit line under the bank credit facility bears interest at the option of the Company, based on the utilization of the borrowing base, at either (i) LIBOR plus 1.25% to 2.0%, or (ii) the “corporate base rate” plus 0.25% to 1.0%. The Company incurs a commitment fee, based on the utilization of the borrowing base, of 0.25% to 0.5% per annum on the unused portion of the borrowing base. The revolving credit line matures on December 9, 2002 or such earlier date as the Company may elect. The bank credit facility contains covenants which, among other things, restrict the payment of cash dividends, limit the amount of consolidated debt, and limit the Company’s ability to make certain loans and investments. Significant financial covenants include the maintenance of a current ratio, as defined, (1.0 to 1.0), maintenance of tangible net worth ($124.5 million), and maintenance of an interest coverage ratio (2.5 to 1.0). The Company’s bank credit facility is secured by the Company’s oil and gas properties.
The Company rents office space under a noncancellable lease. Minimum future payments under the lease are as follows:
2001 ..... $ 423
2002 ..... 416
2003 ..... 416
2004 ..... 452
2005 ..... 477
Thereafter 196
------
$2,380
======
Preferred Stock
On April 29, 1999, the Company sold 3,000,000 shares of newly issued convertible preferred stock with a $10 par value in a private placement for $30.0 million. The preferred stock accrues dividends at an annual rate of 9% which are payable quarterly in cash or in shares of the Company’s common stock, at the election of the Company. Shares of the preferred stock are convertible, at the option of the holder, into shares of common stock of the Company. Based on the initial conversion price of $4.00 per share of common stock, each share of preferred stock is convertible into 2.5 shares of common stock. On May 1, 2005 and on each May 1, thereafter, so long as any shares of the preferred stock are outstanding, the Company is obligated to redeem an amount of shares of preferred stock equal to one-third of the shares of the preferred stock outstanding on May 1, 2005 at $10.00 per share plus accrued and unpaid dividends. The mandatory redemption price may be paid either in cash or in shares of common stock, at the option of the Company. The Company has the option to redeem the shares of preferred stock upon payment to the holders of the preferred stock at a specified rate of return on the initial purchase. Upon a change of control of the Company, the holders of the preferred stock have the right to require the Company to purchase all or a portion of the preferred stock.
In September and October 2000, holders of 1,242,690 shares of the Company’s convertible preferred stock converted their shares into 3,106,725 shares of common stock. As a result of these conversions, $12.4 million of preferred stockholders’ equity was transferred to common stockholders’ equity.
Common Stock
Under a plan adopted by the Board of Directors, non-employee directors can elect to receive shares of common stock valued at the then current market price in payment of annual director and consulting fees. Under this plan, the Company issued 39,678, 44,255 and 8,182 shares of common stock in 1998, 1999 and 2000 respectively, in payment of fees aggregating $263,000, $130,000 and $93,000 for 1998, 1999 and 2000 respectively.
The Company’s outstanding preferred stock series provides that the Company can issue common stock in lieu of cash for payment of quarterly dividends. The Company issued 640,525 shares of common stock in 1999 in payment of dividends on its preferred stock of $1.9 million. The Company paid the preferred stock dividends in cash in 2000.
Options and warrants to purchase common stock of the Company were exercised for 102,000 shares, 115,000 shares and 291,400 shares in 1998, 1999 and 2000, respectively. Such exercises yielded net proceeds to the Company of approximately $288,000, $295,000 and $763,000 in 1998, 1999 and 2000, respectively.
Stock Options and Warrants
On June 23, 1999, the Company’s stockholders approved the 1999 Long-term Incentive Plan for the Company’s management including officers, directors and managerial employees which replaced the Company’s 1991 Long-term Incentive Plan. The 1999 Long-term Incentive Plan together with the 1991 Long-term Incentive Plan (the “Incentive Plans”) authorize the grant of non-qualified stock options and incentive stock options and the grant of restricted stock to key executives of the Company. As of December 31, 2000, the Incentive Plans provide for future awards of stock options or restricted stock grants of up to 292,382 shares of common stock plus 1% of the outstanding shares of common stock each year beginning January 1, 2001.
