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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
X THE SECURITIES EXCHANGE ACT OF 1934
--- For the fiscal year ended December 31, 1998
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ______ to ______
Commission File No. 0-16741
COMSTOCK RESOURCES, INC.
(Exact name of registrant as specified in its charter)
NEVADA 94-1667468
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
5005 LBJ Freeway, Suite 1000, Dallas, Texas 75244
(Address of principal executive offices including zip code)
(972) 701-2000
(Registrant's telephone number and area code)
Securities registered pursuant to Section 12(b) of the Act:
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)
Securities registered pursuant to Section 12(g) of the Act: None
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. [ X ]
As of March 12, 1999, there were 24,350,452 shares of common stock
outstanding.
As of March 12, 1999, the aggregate market value of the voting stock held
by non-affiliates of the registrant was approximately $78,000,000.
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this report is incorporated by
reference from registrant's definitive proxy statement for its 1999 annual
meeting of stockholders (to be filed with the Securities and Exchange Commission
not later than April 30, 1999).
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COMSTOCK RESOURCES, INC.
FORM 10-K
For the Fiscal Year Ended December 31, 1998
CONTENTS
Page
Part I
Items 1 and 2. Business and Properties..................................... 5
Item 3. Legal Proceedings...........................................20
Item 4. Submission of Matters to a Vote of Security Holders.........20
Part II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters.........................................21
Item 6. Selected Financial Data.....................................22
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations...............23
Item 8. Financial Statements........................................29
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure...............29
Part III
Item 10. Directors and Executive Officers of the Registrant..........30
Item 11. Executive Compensation......................................30
Item 12. Security Ownership of Certain Beneficial Owners
and Management....................................30
Item 13. Certain Relationships and Related Transactions..............30
Part IV
Item 14. Exhibits and Reports on Form 8-K............................31
1
FORWARD-LOOKING STATEMENTS
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, estimates of 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 the Company believes that
the expectations reflected in such forward-looking statements are reasonable, it
can give no assurance that such expectations will prove to have been correct.
There are numerous uncertainties inherent in estimating quantities of proved oil
and natural gas reserves and in projecting future rates of production and timing
of development expenditures, including many factors beyond the control of the
Company. Reserve engineering is a subjective process of estimating underground
accumulations of oil and natural gas that cannot be measured in an exact way,
and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment. As
a result, estimates made by different engineers often vary from one another. In
addition, results of drilling, testing and production subsequent to the date of
an estimate may justify revisions of such estimate and such revisions, if
significant, would change the schedule of any further production and development
drilling. Accordingly, reserve estimates are generally different from the
quantities of oil and gas that are ultimately recovered. All forward-looking
statements in this report are expressly qualified in their entirety by the
cautionary statements in this paragraph.
DEFINITIONS
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 Bbl.
"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.
"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.
2
"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
non-property 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.
3
(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 that in 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 cost 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.
4
PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
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. The
Company has an oil and natural gas reserve base which is entirely focused in the
Gulf of Mexico, Southeast Texas and East Texas/ North Louisiana regions.
Approximately 43% of the Company's oil and natural gas reserves are located in
the Gulf of Mexico, 26% in Southeast Texas and 31% in East Texas/ North
Louisiana. Due to this focus, Comstock has accumulated significant geologic
knowledge, technical expertise and industry relationships in these regions.
Additionally, the Company has significant operating control over its properties
and operates 83% of its Present Value of Proved Reserves as of December 31,
1998. Comstock has compiled a high quality reserve base that is 67% natural gas
and 76% proved developed on a Bcfe basis. The Company has estimated proved oil
and natural gas reserves of 371.9 Bcfe with an estimated Present Value of Proved
Reserves of $305.3 million as of December 31, 1998.
Comstock has achieved substantial growth in oil and gas reserves,
production and revenues over the last five years. The Company's estimated proved
oil and natural gas reserves have increased at a compounded annual growth rate
of 32% from 123.6 Bcfe at the end of 1994 to 371.9 Bcfe at the end of 1998.
Average net daily production has increased at a compounded annual growth rate of
51% from 22.2 MMcfe per day in 1994 to 115.5 MMcfe per day in 1998. The
Company's oil and gas revenues have increased from $16.9 million in 1994 to
$93.0 million in 1998.
While its historical growth has been primarily attributable to
acquisitions, during 1998 Comstock focused on the exploitation and development
of its properties through development drilling, workovers, recompletions and
exploration. The Company believes it has a significant inventory of development
and exploration prospects and increased its spending on exploration and
development activities from $2.1 million in 1994 to $64.6 million in 1998. In
1998, Comstock drilled 30 development wells (18.2 net) of which 25 were
successful (14.7 net) and 14 exploratory wells (7.2 net) of which eight were
successful (4.3 net).
Over the past five years, the Company has been able to lower lifting costs
and general and administrative expenses per unit of production, concurrent with
increases in production, through strict control over operations and costs.
Comstock's lifting costs per Mcfe have decreased from $0.75 in 1994 to $0.59 in
1998. Comstock's general and administrative expenses per Mcfe have decreased
from $0.19 in 1994 to $0.04 in 1998. Operated wells represent 83% of the
Company's Present Value of Proved Reserves as of December 31, 1998, which
enables Comstock to effectively control costs and expenses and the timing and
method of exploration and development of its properties. Additionally,
Comstock's geographic focus allows it to manage its asset base with a relatively
small number of employees.
Business Strategy
The Company's strategy is to increase cash flow and net asset value by
exploiting its reserves, pursuing selective exploration opportunities,
maintaining a low cost structure and acquiring oil and gas properties at
attractive costs.
Exploit Existing Reserves
The Company 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
5
techniques. During 1998, the Company spent $20.4 million to drill 30 development
wells (18.2 net), of which 25 wells (14.7 net) were successful, representing a
success rate of 83%. In addition, the Company spent approximately $10.2 million
for recompletion and workover activity during 1998. The Company has budgeted up
to $26.0 million in 1999 for development drilling and installation of production
facilities. Comstock's level of spending on development drilling in 1999 will be
principally dependent on improvement to existing oil and gas prices.
Pursue Selective Exploration Opportunities
The Company pursues selective exploration activities to find additional
reserves on its undeveloped acreage. In 1998, the Company spent approximately
$30.4 million to drill 14 exploratory wells (7.2 net), of which eight wells (4.3
net) were successful, representing a success rate of 53%. The Company has
budgeted up to $10.0 million in 1999 for exploration activities which will be
focused on the Gulf of Mexico region and based on drilling 3-D seismic generated
prospects. These prospects include those acquired from Bois d' Arc Resources and
certain of its affiliates and working interest partners, and those prospects
generated under the joint exploration program with Bois d' Arc Resources and its
principals ("Bois d' Arc") entered into in December 1997 under which the Company
and Bois d' Arc jointly explore for prospects in the Gulf of Mexico Region (the
"Bois d' Arc Exploration Venture"). Under the Bois d' Arc Exploration Venture,
Bois d' Arc is responsible for identifying potential prospects and the parties
jointly acquire 3-D seismic data and leasehold acreage, the costs for which are
shared 80% by the Company and 20% by Bois d' Arc. With respect to any prospect
in which the Company elects to participate in drilling, the Company acquires up
to 33% working interest and recovers any disproportionate seismic and leasehold
costs previously incurred. The Company issued to Bois d' Arc warrants to acquire
up to 1,000,000 shares of the Company's common stock at an exercise price of
$14.00 per share as part of the venture. The warrants vest in 50,000 share
increments based on the success of an initial test well on a prospect.
Maintain Low Cost Structure
The Company seeks to increase cash flow by carefully controlling operating
costs and general and administrative expenses. The Company targets acquisitions
that possess, among other characteristics, low per unit operating costs. In
addition, the Company has been able to reduce per unit operating costs by
eliminating unnecessary field and corporate overhead costs and by divesting
properties that have high lifting costs with little future development
potential. Through these efforts, the Company's general and administrative
expenses and average oil and gas operating costs per Mcfe have decreased from
$0.19 and $0.75, respectively, in 1994 to $0.04 and $0.59, respectively, in
1998.
In addition, the Company prefers to operate the properties it acquires,
allowing it to further control operating costs, exercise greater control over
the timing and plans for future development, the level of drilling and lifting
costs, and the marketing of production. The Company operates 366 of the 580
wells in which it owns an interest which comprise approximately 83% of its
Present Value of Proved Reserves as of December 31, 1998.
Acquire High Quality Properties at Attractive Costs
The Company has a successful track record of increasing its oil and natural
gas reserves through opportunistic acquisitions. Since 1991, Comstock has added
482.4 Bcfe of proved oil and natural gas reserves from 18 acquisitions at a
total cost of $411.9 million, or $0.85 per Mcfe. The acquisitions were acquired
at 63% of their Present Value of Proved Reserves in the year the acquisitions
were completed. The Company's three largest acquisitions to date have been its
acquisition of offshore Gulf of Mexico properties from Bois d' Arc and certain
of its affiliates and working interest partners in December 1997 for $200.9
6
million (the "Bois d'Arc Acquisition"), its acquisition of Black Stone Oil
Company and interests in the Double A Wells field in Southeast Texas in May 1996
for $100.4 million (the "Black Stone Acquisition") and its purchase of
properties from Sonat Inc. in July 1995 for $48.1 million (the "Sonat
Acquisition"). The Company applies strict economic and reserve risk criteria in
evaluating acquisitions and 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.
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, 1998.
Present Value
Net Oil Net Gas of Proved
Field Area (MBbls) (MMcf) MMcfe Reserves Percentage
---------- ------- ------ ----- -------- ----------
(In thousands)
Gulf of Mexico:
Ship Shoal .................... 11,344 35,935 104,000 $ 99,803
South Timbalier/ South Pelto .. 1,191 4,583 11,728 10,580
Bay Marchand .................. 1,062 1,689 8,064 7,725
West Cameron .................. 1 5,638 5,643 5,380
Main Pass ..................... 1,831 2,309 13,295 4,869
East White Point .............. 814 3,512 8,393 3,704
El Campo ...................... 241 3,394 4,842 3,214
Other ......................... 75 3,086 3,538 2,447
------ ------ ------- -------
16,559 60,146 159,503 137,722 45.1%
------ ------ ------- -------
Southeast Texas:
Double A Wells ................ 2,836 76,954 93,968 86,925
Redmond Creek ................. 124 1,522 2,267 1,861
------ ------ ------- -------
2,960 78,476 96,235 88,786 29.1%
------ ------ ------- -------
East Texas/ North Louisiana:
Beckville ..................... 117 27,387 28,089 17,611
Logansport .................... 52 22,133 22,442 17,103
Waskom ........................ 239 13,457 14,893 7,133
Box Church .................... 3 11,855 11,870 6,975
Lisbon ........................ 80 6,095 6,574 6,330
Blocker ....................... 43 9,977 10,234 5,553
Ada ........................... 9 3,934 3,988 4,657
Longwood ...................... 40 5,542 5,779 3,543
Sugar Creek ................... 65 2,980 3,371 3,237
Sligo ......................... 13 2,223 2,299 1,673
Simsboro ...................... 3 2,266 2,282 1,387
Other ......................... 45 3,419 3,699 3,080
------ ------ ------- -------
709 111,268 115,520 78,282 25.6%
------ ------ ------- -------
Other Areas ................... 17 512 614 519 .2%
------ ------- ------- -------- ------
Total ......................... 20,245 250,402 371,872 $305,309 100.0%
====== ======= ======= ======== ======
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 121
producing wells (71.1 net) in 11 field areas, the largest of which are the Ship
Shoal area (Ship Shoal Blocks 66, 67, 68, 69 and South Pelto Block 1), the Main
Pass area (Main Pass Blocks 21 and 25), Bay Marchand Blocks 4 and 5 and the
South Timbalier/ South Pelto area (South Timbalier Blocks 11,16, 34, 50 and
South Pelto Blocks 5 and 15.) The Company has 159.5 Bcfe of oil and natural gas
reserves in the Gulf of Mexico region with a Present Value of Proved Reserves of
$137.7 million as of December 31, 1998. The Company operates 47 of the wells
(46.1 net) that it owns in this region. The Company acquired a large percentage
of its reserves in the region in the Bois d' Arc Acquisition. Production from
the region averaged 17.5 MMcf of natural gas per day and 5,229 barrels of oil
7
per day during 1998. The Company spent $35.7 million in this region in 1998 to
drill two development wells (1.4 net) and to drill 13 exploratory wells (6.7
net). In 1999, the Company plans to spend $2.0 million for production facilities
at Bay Marchand and South Timbalier/ South Pelto and up to $12.0 million for
development drilling and up to $10.0 million for exploration activities in this
region.
