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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, 1997
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, 1998, there were 24,218,874 shares of common stock
outstanding.
As of March 12, 1998, the aggregate market value of the voting stock held
by non-affiliates of the registrant was approximately $227,300,000.
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 1998 annual
meeting of stockholders (to be filed with the Securities and Exchange Commission
not later than April 30, 1998).
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COMSTOCK RESOURCES, INC.
FORM 10-K
For the Fiscal Year Ended December 31, 1997
CONTENTS
Page
Part I
Items 1 and 2. Business and Properties....................................... 5
Item 3. Legal Proceedings..............................................18
Item 4. Submission of Matters to a Vote of Security Holders............18
Part II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters...................................19
Item 6. Selected Financial Data........................................20
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations...................21
Item 8. Financial Statements...........................................25
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure...................25
Part III
Item 10. Directors and Executive Officers of the Registrant.............26
Item 11. Executive Compensation.........................................26
Item 12. Security Ownership of Certain Beneficial Owners
and Management........................................26
Item 13. Certain Relationships and Related Transactions.................26
Part IV
Item 14. Exhibits and Reports on Form 8-K...............................27
1
DEFINITIONS
The following are abbreviations of terms commonly used in the oil and gas
industry and in 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.
"Completion" means the installation of permanent equipment for the production of
oil or gas.
"Condensate" means a hydrocarbon mixture that becomes liquid and separates from
natural gas when the gas is produced and is similar to crude oil.
"Development well" means a well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.
"Dry hole" means a well found to be incapable of producing hydrocarbons in
sufficient quantities such that proceeds from the sale of such production exceed
production expenses and taxes.
"Exploratory well" means a well drilled to find and produce oil or natural gas
reserves not classified as proved, to find a new productive reservoir in a field
previously found to be productive of oil or natural gas in another reservoir or
to extend a known reservoir.
"Gross" when used with respect to acres or wells, production or reserves refers
to the total acres or wells in which the Company or other specified person has a
working interest.
"MBbls" means one thousand barrels of oil.
"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 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%.
2
"Proved developed reserves" means reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods. Additional
oil and gas expected to be obtained through the application of fluid injection
or other improved recovery techniques for supplementing the natural forces and
mechanisms of primary recovery will be included as "proved developed reserves"
only after testing by a pilot project or after the operation of an installed
program has confirmed through production response that increased recovery will
be achieved.
"Proved reserves" means the estimated quantities of crude oil, natural gas, and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
(i) Reservoirs are considered proved if economic
producibility is supported by either actual production or conclusive
formation tests. The area of a reservoir considered proved includes (A)
that portion delineated by drilling and defined by gas-oil and/or
oil-water contacts, if any; and (B) the immediately adjoining portions
not yet drilled, but which can be reasonably judged as economically
productive on the basis of available geological and engineering data.
In the absence of information on fluid contacts, the lowest known
structural occurrence of hydrocarbons controls the lower proved limit
of the reservoir.
(ii) Reserves which can be produced economically through
application of improved recovery techniques (such as fluid injection)
are included in the "proved" classification when successful testing by
a pilot project, or the operation of an installed program in the
reservoir, provides support for the engineering analysis on which the
project or program was based.
(iii) Estimates of proved reserves do not include the
following: (A) oil that may become available from known reservoirs but
is classified separately as "indicated additional reserves"; (B) crude
oil, natural gas, and natural gas liquids, the recovery of which is
subject to reasonable doubt because of uncertainty as to geology,
reservoir characteristics, or economic factors; (C) crude oil, natural
gas, and natural gas liquids, that may occur in undrilled prospects;
and (D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such resources.
"Proved undeveloped reserves" means reserves that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion. Reserves on undrilled acreage
shall be limited to those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves for other
undrilled units can be claimed only where it can be demonstrated with certainty
that there is continuity of production from the existing productive formation.
Under no circumstances should estimates for proved undeveloped reserves be
attributable to any acreage for which an application of fluid injection or other
improved recovery technique is contemplated, unless such techniques have been
proved effective by actual tests in the area and in the same reservoir.
"Recompletion" means the completion for production of an existing well bore in
another formation from that in which the well has been previously completed.
"Royalty" means an interest in an oil and gas lease that gives the owner of the
interest the right to receive a portion of the production from the leased
acreage (or of the proceeds of the sale thereof), but generally does not require
the owner to pay any portion of the costs of drilling or operating the wells on
the leased acreage. Royalties may be either landowner's royalties, which are
reserved by the owner of the leased acreage at the time the lease is granted, or
overriding royalties, which are usually reserved by an owner of the leasehold in
connection with a transfer to a subsequent owner.
"3-D seismic" means an advanced technology method of detecting accumulations of
hydrocarbons identified by the collection and measurement of the intensity and
timing of sound waves transmitted into the earth as they reflect back to the
surface.
3
"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 an 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.
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, increases in oil and
natural gas production, the Company's financial position, oil and natural gas
reserve estimates, business strategy and other plans and objectives for future
operations, are forward-looking statements. Although 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 revision, if
significant, would change the schedule of any further production and development
drilling. Accordingly, reserve estimates are generally different from the
quantities of oil and gas that are ultimately recovered. All forward-looking
statements in this report are expressly qualified in their entirety by the
cautionary statements in this paragraph.
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 gas reserve base which is entirely focused in the Gulf of
Mexico, Southeast Texas and East Texas/North Louisiana regions. Approximately
48% of the Company's oil and natural gas reserves are located in the Gulf of
Mexico, 29% in Southeast Texas and 23% in East Texas/North Louisiana. As a
result of 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
85% of its Present Value of Proved Reserves as of December 31, 1997. Comstock
has compiled a high quality reserve base that is 66% natural gas and 79% proved
developed on a Bcfe basis. The Company has estimated proved oil and natural gas
reserves of 365.7 Bcfe with an estimated Present Value of Proved Reserves of
$459.6 million as of December 31, 1997.
Comstock has achieved substantial growth in reserves, production, revenues
and EBITDA since 1993. The Company's estimated proved oil and natural gas
reserves have increased at a compounded annual growth rate of 35% from 111.0
Bcfe as of December 31, 1993 to 365.7 Bcfe as of December 31, 1997. Over this
period, average net daily production has increased from 27.9 MMcfe per day in
1993 to 135.7 MMcfe per day in 1997, on a pro forma basis. Similarly, the growth
in the Company's oil and natural gas revenues and EBITDA has been substantial,
increasing from $22.1 million and $13.6 million, respectively, for the year
ended December 31, 1993 to $143.5 million and $116.5 million, respectively, for
the year ended December 31, 1997 on a pro forma basis.
Over the past three 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 were $0.65 in 1995, $0.55 in 1996 and $0.51 in
1997 on a pro forma basis. Comstock's general and administrative expenses per
Mcfe were $0.11 in 1995, $0.09 in 1996 and $0.05 in 1997 on a pro forma basis.
The Company operates 342 of the 551 wells in which it has an interest. Operated
wells represent 85% of the Company's Present Value of Proved Reserves 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. As a result of the Company's low cost structure,
Comstock generated a cash margin per Mcfe of $1.17 in 1995, $2.10 in 1996 and
$2.34 in 1997 on a pro forma basis.
Comstock has increased its focus on the exploitation and development of its
properties through development drilling, workovers and recompletions.
Additionally, the Company has a multi-year inventory of exploration prospects.
The Company's spending on exploration and development activities has increased
by 1018% from $2.8 million in 1993 to $31.3 million in 1997. The Company has
budgeted to spend $55.0 million in 1998 for identified development and
exploration projects.
Recent Developments
In December 1997, the Company acquired offshore Gulf of Mexico properties
from Bois d' Arc Resources and certain of its affiliates and working interest
partners (the "Bois d' Arc Acquisition"). The properties are located offshore in
the Louisiana state and federal areas of Main Pass Block 21 and 25, Ship Shoal
Blocks 66, 67, 68 and 69, and South Pelto Block 1. The properties had estimated
proved oil and natural gas reserves of 14.3 MMBbls of oil and 29.4 Bcf of
natural gas, when acquired. The acquisition included 43 wells (29.6 net) and
eight production complexes producing 8,500 net barrels of oil equivalent per day
and seven undrilled prospects which have been delineated by 3-D seismic. The
Company allocated $30.2 million of the purchase price to the undrilled prospects
and $1.0 million to other assets. This acquisition increased the Company's
proved oil and natural gas reserves, daily oil and natural gas production and
EBITDA by 46%, 69% and 78%, respectively, based on pro forma 1997 operating
results.
Comstock recently entered into a joint exploration program with Bois d' Arc
Resources and its principals ("Bois d' Arc") pursuant to which the Company and
Bois d' Arc will jointly explore for prospects in defined parts of the Gulf of
5
Mexico region (the "Bois d' Arc Exploration Venture"). Bois d' Arc will be
responsible for identifying potential prospects and the parties will jointly
acquire 3-D seismic data and leasehold to be shared 80% by the Company and 20%
by Bois d' Arc. Comstock and Bois d' Arc have committed to spend at least $5.0
million during the initial 24 months of the program to acquire seismic data.
With respect to any prospects in which the Company elects to participate in
drilling, the Company will acquire a 33% working interest. As part of the Bois
d' Arc Exploration Venture, the Company issued warrants to Bois d' Arc to
acquire up to 1,000,000 shares of the Company's common stock, at an exercise
price of $14.00 per share. The warrants vest in 50,000 share increments based on
the success of the initial test well on a prospect.
