Back to GetFilings.com
UNITED STATES 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, 2002
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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)
5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034
(Address of principal executive offices including zip code)
(972) 668-8800
(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 ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes x No
---
As of March 26, 2003, there were 28,919,561 shares of common stock
outstanding.
As of June 30, 2002, the aggregate market value of the voting stock held by
non-affiliates of the registrant was approximately $215.0 million.
DOCUMENTS INCORPORATED BY REFERENCE
Proxy statement for the 2003 annual meeting of stockholders - Part III
COMSTOCK RESOURCES, INC.
ANNUAL REPORT ON FORM 10-K
For the Fiscal Year Ended December 31, 2002
CONTENTS
Item Page
- ---------- Part I -----
Forwarding Looking Statements................................... 2
Definitions..................................................... 2
Introductory Note............................................... 5
1. and 2. Business and Properties......................................... 5
3. Legal Proceedings............................................... 21
4. Submission of Matters to a Vote of Security Holders............. 21
Part II
5. Market for Registrant's Common Equity and Related
Stockholder Matters..................................... 22
6. Selected Financial Data......................................... 23
7. Management's Discussion and Analysis of Financial
Condition and Results of Operations..................... 24
7 A. Operations Quantitative and Qualitative Disclosures
About Market Risks...................................... 33
8. Financial Statements............................................ 35
9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure..................... 35
Part III
10. Directors and Executive Officers of the Registrant.............. 36
11. Executive Compensation.......................................... 36
12. Security Ownership of Certain Beneficial Owners
and Management.......................................... 36
13. Certain Relationships and Related Transactions.................. 36
14. Controls and Procedures......................................... 36
Part IV
15. Exhibits and Reports on Form 8-K................................ 37
1
FORWARD-LOOKING STATEMENTS
This report includes "forward-looking statements" within the meaning of Section
27A of the Securities Act of 1933, as amended, and Section 21E of the Securities
Exchange Act of 1934, as amended. 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, our financial
position, oil and natural gas reserve estimates, business strategy and other
plans and objectives for future operations, are forward-looking statements.
Although we believe that the expectations reflected in such forward-looking
statements are reasonable, we can give no assurance that such expectations will
prove to have been correct. There are numerous uncertainties inherent in
estimating quantities of proved oil and natural gas reserves and in projecting
future rates of production and timing of development expenditures, including
many factors beyond our control. Reserve engineering is a subjective process of
estimating underground accumulations of oil and natural gas that cannot be
precisely measured. Furthermore, the accuracy of any reserve estimate is a
function of the quality of available data and of engineering and geological
interpretation and judgment. As a result, estimates made by different engineers
often vary from one another. In addition, results of drilling, testing and
production subsequent to the date of an estimate may justify revisions of such
estimate and such revision, if significant, would change the schedule of any
further production and development drilling. Accordingly, reserve estimates are
generally different from the quantities of oil and gas that are ultimately
recovered. Should one or more of these risks or uncertainties occur, or should
underlying assumptions prove incorrect, our actual results and plans for 2003
and beyond could differ materially from those expressed in forward-looking
statements. All subsequent written and oral forward-looking statements
attributable to us or persons acting on our behalf are expressly qualified in
their entirety by such factors.
DEFINITIONS
The following are abbreviations and definitions of terms commonly used in
the oil and gas industry and this report. Natural gas equivalents and crude oil
equivalents are determined using the ratio of six Mcf to one barrel. All
references to "us," "our," "we" or "Comstock" mean the registrant, Comstock
Resources, Inc. and where applicable, its consolidated subsidiaries.
"Bbl" means a barrel of 42 U.S. gallons of oil.
"Bcf" means one billion cubic feet of natural gas.
"Bcfe" means one billion cubic feet of natural gas equivalent.
"Btu" means British thermal unit, which is the quantity of heat required to
raise the temperature of one pound of water from 58.5 to 59.5 degrees
Fahrenheit.
"Cash Margin per Mcfe" means the equivalent price per Mcfe less oil and gas
operating expenses per Mcfe and general and administrative expenses per Mcfe.
"Completion" means the installation of permanent equipment for the
production of oil or gas.
"Condensate" means a hydrocarbon mixture that becomes liquid and separates
from natural gas when the gas is produced and is similar to crude oil.
2
"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 we or another specified person has a
working interest.
"MBbls" means one thousand barrels of oil.
"MBbls/d" means one thousand barrels of oil per day.
"Mcf" means one thousand cubic feet of natural gas.
"Mcfe" means thousand cubic feet of natural gas equivalent.
"MMBbls" means one million barrels of oil.
"MMcf" means one million cubic feet of natural gas.
"MMcf/d" means one million cubic feet of natural gas per day.
"MMcfe/d" means one million cubic feet of natural gas equivalent per day.
"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 us.
"Net production" means production we own less royalties and production due
others.
"Oil" means crude oil or condensate.
"Operator" means the individual or company responsible for the exploration,
development, and production of an oil or gas well or lease.