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 became the operator of its properties in this area as a
result of the Bois d' Arc Acquisition and owns a 99% to 100% working interest
and operates these properties except for its properties in Ship Shoal Block 69
in which the Company has a 25% working interest. In the Ship Shoal area, oil and
natural gas are produced from numerous Miocene sands occurring at depths from
5,800 feet to 13,500 feet, and in water depths from 10 to 40 feet. The Company's
Ship Shoal area has estimated proved reserves of 104.0 Bcfe (28% of total proved
reserves) with a Present Value of Proved Reserves of $99.8 million as of
December 31, 1998. The Company owns interests in 33 wells (23.9 net) in the Ship
Shoal area, which averaged 12.8 MMcf of natural gas per day and 4,342 barrels of
oil per day during 1998.
In 1998 the Company drilled five wells (5.0 net), four exploratory wells
and one development well in the Ship Shoal area. Three of the exploration wells
were successful and one was a dry hole. The three successful wells were placed
on production in November and December 1998. The Company has temporarily
abandoned the development well as it was unable to successfully complete it.
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. 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 has drilled three successful wells in the area since beginning its
exploration program with Bois d' Arc in 1998. These wells should be placed on
production from common facilities which are expected to be completed by mid-year
1999. The Company also acquired a 33% working interest in seven producing wells
as well as production facilities in this area in 1998. The Company has
identified six exploration prospects and one proved undeveloped location in this
area using 3-D seismic, targeting the Upper Miocene sands occurring at depths
from 10,000 to 12,000 feet. The Company has estimated proved net reserves
totaling 11.7 Bcfe (3% of total proved reserves) in this area as of December 31,
1998.
Bay Marchand
The Company owns a 22.5% working interest in Louisiana state leases in the
Bay Marchand area, located offshore of Lafourche Parish in 12 feet of water. The
Company has drilled three successful wells in its exploration program with Bois
d' Arc since its inception in early 1998. The Company has estimated proved net
reserves totaling 8.1 Bcfe (2% of total proved reserves) at Bay Marchand as of
December 31, 1998. Production from these wells should begin in the second
quarter of 1999 pending the acquisition of production facilities for the new
wells. The properties are located on the west flank of the Bay Marchand salt
dome in a highly prolific oil and natural gas producing region. Producing zones
in this area are Upper to Middle Miocene in age, highly porous and permeable,
and occur at depths ranging from 9,000 to 14,500 feet. The Company has
identified three additional exploration prospects in this area, using 3-D
seismic data.
8
Southeast Texas
Approximately 26% (96.2 Bcfe) of the Company's proved reserves are located
in Southeast Texas where the Company owns interests in 32 producing wells (12.2
net) and operates 24 of these wells. Reserves in Southeast Texas represent 29%
of the Company's Present Value of Proved Reserves as of December 31, 1998.
Production rates from the area averaged 28.3 MMcf of natural gas per day and
1,532 barrels of oil per day during 1998.
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
second largest field area with total estimated proved reserves of 94.0 Bcfe (25%
of total proved reserves) which have a Present Value of Proved Reserves of $86.9
million as of December 31, 1998. The Company acquired its interests in the
Double A Wells field in May 1996 in the Black Stone Acquisition. Net daily
production averaged 1,463 barrels of oil per day and 27.4 MMcf of natural gas
during 1998. These wells typically produce from the Woodbine formation at an
average depth of 14,300 feet. The Company has an average working interest in
this area of 37% and its leasehold position at December 31, 1998 consisted of
21,225 acres (7,863 net). During 1998, the Company successfully recompleted two
wells in this field and is in the process of acquiring 3-D seismic data on
25,000 acres in this area. The Company has budgeted $2.5 million to drill two
development wells (0.6 net) in the Double A Wells field in 1999.
East Texas/ North Louisiana
Approximately 31% (115.5 Bcfe) of the Company's proved reserves are located
in East Texas and North Louisiana where the Company owns interests in 401
producing wells (225.2 net) in 18 field areas and operates 276 of these wells
(199.5 net). The largest of the Company's field areas in this region are the
Beckville, Logansport, Waskom and Box Church fields. Reserves in the region
represented 26% of the Company's Present Value of Proved Reserves as of December
31, 1998. Production from this region averaged 27.1 MMcf of natural gas per day
and 246 barrels of oil per day during 1998. The Company's largest acquisition in
this region was the Sonat Acquisition in July 1995. Since this acquisition, the
Company has focused on increasing production through infill drilling and
recompletions. 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 feet 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 feet to 10,500 feet. The
Company believes that success in these formations can be enhanced by applying
new hydraulic fracturing and completion techniques, magnetic resonance imaging
(MRI) logging tools and infill drilling. In 1998 the Company spent $14.5 million
to drill 29 wells (17.3 net) and plans to spend up to $9.5 million in 1999 to
drill 16 development wells (10.5 net).
Beckville
The Company's properties in the Beckville field, located in Panola County,
Texas, represented approximately 8% (28.1 Bcfe) of the Company's proved reserves
as of December 31, 1998. The Company operates 54 wells in this field and owns
interests in seven additional wells. The Company has an average working interest
of 72% in this field. During 1998, the production attributable to the Company's
interest from this field averaged 4.3 MMcf of natural gas and 23 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 nine wells (6.2 net) in
1998 at a cost of $6.2 million and has budgeted up to $4.5 million to drill six
development wells (4.6 net) in 1999.
9
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 22.4 Bcfe in the Logansport field
represented approximately 6% of the Company's proved reserves as of December 31,
1998. The Company operates 72 wells in this field and owns interests in 32
additional wells. The Company's average working interest in this field is 50%.
During 1998, production attributable to the Company's interest averaged 7.1 MMcf
of natural gas and 28 barrels of oil per day. The Company spent $3.4 million to
drill nine wells (4.4 net) during 1998 and has budgeted up to $2.0 million to
drill six development wells in 1999 (3.2 net).
Waskom
The Waskom field, located in Harrison and Panola Counties in Texas,
represented approximately 4% (14.9 Bcfe) of the Company's proved reserves as of
December 31, 1998. The Company operates 58 wells in this field and owns
interests in 38 additional wells. The Company's average working interest in this
field is 49%. During 1998, production attributable to the Company's interest
averaged 2.3 MMcf of natural gas and 32 barrels of oil per day. The Waskom field
produces from the Cotton Valley formation at depths ranging from 9,000 to 10,000
feet.
Box Church
The Company's properties in the Box Church field, located in Limestone
County, Texas, represented approximately 3% (11.9 Bcfe) of the Company's proved
reserves as of December 31, 1998. The Company operates nine wells in this field
with an average working interest of 86%. During 1998, production attributable to
the Company's interest from this field averaged 1.3 MMcf of natural gas and 2
barrels of oil per day. The Box Church field produces from the Cotton Valley
formation at depths ranging from 10,200 to 10,500 feet. The Company drilled
three wells (3.7 net) in 1998 at a cost of $2.4 million and has budgeted up to
$1.6 million to drill two development wells (1.9 net) in 1999.
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 strong 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. The Company believes that due to the current environment of
depressed commodity prices, the industry will continue to consolidate as
companies look to divest oil and gas properties. As a result, the Company may
have opportunities to make acquisitions at favorable prices, including
attractive acquisitions outside its core operating areas.
10
Major Property Acquisitions
As a result of its acquisitions, the Company has added 482.4 Bcfe of proved
oil and natural gas reserves since 1991 as summarized in the following table:
Present Acquisition
Value of Cost as a
Proved Percentage
Reserves of Present
Acquisition Acquisition When Value of
Cost Proved Reserves When Acquired(1) Cost Per Acquired Proved
Year (000's) (MBbls) (MMcf) (MMcfe) Mcfe(1) (000's)(1) Reserves(1)
- ---- ------- ------- ------ ------- ------- ---------- -----------
1997(2) $ 189,904 14,473 39,970 126,808 $1.50 $205,583 92%
1996 100,446 5,930 100,446 136,027 0.74 282,150 36%
1995 56,081 1,859 108,432 119,585 0.47 85,706 65%
1994 12,970 388 12,744 15,074 0.86 14,050 92%
1993 26,928 2,250 28,349 41,848 0.64 33,502 80%
1992 4,730 44 8,821 9,086 0.52 8,474 56%
1991 20,862 689 29,868 34,002 0.61 27,298 76%
--------- ------ ------- ------- ---- --------
Total $ 411,921 25,633 328,630 482,430 0.85 $656,763 63%
========= ====== ======= ======= ==== ========
<FN>
(1) Based on reserve estimates and prices at the end of the year in which the
acquisition occurred, as adjusted to reflect actual production from the
closing date of the respective acquisition to such year end.
(2) The 1997 Acquisitions exclude acquisition costs allocated to unevaluated
properties of $30.2 million and other assets of $1.0 million.
</FN>
In 1998 the Company's only acquisition was a purchase of acreage and
production facilities at South Timbalier Blocks 34 and 50 and South Pelto Block
15 located offshore of Louisiana in the Gulf of Mexico.
Of the 18 property acquisitions completed by the Company since 1991, four
acquisitions described below account for 83% of the total acquisition cost and
total reserves acquired.
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 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
Company also acquired interests in seven undrilled prospects which were
delineated by 3-D seismic data. The net proved reserves acquired were estimated
at 14.3 MMBbls of oil and 29.4 Bcf of natural gas. Approximately $30.2 million
of the purchase price was attributed to the undrilled prospects and $1.0 million
was attributed to other assets.
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 is 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, Blocker, Longwood and Simsboro fields. The net proved
reserves acquired were estimated at 0.8 MMBbls of oil and 104.7 Bcf of natural
gas.