Business Strategy
The Company's strategy is to increase cash flow and net asset value by
acquiring oil and natural gas properties at attractive costs and developing its
reserves. In addition, the Company intends to pursue selective exploration
opportunities in its core operating areas. The key elements of the Company's
business strategy are to:
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 and for the three year period
ended December 31, 1997, Comstock has replaced 567% of its oil and natural gas
production through 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 the Bois
d' Arc Acquisition for $200.9 million, 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.
Operate Properties
The Company prefers to operate the properties it acquires, allowing it to
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 342 of the 551 wells in which it owns an interest which
comprise approximately 85% of its Present Value of Proved Reserves as of
December 31, 1997.
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
$0.11 and $0.65, respectively, for 1995 to $0.05 and $0.51, respectively, for
1997 on a pro forma basis.
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 newly developed formation
stimulation techniques. During 1997, the Company spent $22.7 million to drill 40
development wells (19.0 net), of which 33 were successful. In 1998, the Company
has budgeted approximately $35.0 million to drill approximately 41 development
wells (25.0 net).
6
Pursue Selective Exploration Opportunities
The Company pursues selective exploration activities to find additional
reserves on its undeveloped acreage. In 1997, the Company spent $6.0 million to
drill nine exploratory wells (3.2 net), five (1.6 net) of which were successful.
The Company plans to increase its spending for exploration activities to
approximately $20.0 million in 1998 to drill 15 wells (5.7 net). The Company's
exploration activities in 1998 are expected to be focused on the Gulf of Mexico
region and based on drilling 3-D seismic generated prospects, including the
prospects acquired in the Bois d' Arc Acquisition and prospects generated under
the Bois d' Arc Exploration Venture.
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 gas reserves by field as
of December 31, 1997.
Present Value
Net Oil Net Gas of Proved
Field Area (MBbls) (MMcf) Reserves Percentage
---------- ------- ------ -------- ----------
(In thousands)
Gulf of Mexico
Ship Shoal Blocks 66/67/68/69
and S. Pelto Block 1 12,721 26,423 $171,018
Main Pass Blocks 21/25 2,269 3,172 19,302
West Cameron Blocks 238/248/249 - 6,116 9,818
East White Point 887 6,288 8,640
El Campo 264 3,548 5,188
Mustang Island 77 1,991 2,252
Other 40 1,801 2,337
------ ------ -------
16,258 49,339 218,555 47.6%
------ ------ -------
Southeast Texas
Double A Wells 3,601 77,073 132,036
Redmond Creek 144 1,495 2,799
------ ------ -------
3,745 78,568 134,835 29.3%
------ ------ -------
East Texas/North Louisiana
Beckville 139 24,142 18,616
Logansport 73 18,820 18,257
Lisbon 132 9,920 15,775
Waskom 238 13,330 10,627
Blocker 46 11,319 8,692
Ada 9 5,085 7,976
Longwood 99 6,010 5,931
Sugar Creek 70 3,844 5,318
Box Church 2 9,880 3,449
Hico Knowles 36 1,994 2,481
Simsboro 3 2,669 2,111
Sligo 12 2,126 2,094
Other 33 2,378 3,869
------ ------- -------
892 111,517 105,196 22.9%
------ ------- -------
Other Areas 32 693 970 .2%
------ ------- ------- ----
Total 20,927 240,117 $459,556 100.0%
====== ======= ======== =====
7
Gulf of Mexico
The Company's largest operating area includes properties located offshore
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 119 producing
wells (68.9 net wells) in ten 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) and West Cameron Blocks 238, 248 and 249.
The Company has 146.9 Bcfe of oil and natural gas reserves in the Gulf of Mexico
region with a Present Value of Proved Reserves of $218.6 million as of December
31, 1997. The Company operates 46 of the 118 producing wells (69.6 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. December 1997 production rates net to
the Company's interests from the area were 20.5 MMcf of natural gas per day and
5,945 barrels of oil per day. The Company has budgeted $14.9 million for
development drilling in this region in 1998 to drill nine wells (5.6 net) and
anticipates spending all of its 1998 exploration budget of $20.0 million in this
region to drill 15 offshore exploratory wells (5.7 net).
Ship Shoal
The Ship Shoal area is located in Louisiana state waters and in federal
waters, offshore 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 where the
Company has a 25% working interest. The Company has estimated reserves of 102.7
Bcfe (28% of total proved reserves) with a Present Value of Proved Reserves of
$171.0 million as of December 31, 1997. The Company owns interests in 30 wells
(20.8 net) in the Ship Shoal area, which had net production rates of 16.8 MMcf
per day and 4,911 barrels of oil per day during December 1997.
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. These areas are primarily oil prone and contain
reservoirs that are typically less than 200 acres in areal extent and exhibit
very high porosity and permeability. The Company has initiated a development
plan on the properties that targets wells with multiple pay objectives. The
Company plans to drill five development wells (3.5 net) at an estimated cost of
$10.8 million in this area during 1998. The development wells, if successful,
would be connected to one of the six existing production platforms, five of
which are operated by the Company, thereby lowering its development and
operating costs.
The Company has identified six exploration prospects in the Ship Shoal area
that it plans to drill during the next three years. If successful, each of these
prospects can be tied into existing production platforms owned by the Company
which would enable the Company to maintain a low operating cost structure in
this area. Each of these prospects has been identified by the use of 3-D seismic
and the Company is currently utilizing 3-D seismic data to evaluate other
prospects in the Ship Shoal area.
Main Pass
Main Pass Blocks 21 and 25 are located in Louisiana state waters, offshore
of Plaquemines Parish in water with a depth of approximately 12 feet. The
Company's wells in this area produce from multiple Miocene sands at depths that
range from 4,400 feet to 7,700 feet and represent approximately 5% (16.8 Bcfe)
of the Company's proved reserves as of December 31, 1997. The Company is the
operator and owns interests in 14 wells at Main Pass Block 21 and 25 with an
average working interest of 96%. During December 1997, the average production
attributable to the Company's interest was approximately .3 MMcf of natural gas
and 730 barrels of oil per day. The Company has seven proved undeveloped
locations in the Main Pass area and has identified one exploration prospect that
it plans to drill in the future which, if successful, can all be tied into the
existing production platforms owned by the Company.
West Cameron
West Cameron Blocks 238, 248 and 249 are located in federal waters with a
depth of approximately 60 feet and produce from complex multi-pay Pliocene and
Miocene aged sands at depths ranging from 5,000 to 11,500 feet. The Company's
proved reserves in this field were 6.1 Bcfe (2% of total proved reserves) as of
December 31, 1997 and the average net daily production in December 1997 was 1.3
MMcf of natural gas per day and 4 barrels of oil per day. The Company has a
working interest of 45% in the West Cameron properties. The Company plans to
8
drill two development wells in 1998 at a budgeted cost of $1.4 million at West
Cameron Block 248 that were identified as the result of a recent 3-D seismic
survey.
Southeast Texas
Approximately 28% (101.0 Bcfe) of the Company's reserves are located in
Southeast Texas where the Company owns interests in 33 producing wells (12.5 net
wells) and operates 25 of these wells. Reserves in Southeast Texas represent
29.3% of the Company's Present Value of Proved Reserves as of December 31, 1997.
December 1997 production rates, net to the Company's interests, from the area
are 31.6 MMcf of natural gas per day and 1,954 barrels of oil per day.
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 98.7 Bcfe (27%
of total proved reserves) which have a Present Value of Proved Reserves of
$132.0 million as of December 31, 1997. The Company acquired its interests in
the Double A Wells in May 1996 pursuant to the Black Stone Acquisition. Since
the acquisition, the Company has drilled seven successful development wells (2.0
net) and two successful exploratory wells (.6 net) and increased its net daily
production by 14% to 1,867 barrels of oil per day and 30.8 MMcf of natural gas
per day during December 1997. 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, 1997
consisted of 28,231 gross acres (9,533 net).
In 1997 the Company spent $10.8 million on its development and exploratory
activities in the Double A Wells field and plans to spend $2.9 million to drill
four wells (.9 net) in 1998. The reservoir distribution within the field is
controlled primarily by stratigraphic factors, and the Company believes that the
analysis of 3-D seismic data which the Company plans to obtain in 1998 may lead
to the identification of additional development drilling opportunities as well
as deeper exploratory prospects in the Woodbine formation.
East Texas/North Louisiana
The Company has 116.9 Bcfe of proved reserves (32% of total proved
reserves) concentrated in East Texas and North Louisiana. The Company owns
interests in 374 producing wells (208.5 net wells) in 19 field areas and
operates 252 of these wells. The largest of the Company's field areas in this
region are the Beckville, Logansport, Lisbon and Waskom fields. Reserves in the
region represent 23% of the Company's Present Value of Proved Reserves as of
December 31, 1997. Current production rates, net to the Company's interests,
from the region are 27.2 MMcf of natural gas per day and 276 barrels of oil per
day. 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. 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. This area represents a
significant focus of the Company's development and exploitation activities. In
1997 the Company spent $15.0 million to drill 18 wells (10.1 net) and has
budgeted $17.2 million in 1998 to drill 28 development wells (18.5 net).