The following table summarizes stock option activity during 1998, 1999 and 2000 under the Incentive Plans:
Weighted
Number Average
of Shares Exercise Price Exercise Price
--------- --------------- --------------
Outstanding at December 31, 1997.... 3,218,500 $2.00 to $12.38 $8.43
Granted ....................... 767,000 $3.44 to $11.94 $4.57
Exercised .......................... (85,000) $2.00 to $2.50 $2.38
Forfeited ..................... (10,000) $3.44 $3.44
---------
Outstanding at December 31, 1998.... 3,890,500 $2.00 to $12.38 $7.81
Granted ....................... 1,010,000 $3.88 $3.88
Exercised........................... (115,000) $2.00 to $3.00 $2.57
Forfeited ..................... (155,500) $3.00 to $12.38 $7.81
---------
Outstanding at December 31, 1999.... 4,630,000 $2.00 to $12.38 $7.08
Granted ....................... 351,250 $6.69 to $8.88 $8.24
Exercised........................... (291,400) $2.00 to $4.81 $2.62
---------
Outstanding at December 31, 2000.... 4,689,850 $2.00 to $12.38 $7.45
=========
Exercisable at December 31, 2000.... 2,765,100 $2.00 to $12.38 $7.33
=========
The following table summarizes information about the Incentive Plans stock options outstanding at December 31, 2000:
Number of Number of
Shares Weighted Average Shares
Exercise Price Outstanding Remaining Life Exercisable
-------------- ----------- ---------------- --------------
(Years)
$2.00 248,300 0.2 248,300
$2.50 20,000 1.5 20,000
$3.44 498,300 6.8 362,800
$3.88 1,005,000 7.3 288,750
$4.81 224,000 0.6 224,000
$6.56 235,000 1.1 235,000
$6.69 102,000 6.5 40,000
$6.94 150,000 3.0 150,000
$8.88 249,250 8.5 --
$9.63 90,000 1.5 90,000
$11.00 1,269,000 4.7 809,000
$11.94 40,000 2.4 40,000
$12.38 559,000 4.5 257,250
---------- ------ --------------
4,689,850 4.9 2,765,100
========== ====== ==============
The Company accounts for the stock options issued under the Incentive Plans under APB Opinion No. 25, under which no compensation cost has been recognized. Had compensation cost for these plans been determined consistent with Statement of Financial Accounting Standards 123 (“SFAS 123”) “Accounting for Stock-Based Compensation,” the Company’s net income attributable to common stock and earnings per share from continuing operations would have been reduced to the following pro forma amounts:
1998 1999 2000
--------- --------- --------
(In thousands, except per share amounts)
Net income:
As Reported.......... $ (17,168) $ (4,669) $ 38,932
Pro Forma............ (20,651) (6,644) 34,832
Basic earnings per share:
As Reported.......... (0.71) (0.19) 1.48
Pro Forma............ (0.85) (0.27) 1.32
Diluted earnings per share:
As Reported.......... 1.21
Pro Forma............ 1.02
Because the SFAS 123 method of accounting has not been applied to options granted prior to January 1, 1995, the resulting pro forma compensation cost may not be representative of that to be expected in future years.
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for grants in 1998, 1999 and 2000, respectively: average risk-free interest rates of 5.3, 5.7 and 6.2 percent; average expected lives of 8.2, 8.8 and 7.8 years; average expected volatility factors of 58.8, 64.2 and 66.4; and no dividend yield. The estimated weighted average fair value of options to purchase one share of common stock issued under the Company’s Incentive Plans was $2.98 in 1998, $2.86 in 1999 and $5.98 in 2000.
On December 8, 1997, the Company awarded warrants to purchase up to 1,000,000 shares of the Company’s common stock at $14.00 per share under a five-year joint exploration venture. The warrants become exercisable in increments of 50,000 shares upon the election by the Company to complete a successful exploration well on a prospect generated under the joint exploration venture. Warrants which become exercisable under the exploration venture expire on December 31, 2007. The fair value of each warrant to purchase one share of common stock is estimated at the date of grant at $9.97 using the Black-Scholes option pricing model with the following assumptions: risk-free interest rate of 6.35 percent; expected life of 10.1 years; expected volatility factor of 51.9 percent; and no dividend yield. Warrants to purchase 150,000, 50,000 and 300,000 shares became vested in 1998, 1999 and 2000, respectively. The estimated value of the warrants which vested in 1998, 1999 and 2000 of $1.5 million, $0.5 million and $3.0 million, respectively, was included as exploration costs in each year.
Restricted Stock Grants
Under the Incentive Plans, officers and managerial employees of the Company may be granted a right to receive shares of the Company’s common stock without cost to the employee. The shares vest over a specified period with credit given for past service rendered to the Company. Restricted stock grants for 611,250 shares have been awarded under the Incentive Plans. As of December 31, 2000, 414,375 shares of such awards are vested. A provision for the restricted stock grants is made ratably over the vesting period.