11
Stanford Acquisition. In November 1993, the Company acquired Stanford
Offshore Energy, Inc. ("Stanford") through a merger with a wholly owned
subsidiary. The Stanford stockholders were issued an aggregate of 1,760,000
shares of common stock of the Company in the merger with a total value of $6.2
million and the Company assumed approximately $16.5 million of indebtedness of
Stanford. Stanford had interests in 107 producing wells (58.8 net) located
primarily in the Gulf of Mexico region. Major properties acquired include West
Cameron Blocks 238, 248 and 249, the East White Point field and the Redmond
Creek field. The net proved reserves acquired were estimated at 1.0 MMBbls of
oil and 17.8 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, 1998:
Present
Value of
Proved
Oil Gas Total Reserves
Category (MBbls) (Mmcf) (Mmcfe) (000's)
-------- ------- ------ ------- -------
Proved Developed Producing 9,800 132,613 191,414 $176,780
Proved Developed Non-producing 6,785 50,342 91,053 72,436
Proved Undeveloped 3,660 67,447 89,405 56,093
------ ------- ------- --------
Total Proved 20,245 250,402 371,872 $305,309
====== ======= ======= ========
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 Company's average price received for crude oil production on December
31, 1997 was $17.24 per Bbl. This price declined to $10.55 per Bbl on December
31, 1998. The Company's average price received for natural gas production on
December 31, 1997 was $2.64 per Mcf. This price declined to $2.21 per Mcf on
December 31, 1998. Further declines in the price of crude oil or natural gas
could have an adverse effect on the Company's Present Value of Proved Reserves,
which in turn could adversely affect borrowing capacity and the Company's
ability to obtain additional capital and the Company's financial condition,
revenues, profitability and cash flows from operations.
12
Drilling Activity Summary
During the three-year period ended December 31, 1998, the Company drilled
development and exploratory wells as set forth in the table below.
Year Ended December 31,
-----------------------
1996 1997 1998
---- ---- ----
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Development Wells:
Oil 2 1.0 2 0.6 -- --
Gas 16 8.4 31 16.1 25 14.7
Dry 1 1.0 7 2.3 5 3.5
-- ---- -- ---- -- ----
19 10.4 40 19.0 30 18.2
-- ---- -- ---- -- ----
Exploratory Wells:
Oil -- -- 1 0.3 6 2.3
Gas -- -- 4 1.3 2 2.0
Dry 1 0.2 4 1.6 6 2.9
-- ---- -- ---- -- ----
1 0.2 9 3.2 14 7.2
-- ---- -- ---- -- ----
Total Wells 20 10.6 49 22.2 44 25.4
== ==== == ==== == ====
As of December 31, 1998, the Company was drilling one exploratory well (0.2
net) which subsequently resulted in a successful discovery.
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, 1998.
Oil Gas
--- ---
Gross Net Gross Net
----- --- ----- ---
Texas 17 10.7 277 149.5
Louisiana 9 5.7 204 99.2
State and Federal Offshore 32 23.9 38 22.3
Mississippi 1 0.1 2 0.3
-- ---- --- -----
Total wells 59 40.4 521 271.3
== ==== === =====
The Company operates 366 of the 580 producing wells presented in the
above table.
Acreage
The following table summarizes the Company's developed and undeveloped
leasehold acreage at December 31, 1998. Excluded is acreage in which the
Company's interest is limited to royalty or similar interests.
Developed Undeveloped
--------- -----------
Gross Net Gross Net
----- --- ----- ---
Texas 164,529 118,471 37,102 15,876
Louisiana 78,812 58,381 1,896 1,123
State and Federal Offshore 34,056 14,619 870 870
Mississippi 1,360 210 - -
------- ------- ------ ------
Total 278,757 191,681 39,868 17,869
======= ======= ====== ======
13
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, 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, 2000
with pricing based on a percentage of spot gas prices for natural gas delivered
to the Houston Ship Channel. Total gas sales in 1998 to HPL accounted for
approximately 17% of the Company's 1998 oil and gas sales. Gas production from
the Company's offshore properties at the Ship Shoal and Main Pass areas, which
represented 12% of the Company's 1998 oil and gas sales, is sold under a
short-term contract based on spot market gas prices to H & N Gas, Ltd.
All of the Company's oil production is sold at the well site at posted
field prices tied to the spot oil markets. Sales of oil production from the
Company's Ship Shoal and Main Pass offshore properties to Gulfmark Energy, Inc,
accounted for 25% of the Company's 1998 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
14
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 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
15
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. Amendments to the Federal Clean Air Act enacted in 1990 (the
"1990 CAA Amendments") require or will require most 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. The 1990 CAA Amendments impose a new
operating permit on major sources, and several of the Company's facilities may
require permits under this new program. Although no assurances can be given, the
Company believes implementation of the 1990 CAA Amendments 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
16
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 5005 LBJ Freeway, Suite
1000, Dallas, Texas 75244, and its telephone number is (972) 701-2000.
The Company leases office space in Dallas, Texas. The Dallas lease covers
13,525 square feet at a monthly rate of $19,682 during 1998. The lease expires
on July 31, 1999. In August 1997, the Company entered into a seven year lease
covering 20,046 square feet in a building under construction. The Company plans
to relocate its corporate headquarters to the building in June 1999. The new
lease begins when the space is occupied and is at an initial monthly rate of
$35,081. The Company also owns production offices and pipe yard facilities near
Marshall and Livingston, Texas and near Logansport, Louisiana.
Employees
As of December 31, 1998, the Company had 47 employees and utilized contract
employees for certain of its field operations. The Company considers its
employee relations to be satisfactory.
17
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 43 President, Chief Executive Officer and
Charirman of the Board of Directors
Roland O. Burns 38 Senior Vice President, Chief Financial
Officer, Secretary and Treasurer
Mack D. Good 48 Vice President of Operations
Stephen E. Neukom 49 Vice President of Marketing
Richard G. Powers 44 Vice President of Land
Daniel K. Presley 38 Vice President of Accounting and Controller
Michael W. Taylor 45 Vice President of Corporate Development
Richard S. Hickok 73 Director
Franklin B. Leonard 71 Director
Cecil E. Martin, Jr 57 Director
David W. Sledge 42 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.
Roland O. Burns has been Senior Vice President of the Company since 1994,
Chief Financial Officer and Treasurer since 1990 and Secretary since 1991. 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.
18
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. Prior to joining the Company, Mr. Taylor had been an independent oil and
gas producer and petroleum consultant for the previous 15 years. 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
Richard S. Hickok has been a director of the Company since 1987. From 1948
to 1983, he was employed by the international accounting firm of Main Hurdman
where he retired as Chairman. From 1978 to 1980, Mr. Hickok served as a Trustee
of the Financial Accounting Foundation and has extensive involvement serving on
various committees of the American Institute of Certified Public Accountants.
Mr. Hickok holds a B.S. degree from the Wharton School of the University of
Pennsylvania.
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.
19
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 1998.
20
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
---- ---
1997 - First Quarter $ 14.38 $ 8.13
Second Quarter 10.88 6.63
Third Quarter 12.94 9.88
Fourth Quarter 17.50 10.63
1998 - First Quarter $12.00 $ 8.75
Second Quarter 13.50 7.31
Third Quarter 8.13 5.25
Fourth Quarter 6.13 2.81
As of March 12, 1999, the Company had 24,350,452 shares of common stock
outstanding, which were held by 734 holders of record and approximately 8,500
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 prohibited under the Company's bank credit
facility from paying or declaring cash dividends.
21
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, 1998 are derived from the Consolidated Financial Statements of the Company. Significant acquisitions of producing oil
and gas properties affect the comparability of the financial and operating data for the periods presented. 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,
-------------------------------------------------------------
1994 1995 1996 1997 1998
---- ---- ---- ---- ----
($ in thousands, except per share data)
Statement of Opertatons Data:
Revenues:
Oil and gas sales ............................ $ 16,855 $ 22,091 $ 68,915 $ 88,555 $ 92,961
Gain on sales of property .................... 328 19 1,447 85 --
Other income ................................. 416 264 593 704 274
------ ------ ------ ------ ------
Total revenues ............................ 17,599 22,374 70,955 89,344 93,235
------ ------ ------ ------ ------
Expenses:
Oil and gas operating(1) ..................... 6,099 7,427 13,838 17,919 24,747
Exploration .................................. -- -- 436 2,810 8,301
Depreciation, depletion and amortization ..... 7,350 8,379 18,269 26,235 51,005
General and administrative, net .............. 1,569 1,301 2,239 2,668 1,617
Interest ..................................... 2,869 5,542 10,086 5,934 16,977
Impairment of oil and gas properties ......... -- 29,150 -- -- 17,000
--------- --------- --------- --------- ---------
Total expenses ............................ 17,887 51,799 44,868 55,566 119,647
--------- --------- --------- --------- ---------
Income (loss) from continuing operations
before income taxes and extraordinary item .... (288) (29,425) 26,087 33,778 (26,412)
Income tax benefit (expense) ................. -- -- -- (11,622) 9,244
--------- --------- --------- --------- ---------
Net income (loss) from continuing operations
before extraordinary item ..................... (288) (29,425) 26,087 22,156 (17,168)
Preferred stock dividends .................... (818) (1,908) (2,021) (410) --
--------- --------- --------- --------- ---------
Net income (loss) from continuing operations
attributable to common stock before
extraordinary item ............................ (1,106) (31,333) 24,066 21,746 (17,168)
Income from discontinued operations .......... 229 3,264 1,866 -- --
Extraordinary loss ........................... (615) -- -- -- --
--------- --------- --------- --------- ---------
Net income (loss) attributable to common stock.... $ (1,492) $ (28,069) $ 25,932 $ 21,746 $ (17,168)
========= ========= ========= ========= =========
Weighted average shares outstanding:
Basic ......................................... 12,065 12,546 15,449 24,186 24,275
========= ========= ========= ========= =========
Diluted........................................ 21,199 26,008
========= =========
Basic earnings per share:
Net income (loss) from continuing operations
before extraordinary item.................... $ (0.09) $ (2.50) $ 1.56 $ 0.90 $ (0.71)
Net income (loss) after extraordinary item.... (0.12) (2.24) 1.68 0.90 (0.71)
Diluted earnings per share:
Net income (loss) from continuing operations
before extraordinary item.................... $ 1.23 $ 0.85
Net income (loss) after extraordinary item..... 1.32 0.85
Other Financial Data:
EBITDA(2)......................................... $ 9,931 $ 13,646 $ 54,878 $ 68,757 $ 66,871
Ratio of EBITDA to interest expense............... 3.5 2.5 5.4 11.3 3.5
As of December 31,
--------------------------------------------------------------
Balance Sheet Data: 1994 1995 1996 1997 1998
---- ---- ---- ---- ----
Cash and cash equivalents ..................... $ 3,425 $ 1,917 $ 16,162 $ 14,504 $ 5,176
Property and equipment, net ................... 77,989 102,116 185,928 410,781 404,017
Total assets .................................. 91,571 120,099 222,002 456,800 429,672
Total debt .................................... 37,932 71,811 80,108 260,000 278,104
Stockholders' equity .......................... 41,205 30,128 118,216 124,594 109,663
(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.
22
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Results of Operations
General
The Company's results of operations have been significantly affected by its
success in acquiring producing oil and natural gas properties. Fluctuations in
oil and natural gas prices have also influenced the Company's financial results.
Relatively minor movements in oil and natural gas prices can lead to a change in
the Company's results of operations and cash flow and could have an impact on
the Company's borrowing base under its bank credit facility. Based on the 1998
operating results, a change in the average natural gas price realized by the
Company of $0.10 per Mcf would result in a change in net income attributable to
common stock of approximately $1.6 million, or $0.07 per share. A change in the
average oil price realized by the Company of $1.00 per barrel would result in a
change in net income attributable to common stock of approximately $1.5 million
or $0.06 per share.