Beckville
The Company's properties in the Beckville field, located in Panola County,
Texas, represent approximately 7% (25.0 Bcfe) of the Company's proved reserves
as of December 31, 1997. The Company operates 48 wells in this field and owns
interests in 6 additional wells. The Company has an average working interest of
67% in this field. During December 1997, the average production attributable to
the Company's interest was approximately 2.1 MMcf of natural gas and 13 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 has identified 16 proved
undeveloped locations in the Beckville field and plans to drill nine wells in
1998 at a budgeted cost of $7.1 million.
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 19.3 Bcfe in the Logansport field
represented approximately 5% of the Company's proved reserves as of December 31,
1997. The Company operates 67 wells in this field and owns interests in 30
additional wells. The Company's average working interest in this field is 48%.
During December 1997, the average production attributable to the Company's
interest was approximately 6.5 MMcf of natural gas and 29 barrels of oil per
day. The Company drilled seven development wells (3.2 net) in this field during
1997, of which all were successful. The Company has budgeted $4.5 million to
drill six wells (4.7 net) during 1998.
Lisbon
The Company acquired its interest in the Lisbon field in May 1997 for $20.1
million. The Lisbon field represented approximately 3% (10.7 Bcfe) of the
Company's proved reserves as of December 31, 1997. The Company operates 15 wells
and owns interests in three additional wells in this field. The Company's
average working interest in this field is 52%. During December 1997 the average
net daily production from the field was approximately 3.2 MMcf of natural gas
and 40 barrels of oil per day. The Lisbon field produces from the Cotton Valley
formation at an average depth of 8,000 feet. The Company drilled and completed
seven wells (4.8 net) during 1997 in the Lisbon field. The Company has budgeted
$2.5 million in 1998 to drill seven development wells (3.5 net).
Waskom
The Waskom field represented approximately 4% (14.8 Bcfe) of the Company's
proved reserves as of December 31, 1997. The Company operates 58 wells in this
field and owns interests in 37 additional wells. The Company's average working
interest in this field is 49%. During December 1997, the average production
attributable to the Company's interest was approximately 2.9 MMcf of natural gas
and 47 barrels of oil per day. The Waskom field produces from the Cotton Valley
formation at depths ranging from 9,000 to 10,000 feet. The Company has
identified 10 proved undeveloped locations in the Waskom field and plans to
drill one of these wells in 1998 at a budgeted cost of approximately $1.0
million.
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 transaction completion. 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.
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>
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. On December 9, 1997, the Company acquired working
interests in certain producing offshore Louisiana oil and gas properties as well
as interests in undeveloped offshore oil and gas leases for approximately $200.9
million from 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. The Company also acquired interests in seven undrilled prospects which have
been 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 Logansport, Waskom,
Beckville, Blocker, Longwood, Hico Knowles and Simsboro fields. The net proved
reserves acquired were estimated at 0.8 MMBbls of oil and 104.7 Bcf of natural
gas.
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
interests in the West Cameron Blocks 238, 248 and 249, East White Point, Redmond
11
Creek and Mustang Island. 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 tables set forth the estimated proved oil and natural gas
reserves of the Company and the Present Value of Proved Reserves as of December
31, 1997:
Present
Value of
Oil Gas Total Proved
Category (MBbls) (Mmcf) (Mmcfe) Reserves
-------- ------- ------ ------- --------
(000's)
Proved Developed Producing 12,500 141,178 216,178 $311,419
Proved Developed Non-producing 4,135 46,924 71,734 70,338
Proved Undeveloped 4,292 52,015 77,765 77,799
------ ------- ------- --------
Total Proved 20,927 240,117 365,677 $459,556
====== ======= ======= ========
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.
Drilling Activity Summary
During the three-year period ended December 31, 1997, the Company drilled
development and exploratory wells as set forth in the table below:
Year Ended December 31,
-----------------------
1995 1996 1997
---- ---- ----
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Development Wells:
Oil 2 0.5 2 1.0 2 0.6
Gas 9 2.4 16 8.4 31 16.1
Dry 2 0.7 1 1.0 7 2.3
--- ---- --- ---- --- ----
13 3.6 19 10.4 40 19.0
--- ---- --- ---- --- ----
Exploratory Wells:
Oil - - - - 1 0.3
Gas - - - - 4 1.3
Dry - - 1 0.2 4 1.6
--- ---- --- ---- --- ----
- - 1 0.2 9 3.2
--- ---- --- ---- --- ----
Total Wells 13 3.6 20 10.6 49 22.2
=== ==== === ==== === ====
12
As of December 31, 1997, two development wells (1.0 net) were in the
process of being drilled. Both wells were successfully completed in March 1998.
Subsequent to December 31, 1997, the Company commenced drilling five development
wells (2.5 net). Four of the five wells were successful with the remaining well
still in the process of drilling.
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, 1997.
Oil Gas
--- ---
Gross Net Gross Net
----- --- ----- ---
Texas 17 10.5 263 139.0
Louisiana 9 5.8 192 93.4
State and Federal Offshore 29 23.4 38 21.5
Mississippi 1 0.1 2 0.3
--- ---- --- -----
Total wells 56 39.8 495 254.2
=== ==== === =====
The Company operates 342 of the 551 producing wells presented in the above
table.
Acreage
The following table summarizes the Company's developed and undeveloped
leasehold acreage at December 31, 1997. Excluded is acreage in which the
Company's interest is limited to royalty or similar interests.
Developed Undeveloped
--------- -----------
Gross Net Gross Net
----- --- ----- ---
Texas 165,172 118,747 42,925 17,271
Louisiana 78,851 58,400 1,896 1,100
State and Federal Offshore 20,284 10,055 754 754
Mississippi 1,360 210 - -
------- ------- ------ ------
Total 265,667 187,412 45,575 19,125
======= ======= ====== ======
Title to the Company's oil and natural gas properties is subject to
royalty, overriding royalty, carried and other similar interests and contractual
arrangements customary in the oil and gas industry, liens incident to operating
agreements and for current taxes not yet due, and other minor encumbrances. All
of the Company's oil and natural gas properties are pledged as collateral under
the Company's bank credit facility. As is customary in the oil and gas industry,
the Company is generally able to retain its ownership interest in undeveloped
acreage by production of existing wells, by drilling activity which establishes
commercial reserves sufficient to maintain the lease or by payment of delay
rentals.
Markets and Customers
The market for oil and natural gas produced by the Company depends on
factors beyond its control, including the extent of domestic production and
imports of oil and natural gas, the proximity and capacity of natural gas
pipelines and other transportation facilities, demand for oil and natural gas,
the marketing of competitive fuels and the effects of state and federal
regulation. The oil and gas industry also competes with other industries in
supplying the energy and fuel requirements of industrial, commercial and
individual consumers.
Substantially all of the Company's natural gas production is sold either on
the spot 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. Gas
production from the Company's Double A Wells field is sold under a long-term
contract to HPL Resources Company, a subsidiary of Enron Corp. ("HPL"). The
agreement with HPL is for a term expiring 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 1997 to HPL accounted for approximately 35% of the
Company's 1997 oil and gas sales.
13
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 to Scurlock
Permian Corporation, a subsidiary of Ashland Inc., accounted for approximately
17% of the Company's 1997 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.
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 reports concerning operations and impose other requirements
relating to the exploration and production of oil and gas. Such 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.
Sales of natural gas by the Company are not regulated and are made at
market prices. However, the Federal Energy Regulatory Commission ("FERC")
regulates interstate and certain intrastate natural gas transportation rates and
service conditions, which affect the marketing of natural gas produced by the
Company, as well as the revenues received by the Company for sales of such
production. Since the mid-1980s, FERC has issued a series of orders, culminating
in Order Nos. 636, 636-A and 636-B ("Order 636"), that have significantly
altered the marketing and transportation of gas. Order 636 mandates 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. Order 636 and subsequent FERC orders issued in individual pipeline
restructuring proceedings have been the subject of appeals, the results of which
have generally been supportive of the FERC's open-access policy. Earlier this
year the United States Court of Appeals for the District of Columbia Circuit
largely upheld Order No. 636, et seq. Because further review of certain of these
orders is still possible, and other appeals remain pending, it is difficult to
predict the ultimate impact of the orders on the Company and its gas marketing
efforts. 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. While
significant regulatory uncertainty remains, Order 636 may ultimately enhance the
Company's ability to market and transport its gas, although it may also subject
the Company to greater competition and the more restrictive pipeline imbalance
tolerances and greater associated penalties for violation of such tolerances.
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.
Effective as of January 1, 1995, FERC implemented regulations establishing an
indexing system for transportation rates for interstate common carrier oil
pipelines, which, generally, would index such rates to inflation, subject to
14
certain conditions and limitations. These regulations could increase the cost of
transporting oil and natural gas liquids by interstate pipelines, although the
most recent adjustment generally decreased rates. These regulations have
generally been approved on judicial review. The Company is not able to predict
with certainty what effect, if any, these regulations will have on it, but,
other factors being equal, the regulations may, over time, tend to increase
transportation costs or reduce wellhead prices for oil and natural liquids.
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 certain activities, limit or prohibit other activities
because of protected areas or species, impose 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
generally, 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 is potentially unable to predict the future costs or other future
impacts of environmental regulations on its future operations. A discharge of
hydrocarbons or hazardous substances into the environment could subject the
Company to substantial expense, including the cost to comply with applicable
regulations that require a response to the discharge, such as containment or
cleanup, claims by neighboring landowners or other third parties for personal
injury, property damage or their response costs and penalties assessed, or other
claims sought, by regulatory agencies for response cost or for natural resource
damages.
The following are examples of some environmental laws that potentially
impact the Company and its operations.