Compensation expense recognized for restricted stock grants for the years ended December 31, 1998, 1999 and 2000 was $7,000, $116,000 and $221,000, respectively.
The Company had sales to one purchaser of crude oil which accounted for 25%, 33%, and 29% of the Company’s oil and gas sales in 1998, 1999 and 2000, respectively. The Company had two purchasers of natural gas which accounted for 17% and 12% of the Company’s oil and gas sales in 1998 and 21% and 11% of the Company’s oil and gas sales in 2000. In 1999, the Company had one purchaser of natural gas which accounted for 20% of the Company’s oil and gas sales.
The tax effects of significant temporary differences representing the net deferred tax liability at December 31, 1999 and 2000 were as follows:
1999 2000
-------- --------
(In thousands)
Net deferred tax assets (liabilities):
Property and equipment ............ $(15,804) $(36,562)
Net operating loss carryforwards .. 14,993 13,457
Other carryforwards ............... 550 550
-------- --------
$ (261) $(22,555)
======== ========
The following is an analysis of the consolidated income tax benefit (expense):
1999 2000
-------- --------
(In thousands)
Current.............................. $ -- $ --
Deferred ............................ 1,517 22,294
------- -------
$ 1,517 $ 22,294
======= ========
There were no differences between income taxes computed using the statutory rate of 35% and the Company’s effective tax rate in 1999 and 2000 of 35%.
The Company has net operating loss carryforwards of approximately $38.0 million as of December 31, 2000 for income tax reporting purposes which expire in varying amounts from 2009 to 2019.
The Company’s market risk exposures relate primarily to commodity prices and interest rates. Therefore, the Company periodically uses commodity price swaps to hedge the impact of natural gas price fluctuations and uses interest rate swaps to hedge interest rates on floating rate debt. The Company does not engage in activities using complex or highly leveraged instruments. These instruments are generally put in place to limit risk of adverse natural gas price or interest rate movements, however, these instruments usually limit future gains from favorable natural gas prices or lower interest rates. Recognition of realized gains or losses in the Consolidated Statements of Operations is deferred until the underlying physical product is purchased or sold. Unrealized gains or losses on derivative financial instruments are not recorded. The cash flow impact of derivative and other financial instruments is reflected as cash flows from operating activities in the Consolidated Statements of Cash Flows.
As a result of certain hedging transactions for natural gas the Company realized the following gains and losses:
1998 1999 2000
------- ------- --------
(In thousands)
Realized Gains.... $ 367 $ 248 $ --
Realized Losses... -- (5,178) --
As of December 31, 1999 and 2000, the Company had no open derivative financial instruments held for price risk management.
The Company periodically enters into interest rate swap agreements to hedge the impact of interest rate changes on a portion of its long-term debt. Gains and losses attributable to the swap agreements are accounted for as a hedge. Gains from the swap agreements reduced interest expense by $59,000, $169,000 and $988,000 in 1998, 1999 and 2000, respectively. As of December 31, 1999 and 2000, the Company had no open derivative financial instruments held for interest rate management.
First Second Third Fourth Total
-------- -------- -------- -------- --------
(In thousands, except per share amounts)
1999 -
Total revenues ............... $ 19,634 $ 22,676 $ 22,974 $ 26,860 $ 92,144
======== ======== ======== ======== ========
Net income (loss) attributable
to common stock ........... $ (4,119) $ (1,384) $ (1,339) $ 2,173 $ (4,669)
======== ======== ======== ======== ========
Net income (loss) per share .. $ (0.17) $ (0.06) (0.05) $ 0.09 $ (0.19)
======== ======== ======== ======== ========
2000 -
Total revenues ............... $ 33,143 $ 38,634 $ 44,987 $ 52,938 $169,702
======== ======== ======== ======== ========
Net income attributable
to common stock ........... $ 4,085 $ 7,934 $ 12,135 $ 14,778 $ 38,932
======== ======== ======== ======== ========
Net income per share:
Basic ..................... $ 0.16 $ 0.31 $ 0.47 $ 0.52 $ 1.48
======== ======== ======== ======== ========
Diluted ................... $ 0.14 $ 0.25 $ 0.37 $ 0.44 $ 1.21
======== ======== ======== ======== ========
The estimates of proved oil and gas reserves utilized in the preparation of the financial statements were estimated by independent petroleum engineers in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board, which require that reserve reports be prepared under existing economic and operating conditions with no provision for price and cost escalation except by contractual agreement. All of the Company’s reserves are located onshore in or offshore to the continental United States.
Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. There can be no assurance that the proved reserves will be developed within the periods indicated or that prices and costs will remain constant. There can be no assurance that actual production will equal the estimated amounts used in the preparation of reserve projections. In accordance with the Securities and Exchange Commission’s guidelines, the Company’s independent petroleum engineers’ estimates of future net cash flows from the Company’s proved properties and the present value thereof are made using oil and natural gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties. Average prices used in estimating the future net cash flows were as follows: $24.56 and $26.34 per barrel of oil at December 31, 1999 and 2000, respectively, and $2.51 and $10.51 per Mcf of natural gas at December 31, 1999 and 2000, respectively.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and estimates of other engineers might differ materially from those shown below. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Results of drilling, testing and production after the date of the estimate may justify revisions. Accordingly, reserve estimates are often materially different from the quantities of oil and gas that are ultimately recovered. Reserve estimates are integral in management’s analysis of impairments of oil and gas properties and the calculation of depreciation, depletion and amortization on those properties.
The following unaudited table sets forth proved oil and gas reserves at December 31, 1998, 1999 and 2000:
1998 1999 2000
-------------------- -------------------- --------------------
Oil Gas Oil Gas Oil Gas
(MBbls) (MMcf) (MBbls) (MMcf) (MBbls) (MMcf)
-------- -------- -------- -------- -------- --------
Proved Reserves:
Beginning of year .............. 20,927 240,117 20,245 250,402 19,467 258,121
Revisions of previous
estimates ................. (3,284) 12,025 (1,695) (14,272) (1,725) 1,205
Extensions and discoveries ..... 5,173 24,973 3,029 39,534 1,599 54,574
Purchases of minerals in place.. -- -- 16 6,329 416 11,059
Sales of minerals in place ..... -- -- -- -- (499) (134)
Production ..................... (2,571) (26,713) (2,128) (23,872) (1,807) (26,990)
-------- -------- -------- -------- -------- --------
End of year .................... 20,245 250,402 19,467 258,121 17,451 297,835
======== ======== ======== ======== ======== ========
Proved Developed Reserves:
Beginning of year .............. 16,635 188,102 16,585 182,955 14,379 184,123
======== ======== ======== ======== ======== ========
End of year .................... 16,585 182,955 14,379 184,123 12,290 200,349
======== ======== ======== ======== ======== ========
The following table sets forth the standardized measure of discounted future net cash flows relating to proved reserves at December 31, 1999 and 2000:
1999 2000
----------- -----------
(In thousands)
Cash Flows Relating to Proved Reserves:
Future Cash Flows ................................... $ 1,124,796 $ 3,590,711
Future Costs:
Production ...................................... (250,068) (527,939)
Development ..................................... (80,519) (126,904)
----------- -----------
Future Net Cash Flows Before Income Taxes ........... 794,209 2,935,868
Future Income Taxes ................................. (144,048) (825,033)
----------- -----------
Future Net Cash Flows ............................... 650,161 2,110,835
10% Discount Factor ................................. (181,448) (822,071)
----------- -----------
Standardized Measure of Discounted Future Net Cash Flows.. $ 468,713 $ 1,288,764
=========== ===========
The following table sets forth the changes in the standardized measure of discounted future net cash flows relating to proved reserves for the years ended December 31, 1998, 1999 and 2000:
1998 1999 2000
----------- ---------- ----------
(In thousands)
Standardized Measure, Beginning of Year ............ $ 418,276 $ 304,993 $ 468,713
Net Change in Sales Price, Net of Production Costs (146,742) 179,042 1,141,880
Development Costs Incurred During the Year Which
Were Previously Estimated ..................... 20,361 5,303 17,340
Revisions of Quantity Estimates .................. (7,391) (35,727) (44,256)
Accretion of Discount ............................ 45,956 30,531 51,506
Changes in Future Development Costs .............. (19,318) (437) (41,525)
Changes in Timing and Other ...................... (39,805) (2,271) (166,410)
Extensions and Discoveries ....................... 60,906 91,911 375,632
Purchases of Reserves in Place ................... -- 7,787 62,621
Sales of Reserves in Place ....................... -- -- (3,355)
Sales, Net of Production Costs ................... (68,214) (66,389) (139,643)
Net Changes in Income Taxes ...................... 40,964 (46,030) (433,739)
---------- ----------- ----------
Standardized Measure, End of Year .................. $ 304,993 $ 468,713 $1,288,764
=========== ========== ==========
Exhibit No. Description Page
- -------------- ---------------------------------------------- --------
3.1(a) Restated Articles of Incorporation of the
Company (incorporated by reference to Exhibit
3.1 to the Company's Annual Report on Form
10-K for the year ended December 31, 1995).