The following table reflects certain summary operating data for the periods
presented:
Year Ended December 31,
-----------------------
1996 1997 1998
---- ---- ----
Net Production Data:
Oil (MBbls) 952 1,343 2,571
Natural gas (MMcf) 19,427 22,860 26,713
Average Sales Price:
Oil (per Bbl) $21.96 $19.47 $12.73
Natural gas (per Mcf) 2.47 2.73 2.25
Average equivalent price (per Mcfe) 2.74 2.87 2.21
Expenses ($ per Mcfe):
Oil and gas operating(1) $ 0.55 $ 0.58 $ 0.59
General and administrative 0.09 0.09 0.04
Depreciation, depletion and
amortization(2) 0.72 0.84 1.20
Cash Margin ($ per Mcfe)(3) $ 2.10 $ 2.20 $ 1.58
(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, 1998 Compared to Year Ended December 31, 1997
Oil and gas sales increased $4.4 million (5%) to $93.0 million in 1998 from
$88.6 million in 1997. The increase is attributable to a 17% increase in natural
gas production and a 92% increase in oil production, offset by 18% lower
realized natural gas prices and 35% lower realized oil prices. The increase in
production is attributable to the Bois d' Arc Acquisition completed in December
1997.
Other income in 1998 decreased $430,000 (61%) to $274,000 from $704,000 for
1997. This decrease is attributable to a lower level of short-term cash deposits
outstanding as well as the termination of management fee income previously
received by the Company.
Oil and gas operating costs in 1998 increased $6.8 million (38%) to $24.7
million from $17.9 million in 1997 due to the 36% increase in oil and gas
production (on an equivalent Mcf basis). Oil and gas operating expenses per
equivalent Mcf produced increased $0.01 to $0.59 in 1998 from $0.58 in 1997.
23
Exploration expense for 1998 was $8.3 million which relates to the
write-off of the six unsuccessful exploratory wells, as compared to $2.8 million
in 1997.
Depreciation, depletion and amortization ("DD&A") increased $24.8 million
(94%) to $51.0 million from $26.2 million in 1997. The increase is due to a 36%
increase in oil and natural gas production and to higher costs per unit of
amortization. DD&A per equivalent Mcf increased by $0.36 to $1.20 in 1998 from
$0.84 in 1997. The increases in the DD&A rate relate to the higher costs of the
offshore properties acquired in the Bois d' Arc Acquisition.
General and administrative expenses, which are reported net of overhead
reimbursements, decreased $1.1 million (39%) to $1.6 million in 1997. The
decrease is attributable to an increase in overhead reimbursements received by
the Company in 1998 which was greater than the increase in the Company's
overhead costs before reimbursements.
Interest expense in 1998 increased $11.0 million (186%) to $17.0 million in
1998 from $5.9 million in 1997. The increase is related to a higher level of
outstanding advances under the Company's bank credit facility due to the Bois d'
Arc Acquisition completed in December 1997 as well as a higher average interest
rate on the Company's bank credit facility. The weighted average annual interest
rate under the Company's bank credit facility increased to 7.2% in 1998 as
compared to 6.6% in 1997. The increase in the rate was attributable to a higher
utilization of the borrowing base under the bank credit facility after the
December 1997 acquisition.
Due to the substantial drop in oil and gas prices during 1998, the Company
provided an impairment of $17.0 million in 1998 of its oil and gas properties.
The Company had a deferred tax benefit of $9.2 million for 1998, using an
estimated tax rate of 35%.
The net loss for the year ended December 31, 1998 was $17.2 million, as
compared to net income of $21.7 million, in 1997. Net loss per share for 1998
was $0.71 on weighted average shares outstanding of 24.3 million as compared to
net income per share of $0.85 for 1997 on diluted weighted average shares
outstanding of 26.0 million.
Year Ended December 31, 1997 Compared to Year Ended December 31, 1996
Oil and gas sales increased $19.6 million (28%) to $88.6 million in 1997
from $68.9 million in 1996 due primarily to a 18% increase in natural gas
production and a 41% increase in oil production as well as higher natural gas
prices. The production increases related primarily to production from the Black
Stone Acquisition, which closed in May 1996 and the Bois d' Arc Acquisition
which closed in December 1997. The Company's average gas price increased 11% and
its average oil price decreased 11% during 1997 as compared to 1996.
Other income increased $111,000 (19%) to $704,000 in 1997 from $593,000 in
1996 due primarily to additional interest income earned on an increased level of
short-term cash deposits in 1997.
Oil and gas operating expenses, including production taxes, increased $4.1
million (29%) to $17.9 million in 1997 from $13.8 million in 1996 due primarily
to the 23% increase in oil and natural gas production (on an equivalent Mcf
basis) resulting primarily from the acquisitions in 1996 and 1997. Oil and gas
operating expenses per Mcfe produced increased 5% to $0.58 in 1997 from $0.55 in
1996 due primarily to increases in production taxes and ad valorem taxes which
were related to the higher gas prices received in 1997.
24
General and administrative expenses increased $429,000 (19%) to $2.7
million in 1997 from $2.2 million in 1996. This increase related to increased
general corporate expenses associated with the increased size of the Company's
operations.
DD&A increased $8.0 million (44%) to $26.2 million in 1997 from $18.3
million in 1996 due to the 23% increase in oil and natural gas production (on an
Mcfe basis). Oil and gas property DD&A per Mcfe produced of $0.84 in 1997
increased from $0.72 in 1996 due to the higher costs of the acquisitions closed
in 1996 and 1997.
Interest expense decreased $4.2 million (41%) to $5.9 million in 1997 from
$10.1 million in 1996 due primarily to a decrease in the average outstanding
advances under the Company's bank credit facility. The average annual interest
rate paid under the Company's bank credit facility also decreased to 6.6% in
1997 as compared to 8.1% in 1996.
The Company provided for income taxes of $11.6 million for 1997 using an
estimated effective tax rate of 34%. No provision for income taxes was made in
1996 due to the availability of previously unrecognized tax assets relating to
net operating loss carryforwards.
The Company reported net income of $21.7 million, after preferred stock
dividends of $410,000, for the year ended December 31, 1997, as compared to a
net income of $24.1 million from continuing operations, after preferred stock
dividends of $2.0 million, for the year ended December 31, 1996. Net income per
share for 1997 was $0.85 on diluted average shares outstanding of 26.0 million
as compared to $1.23 for 1996 on diluted average shares outstanding of 21.2
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 1998
the Company's net cash flow provided by operating activities totaled $40.7
million ($50.2 million before changes to other working capital accounts). In
addition to operating cash flow, the primary source of funds for the Company in
1998 was aggregate borrowings of $23.2 million.
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 principal and interest on debt. In 1998, the
Company repaid $5.1 million of indebtedness and incurred capital expenditures of
$67.4 million primarily for development and exploration activities.
The Company's annual capital expenditure activity is summarized as follows:
Year Ended December 31,
---------------------------------------
1996 1997 1998
-------- -------- --------
(In thousands)
Acquisition of oil and gas properties $100,446 $220,054 $ 2,453
Other leasehold costs 93 2,304 3,622
Workovers and recompletions 2,972 2,517 10,198
Development drilling 7,964 22,765 20,361
Exploratory drilling 436 6,043 30,423
Other 51 1,160 330
-------- -------- --------
Total $111,962 $254,843 $ 67,387
======== ======== ========
25
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 $11.5 million, $33.6
million and $64.6 million on development and exploration activities in 1996,
1997 and 1998, respectively. The Company currently anticipates spending
approximately $10.0 to $36.0 million on development and exploration projects in
1999. The Company intends to primarily use internally generated cash flow to
fund capital expenditures other than significant acquisitions and plans to limit
drilling expenditures in 1999 to available cash flow after debt service
payments. Such debt service payments are expected to require a substantial
amount of the Company's available cash flow unless oil and gas prices improve
from current levels. Without an improvement in oil and gas prices or the
completion of a debt or equity financing, the Company's 1999 total capital
expenditures will probably be limited to $10.0 million to $15.0 million.
The Company does not have a specific acquisition budget 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's bank credit facility consists of a $280.0 million revolving
credit commitment provided by a syndicate of ten banks for which The First
National Bank of Chicago serves as administrative agent. Indebtedness under the
bank credit facility is secured by substantially all of the Company's assets.
The Company's bank credit facility 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. As of
December 31, 1998, the borrowing base was $280.0 million and is scheduled to
reduce to $240.0 million by December 31, 1999 and by an additional $20.0 million
by January 1, 2000. 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 next scheduled
borrowing base redetermination will occur in April 1999; however, the bank group
can request a redetermination at any time. The revolving credit line bears
interest at the option of the Company at either (i) LIBOR plus 2.25% or (ii) the
"corporate base rate" plus 1.25%. The Company incurs a commitment fee of up to
0.5% per annum on the unused portion of the borrowing base. The average annual
interest rate as of December 31, 1998 of all outstanding indebtedness under the
Company's bank credit facility was approximately 7.6%. The revolving credit line
matures on December 9, 2002 or such earlier date as the Company may elect. The
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, capital expenditures and investments.
Significant financial covenants include the maintenance of a current ratio, as
defined, (0.75 to 1.0), maintenance of tangible net worth ($98.0 million),
maintenance of an interest coverage ratio (2.5 to 1), and a limitation on
capital expenditures ($30.0 million).
Based on the scheduled borrowing base reductions in 1999, the Company has
classified $38.0 million of the amount outstanding under its bank credit
facility as a current liability at December 31, 1998. The Company plans to
reduce its drilling expenditures in 1999 as compared to 1998 and utilize cash
flow generated from operations to reduce outstanding borrowings under the bank
credit facility. The Company believes that it will generate sufficient operating
cash flow during 1999 to reduce the amounts outstanding under the bank credit
facility in accordance with the scheduled reductions to the borrowing base. The
Company intends to refinance the additional $20.0 million reduction to the
26
borrowing base scheduled to occur in January 2000 with a future debt or equity
financing or to pay down such debt from proceeds from sale of existing
properties. Management cannot be assured that such debt or equity financing will
be available for the Company on the terms acceptable to its existing
shareholders or that the banks will not require additional reductions to the
borrowing base in the future.
Based on estimated 1999 oil and natural gas production, the Company
estimates a change in the average natural gas price realized by the Company of
$0.10 per Mcf on unhedged production would result in a change in cash flow of
approximately $1.5 million. Also, the Company estimates a change in the average
oil price realized by the Company of $1.00 per barrel on unhedged production
would result in a change in cash flow of approximately $2.9 million. If oil and
gas prices were to fall significantly below current levels for the remainder of
1999 or if the banks were to further reduce the Company's borrowing base, the
Company would likely have to complete a debt or equity financing or sell
selected properties in order to meet the required 1999 scheduled reductions to
its borrowing base.
The Company may consider additional debt or equity financings in order to
provide liquidity and working capital for attractive acquisition opportunities
during the current depressed price environment of the industry. Based on the
current low oil and gas price environment, there can be no assurance that such
capital would be available with terms and conditions acceptable to the Company
or its existing stockholders.
Federal Taxation
At December 31, 1998, the Company had federal income tax net operating loss
("NOL") carryforwards of approximately $57.4 million. The NOL carryforwards
expire from 2005 through 2018. 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.
Inflation
In recent years inflation has not had a significant impact on the Company's
operations or financial condition.
Risk Management
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 price or lower interest rates.
Recognition of realized gains or losses are 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.