Water. The Oil Pollution Act ("OPA") was enacted in 1990 and amends
provisions of the Federal Water Pollution Control Act of 1972 ("FWPCA") and
other statutes as they pertain to 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, where such spill is into navigable waters, or along shorelines. In the
event of an oil spill into such waters, substantial liabilities could be imposed
upon the Company. 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 effect 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.
15
Air Emissions. Amendments to the Federal Clean Air Act enacted in late 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 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 anticipated that additional wastes, which could
include wastes currently generated during the Company's operations, could in the
future be designated as "hazardous wastes." Hazardous wastes are subject to more
rigorous and costly disposal and management requirements than are non-hazardous
wastes. Such changes in the regulations may result in additional capital
expenditures or operating expenses by the Company.
Superfund. The Comprehensive Environmental Response, Compensation, and
Liability Act ("CERCLA"), also known as "Superfund", imposes liability, without
regard to fault or the legality of the original act, on certain classes of
persons in connection with the release of a "hazardous substance" into the
environment. These persons include the current owner or operator of any site
where a release historically occurred and companies that disposed or arranged
for the disposal of the hazardous substances found at the site. CERCLA also
authorizes the EPA and, in some instances, third parties to act in response to
threats to the public health or the environment and to seek to recover from the
responsible classes of persons the costs they incur. In the course of its
ordinary operations, the Company may have managed substances that may fall
within CERCLA's definition of a "hazardous substance." 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 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 September 30, 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 late 1998. The
new lease begins when the space is occupied and is at an initial monthly rate of
$35,081. The Company also owns or leases four production offices and pipe yard
facilities near Marshall and Livingston, Texas and Logansport and Homer,
Louisiana.
16
Employees
At December 31, 1997, the Company had 47 employees and utilized contract
employees for certain of its field operations. The Company considers its
employee relations to be satisfactory.
Directors, Executive Officers and Other Management
The following table sets forth certain information concerning the executive
officers and directors of the Company.
Name Age Position with Company
---- --- ---------------------
Directors and Executive
Officers
M. Jay Allison 42 President, Chief Executive Officer and
Chairman of the Board of Directors
Roland O. Burns 37 Senior Vice President, Chief Financial
Officer, Secretary and Treasurer
Richard S. Hickok 72 Director
Franklin B. Leonard 70 Director
Cecil E. Martin, Jr. 56 Director
James L. Menke 46 Vice President of Operations
Stephen E. Neukom 48 Vice President of Marketing
Richard G. Powers 43 Vice President of Land
Daniel K. Presley 37 Vice President of Accounting and Controller
David W. Sledge 41 Director
Michael W. Taylor 44 Vice President of Corporate Development
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.
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. He
currently serves as a director of Marsh & McLennan Company, Inc. and
Projectavision, Inc. 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 also served as a director of Glen Ridge Savings and Loan Association
from 1968 to 1990. Mr. Leonard holds a B.S. degree from Yale University.
17
Cecil E. Martin, Jr. has been a director of the Company since 1988. Mr.
Martin has been a significant investor in the Company since 1987. From 1973 to
1991 he served as Chairman of a public accounting firm in Richmond, Virginia.
Mr. Martin also serves as a director for Ten-Key, Inc. Mr. Martin holds a B.B.A.
degree from Old Dominion University and is a Certified Public Accountant.
James L. Menke has been Vice President of Operations of the Company since
March 1994. From 1987 to 1994, Mr. Menke was Manager of Engineering for Atropos
Exploration Company. From 1973 to 1986, Mr. Menke held engineering positions
with Pennzoil Company, Gruy Management Services Company, Maynard Oil Company,
and Santa Fe Minerals. Mr. Menke received a B.S. degree in Petroleum Engineering
from Texas A & M University in 1973 and is a Registered Professional Engineer.
Stephen E. Neukom was elected Vice President of Marketing of the Company in
December 1997 and served as Manager of Crude Oil and Natural Gas Marketing since
December 1996. From October 1994 to 1996, Mr. Neukom served as Vice President of
Comstock Natural Gas, Inc., the Company's wholly owned gas marketing subsidiary.
Prior to joining the Company, Mr. Neukom was Senior Vice President of Victoria
Gas Corporation from 1987 to 1994. Mr. Neukom received a B.B.A. degree from the
University of Texas in 1972.
Richard G. Powers joined the Company as Land Manager in October 1994 and
was elected Vice President of Land in 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 was elected Vice President of Accounting in 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.
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.
Michael W. Taylor was elected Vice President of Corporate Development in
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 fifteen 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.
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 1997.
18
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The Company's common stock was listed for trading on the New York Stock
Exchange under the symbol "CRK" on December 17, 1996. Prior to December 17,
1996, the Company's common stock traded on the Nasdaq National Market tier of
the Nasdaq Stock Market. 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 Nasdaq Stock Market or the New York
Stock Exchange, as applicable.
High Low
---- ---
1996 - First Quarter $ 5.75 $ 4.56
Second Quarter 10.50 4.69
Third Quarter 12.13 8.63
Fourth Quarter 14.63 11.13
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
As of March 12, 1997, the Company had 24,218,874 shares of common stock
outstanding, which were held by 893 holders of record and approximately 9,700
beneficial owners who maintain their shares in "street name" accounts.
The Company has never paid cash dividends on its common stock. The Company
presently intends to retain any earnings for the operation and expansion of its
business and does not anticipate paying cash dividends in the foreseeable
future. Any future determination as to the payment of dividends will depend upon
results of operations, capital requirements, the financial condition of the
Company and such other factors as the Board of Directors of the Company may deem
relevant. In addition, the Company is limited under the Company's bank credit
facility from paying or declaring cash dividends.
19
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, 1997 are derived from the Consolidated Financial Statements of the Company. Significant acquisitions of producing oil
and gas properties affect the comparability of the historical financial and operating data for the periods presented. The pro forma
financial information for the year ended December 31, 1997 has been prepared as if the oil and gas property acquisitions which were
completed during 1997 had occurred at January 1, 1997. Neither the historical results nor the pro forma results are 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,
----------------------- Pro Forma
1993 1994 1995 1996 1997 1997
---- ---- ---- ---- ---- ----
($ in thousands, except per share data)
Statement of Operations Data:
Revenues:
Oil and gas sales ......................... $ 21,805 $ 16,855 $ 22,091 $ 68,915 $ 88,555 $ 143,524
Gain on sales of property ................. 26 328 19 1,447 85 85
Other income ................................. 430 416 264 593 704 704
--------- --------- --------- --------- --------- ---------
Total revenues ...................... 22,261 17,599 22,374 70,955 89,344 144,313
Expenses: --------- --------- --------- --------- --------- ---------
Oil and gas operating(1) ..................... 6,673 6,099 7,427 13,838 17,919 25,419
Exploration .................................. 423 - - 436 2,810 2,810
Depreciation, depletion and amortization .. 8,322 7,350 8,379 18,269 26,235 53,943
General and administrative, net ........... 1,834 1,569 1,301 2,239 2,668 2,373
Interest .................................. 2,184 2,869 5,542 10,086 5,934 17,404
Impairment of oil and gas properties ......... - - 29,150(2) - - -
--------- --------- --------- --------- --------- ---------
Total expenses ................... 19,436 17,887 51,799 44,868 55,566 101,949
--------- --------- --------- --------- --------- ---------
Income (loss) from continuing operations
before income taxes and extraordinary item . 2,825 (288) (29,425) 26,087 33,778 42,364
Provision for income taxes ................ - - - - (11,622) (14,627)
--------- --------- --------- --------- --------- ---------
Net income (loss) from continuing operations
before extraordinary item .................. 2,825 (288) (29,425) 26,087 22,156 27,737
Preferred stock dividends ................. (173) (818) (1,908) (2,021) (410) (410)
--------- --------- --------- --------- --------- ---------
Net income (loss) from continuing operations
attributable to common stock before
extraordinary item ......................... 2,652 (1,106) (31,333) 24,066 21,746 27,327
Income from discontinued operations ....... 89 229 3,264 1,866 - -
Extraordinary loss ........................ (417) (615) - - - -
--------- --------- --------- --------- --------- ---------
Net income (loss) attributable to common stock $ 2,324 $ (1,492) $ (28,069) $ 25,932 $ 21,746 $ 27,327
========= ========= ========= ========= ========= =========
Weighted average shares outstanding:
Basic ..................................... 10,402 12,065 12,546 15,449 24,186 24,186
========= ========= ========= ========= ========= =========
Diluted.................................... 11,616 21,199 26,008 26,008
Basic earnings per share: ========= ========= ========= =========
Net income (loss) from continuing operations
before extraordinary item................ $ 0.25 $ (0.09) $ (2.50) $ 1.56 $ 0.90 $ 1.13
Net income (loss) after extraordinary item 0.22 (0.12) (2.24) 1.68 0.90 1.13
Diluted earnings per share:
Net income (loss) from continuing operations
before extraordinary item................. $ 0.24 $ 1.23 $ 0.85 $ 1.07
Net income (loss) after extraordinary item.. 0.21 1.32 0.85 1.07
Other Financial Data:
EBITDA(3)...................................... $ 13,754 $ 9,931 $ 13,646 $ 54,878 $ 68,757 $ 116,521
Ratio of EBITDA to interest expense............ 6.3 3.5 2.5 5.4 11.3 6.1
As of December 31,
------------------
1993 1994 1995 1996 1997
---- ---- ---- ---- ----
Balance Sheet Data: (In thousands)
Cash and cash equivalents.....................$ 755 $ 3,425 $ 1,917 $ 16,162 $ 14,504
Property and equipment, net................... 66,068 77,989 102,116 185,928 410,781
Total assets.................................. 74,095 91,571 120,099 222,002 456,800
Total debt.................................... 21,930 37,932 71,811 80,108 260,000
Stockholders' equity.......................... 27,646 41,205 30,128 118,216 124,594
(1)Includes lease operating costs and production and ad valorem taxes.