3.1(b) Certificate of Amendment to the Restated
Articles of Incorporation dated July 1, 1997
(incorporated herein by reference to Exhibit
3.1 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1997).
3.2 Bylaws of the Company (incorporated by
reference to Exhibit 3.2 to the Company's
Registration Statement on Form S-3, dated
October 25, 1996).
4.1 Rights Agreement dated as of December 14,
2000, by and between the Company and American
Stock Transfer and Trust Company, as Rights
Agent (incorporated herein by reference to
Exhibit 1 to the Company's Registration
Statement on Form 8-A dated January 11,
2001).
4.2 Certificate of Voting Powers, Designations,
Preferences, and Relative, Participating,
Optional or Other Special Rights of the
Series A 1999 Convertible Preferred Stock and
Series B 1999 Non-Convertible Preferred Stock
(incorporated herein by reference to Exhibit
4.1 to the Company's Current Report on Form
8-K dated April 29, 1999).
4.3 Stock Purchase Agreement dated April 29, 1999
between the Company and certain purchasers
(incorporated herein by reference to Exhibit
10.1 to the Company's Current Report on Form
8-K dated April 29, 1999).
4.4 Certificate of Designation, Preferences and
Rights of Series B Junior Participating
Preferred Stock (incorporated herein by
reference to Exhibit 2 to the Company
Registration Statement on Form 8-A dated
January 11, 2001.
4.5 Indenture dated as April 29, 1999 between the
Company and U.S. Trust Company of Texas,
N.A., Trustee for the $150,000,000 11 1/4%
Senior Notes due 2007 (incorporated herein by
reference to Exhibit 10.5 to the Company's
Current Report on Form 8-K dated April 29,
1999).
10.1 Amended and Restated Credit Agreement dated
as of November 7, 2000, between the Company,
the Banks Party thereto and Bank One, NA, as
Administrative Agent, Toronto Dominion
(Texas), Inc., as Syndication Agent and
Paribas, as Documentation Agent (incorporated
herein by reference to Exhibit 10.1 to the
Company's Quarterly Report on Form 10- Q for
the quarter ended September 30, 2000).
E - 1
Exhibit No. Description Page
- -------------- ---------------------------------------------- --------
10.2# Employment Agreement dated May 16, 2000, by
and between the Company and M. Jay Allison
(incorporated herein by reference to Exhibit
10.4 to the Company's Quarterly Report on
Form 10-Q for the quarter ended June 30,
2000).
10.3# Employment Agreement dated May 16, 2000, by
and between the Company and Roland O. Burns
(incorporated herein by reference to Exhibit
10.5 to the Company's Quarterly Report on
Form 10-Q for the quarter ended June 30,
2000).
10.4# Comstock Resources, Inc. 1999 Long-term
Incentive Plan (incorporated herein by
reference to Exhibit 10.1 to the Company's
Quarterly Report on Form 10-Q for the quarter
ended June 30, 1999).
10.5# Form of Nonqualified Stock Option Agreement
between the Company and certain officers and
directors of the Company (incorporated herein
by reference to Exhibit 10.2 to the Company's
Quarterly Report on Form 10-Q for the year
ended June 30, 1999).
10.6# Form of Restricted Stock Agreement between
the Company and certain officers of the
Company (incorporated herein by reference to
Exhibit 10.3 to the Company's Quarterly
Report on Form 10-Q for the quarter ended
June 30, 1999).
10.7 Warrant Agreement dated December 9, 1997 by
and between the Company and Bois d' Arc
Resources (incorporated herein by reference
to Exhibit 10.10 to the Company's Annual
Report on Form 10-K for the year ended
December 31, 1997).
10.8 Joint Exploration Agreement dated December 8,
1997 by and between the Company and Bois d'
Arc Resources (incorporated herein by
reference to Exhibit 10.11 to the Company's
Annual Report on Form 10- K for the year
ended December 31, 1997).
10.9 Office Lease Agreement dated August 12, 1997
between the Company and Briar Center LLC
(incorporated by reference to Exhibit 10.2 to
the Company's Quarterly Report on Form 10-Q
for the quarter ended September 30, 1997).
21* Subsidiaries of the Company. E-3
23* Consent of Arthur Andersen LLP. E-4
*Filed herewith.
# Management contract or compensatory plan document.
E - 2