As a result of certain hedging transactions for natural gas the Company's
average realized natural gas price has been impacted as follows:
Year Ended December 31,
-----------------------------
1996 1997 1998
---- ---- ----
Percent of natural gas production hedged 15% - 7%
Price realized without hedging (per Mcf) $ 2.53 $ 2.73 $ 2.24
Increase (decrease) in price realized (per Mcf) $ (0.06) - $ 0.01
27
As of December 31, 1998, the Company had no open derivative financial
instruments held for price risk management. Subsequent to December 31, 1998, the
Company entered into natural gas price swaps covering 10,480,000 MMBtus of its
natural gas production for March 1999 to October 1999 at 1,310,000 MMBtus per
month at a fixed index price of $1.81 (after basis adjustment), which represents
approximately 60% of the Company's estimated gas production for that period.
The table below provides information about the Company's derivative
financial instruments that are sensitive to changes in interest rates, including
interest rate swaps and debt obligations. For interest rate swaps, the table
presents notional amounts and weighted average interest rates by contractual
maturity dates. Notional amounts are used to calculate the contractual payments
to be exchanged under the contract. Weighted average variable rates are based on
implied forward rates in the yield curve as of December 31, 1998.
Expected Maturity Date
-------------------------------------------------------- Fair Value
as of
1999 2000 2001 2002 Total December 31, 1998
---- ---- ---- ---- ----- -----------------
($ in thousands)
Liabilities:
Bank credit facility $ 38,000 $ 20,000 $ - $ 220,000 $ 278,000 $ 278,000
Variable rate 7.2% 7.2% - 7.4% 7.4%
Interest Rate Swaps:
Variable to fixed $ - $ - $ - $ 125,000 $ 125,000 (95)
Average pay rate 5.0% 5.0%
Average receive rate 5.1% 5.1%
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 are not Year 2000 compliant by January 1, 2000 may cause an adverse effect
to companies and organizations that rely upon those systems. The Company is
assessing and correcting the potential impact of problems with computer
software, operating systems, and equipment containing computer processing chips
that are unable to properly process dates beyond 1999. The Company has
outsourced its significant financial information systems. Based on information
received from the Company's providers, 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 and it expects future costs will not be
material.
Because the Company outsources its information technology systems and
software, it believes that there is little risk associated with Year 2000 for
its information systems. The Company believes that there is minimal risk with
embedded technology associated with its operations because it does not own any
significant gas processing plants or pipelines, nor does it have any significant
electronic field data capture systems on its wells. However, the Company cannot
provide assurance that all significant third parties will achieve compliance in
a timely manner. Such failure to achieve Year 2000 compliance could have an
adverse effect on the Company's operations and cash flow due to potential
shut-in production or delay in drilling schedules. Although the Company does not
have a formal contingency plan, it stands ready to switch from vendors that are
not Year 2000 compliant.
28
ITEM 8. FINANCIAL STATEMENTS
The Consolidated Financial Statements for Comstock Resources, Inc. and
Subsidiaries are included on pages F-1 to F-19 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.
29
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, 1998.
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, 1998.
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, 1998.
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, 1998.
30
PART IV
ITEM 14. EXHIBITS AND REPORTS ON FORM 8-K
Exhibits:
The following exhibits are included on pages E-1 to E-61 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).
4.2(a) Rights Agreement dated as of December 10, 1990, by and between the
Company and Society National Bank, as Rights Agent (incorporated
herein by reference to Exhibit 1 to the Company's Registration
Statement on Form 8-A, dated December 14, 1990).
4.2(b) First Amendment to the Rights Agreement, by and between the Company
and Society National Bank (successor to Ameritrust Texas, N.A.), as
Rights Agent, dated January 7, 1994 (incorporated herein by reference
to Exhibit 3.6 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1993).
4.2(c) Second Amendment to the Rights Agreement, by and between the Company
and Bank One, Texas N.A. (successor to Society National Bank), as
Rights Agent, dated April 1, 1995 (incorporated by reference to
Exhibit 4.7 to the Company's Annual Report on Form 10-K for the ended
December 31, 1995).
4.2(d) Third Amendment to the Rights Agreement, by and between the Company
and Bank One, Texas N.A. (successor to Society National Bank), as
Rights Agent, dated April 1, 1995 (incorporated by reference to
Exhibit 4.8 to the Company's Annual Report on Form 10-K for the ended
December 31, 1995).
4.2(e) Fourth Amendment to the Rights Agreement, by and between the Company
and Bank One, Texas N.A. (successor to Society National Bank), as
Rights Agent, dated April 1, 1995 (incorporated by reference to
Exhibit 4.9 to the Company's Annual Report on Form 10-K for the ended
December 31, 1995).
4.3 Certificate of Designation, Preferences and Rights of Series A Junior
Participating Preferred Stock dated December 6, 1990 (incorporated by
reference to Exhibit 4.3 to the Company's Registration Statement on
Form S-3, dated October 25, 1996).
10.1(a)* Credit Agreement dated as of December 23, 1998, between the Company,
the Banks Party thereto and The First National Bank of Chicago, as
Administrative Agent and Toronto Dominion (Texas), Inc., as
Syndication Agent.
10.2# Employment Agreement dated May 11, 1998, by and between the Company
and M. Jay Allison (incorporated herein by reference to Exhibit 10.1
to the Company's Quarterly Report on Form 10-Q for the quarter ended
March 31, 1998).
10.3# Employment Agreement dated May 11, 1998, by and between the Company
and Roland O. Burns (incorporated herein by reference to Exhibit 10.2
to the Company's Quarterly Report on Form 10-Q for the quarter ended
March 31, 1998).
31
10.4# Change in Control Employment Agreement dated May 15, 1997, 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, 1997).
10.5# Change in Control Employment Agreement dated May 15, 1997, 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, 1997).
10.6(a)# Comstock Resources, Inc. 1991 Long-term Incentive Plan, dated as of
April 1, 1991 (incorporated herein by reference to Exhibit 10.8 to the
Company's Annual Report on Form 10-K for the year ended December 31,
1991).
10.6(b)# Amendment No. 1 to the Comstock Resources, Inc. 1991 Long-term
Incentive Plan (incorporated by reference to Exhibit 10.4 to the
Company's Quarterly Report on Form 10-Q for the quarter ended
September 30, 1996).
10.7# Form of Nonqualified Stock Option Agreement, dated April 2, 1991,
between the Company and certain officers and directors of the Company
(incorporated herein by reference to Exhibit 10.9 to the Company's
Annual Report on Form 10-K for the year ended December 31, 1991).
10.8# Form of Restricted Stock Agreement, dated April 2, 1991, between the
Company and certain officers of the Company (incorporated herein by
reference to Exhibit 10.10 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1991).
10.9 Form of Stock Option Agreement, dated October 12, 1994 by and between
the Company and Christopher T. H. Pell, et al. (incorporated herein by
reference to Exhibit 10.18 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1994).
10.10 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).
10.11 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).
10.12 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.
27* Financial Data Schedule for the twelve months ended December 31, 1998.
*Filed herewith.
# Management contract or compensatory plan document.
Reports on Form 8-K:
There were no reports filed on Form 8-K filed subsequent to September 30,
1998 to the date of this report.
32
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
COMSTOCK RESOURCES, INC.
By:/s/M. JAY ALLISON
--------------------
M. Jay Allison
President and Chief Executive Officer
(Principal Executive Officer)
Date: March 12, 1999
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
/s/M. JAY ALLISON President, Chief Executive Officer and March 12, 1999
- ----------------------
M. Jay Allison Chairman of the Board of Directors
(Principal Executive Officer)
/s/ROLAND O. BURNS Senior Vice President, Chief Financial March 12, 1999
- ----------------------
Roland O. Burns Officer, Secretary and Treasurer
(Principal Financial and
Accounting Officer)
/s/RICHARD S. HICKOK Director March 12, 1999
- ----------------------
Richard S. Hickok
/s/FRANKLIN B. LEONARD Director March 12, 1999
- ----------------------
Franklin B. Leonard
/s/CECIL E. MARTIN, JR. Director March 12, 1999
- ----------------------
Cecil E. Martin, Jr.
/s/DAVID W. SLEDGE Director March 12, 1999
- ----------------------
David W. Sledge
33
CONSOLIDATED FINANCIAL STATEMENTS OF
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
INDEX
Report of Independent Public Accountants.....................................F-2
Consolidated Balance Sheets as of December 31, 1997 and 1998.................F-3
Consolidated Statements of Operations for the Years Ended
December 31, 1996, 1997 and 1998.....................................F-4
Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 1996, 1997 and 1998.....................................F-5
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1996, 1997 and 1998.....................................F-6
Notes to Consolidated Financial Statements...................................F-7
F-1
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
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, 1997
and 1998, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1998. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Comstock Resources, Inc. and
subsidiaries as of December 31, 1997 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Dallas, Texas,
February 15, 1999
F-2
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31, 1997 and 1998
ASSETS
December 31,
1997 1998
--------- ---------
(In thousands)
Cash and Cash Equivalents............................ $ 14,504 $ 5,176
Accounts Receivable:
Oil and gas sales ................................. 24,509 13,355
Joint interest operations ......................... 6,732 4,506
Other Current Assets ................................ 172 1,457
--------- ---------
Total current assets ...................... 45,917 24,494
Property and Equipment:
Unevaluated oil and gas properties ................ 30,291 436
Oil and gas properties, successful
efforts method .................................. 456,606 547,372
Other ............................................. 1,561 1,648
Accumulated depreciation, depletion
and amortization ................................ (77,677) (145,439)
--------- ---------
Net property and equipment ................ 410,781 404,017
Other Assets ........................................ 102 1,161
--------- ---------
$ 456,800 $ 429,672
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Portion of Long-Term Debt.................... $ -- $ 38,104
Accounts Payable and Accrued Expenses ............... 56,184 34,652
--------- ---------
Total current liabilities ................. 56,184 72,756
Long-Term Debt, less current portion ................ 260,000 240,000
Deferred Taxes Payable .............................. 11,207 1,778
Reserve for Future Abandonment Costs ................ 4,815 5,475
Stockholders' Equity:
Preferred stock--$10.00 par, 5,000,000 shares
aurthorized, no shares outstanding............... -- --
Common stock--$0.50 par, 50,000,000 shares
authorized, 24,208,785 and 24,350,452 shares
shares outstanding at December 31, 1997
and 1998, respectively .......................... 12,104 12,175
Additional paid-in capital ........................ 110,273 112,432
Retained earnings (deficit) ....................... 2,234 (14,934)
Less: Deferred compensation-restricted
stock grants .................................... (17) (10)
--------- ---------
Total stockholders' equity ................ 124,594 109,663
--------- ---------
$ 456,800 $ 429,672
========= =========
The accompanying notes are an integral part of these statements.