(2)Represents the impairment provision for the adoption of a new accounting standard regarding the carrying value of long-lived
assets.
(3) 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.
20
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 the Company's bank credit facility. Based on
the 1997 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 $1.4 million, or $0.05 per share
(on an as diluted basis). 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 $831,000, or $ 0.03 per share (on an as diluted
basis).
The following table reflects certain summary operating data for the periods
presented:
Year Ended December 31,
-----------------------
Pro Forma
1995 1996 1997 1997
---- ---- ---- ----
Net Production Data:
Oil (MBbls) 356 952 1,343 3,097
Natural gas (MMcf) 9,297 19,427 22,860 30,956
Average Sales Price:
Oil (per Bbl) $16.81 $21.96 $19.47 $19.80
Natural gas (per Mcf) 1.73 2.47 2.73 2.66
Average equivalent price (per Mcfe) 1.93 2.74 2.87 2.90
Expenses ($ per Mcfe):
Oil and gas operating(1) $ 0.65 $ 0.55 $ 0.58 $ 0.51
General and administrative 0.11 0.09 0.09 0.05
Depreciation, depletion and
amortization(2) 0.72 0.72 0.84 1.09
Cash Margin ($ per Mcfe)(3) $ 1.17 $ 2.10 $ 2.20 $ 2.34
<FN>
(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.
</FN>
Average oil and natural gas prices received by the Company generally
fluctuate with changes in the posted prices for oil and spot market prices for
natural gas. In prior years, the Company has entered into price swap agreements
to reduce its exposure to natural gas price fluctuations. In 1995, the Company
hedged approximately 25% of its natural gas production and realized a 5% higher
average gas price than it otherwise would have without hedging. In 1996, the
Company hedged approximately 15% of its natural gas production and realized a 2%
lower gas price than it otherwise would have without hedging. The Company did
not hedge any production in 1997. As of March 12, 1998, the Company does not
have any commodity price hedges in place.
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 for 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.
21
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 Mcfe 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.
General and administrative expenses increased $429,000 (19%) to $2.7
million in 1997 from $2.2 million in 1996. The increase related to increased
general corporate expenses associated with the increased size of the Company's
operations.
Depreciation, depletion and amortization ("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 a 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 for 1997 from
$10.1 million for 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.
Year Ended December 31, 1996 Compared to Year Ended December 31, 1995
Oil and gas sales increased $46.8 million (212%), to $68.9 million for 1996
from $22.1 million in 1995 due primarily to a 109% increase in natural gas
production and a 168% increase in oil production as well as higher oil and
natural gas prices. The production increases related primarily to production
from properties acquired in 1995 and the Black Stone Acquisition, which closed
in May 1996. The Company's average gas price increased 43% and its average oil
price increased 31% during 1996 as compared to 1995.
During 1996, the Company sold certain of its non-strategic oil and gas
properties for cash proceeds of $9.0 million. The sales resulted in a gain of
approximately $1.4 million.
Other income increased $329,000 (125%) to $593,000 in 1996 from $264,000 in
1995 due primarily to additional interest income earned on an increased level of
short-term cash deposits in 1996.
Oil and gas operating expenses, including production taxes, increased $6.4
million (86%) to $13.8 million in 1996 from $7.4 million in 1995 due primarily
to the 120% increase in oil and natural gas production (on an Mcfe basis)
resulting primarily from the acquisitions in 1995 and the Black Stone
Acquisition. Oil and gas operating expenses per Mcfe produced decreased 15% to
$0.55 in 1996 from $0.65 in 1995 due to the lower lifting costs associated with
the properties acquired in 1995 and 1996.
General and administrative expenses increased $938,000 (72%) to $2.2
million in 1996 from $1.3 million in 1995. The increase is attributable to a
$600,000 litigation settlement incurred by the Company in 1996 and an increase
in the number of employees of the Company in 1996.
22
DD&A increased $9.9 million (118%) to $18.3 million in 1996 from $8.4
million in 1995 due to the 120% increase in oil and natural gas production (on
an Mcfe basis). Oil and gas property DD&A per Mcfe produced of $0.72 in 1996
remained unchanged from $0.72 in 1995.
Interest expense increased $4.5 million (82%) to $10.1 million for 1996
from $5.5 million for 1995 due primarily to an increase 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 decreased to
8.1% in 1996 as compared to 10.5% in 1995.
The Company reported net income of $24.1 million from continuing
operations, after preferred stock dividends of $2.0 million, for the year ended
December 31, 1996, as compared to a net loss of $31.3 million from continuing
operations, after preferred stock dividends of $1.9 million, for the year ended
December 31, 1995.
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 cash of approximately $3.0 million and discontinued its gas
gathering, processing and marketing segment. Net income from this segment in
1996 was $1.9 million including a gain on the sale of $818,000.
Liquidity and Capital Resources
Funding for the Company's activities has historically been provided by
operating cash flows, debt and equity financings and asset dispositions. Net
cash flows provided by operating activities totaled $84.3 million for the year
ended December 31, 1997, a substantial increase from 1996 of $45.9 million. In
addition to operating cash flow, the primary sources of funds for the Company in
1997 were aggregate borrowings of $295.0 million and proceeds from the sale of
assets of $5.1 million.
The Company's primary needs for capital, in addition to funding of ongoing
operations, are for the acquisition, development and exploration of oil and gas
properties, and the repayment of principal and interest on debt. In 1997, the
Company repaid $115.1 million of indebtedness, repurchased common stock for
$16.1 million and made capital expenditures of $254.8 million.
During 1997, the Company completed three significant transactions which
were all funded by borrowings under the Company's bank credit facility. In May
and December 1997, the Company closed two acquisitions of producing oil and gas
properties for a total of $221.0 million. On August 20, 1997, the holders of the
Company's Series 1995 Convertible Preferred Stock converted all of the shares of
the Series 1995 Convertible Preferred Stock into 1,345,373 shares of the
Company's common stock. The conversion of the Series 1995 Convertible Preferred
Stock into common stock reduced the dividends which would have been paid on the
preferred stock by $645,000 per annum. On August 20, 1997, the Company
repurchased the 1,345,373 shares of common stock from the former preferred
stockholders at $12.00 per share for an aggregate purchase price of $16.1
million.
The Company's annual capital expenditure activity is summarized as follows:
Year Ended December 31,
1995 1996 1997
---- ---- ----
(In thousands)
Acquisition of oil and gas properties $56,081 $100,446 $220,054
Other leasehold costs 12 93 2,304
Workovers and recompletions 2,152 2,972 2,517
Development drilling 1,514 7,964 22,765
Exploratory drilling - 436 6,043
Other 2,050 51 1,160
------- -------- --------
Total $61,809 $111,962 $254,843
======= ======== ========
23
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 $3.6 million, $11.5
million and $33.6 million on development and exploration activities in 1995,
1996 and 1997, respectively. The Company currently anticipates spending
approximately $35.0 million on development projects in 1998 and $20.0 million
for exploration projects in 1998. The Company intends to primarily use
internally generated cash flow to fund capital expenditures other than
significant acquisitions. The Company anticipates that such sources will be
sufficient to fund the expected 1998 development and exploration expenditures.
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 the Company's bank credit facility
or other debt or equity financing 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 natural gas prices and other
market conditions.
The Company's bank credit facility consists of a $290.0 million revolving
credit commitment provided by a syndicate of ten banks for which The First
National Bank of Chicago serves as agent. Indebtedness under the 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, 1997, the
borrowing base was $290.0 million. Such borrowing base may be affected from time
to time by the performance of the Company's oil and natural gas properties and
changes in oil and natural gas prices. The revolving credit line bears interest
at the option of the Company at either (i) LIBOR plus 0.625% to 1.5% or (ii) the
"corporate base rate" plus 0% to 0.5%, depending in each case on the utilization
of the available borrowing base. The Company incurs a commitment fee of up to
0.2% to 0.375% per annum, depending on the utilization of the available
borrowing base, on the unused portion of the borrowing base. The average annual
interest rate as of December 31, 1997, of all outstanding indebtedness under the
Company's bank credit facility was approximately 7.3%. 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 and investments.
Federal Taxation
At December 31, 1997, the Company had federal income tax net operating loss
("NOL") carryforwards of approximately $6.3 million. The NOL carryforwards
expire from 2005 through 2010. 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.
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,
24
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.
25
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, 1997.
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, 1997.
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, 1997.
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, 1997.
26
PART IV
ITEM 14. EXHIBITS AND REPORTS ON FORM 8-K
Exhibits:
The following exhibits are included on pages E-1 to E-74 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 (the "1995 Form
10-K").
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 1995 Form 10-K).
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 1995 Form 10-K).
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 1995 Form 10-K). 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 9, 1997, between the
Company, the Banks Party thereto and The First National Bank of
Chicago, as agent and Bank One, Texas, N.A., as Documentation
Agent.