"Present Value of Proved Reserves" means the present value of estimated
future revenues to be generated from the production of proved reserves
calculated in accordance with the Securities and Exchange Commission guidelines,
net of estimated production and future development costs, using prices and costs
as of the date of estimation without future escalation, without giving effect to
non-property related expenses such as general and administrative expenses, debt
service, future income tax expense and depreciation, depletion and amortization,
and discounted using an annual discount rate of 10%.
3
"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.
"Proved undeveloped reserves" means reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
"Recompletion" means the completion for production of an existing well bore
in another formation from which the well has been previously completed.
"Reserve life" means the calculation derived by dividing year-end reserves
by total production in that year.
"Reserve replacement" means the calculation derived by dividing additions
to reserves from acquisitions, extensions, discoveries and revisions of previous
estimates in a year by total production in that year.
"Royalty" means an interest in an oil and gas lease that gives the owner of
the interest the right to receive a portion of the production from the leased
acreage (or of the proceeds of the sale thereof), but generally does not require
the owner to pay any portion of the costs of drilling or operating the wells on
the leased acreage. Royalties may be either landowner's royalties, which are
reserved by the owner of the leased acreage at the time the lease is granted, or
overriding royalties, which are usually reserved by an owner of the leasehold in
connection with a transfer to a subsequent owner.
"3-D seismic" means an advanced technology method of detecting
accumulations of hydrocarbons identified by the collection and measurement of
the intensity and timing of sound waves transmitted into the earth as they
reflect back to the surface.
"Working interest" means an interest in an oil and gas lease that gives the
owner of the interest the right to drill for and produce oil and gas on the
leased acreage and requires the owner to pay a share of the costs of drilling
and production operations. The share of production to which a working interest
owner is entitled will always be smaller than the share of costs that the
working interest owner is required to bear, with the balance of the production
accruing to the owners of royalties. For example, the owner of a 100% working
interest in a lease burdened only by a landowner's royalty of 12.5% would be
required to pay 100% of the costs of a well but would be entitled to retain
87.5% of the production.
"Workover" means operations on a producing well to restore or increase
production.
4
PART I
INTRODUCTORY NOTE
Subsequent to the issuance of our Annual Report for the year ended December
31, 2001, we determined that certain outstanding advances made by us to our
partner under our joint exploration venture in the Gulf of Mexico for seismic
data acquisition should have been charged to exploration expense rather than
reflected on the balance sheet as an asset. As a result of changing our
accounting treatment for the advances used for seismic data acquisition, we
determined that our financial statements for 1998, 1999, 2000 and 2001 should be
restated. The effect of the restatement is a reduction to previously reported
net income by $0.4 million, $0.3 million, $0.2 million and $1.6 million for the
years 1998, 1999, 2000 and 2001, respectively, as a result of the additional
exploration expense in each year. These changes primarily affect the timing of
our recognition of exploration expense. As reimbursements are received for the
advances we have made, our future exploration expense will be reduced. In
addition, we have reclassified our Series 1999 Preferred Stock from
stockholders' equity at December 31, 2001 to temporary equity. Please see
"Restatement of Previously Issued Financial Statements" in Item 7 of this Annual
Report and Note 13 to our Consolidated Financial Statements filed as part of
this Annual Report.
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
We are an independent energy company engaged in the acquisition,
development, production and exploration of oil and natural gas properties. Our
oil and natural gas operations are concentrated in the Gulf of Mexico, East
Texas / North Louisiana, Southeast Texas and South Texas regions. In addition,
we have properties in the Illinois Basin region in Kentucky and in the
Mid-Continent regions located in the Texas panhandle, Oklahoma and Kansas. Our
oil and natural gas properties are estimated to have proved reserves of 613.9
Bcfe with an estimated Present Value of Proved Reserves of $1.3 billion as of
December 31, 2002. Our proved oil and natural gas reserve base is 80% natural
gas and 66% proved developed on a Bcfe basis as of December 31, 2002.
Our proved reserves at December 31, 2002 and our 2002 average daily
production are summarized below:
Reserves at December 31, 2002 2002 Daily Production
--------------------------------- ----------------------------------------
% of % of
Oil Gas Total Total Oil Gas Total Total
-------- ------ ------- ----- -------- -------- -------- ------
(MMBbls) (Bcf) (Bcfe) (MBbls/d) (MMcf/d) (MMcfe/d)
Gulf of Mexico........... 15.6 96.1 189.7 30.9 2.2 20.7 33.6 29.8
East Texas /
North Louisiana 1.1 182.0 188.5 30.7 0.3 32.4 34.2 30.4
Southeast Texas.......... 3.1 107.1 125.5 20.4 0.9 24.3 29.5 26.2
South Texas.............. 0.7 47.0 51.3 8.4 0.1 6.5 7.0 6.2
Other Regions............ 0.3 56.6 58.9 9.6 0.1 7.2 8.3 7.4
------ ------ ------ ----- ---- ----- ------ ------
Total.............. 20.8 488.8 613.9 100.0% 3.6 91.1 112.6 100.0%
====== ====== ====== ===== ==== ===== ====== ======
Strengths
Quality Properties. Our operations are focused in four geographically
concentrated areas, the Gulf of Mexico, East Texas / North Louisiana, Southeast
Texas and South Texas regions, which account for approximately 31%, 31%, 20% and
8% of our proved reserves, respectively. We have high price realizations
relative to benchmark prices for natural gas and crude oil production. We also
have favorable operating costs which results in us having high cash margins.