F-3
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Years Ended December 31, 1996, 1997 and 1998
1996 1997 1998
---- ---- ----
(In thousands, except
per share amounts)
Revenues:
Oil and gas sales................................................. $ 68,915 $ 88,555 $ 92,961
Gain on sales of property ........................................ 1,447 85 --
Other income ..................................................... 593 704 274
--------- --------- ---------
Total revenues .......................................... 70,955 89,344 93,235
--------- --------- ---------
Expenses:
Oil and gas operating ........................................... 13,838 17,919 24,747
Exploration ..................................................... 436 2,810 8,301
Depreciation, depletion and amortization ........................ 18,269 26,235 51,005
General and administrative, net ................................. 2,239 2,668 1,617
Interest ........................................................ 10,086 5,934 16,977
Impairment of oil and gas properties ............................ -- -- 17,000
--------- --------- ---------
Total expenses .......................................... 44,868 55,566 119,647
--------- --------- ---------
Income (loss) from continuing operations
before income taxes .......................................... 26,087 33,778 (26,412)
Income tax benefit (expense) ...................................... -- (11,622) 9,244
--------- --------- ---------
Net income (loss) from continuing operations ...................... 26,087 22,156 (17,168)
Preferred stock dividends ......................................... (2,021) (410) --
--------- --------- ---------
Net income (loss) from continuing operations
attributable to common stock ................................. 24,066 21,746 (17,168)
Income from discontinued gas gathering, processing
and marketing operations including gain on disposal .......... 1,866 -- --
--------- --------- ---------
Net income (loss) attributable to common stock..................... $ 25,932 $ 21,746 $ (17,168)
========= ========= =========
Net income (loss) per share:
Basic -
Net income (loss) per share from continuing operations....... $ 1.56 $ 0.90 $ (0.71)
========= ========== =========
Net income (loss) per share.................................. $ 1.68 $ 0.90 $ (0.71)
========= ========== =========
Diluted -
Net income (loss) per share from continuing operations....... $ 1.23 $ 0.85
========= =========
Net income (loss) per share.................................. $ 1.32 $ 0.85
========= =========
Weighted average shares outstanding:
Basic................................................... 15,449 24,186 24,275
========= ========= =========
Diluted................................................. 21,199 26,008
========= =========
The accompanying notes are an integral part of these statements.
F-4
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Years Ended December 31, 1996, 1997 and 1998
Deferred
Additional Retained Compensation-
Preferred Common Paid-In Earnings Restricted
Stock Stock Capital (Deficit) Stock Grants Total
----- ----- ------- --------- ------------ -----
(In thousands)
Balance at December 31, 1995............... $ 31,000 $ 6,463 $ 38,183 $ (45,444) $ (74) $ 30,128
Conversion of preferred stock .......... (23,937) 2,506 21,431 -- -- --
Issuance of common stock ............... -- 3,082 59,033 -- -- 62,115
Restricted stock grants ................ -- -- -- -- 41 41
Net income attributable to
common stock ......................... -- -- -- 25,932 -- 25,932
--------- --------- --------- --------- --------- ---------
Balance at December 31, 1996 .............. 7,063 12,051 118,647 (19,512) (33) 118,216
--------- --------- --------- --------- --------- ---------
Conversion of preferred stock .......... (7,063) 673 6,390 -- -- --
Issuance of common stock ............... -- 53 708 -- -- 761
Repurchase of common stock ............. -- (673) (15,472) -- -- (16,145)
Restricted stock grants ................ -- -- -- -- 16 16
Net income attributable to
common stock ......................... -- -- -- 21,746 -- 21,746
--------- --------- --------- --------- --------- ---------
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
========= ========= ========= ========= ========= =========
The accompanying notes are an integral part of these statements.
F-5
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1996, 1997 and 1998
1996 1997 1998
---- ---- ----
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)............................................... $ 27,953 $ 22,156 $ (17,168)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Compensation paid in common stock ............................ 196 129 269
Depreciation, depletion and amortization ..................... 18,642 26,235 51,005
Impairment of oil and gas properties ......................... -- -- 17,000
Deferred income taxes ........................................ -- 11,363 (9,244)
Deferred revenue ............................................. (430) -- --
Exploration .................................................. 436 2,810 8,301
Gain on sales of property .................................... (2,265) (85) --
--------- --------- ---------
Working capital provided by operations ..................... 44,532 62,608 50,163
Decrease (increase) in accounts receivable ................... (4,764) (11,744) 13,380
Decrease (increase) in other current assets .................. 86 2 (1,285)
Increase (decrease) in accounts payable and
accrued expenses ........................................... 6,065 33,411 (21,532)
--------- --------- ---------
Net cash provided by operating activities .................. 45,919 84,277 40,726
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sales of properties ............................ 9,016 5,079 --
Proceeds from sale of discontinued operations ................ 3,036 -- --
Capital expenditures and acquisitions ........................ (111,962) (254,843) (67,387)
--------- --------- ---------
Net cash used for investing activities ..................... (99,910) (249,764) (67,387)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings ................................................... 172,150 295,000 23,238
Debt issuance costs .......................................... -- -- (1,059)
Principal payments on debt ................................... (163,853) (115,108) (5,134)
Proceeds from common stock issuances ......................... 61,503 507 288
Repurchase of common stock ................................... -- (16,145) --
Stock issuance costs ......................................... (863) (15) --
Dividends paid on preferred stock ............................ (701) (410) --
--------- --------- ---------
Net cash provided by financing activities .................. 68,236 163,829 17,333
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents ..... 14,245 (1,658) (9,328)
Cash and cash equivalents, beginning of year ............. 1,917 16,162 14,504
--------- --------- ---------
Cash and cash equivalents, end of year.................... $ 16,162 $ 14,504 $ 5,176
========= ========= =========
The accompanying notes are an integral part of these statements.
F-6
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Business and Organization
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.
(2) Significant Accounting Policies
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.
F-7
In accordance with the Statement of Financial Accounting Standards No. 121
("SFAS 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 1996 or
1997. 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, a gas gathering system, computer equipment, and furniture and fixtures
which are depreciated over estimated useful lives 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 1996, 1997 and 1998 were
determined as follows:
For the Year Ended December 31,
------------------------------------------------------------------------------------
1996 1997 1998
------------------------- ------------------------ ---------------------------
Per Per Income Per
Income Shares Share Income Shares Share (Loss) Shares Share
(In thousands, except per share amounts)
Basic Earnings Per Share:
Income (Loss) from
Continuing Operations $ 26,087 15,449 $ 22,156 24,186 $(17,168) 24,275 $(0.71)
Less Preferred Stock
Dividends (2,021) - (410) - - - -
-------- ------- -------- ------- -------- ------- ------
Net Income (Loss) Available
to Common Stockholders $ 24,066 15,449 $1.56 21,746 24,186 $0.90 $(17,168) 24,275 $(0.71)
===== ===== ======== ======= ======
Diluted Earnings Per Share:
Effect of Dilutive Securities:
Stock Options - 922 - 967
Convertible Preferred Stock 2,021 4,828 410 855
-------- ------ -------- -------
Net Income Available to
Common Stockholders and
Assumed Conversions $ 26,087 21,199 $1.23 $ 22,156 26,008 $0.85
======== ====== ===== ======== ======= =====
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.
F-8
The following is a summary of all significant noncash investing and
financing activities and cash payments made for interest and income taxes:
Year Ended December 31,
1996 1997 1998
---- ---- ----
(In thousands)
Noncash activities -
Common stock issued for compensation ..... $ 154 $ 113 $ 269
Value of vested stock options under
exploration venture .................. -- -- 1,495
Common stock issued in payment of
preferred stock dividends .............. 1,320 -- --
Cash payments -
Interest payments ........................ 9,934 5,112 19,898
Income tax payments ...................... -- 270 --
New Accounting Standard
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" ("SFAS No. 133"). The Statement establishes accounting
and reporting standards that are effective for the fiscal years beginning after
June 15, 1999 which require that every derivative instrument (including certain
derivative instruments embedded in other contracts) be recorded in 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 uses derivatives to hedge floating interest rate and natural
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, the Company's adoption of SFAS No. 133 will have an impact on the
reported financial position of the Company, and although such impact has not
been determined, it is currently not believed to be material. Adoption of SFAS
No. 133 should have no significant impact on reported earnings, but could
materially affect comprehensive income.
(3) Acquisitions of Oil and Gas Properties
On May 7, 1997, the Company purchased certain producing oil and gas
properties located in the Lisbon field in Claiborne Parish, Louisiana for a net
purchase price of $20.1 million. The acquisition included interests in 13 wells
(7.1 net wells).
On December 9, 1997, the Company acquired interests in certain offshore
Louisiana oil and gas properties as well as interests in undeveloped oil and gas
leases for $200.9 million from Bois d' Arc Resources ("Bois d' Arc") and certain
affiliates and working interest partners of Bois d' Arc. The Company acquired
interests in 43 wells (29.6 net wells) 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. Approximately $30.2 million of the purchase price
was attributed to the undrilled prospects and $1.0 million of the purchase price
was attributed to other assets.
F-9
The acquisitions were accounted for utilizing the purchase method of
accounting. The accompanying consolidated statements of operations include the
results of operations from the acquired properties beginning on the dates that
the acquisitions were closed. The following table summarizes the unaudited pro
forma effect on the Company's consolidated statements of operations as if the
acquisitions consummated in 1997 had been closed on January 1, 1997. Future
results may differ substantially from pro forma results due to changes in prices
received for oil and gas sold, production declines and other factors. Therefore,
the pro forma amounts should not be considered indicative of future operations.
Unaudited 1997 Pro Forma Results -
Total Revenues (000s) $ 144,313
Net income from continuing operations attributable
to common stock (000s) 27,327
Net income from continuing operations per share:
Basic 1.13
Diluted 1.07
(4) Sales of Oil and Gas Properties
The Company sold certain oil and gas properties for approximately $9.0
million and $5.1 million in 1996 and 1997, respectively. The properties sold
were non-strategic assets to the Company. Gains from the property sales of $1.4
million and $85,000 are included in the accompanying Consolidated Statements of
Operations for 1996 and 1997, respectively.
(5) Oil and Gas Producing Activities
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,
1997 1998
---- ----
(In thousands)
Proved properties $ 456,606 $ 547,372
Unproved properties 30,291 436
Accumulated depreciation,
depletion and amortization (77,414) (145,152)
--------- ---------
$ 409,483 $ 402,656
========= =========
Costs Incurred
For the Year Ended December 31,
1996 1997 1998
---- ---- ----
(In thousands)
Property acquisitions:
Proved properties $ 100,539 $ 190,708 $ --
Unproved properties - 31,650 6,075
Development costs 10,936 25,282 30,559
Exploration costs 436 6,043 30,423
--------- --------- ---------
$ 111,911 $ 253,683 $ 67,057
========= ========= =========
F-10
The following presents the results of operations of oil and gas producing
activities for the three years in the period ended December 31, 1998:
1996 1997 1998
---- ---- ----
(In thousands)
Oil and gas sales $ 68,915 $ 88,555 $ 92,961
Production costs (13,838) (17,919) (24,747)
Exploration (436) (2,810) (8,301)
Depreciation, depletion and amortization (18,162) (26,111) (50,738)
Impairment of oil and gas properties -- -- (17,000)
-------- -------- --------
Operating income (loss) 36,479 41,715 (7,825)
Income tax -- (14,353) 2,739
-------- -------- --------
Results of operations (excluding general
and administrative and interest expenses) $ 36,479 $ 27,362 $ (5,086)
======== ======== ========
(6) Long-Term Debt
Total debt at December 31, 1997 and 1998 consists of the following:
1997 1998
---- ----
(In thousands)
Bank Credit Facility $ 260,000 $ 278,000
Other -- 104
--------- ---------
260,000 278,104
Less current portion -- (38,104)
--------- ---------
$ 260,000 $ 240,000
========= =========
The Company has a $280.0 million revolving credit facility with a
syndication of ten banks in which The First National Bank of Chicago serves as
administrative agent, (the "Bank Credit Facility"). As of December 31, 1998, the
Company had $278.0 million outstanding under the Bank Credit Facility.