10.2# Employment Agreement dated May 15, 1997, by and between the
Company and M. Jay Allison (incorporated herein by reference to
Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for
the quarter ended June 30, 1997).
10.3# Employment Agreement dated May 15, 1997, by and between the
Company and Roland O. Burns (incorporated herein by reference to
Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for
the quarter ended June 30, 1997).
10.4# Change in Control Employment Agreement dated May 15, 1997 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).
27
Exhibit No. Description
- ---------- -----------------------------------------------------------------
10.5# Change in Control Employment Agreement dated May 15, 1997 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.
10.11* Joint Exploration Agreement dated December 8, 1997 by and between
the Company and Bois d' Arc Resources.
10.12 Lease Agreement, dated as of December 20, 1994, by and between
the Company and Occidental Tower Corporation (incorporated herein
by reference to Exhibit 10.19 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1994).
10.13 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,
1997.
*Filed herewith.
# Management contract or compensatory plan document.
Reports on Form 8-K:
The following Form 8-K Reports filed subsequent to September 30, 1997 to
the date of this report:
Date Filed Item Description
---------- ---- -----------
December 12, 1997 2 Acquisition of Bois d' Arc Resources properties.
28
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, 1998
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, 1998
- ----------------------
M. Jay Allison Chairman of the Board of Directors
(Principal Executive Officer)
/s/ROLAND O. BURNS Senior Vice President, Chief Financial March 12, 1998
- ----------------------
Roland O. Burns Officer, Secretary and Treasurer
(Principal Financial and
Accounting Officer)
/s/RICHARD S. HICKOK Director March 12, 1998
- ----------------------
Richard S. Hickok
/s/FRANKLIN B. LEONARD Director March 12, 1998
- ----------------------
Franklin B. Leonard
/s/CECIL E. MARTIN, JR. Director March 12, 1998
- ----------------------
Cecil E. Martin, Jr.
/s/DAVID W. SLEDGE Director March 12, 1998
- ----------------------
David W. Sledge
29
CONSOLIDATED FINANCIAL STATEMENTS OF
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
INDEX
Report of Independent Public Accountants.....................................F-2
Consolidated Balance Sheets as of December 31, 1996 and 1997.................F-3
Consolidated Statements of Operations for the Years Ended
December 31, 1995, 1996 and 1997.....................................F-4
Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 1995, 1996 and 1997.....................................F-5
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1995, 1996 and 1997.....................................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, 1996
and 1997, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1997. 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, 1996 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.
As discussed in Note 2 to the financial statements, the Company changed its
method of accounting for the impairment of long-lived assets in the fourth
quarter of 1995.
ARTHUR ANDERSEN LLP
Dallas, Texas,
February 19, 1998
F-2
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31, 1996 and 1997
ASSETS
December 31,
------------
1996 1997
---- ----
(In thousands)
Cash and Cash Equivalents...............................$ 16,162 $ 14,504
Accounts Receivable:
Oil and gas sales .................................... 17,309 24,509
Joint interest operations ............................ 2,188 6,732
Other Current Assets ................................... 174 172
--------- ---------
Total current assets ......................... 35,833 45,917
Property and Equipment:
Unevaluated oil and gas properties ................... - 30,291
Oil and gas properties, successful
efforts method ..................................... 239,671 456,606
Other ................................................ 401 1,561
Accumulated depreciation, depletion
and amortization ................................... (54,144) (77,677)
--------- ---------
Net property and equipment ................... 185,928 410,781
Other Assets ........................................... 241 102
--------- ---------
$ 222,002 $ 456,800
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Portion of Long-Term Debt.......................$ 108 $ -
Accounts Payable and Accrued Expenses .................. 22,773 56,184
--------- ---------
Total current liabilities .................... 22,881 56,184
Long-Term Debt, less current portion ................... 80,000 260,000
Deferred Taxes Payable ................................. - 11,207
Reserve for Future Abandonment Costs ................... 905 4,815
Stockholders' Equity:
Preferred stock--$10.00 par, 5,000,000 shares
authorized,706,323 shares outstanding
at December 31, 1996 ............................... 7,063 -
Common stock--$0.50 par, 50,000,000 shares
authorized, 24,101,430 and 24,208,785
shares outstanding at December 31, 1996
and 1997, respectively ............................. 12,051 12,104
Additional paid-in capital ........................... 118,647 110,273
Retained earnings (deficit) .......................... (19,512) 2,234
Less: Deferred compensation-restricted
stock grants ....................................... (33) (17)
--------- ---------
Total stockholders' equity ................... 118,216 124,594
--------- ---------
$ 222,002 $ 456,800
========= =========
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, 1995, 1996 and 1997
1995 1996 1997
---- ---- ----
(In thousands, except
per share amounts)
Revenues:
Oil and gas sales.................................$ 22,091 $ 68,915 $ 88,555
Gain on sales of property ........................ 19 1,447 85
Other income ..................................... 264 593 704
--------- -------- --------
Total revenues ........................... 22,374 70,955 89,344
--------- -------- --------
Expenses:
Oil and gas operating ............................ 7,427 13,838 17,919
Exploration ...................................... - 436 2,810
Depreciation, depletion and amortization ......... 8,379 18,269 26,235
General and administrative, net .................. 1,301 2,239 2,668
Interest ......................................... 5,542 10,086 5,934
Impairment of oil and gas properties ............. 29,150 - -
--------- -------- --------
Total expenses ........................... 51,799 44,868 55,566
--------- -------- --------
Income (loss) from continuing operations
before income taxes ........................... (29,425) 26,087 33,778
Provision for income taxes ......................... - - (11,622)
--------- -------- --------
Net income (loss) from continuing operations ....... (29,425) 26,087 22,156
Preferred stock dividends .......................... (1,908) (2,021) (410)
--------- -------- --------
Net income (loss) from continuing operations
attributable to common stock .................. (31,333) 24,066 21,746
Income from discontinued gas gathering,
processing and marketing operations
including gain on disposal .................... 3,264 1,866 -
--------- -------- --------
Net income (loss) attributable to common stock......$ (28,069) $ 25,932 $ 21,746
========= ======== ========
Net income (loss) per share:
Basic -
Net income (loss) per share from
continuing operations....................$ (2.50) $ 1.56 $ 0.90
======== ======== ========
Net income (loss) per share....................$ (2.24) $ 1.68 $ 0.90
======== ======== ========
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.................................... 12,546 15,449 24,186
====== ====== ======
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, 1995, 1996 and 1997
Deferred
Additional Retained Compensation-
Preferred Common Paid-In Earnings Restricted
Stock Stock Capital (Deficit) Stock Grants Total
----- ----- ------- --------- ------------ -----
(In thousands)
Balance at December 31, 1994 ... $ 16,000 $ 6,171 $ 36,524 $ (17,375) $ (115) $ 41,205
Issuance of preferred stock . 15,000 - - - - 15,000
Issuance of common stock .... - 292 1,659 - - 1,951
Restricted stock grants ..... - - - - 41 41
Net loss attributable to
common stock .............. - - - (28,069) - (28,069)
--------- --------- --------- --------- --------- ---------
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
========= ========= ========= ========= ========= =========
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, 1995, 1996 and 1997
1995 1996 1997
---- ---- ----
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) ........................................$ (26,161) $ 27,953 $ 22,156
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Compensation paid in common stock ...................... 154 196 129
Depreciation, depletion and amortization ............... 8,613 18,642 26,235
Impairment of oil and gas properties ................... 29,150 - -
Deferred income taxes .................................. - - 11,363
Deferred revenue ....................................... 430 (430) -
Exploration ............................................ - 436 2,810
Gain on sales of property .............................. (2,608) (2,265) (85)
--------- --------- ---------
Working capital provided by operations ............... 9,578 44,532 62,608
Increase in accounts receivable ........................ (6,272) (4,764) (11,744)
Decrease in other current assets ....................... 79 86 2
Increase in accounts payable and accrued expenses ...... 5,022 6,065 33,411
--------- --------- ---------
Net cash provided by operating activities ............ 8,407 45,919 84,277
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sales of properties ...................... 3,085 9,016 5,079
Proceeds from sale of discontinued operations .......... - 3,036 -
Capital expenditures and acquisitions .................. (61,809) (111,962) (254,843)
--------- --------- ---------
Net cash used for investing activities ............... (58,724) (99,910) (249,764)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings ............................................. 58,404 172,150 295,000
Proceeds from preferred stock issuances ................ 15,000 - -
Proceeds from common stock issuances ................... 25 61,503 507
Repurchase of common stock ............................. - - (16,145)
Stock issuance costs ................................... (95) (863) (15)
Principal payments on debt ............................. (24,525) (163,853) (115,108)
Dividends paid on preferred stock ...................... - (701) (410)
--------- --------- ---------
Net cash provided by financing activities ............ 48,809 68,236 163,829
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents (1,508) 14,245 (1,658)
Cash and cash equivalents, beginning of year ....... 3,425 1,917 16,162
--------- --------- ---------
Cash and cash equivalents, end of year .............$ 1,917 $ 16,162 $ 14,504
========= ========= =========
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
Prior to 1995, the Company periodically reviewed the carrying value of its
proved oil and gas properties for impairment in value on a company-wide basis by
comparing the capitalized costs of proved oil and gas properties with the
undiscounted future cash flows after income taxes attributable to proved oil and
gas properties. In 1995, the Company adopted 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." SFAS 121 requires
the Company to assess 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. In connection with the adoption of SFAS 121, the Company
provided an impairment of $29,150,000 in 1995. No impairment was required in
1996 or 1997.