Borrowings under the Bank Credit Facility cannot exceed a borrowing base
determined semiannually by the banks. The borrowing base at December 31, 1998
was $280.0 million. The borrowing base is scheduled to reduce to $240.0 million
by December 31, 1999 and will reduce by an additional $20.0 million by January
1, 2000. The determination of the Company's borrowing base is at the sole
discretion of the administrative agent and the bank group. The next scheduled
borrowing base redetermination will occur in April 1999; however, the bank group
can request a redetermination at any time. Amounts outstanding under the Bank
Credit Facility bear interest at a floating rate based on The First National
Bank of Chicago's base rate (as defined) plus 1.25% or, at the Company's option,
at a fixed rate for up to six months based on the London Interbank Offered Rate
("LIBOR") plus 2.25%. As of December 31, 1998, the Company had placed the
outstanding advances under the revolving credit facility under fixed rate loans
based on LIBOR at an average rate of approximately 7.6% per annum. In addition,
the Company incurs a commitment fee of 0.5% on the unused portion of the
borrowing base depending upon the utilization of the available borrowing base.
The Bank Credit Facility matures on December 9, 2002. Significant financial
covenants under the Bank Credit Facility include the maintenance of a current
ratio, as defined, (0.75 to 1.0), maintenance of tangible net worth ($98.0
million), maintenance of an interest coverage ratio (2.5 to 1), and a limitation
on capital expenditures ($30.0 million).
Based on the scheduled borrowing base reductions in 1999, the Company has
classified $38.0 million of the amount outstanding under the Bank Credit
Facility as a current liability at December 31, 1998. The Company plans to
reduce its drilling expenditures in 1999 as compared to 1998 and utilize cash
flow generated from operations to reduce outstanding borrowings under the Bank
F-11
Credit Facility. The Company believes that it will generate sufficient operating
cash flow during 1999 to reduce the amounts outstanding under the Bank Credit
Facility in accordance with the scheduled reductions to the borrowing base. The
Company intends to refinance the additional $20.0 million reduction to the
borrowing base scheduled to occur in January 2000 with a future debt or equity
financing or to pay down such debt from proceeds from sale of existing
properties. Management cannot be assured that such debt or equity financing will
be available for the Company on the terms acceptable to its existing
shareholders or that the banks will not require additional reductions to the
borrowing base in the future. If oil and gas prices were to fall significantly
below current levels for the remainder of 1999 or if the banks were to further
reduce the Company's borrowing base, the Company would likely have to complete a
debt or equity financing or sell selected properties in order to meet the
required 1999 scheduled reductions to its borrowing base.
(7) Lease Commitments
The Company rents office space under certain noncancellable leases. Minimum
future payments under the leases are as follows:
(In thousands)
1999 $ 389
2000 421
2001 421
2002 421
2003 421
(8) Stockholders' Equity
Preferred Stock
On January 7, 1994, the Company sold 600,000 shares of its Series 1994
Convertible Preferred Stock, $10 par value per share (the "Series 1994
Preferred"), in a private placement for $6.0 million. Dividends were payable at
the quarterly rate of $0.225 on each outstanding share of the Series 1994
Preferred (9% per annum of the par value). On September 16, 1996, the holders of
the Series 1994 Preferred converted all of the shares of the Series 1994
Preferred into 1,500,000 shares of common stock of the Company.
On July 22, 1994, the Company issued 1,000,000 shares of its 1994 Series B
Convertible Preferred Stock, $10 par value per share (the "1994 Series B
Preferred"), in connection with the repurchase of certain production payments
previously conveyed by the Company to a major natural gas company. Dividends
were payable at the quarterly rate of $0.15625 on each outstanding share (6.25%
per annum of the par value). On July 11, 1996, the Company redeemed the
1,000,000 shares of the 1994 Series B Preferred by issuing 2,000,000 shares of
common stock of the Company.
On June 19, 1995, the Company sold 1,500,000 shares of its Series 1995
Convertible Preferred Stock, $10 par value per share (the "Series 1995
Preferred"), in a private placement for $15.0 million. Dividends were payable at
the quarterly rate of $0.225 on each outstanding share (9% per annum of the par
value). On December 2, 1996, holders of 793,677 shares of the Series 1995
Preferred converted their preferred shares into 1,511,761 shares of common stock
of the Company. On August 20, 1997, the holders of the Series 1995 Preferred
converted all of the remaining shares of the Series 1995 Preferred, $10 par
value, into 1,345,373 shares of common stock of the Company.
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 37,117, 9,256 and 39,678 shares of common stock in 1996, 1997, 1998
F-12
respectively, in payment of fees aggregating $154,000, $113,000 and $263,000 for
1996, 1997 and 1998, respectively. Shares issued in 1998 also prepaid the
director and consulting fees for 1999.
Each of the Company's formerly outstanding preferred stock series provided
that the Company could issue common stock in lieu of cash for payment of
quarterly dividends. The Company issued 249,453 shares of common stock in 1996
in payment of dividends on its preferred stock of $1,320,000.
On December 2, 1996, the Company completed a public offering of 5,795,000
shares of common stock of which 4,000,000 (4,869,250 including the
over-allotment option which was exercised on December 12, 1996) shares were sold
by the Company and 1,795,000 shares were sold by certain stockholders. Net
proceeds to the Company, after the underwriting discount and other expenses,
were approximately $57.0 million and were used to reduce indebtedness under the
Bank Credit Facility.
On August 20, 1997, the Company repurchased the 1,345,373 shares of common
stock held by former Series 1995 Preferred stockholders at $12.00 per share for
an aggregate purchase price of $16.1 million.
Options and warrants to purchase common stock of the Company were exercised
for 1,007,177 shares, 98,100 shares and 102,000 shares in 1996, 1997 and 1998,
respectively. Such exercises yielded net proceeds to the Company of
approximately $3.6 million, $507,000 and $288,000 in 1996, 1997 and 1998,
respectively.
Stock Options and Warrants
On July 16, 1991, the Company's stockholders approved the 1991 Long-Term
Incentive Plan (the "Incentive Plan") for the Company's management including
officers, directors and managerial employees. The Incentive Plan authorizes the
grant of non-qualified stock options and incentive stock options and the grant
of restricted stock to key executives of the Company. On May 15, 1996, the
Company's stockholders approved an amendment to the Incentive Plan increasing
the shares to be awarded by 1,240,000. As of December 31, 1998, the Incentive
Plan provided for future awards of stock options or restricted stock grants of
up to 228,630 shares of common stock plus 10% of any future issuances of common
stock.
The following table summarizes stock option activity during 1996, 1997 and
1998 under the Incentive Plan:
Weighted
Average
Number of Exercise Exercise
Shares Price Price
------ ----- -----
Outstanding at December 31, 1995 791,750 $2.00 to $3.00 $2.27
Granted 1,933,000 $4.81 to $11.00 $9.31
Exercised (113,250) $2.00 to $4.81 $3.06
Forfeited (10,000) $6.56 $6.56
-----------
Outstanding at December 31, 1996 2,601,500 $2.00 to $11.00 $7.45
Granted 667,000 $9.63 to $12.38 $12.00
Exercised (50,000) $3.00 to $6.56 $5.33
-----------
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
===========
Exercisable at December 31, 1998 1,839,750 $2.00 to $12.38 $6.76
===========
F-13
The following table summarizes information about Incentive Plan stock
options outstanding at December 31, 1998:
Number of Weighted Average Number of
Shares Remaining Life Shares
Exercise Price Outstanding (Years) Exercisable
-------------- ----------- ------- -----------
$2.00 451,000 2.3 436,500
$2.50 20,000 3.5 14,000
$3.00 155,000 1.1 155,000
$3.44 567,000 8.8 --
$4.81 264,000 2.6 264,000
$6.56 250,000 3.1 250,000
$6.94 150,000 5.0 --
$9.63 90,000 3.6 90,000
$11.00 1,326,500 6.6 366,500
$11.94 40,000 4.9 40,000
$12.38 577,000 6.5 223,750
----------- --- ---------
3,890,500 5.5 1,839,750
=========== === =========
The Company accounts for the stock options issued under the Incentive Plan
under APB Opinion No. 25, under which no compensation cost has been recognized.
Had compensation cost for this plan been determined consistent with Statement of
Financial Accounting Standards No. 123 ("SFAS 123") "Accounting for Stock-Based
Compensation," the Company's net income and earnings per share from continuing
operations would have been reduced to the following pro forma amounts:
1996 1997 1998
---- ---- ----
(In thousands, except per share amounts)
Net income (loss) from
continuing operations: As Reported $ 24,066 $ 21,746 $(17,168)
Pro Forma 20,296 18,633 (20,651)
Basic earnings per share: As Reported 1.56 0.90 (0.71)
Pro Forma 1.31 0.77 (0.85)
Diluted earnings per share: As Reported 1.23 0.85
Pro Forma 0.96 0.72
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 1996, 1997, and 1998, respectively: average
risk-free interest rates of 6.34, 6.33, and 5.30 percent; average expected lives
of 7.7, 7.3, and 8.2 years; average expected volatility factors of 54.5, 51.9
and 58.8; 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 Plan was $6.20 in 1996, $7.45 in 1997, and $2.98 in 1998.
The Company also has options outstanding to purchase 220,530 common shares
at $5.00 per share at December 31, 1998 that were issued in connection with an
oil and gas property acquisition in 1994. These options expire in 1999.
F-14
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 to Bois d'
Arc in connection with 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 by
Bois d' Arc 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.
During 1998, warrants to purchase 150,000 shares became vested. The estimated
value of the warrants which vested in 1998 of $1.5 million was included as
exploration costs for three successful wells under the exploration venture.
Restricted Stock Grants
Under the Incentive Plan, 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 ten-year period with credit given
for past service rendered to the Company. Restricted stock grants for 330,000
shares have been awarded under the Incentive Plan. As of December 31, 1998,
322,500 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, 1996, 1997 and 1998
was $41,000, $15,000, and $7,000, respectively.
(9) Significant Customers
The Company had sales to one purchaser of crude oil which accounted for
17%, 17%, and 25% of the Company's oil and gas sales in 1996, 1997, and 1998,
respectively. In 1996 and 1997, the Company had one purchaser of natural gas
which accounted for 31% and 35%, respectively, of the Company's oil and gas
sales. In 1998 the Company had two purchasers of natural gas which accounted for
17% and 12% of the Company's oil and gas sales.
(10) Income Taxes
The tax effects of significant temporary differences representing the net
deferred tax liability at December 31, 1997 and 1998 were as follows:
1997 1998
---- ----
(In thousands)
Net deferred tax assets (liabilities):
Property and equipment $(13,965) $(22,150)
Net operating loss carryforwards 2,193 20,102
Other carryforwards 565 270
Valuation allowance -- --
-------- --------
$(11,207) $ (1,778)
======== ========
The following is an analysis of the consolidated income tax benefit
(expense):
1997 1998
---- ----
(In thousands)
Current $ (259) $ --
Deferred (11,363) 9,244
-------- --------
$(11,622) $ 9,244
======== ========
F-15
No income tax provision was recognized in 1996 due to the availability of
net operating loss carryforwards to offset any current or deferred income tax
liabilities.
The difference between income taxes computed using the statutory rate of
35% and the Company's effective tax rate in 1997 and 1998 is as follows:
1997 1998
---- ----
(In thousands)
Income tax benefit (expense) computed at federal
statutory rate $(11,822) $ 9,244
Reduction in valuation allowance
for net operating loss carryforward 176 --
Other 24 --
--------- --------
$ (11,622) $ 9,244
========= ========
The Company has net operating loss carryforwards of approximately $57.4
million as of December 31, 1998 for income tax reporting purposes which expire
in varying amounts from 2005 to 2018.