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
In February 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 128 ("SFAS 128"), "Earnings Per Share".
This new standard simplifies the method for computing earnings per share whereby
the Company will report basic earnings per share without the effect of any
outstanding potentially dilutive stock options or other convertible securities
and diluted earning per share with the effect of outstanding stock options and
other convertible securities that are potentially dilutive. Basic and diluted
earnings per share for 1995, 1996 and 1997 were determined as follows:
For the Year Ended December 31,
1995 1996 1997
--------------------------- --------------------------- ---------------------------
Per Per Per
Income Shares Share Income Shares Share Income Shares Share
------- ------ ------ ------- ------ ------ ------- ------ ------
(In thousands, except per share amounts)
Basic Earnings Per Share:
Income (Loss) from
Continuing Operations $(29,425) 12,546 $ 26,087 15,449 $ 22,156 24,186
Less Preferred Stock
Dividends (1,908) - (2,021) - (410) -
-------- ------ -------- ------ -------- ------
Net Income Available
to Common Stockholders $(31,333) 12,546 $(2.50) 24,066 15,449 $ 1.56 21,746 24,186 $ 0.90
======== ====== ====== ====== ======
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
======== ====== ====== ======== ====== ======
F-8
Statements of Cash Flows
For the purpose of the consolidated statements of cash flows, the Company
considers all highly liquid investments purchased with an original maturity of
three months or less to be cash equivalents.
The following is a summary of all significant noncash investing and
financing activities:
For the Year Ended December 31,
-------------------------------
1995 1996 1997
---- ---- ----
(In thousands)
Common stock issued in payment of
preferred stock dividends $1,908 $1,320 $ -
Common stock issued for compensation 113 154 113
The Company made cash payments for interest of $5,836,000, $9,934,000 and
$5,112,000 in 1995, 1996 and 1997, respectively. The Company made cash payments
for income taxes of $300,000 in 1997.
(3) Acquisitions of Oil and Gas Properties
On May 1 and May 2, 1996, the Company purchased working interests in the
Double A Wells field in Polk County, Texas for a net purchase price of $100.4
million. The Company acquired 100% of the capital stock of Black Stone Oil
Company, the operator of the field, together with additional interests held by
other working interest owners in 19 producing oil and gas properties as well as
interests in adjacent undeveloped oil and gas leases.
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) and approximately 6,400 gross acres.
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 includes 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 is
attributed to the undrilled prospects and $1.0 million of the purchase price is
attributed to other assets.
The 1996 and 1997 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 1996 and in 1997 had been
closed on January 1, 1996. 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.
F-9
Unaudited
1996 1997
Pro Forma Pro Forma
--------- ---------
(In thousands, except per share amounts)
Total Revenues $ 126,896 $ 144,313
Net income from continuing operations
attributable to common stock 31,271 27,327
Net income from continuing operations
per share:
Basic 2.02 1.13
Diluted 1.57 1.07
(4) Sale 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,
1996 1997
---- ----
(In thousands)
Proved properties $ 239,671 $ 456,606
Unproved properties - 30,291
Accumulated depreciation, depletion and amortization (53,953) (77,414)
--------- ---------
$ 185,718 $ 409,483
========= =========
Costs Incurred
Year Ended December 31,
-----------------------
1995 1996 1997
---- ---- ----
(In thousands)
Property acquisitions:
Proved properties $ 56,093 $ 100,539 $ 190,708
Unproved properties - - 31,650
Development costs 3,666 10,936 25,282
Exploration costs - 436 6,043
--------- --------- ---------
$ 59,759 $ 111,911 $ 253,683
========= ========= =========
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, 1997:
1995 1996 1997
---- ---- ----
(In thousands)
Oil and gas sales $ 22,091 $ 68,915 $ 88,555
Production costs (7,427) (13,838) (17,919)
Exploration - (436) (2,810)
Depreciation, depletion and amortization (8,277) (18,162) (26,111)
Impairment of oil and gas properties (29,150) - -
-------- -------- --------
Operating income (loss) (22,763) 36,479 41,715
Income tax expense - - (14,353)
-------- -------- --------
Results of operations (excluding general
and administrative and interest expenses) $(22,763) $ 36,479 $ 27,362
======== ======== ========
(6) Long-Term Debt
Total debt at December 31, 1996 and 1997 consists of the following:
1996 1997
---- ----
(In thousands)
Bank Credit Facility $ 80,000 $ 260,000
Other 108 -
80,108 260,000
Less current portion (108) -
--------- ---------
$ 80,000 $ 260,000
========= =========
In connection with the oil and gas property acquisition closed in December
1997, the Company entered into a $290.0 million revolving credit facility with a
syndication of ten banks in which The First National Bank of Chicago serves as
agent, (the "Bank Credit Facility"). The Company financed the acquisition and
refinanced $77.0 million outstanding under its existing credit facility with
borrowings under the Bank Credit Facility. The Bank Credit Facility matures on
December 9, 2002.
As of December 31, 1997, the Company had $260.0 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, 1997 was $290.0 million. 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 0% to 0.5% or, at the Company's
option, at a fixed rate for up to six months based on the London Interbank
Offered Rate ("LIBOR") plus 0.625% to 1.5% depending upon the utilization of the
available borrowing base. As of December 31, 1997, 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 7.3% per annum. In addition,
the Company incurs a commitment fee of 0.2% to 0.375% on the unused portion of
the borrowing base depending upon the utilization of the available borrowing
base.
F-11
(7) Lease Commitments
The Company rents office space under certain noncancellable leases. Minimum
future payments under the leases are as follows:
(In thousands)
1998 $350
1999 598
2000 421
2001 421
2002 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 27,815, 37,117, and 9,256 shares of common stock in 1995, 1996 and 1997,
respectively, in payment of fees aggregating $113,000, $154,000, and $113,000
for 1995, 1996 and 1997, respectively.
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 546,046 and 249,453 shares of common
stock in 1995 and 1996, respectively, in payment of dividends on its preferred
stock of $1,908,000 and $1,320,000 in 1995 and 1996, respectively. No shares
were issued in lieu of cash dividends in 1997.
F-12
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
Company's 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.
During 1996, options and warrants to purchase common stock of the Company
were exercised at prices ranging from $2.00 to $5.75 per share for 1,007,177
shares of common stock yielding net proceeds to the Company of approximately
$3.6 million. During 1997, options to purchase common stock of the Company were
exercised at prices ranging from $3.00 to $6.56 per share for 98,100 shares of
common stock yielding net proceeds to the Company of $507,000.
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, 1997, the Incentive
Plan provided for future awards of stock options or restricted stock grants of
up to 454,963 shares of common stock plus 10% of any future issuances of common
stock.
The following table summarizes stock option activity during 1995, 1996 and
1997 under the Incentive Plan:
Weighted
Average
Number of Exercise Exercise
Shares Price Price
------ ----- -----
Outstanding at January 1, 1995 704,250 $2.00 to $3.00 $2.18
Granted 97,500 $3.00 $3.00
Exercised (10,000) $2.50 $2.50
---------
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
=========
Exercisable at December 31, 1997 1,408,500 $2.00 to $11.00 $4.77
=========
F-13
The following table summarizes information about Incentive Plan stock
options outstanding at December 31, 1997:
Number of Weighted Average Number of
Shares Remaining Life Shares
Exercise Price Outstanding (Years) Exercisable
-------------- ----------- ------- -----------
$2.00 471,000 3.2 447,000
$2.50 85,000 1.5 76,000
$3.00 155,000 2.1 155,000
$4.81 264,000 3.6 264,000
$6.56 250,000 4.1 250,000
$9.63 90,000 4.6 90,000
$11.00 1,326,500 7.6 126,500
$12.38 577,000 7.4 -
--------- --- ---------
3,218,500 5.8 1,408,500
========= === =========
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:
1995 1996 1997
---- ---- ----
(In thousands, except per share amounts)
Net income (loss) from
continuing operations: As Reported $(31,333) $ 24,066 $ 21,746
Pro Forma $(31,498) $ 20,296 $ 18,633
Basic earnings per share: As Reported $ (2.50) $ 1.56 $ 0.90
Pro Forma $ (2.51) $ 1.31 $ 0.77
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 1995, 1996, and 1997, respectively: average
risk-free interest rates of 6.38, 6.34, and 6.33 percent; average expected lives
of 5.2, 7.7, and 7.3 years; average expected volatility factors of 55.7, 54.5,
and 51.9; 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 $1.69 in 1995, $6.20 in 1996 and $7.45 in 1997.
The Company also has options to purchase 237,530 common shares at $5.00 per
share outstanding at December 31, 1997 that were issued in connection with an
oil and gas property acquisition in 1994. These options expire in 1999.
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
F-14
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
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. The
estimated value of the warrants will be included as exploration costs for wells
that are discovered 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, 1997,
317,500 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, 1995, 1996 and 1997
was $41,000, $41,000, and $15,000, respectively.
(9) Significant Customers
During 1996 and 1997, sales to one purchaser of crude oil accounted for 17%
of the Company's oil and gas sales and one purchaser of natural gas accounted
for 31% and 35%, respectively, of the Company's oil and gas sales. No single
purchaser accounted for more than 10% of the Company's total oil and gas sales
in 1995.
(10) Income Taxes
The tax effects of significant temporary differences representing the net
deferred tax liability at December 31, 1996 and 1997 were as follows:
1996 1997
---- ----
(In thousands)
Net deferred tax assets (liabilities):
Property and equipment $ (6,399) $(13,965)
Net operating loss carryforwards
6,255 2,193
Other carryforwards 320 565
Valuation allowance (176) -
-------- --------
$ - $(11,207)
======== ========
The following is an analysis of the consolidated income tax provisions for
the year ended December 31, 1997:
(In thousands)
Current $ 259
Deferred 11,363
---------
$ 11,622
=========
No income tax provision was recognized in 1995 and 1996 due to the
availability of net operating loss carryforwards to offset any current or
deferred income tax liabilities.
F-15
The difference between income taxes computed using the statutory rate of
35% and the Company effective tax rate of 34% for 1997 is as follows:
(In thousands)
Income taxes computed at federal statutory rate $ 11,822
Reduction in valuation allowance
for net operating loss carryforward (176)
Other (24)
--------
$ 11,622
========
The Company has net operating loss carryforwards of approximately $6.3
million as of December 31, 1997 for income tax reporting purposes which expire
in varying amounts from 2005 to 2010.
(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. For
1995, 1996 and 1997 the Company received management fees from Comstock DR-II of
$87,000, $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 $39,000 and $82,000 in fees for
management and construction services provided to Crosstex in 1995 and 1996,
respectively. In addition, Crosstex reimbursed the Company $104,000 and $228,000
for direct expenses incurred in connection with managing Crosstex in 1995 and
1996, respectively. The Company paid $158,000 and $477,000 to Crosstex for
transportation of its natural gas production in 1995 and 1996, respectively.
(12) Price Risk Management
The Company periodically uses derivative financial instruments to manage
natural gas price risk. The Company's realized gains and losses attributable to
its price risk management activities are as follows:
1995 1996 1997
---- ---- ----
(In thousands)
Realized Gains $ 913 $ 509 $ -
Realized Losses 28 1,643 -
As of December 31, 1996 and 1997, the Company had no open derivative
financial instruments held for price risk management.
(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.
F-16
Income for discontinued gas gathering, processing and marketing operations
included in the Consolidated Statements of Operations is comprised of the
following:
Year Ended December 31,
1995 1996
---- ----
(In thousands)
Revenues $ 50,713 $ 85,398
Operating costs (49,118) (83,168)
Depreciation, depletion and amortization (234) (373)
General and administrative, net (686) (809)
Gain on sales of property 2,589 -
Gain on disposal of segment - 818
Provision for income taxes - -
-------- --------
Income from discontinued operations $ 3,264 $ 1,866
======== ========
(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
========= ========= ========= ========= ========
1996 -
Total revenues............................. $ 9,628 $ 17,890 $ 19,943 $ 23,494 $ 70,955
========= ========= ========= ========= ========
Net income attributable to common stock
from continuing operations............... $ 1,922 $ 6,258 $ 6,590 $ 9,296 $ 24,066
Net income from discontinued operations.... 454 135 253 1,024 1,866
--------- --------- --------- --------- --------
Net income attributable to common stock.... $ 2,376 $ 6,393 $ 6,843 $ 10,320 $ 25,932
========= ========= ========= ========= ========
Basic net income per share:
Continuing operations.................... $ 0.15 $ 0.46 $ 0.42 $ 0.48 $ 1.56
Discontinued operations.................. 0.03 0.01 0.01 0.05 0.12
--------- --------- --------- --------- --------
Net income per share..................... $ 0.18 $ 0.47 $ 0.43 $ 0.53 $ 1.68
========= ========= ========= ========= ========
Diluted net income per share:
Continuing operations.................... $ 0.13 $ 0.33 $ 0.33 $ 0.42 $ 1.23
Discontinued operations.................. 0.02 0.01 0.02 0.04 0.09
--------- --------- --------- --------- --------
Net income per share..................... $ 0.15 $ 0.34 $ 0.35 $ 0.46 $ 1.32
========= ========= ========= ========= ========
F-17
(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 at December 31, 1996 and 1997 were as
follows: $24.61 and $17.24 per barrel for oil in 1996 and 1997, respectively,
and $3.84 and $2.64 per Mcf for natural gas in 1996 and 1997, respectively.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures. Oil and gas reserve engineering must be recognized as
a subjective process of estimating underground accumulations of oil and gas that
cannot be measured in an exact way, and estimates of other engineers might
differ materially from those shown below. The accuracy of any reserve estimate
is a function of the quality of available data and engineering and geological
interpretation and judgment. Results of drilling, testing and production after
the date of the estimate may justify revisions. Accordingly, reserve estimates
are often materially different from the quantities of oil and gas that are
ultimately recovered. Reserve estimates are integral in management's analysis of
impairments of oil and gas properties and the calculation of depreciation,
depletion and amortization on those properties.
The following unaudited table sets forth proved oil and gas reserves at
December 31, 1995, 1996 and 1997:
1995 1996 1997
---- ---- ----
Oil Gas Oil Gas Oil Gas
(MBbls) (MMcf) (MBbls) (MMcf) (MBbls) (MMcf)
------- ------ ------- ------ ------- ------
Proved Reserves:
Beginning of year 5,119 92,840 3,779 173,165 8,994 234,444
Revisions of previous
estimates (2,843) (18,810) 243 (5,926) (1,202) (7,398)
Extensions and discoveries - - 613 551 263 5,566
Purchases of minerals
in place 1,859 108,432 5,930 100,446 14,473 39,970
Sales of minerals in place - - (619) (14,365) (258) (9,605)
Production (356) (9,297) (952) (19,427) (1,343) (22,860)
------- ------- ------- ------- ------- -------
End of year 3,779 173,165 8,994 234,444 20,927 240,117
======= ======= ======= ======= ======= =======
Proved Developed Reserves:
Beginning of year 1,504 62,827 2,562 130,375 6,953 187,247
======= ======= ======= ======= ======= =======
End of year 2,562 130,375 6,953 187,247 16,635 188,102
======= ======= ======= ======= ======= =======
F-18
The following table sets forth the standardized measure of discounted
future net cash flows relating to proved reserves at December 31, 1996 and 1997:
1996 1997
---- ----
(In thousands)
Cash Flows Relating to Proved Reserves:
Future Cash Flows $ 1,120,601 $ 993,812
Future Costs:
Production (202,722) (217,637)
Development (47,548) (66,418)
Future Net Cash Flows Before Income Taxes 870,331 709,757
Future Income Taxes (239,065) (128,983)
Future Net Cash Flows 631,266 580,774
10% Discount Factor (240,844) (162,498)
----------- -----------
Standardized Measure of Discounted
Future Net Cash Flows $ 390,422 $ 418,276
=========== ===========
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, 1995, 1996 and 1997:
1995 1996 1997
---- ---- ----
(In thousands)
Standardized Measure, Beginning of Year $ 78,481 $ 146,506 $ 390,422
Net Change in Sales Price, Net of Production Costs 9,450 132,094 (188,079)
Development Costs Incurred During the Year Which
Were Previously Estimated 822 5,934 10,740
Revisions of Quantity Estimates (30,298) (7,612) (16,779)
Accretion of Discount 7,874 14,829 50,292
Changes in Future Development Costs 13,248 (5,801) (3,919)
Changes in Timing and Other (2,590) (13,165) (20,347)
Extensions and Discoveries - 9,216 6,233
Purchases of Reserves In Place 85,706 282,150 205,583
Sales of Reserves In Place - (10,342) (16,450)
Sales, Net of Production Costs (14,664) (55,077) (70,636)
Net Changes in Income Taxes (1,523) (108,310) 71,216
--------- --------- ---------
Standardized Measure, End of Year $ 146,506 $ 390,422 $ 418,276
========= ========= =========
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 (the "1995 Form 10-K").
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 1995 Form 10-K).
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 1995 Form 10-K).
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 1995 Form 10-K).
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).
E-1
INDEX TO EXHIBITS
Exhibit No. Description Page
- ----------- ------------------------------------------------------- -------
10.1(a)* Credit Agreement dated as of December 9, 1997, between E-4
the Company, the Banks Party thereto and The First
National Bank of Chicago, as agent and Bank One, Texas,
N.A., as Documentation Agent.
10.2# Employment Agreement dated May 15, 1997, by and between
the Company and M. Jay Allison (incorporated herein by
reference to Exhibit 10.2 to the Company's Quarterly
Report on Form 10-Q for the quarter ended June 30,
1997).
10.3# Employment Agreement dated May 15, 1997, by and between
the Company and Roland O. Burns (incorporated herein by
reference to Exhibit 10.3 to the Company's Quarterly
Report on Form 10-Q for the quarter ended June 30,
1997).
10.4# Change in Control Employment Agreement dated May 15,
1997 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 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).
E-2
INDEX TO EXHIBITS
Exhibit No. Description Page
- ----------- -------------------------------------------------------- -------
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 E-57
between the Company and Bois d' Arc Resources.
10.11* Joint Exploration Agreement, dated December 8, 1997 by E-67
and between the Company and Bois d' Arc Resources.
10.12 Lease Agreement, dated as of December 20, 1994, by and
between the Company and Occidental Tower Corporation
(incorporated herein by reference to Exhibit 10.19 to
the Company's Annual Report on Form 10-K for the year
ended December 31, 1994).
10.13 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-72
23* Consent of Arthur Andersen LLP. E-73
27* Financial Data Schedule for the twelve months ended E-74
December 31, 1997.
*Filed herewith.
# Management contract or compensatory plan document.
E-3