(11) Related Party Transactions
The Company served as general partner of Comstock DR-II Oil & Gas
Acquisition Limited Partnership ("Comstock DR-II") until December 29, 1997. In
1996 and 1997, the Company received management fees from Comstock DR-II of
$87,000 and $40,000, respectively.
From August 1, 1995 to December 1, 1996, the Company was the managing
general partner and owned a 20.31% limited partner interest in Crosstex Pipeline
Partners, Ltd. ("Crosstex"). The Company sold its interest in connection with
the sale of its third party natural gas marketing operations (see Note 13
"Discontinued Operations"). The Company received $82,000 in fees for management
and construction services provided to Crosstex in 1996 and was reimbursed
$228,000 for direct expenses incurred in connection with managing Crosstex in
1996. The Company paid $477,000 to Crosstex for transportation of its natural
gas production in 1996.
(12) Risk Management
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 are 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.
F-16
As a result of certain hedging transactions for natural gas the Company
realized the following gains and losses:
1996 1997 1998
---- ---- ----
(In thousands)
Realized Gains $ 509 $ -- $ 367
Realized Losses 1,643 -- --
As of December 31, 1997 and 1998, the Company had no open derivative
financial instruments held for price risk management. Subsequent to December 31,
1998, the Company entered into natural gas price swaps covering 10,480,000
MMBtus of its natural gas production for March 1999 to October 1999 at 1,310,000
MMBtus per month at a fixed index price of $1.81 (after basis adjustment).
The Company entered into interest rate swap agreements in September 1998 to
hedge the impact of interest rate changes on a portion of its long-term debt.
The notional amount of the swap agreements is $125.0 million and fixed the LIBOR
rate at an average rate of 5.1% through September 2000. 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 in 1998. The fair value of
the interest rate swaps as of December 31, 1998 was a liability of approximately
$95,000.
(13) Discontinued Operations
In December 1996, the Company sold its third party natural gas marketing
operations and substantially all of its related gas gathering and gas processing
assets for approximately $3.0 million. The Company realized a $818,000 gain from
the sale. The Company's gas gathering, processing and marketing segment is
accounted for as discontinued operations in the accompanying financial
statements, and accordingly, the results of the gas gathering, processing and
marketing operations as well as the gain on disposal are segregated in the
accompanying Consolidated Statements of Operations.
Income for discontinued gas gathering, processing and marketing operations
included in the Consolidated Statements of Operations for the year ended
December 31, 1996 is comprised of the following:
(In thousands)
Revenues $ 85,398
Operating costs (83,168)
Depreciation, depletion and amortization (373)
General and administrative, net (809)
Gain on sales of property --
Gain on disposal of segment 818
Provision for income taxes --
--------
Income from discontinued operations $ 1,866
========
F-17
(14) Supplementary Quarterly Financial Data (Unaudited)
First Second Third Fourth Total
----- ------ ----- ------ -----
(In thousands, except per share amounts)
1997 -
Total revenues..................................$ 23,727 $ 18,279 $ 18,285 $ 29,053 $ 89,344
========= ========= ========= ========= ========
Net income attributable to common stock.........$ 7,764 $ 3,973 $ 4,190 $ 5,819 $ 21,746
========= ========= ========= ========= ========
Net income per share:
Basic ........................................$ 0.32 $ 0.16 $ 0.17 $ 0.24 $ 0.90
========= ========= ========= ========= ========
Diluted ......................................$ 0.30 $ 0.16 $ 0.17 $ 0.23 $ 0.85
========= ========= ========= ========= ========
1998 -
Total revenues..................................$ 25,558 $ 24,894 $ 21,517 $ 21,266 $ 93,235
========= ========= ========= ========= ========
Net income (loss) attributable to common stock..$ 570 $ (1,304) $ (3,387) $ (13,047)(1) $(17,168)(1)
========= ========= ========= ========= ========
Net income (loss) per share:
Basic.........................................$ 0.02 $ (0.05) $ (0.14) $ (0.54) $ (0.71)
========= ========== ========= ========= ========
Diluted.......................................$ 0.02
=========
(1) Includes impairment of oil and gas properties of $17 million.
(15) Oil and Gas Reserves Information (Unaudited)
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: $17.24 and $10.55 per
barrel of oil for 1997 and 1998, respectively, and $2.64 and $2.21 per Mcf of
natural gas for 1997 and 1998, 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.
F-18
The following unaudited table sets forth proved oil and gas reserves at
December 31, 1996, 1997 and 1998:
1996 1997 1998
---- ---- ----
Oil Gas Oil Gas Oil Gas
(MBbls) (MMcf) (MBbls) (MMcf) (Mbbls) (MMcf)
------- ------ ------- ------ ------- ------
Proved Reserves:
Beginning of year 3,779 173,165 8,994 234,444 20,927 240,117
Revisions of previous
estimates 243 (5,926) (1,202) (7,398) (3,284) 12,025
Extensions and discoveries 613 551 263 5,566 5,173 24,973
Purchases of minerals in place 5,930 100,446 14,473 39,970 -- --
Sales of minerals in place (619) (14,365) (258) (9,605) -- --
Production (952) (19,427) (1,343) (22,860) (2,571) (26,713)
-------- -------- -------- -------- -------- --------
End of year 8,994 234,444 20,927 240,117 20,245 250,402
======== ======== ======== ======== ======== ========
Proved Developed Reserves:
Beginning of year 2,562 130,375 6,953 187,247 16,635 188,102
======== ======== ======== ======== ======== ========
End of year 6,953 187,247 16,635 188,102 16,585 182,955
======== ======== ======== ======== ======== ========
The following table sets forth the standardized measure of discounted
future net cash flows relating to proved reserves at December 31, 1997 and 1998:
1997 1998
---- ----
(In thousands)
Cash Flows Relating to Proved Reserves:
Future Cash Flows $ 993,812 $ 767,869
Future Costs:
Production (217,637) (212,558)
Development (66,418) (74,130)
--------- ---------
Future Net Cash Flows Before Income Taxes 709,757 481,181
Future Income Taxes (128,983) (30,221)
--------- ---------
Future Net Cash Flows 580,774 450,960
10% Discount Factor (162,498) (145,967)
--------- ---------
Standardized Measure of Discounted Future Net Cash Flows $ 418,276 $ 304,993
========= =========
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, 1996, 1997 and 1998:
1996 1997 1998
---- ---- ----
(In thousands)
Standardized Measure, Beginning of Year $ 146,506 $ 390,422 $ 418,276
Net Change in Sales Price, Net of Production Costs 132,094 (188,079) (146,742)
Development Costs Incurred During the Year Which
Were Previously Estimated 5,934 10,740 20,361
Revisions of Quantity Estimates (7,612) (16,779) (7,391)
Accretion of Discount 14,829 50,292 45,956
Changes in Future Development Costs (5,801) (3,919) (19,318)
Changes in Timing and Other (13,165) (20,347) (39,805)
Extensions and Discoveries 9,216 6,233 60,906
Purchases of Reserves In Place 282,150 205,583 --
Sales of Reserves In Place (10,342) (16,450) --
Sales, Net of Production Costs (55,077) (70,636) (68,214)
Net Changes in Income Taxes (108,310) 71,216 40,964
--------- --------- ---------
Standardized Measure, End of Year $ 390,422 $ 418,276 $ 304,993
========= ========= =========
F-19
INDEX TO EXHIBITS
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).
4.2(a) Rights Agreement dated as of December 10, 1990, by
and between the Company and Society National Bank, as
Rights Agent (incorporated herein by reference to
Exhibit 1 to the Company's Registration Statement on
Form 8-A, dated December 14, 1990).
4.2(b) First Amendment to the Rights Agreement, by and
between the Company and Society National Bank
(successor to Ameritrust Texas, N.A.), as Rights
Agent, dated January 7, 1994 (incorporated herein by
reference to Exhibit 3.6 to the Company's Annual
Report on Form 10-K for the year ended December 31,
1993).
4.2(c) Second Amendment to the Rights Agreement, by and
between the Company and Bank One, Texas N.A.
(successor to Society National Bank), as Rights
Agent, dated April 1, 1995 (incorporated by reference
to Exhibit 4.7 to the Company's Annual Report on Form
10-K for the ended December 31, 1995).
4.2(d) Third Amendment to the Rights Agreement, by and
between the Company and Bank One, Texas N.A.
(successor to Society National Bank), as Rights
Agent, dated April 1, 1995 (incorporated by reference
to Exhibit 4.8 to the Company's Annual Report on Form
10-K for the ended December 31, 1995).
4.2(e) Fourth Amendment to the Rights Agreement, by and
between the Company and Bank One, Texas N.A.
(successor to Society National Bank), as Rights
Agent, dated April 1, 1995 (incorporated by reference
to Exhibit 4.9 to the Company's Annual Report on Form
10-K for the ended December 31, 1995).
4.3 Certificate of Designation, Preferences and Rights of
Series A Junior Participating Preferred Stock dated
December 6, 1990 (incorporated by reference to
Exhibit 4.3 to the Company's Registration Statement
on Form S-3, dated October 25, 1996).
10.1(a)* Credit Agreement dated as of December 23, 1998, E-4
between the Company, the Banks Party thereto and The
First National Bank of Chicago, as Administrative
Agent and Toronto Dominion (Texas), Inc., as
Syndication Agent.
E-1
INDEX TO EXHIBITS
Exhibit No. Description Page
- ---------- ------------------------------------------------------ -----------
10.2# Employment Agreement dated May 11, 1998, by and
between the Company and M. Jay Allison (incorporated
herein by reference to Exhibit 10.1 to the Company's
Quarterly Report on Form 10-Q for the quarter ended
March 31, 1998).
10.3# Employment Agreement dated May 11, 1998, by and
between the Company and Roland O. Burns (incorporated
herein by reference to Exhibit 10.2 to the Company's
Quarterly Report on Form 10-Q for the quarter ended
March 31, 1998).
10.4# Change in Control Employment Agreement dated May 15,
1997, 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, 1997).
10.5# Change in Control Employment Agreement dated May 15,
1997, 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, 1997).
10.6(a)# Comstock Resources, Inc. 1991 Long-term Incentive
Plan, dated as of April 1, 1991 (incorporated herein
by reference to Exhibit 10.8 to the Company's Annual
Report on Form 10-K for the year ended December 31,
1991).
10.6(b)# Amendment No. 1 to the Comstock Resources, Inc. 1991
Long-term Incentive Plan (incorporated by reference
to Exhibit 10.4 to the Company's Quarterly Report on
Form 10-Q for the quarter ended September 30, 1996).
10.7# Form of Nonqualified Stock Option Agreement, dated
April 2, 1991, between the Company and certain
officers and directors of the Company (incorporated
herein by reference to Exhibit 10.9 to the Company's
Annual Report on Form 10-K for the year ended
December 31, 1991).
10.8# Form of Restricted Stock Agreement, dated April 2,
1991, between the Company and certain officers of the
Company (incorporated herein by reference to Exhibit
10.10 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1991).
10.9 Form of Stock Option Agreement, dated October 12,
1994 by and between the Company and Christopher T. H.
Pell, et al (incorporated herein by reference to
Exhibit 10.18 to the Company's Annual Report on Form
10-K for the year ended December 31, 1994).
10.10 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).
E-2
INDEX TO EXHIBITS
Exhibit No. Description Page
- ---------- ------------------------------------------------------ -----------
10.11 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).
10.12 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-59
23* Consent of Arthur Andersen LLP. E-60
27* Financial Data Schedule for the twelve months ended
December 31, 1998. E-61
*Filed herewith.
# Management contract or compensatory plan document.
E-3