Finally, our properties have an average reserve life of approximately 15.0 years
and have extensive development and exploration potential.
5
Successful Exploration and Development Program. In 2002, we spent $35.3
million on the exploitation and development of our oil and natural gas
properties for development drilling, recompletions, workovers and production
facilities. Overall, we drilled 27 development wells, 11.7 net to us, with a 96%
success rate. We also had a successful exploratory drilling program in 2002,
spending a total of $31.1 million to drill 20 wells, 7.6 net to us, with a 75%
success rate. We spent an additional $4.3 million in acquiring new acreage in
2002 to support our exploration program.
Successful Acquisitions. We have had significant growth over the years as a
result of acquisitions. Since 1991, we have added 711.7 Bcfe of proved oil and
natural gas reserves from 29 acquisitions at an average cost of $0.84 per Mcfe.
Our application of strict economic and reserve risk criteria have enabled us to
successfully evaluate and integrate acquisitions.
Efficient Operator. We operate 60% of our proved oil and natural gas
reserve base as of December 31, 2002. This allows us to control operating costs,
the timing and plans for future development, the level of drilling and lifting
costs and the marketing of production. As an operator, we receive reimbursements
for overhead from other working interest owners, which reduces our general and
administrative expenses.
High Price Realizations. The majority of our wells are located in areas
which can access attractive natural gas and crude oil markets. In addition, our
natural gas production has a relatively high Btu content of approximately 1,079
Btu. Our crude oil production has a favorable API gravity of approximately 40
degrees. Due to these factors, we have relatively high price realizations
compared to benchmark prices. In 2002 our average natural gas price, before
gains from hedging activities, was $3.26 per Mcf, which represented a $0.04
premium to the 2002 NYMEX average monthly settlement price. Also in 2002, our
average crude oil price was $24.95 per barrel, which represented a $2.04 barrel
premium to the average monthly West Texas Intermediate crude oil price for 2002
posted by Koch Industries,Inc.
High Cash Margins. As a result of our quality properties, higher price
realizations and efficient operations, we have higher cash margins.
Consequently, our oil and natural gas reserves have a higher value per Mcfe than
reserves that generate lower cash margins.
Business Strategy
Exploit Existing Reserves. We seek to maximize the value of our oil and
natural gas properties by increasing production and recoverable reserves through
active workover, recompletion and exploitation activities. We utilize advanced
industry technology, including 3-D seismic data, improved logging tools, and
formation stimulation techniques. During 2002, we spent approximately $22.9
million to drill 27 development wells, 11.7 net to us, of which 26 wells, 10.7
net to us, were successful, representing a success rate of 96%. In addition, we
spent approximately $12.4 million for new production facilities, leasehold costs
and for recompletion and workover activities. For 2003, we have budgeted $49.0
million for development drilling and for workover and recompletion activity.
Pursue Exploration Opportunities. We conduct exploration activities to grow
our reserve base and to replace our production each year. In 2002 we replaced
131% of our 2002 production from new discoveries. In 2002, we spent
approximately $31.1 million to drill 20 exploratory wells, 7.6 net to us, of
which 15 wells, 5.3 net to us, were successful, representing a success rate of
75%. We also spent $4.3 million in acquiring new acreage in 2002 to support our
exploration program. We have budgeted $51.0 million in 2003 for exploration
activities which will be focused primarily in the Gulf of Mexico, Southeast
Texas and South Texas regions.
6
Maintain Low Cost Structure. We seek to increase cash flow by carefully
controlling operating costs and general and administrative expenses. Our average
oil and gas operating costs per Mcfe were $0.82 in 2002 and our general and
administrative expenses per Mcfe averaged only $0.12 in 2002.
Acquire High Quality Properties at Attractive Costs. We have a successful
track record of increasing our oil and natural gas reserves through
opportunistic acquisitions. Since 1991, we have added 711.7 Bcfe of proved oil
and natural gas reserves from 29 acquisitions at a total cost of $598.3 million,
or $0.84 per Mcfe. The acquisitions were acquired at an average of 63% of their
Present Value of Proved Reserves in the year the acquisitions were completed. We
apply strict economic and reserve risk criteria in evaluating acquisitions. We
target properties in our core operating areas with established production and
low operating costs that also have potential opportunities to increase
production and reserves through exploration and exploitation activities.
Maintain Flexible Capital Expenditure Budget. The timing of most of our
capital expenditures is discretionary because we have not made any significant
long-term capital expenditure commitments. Consequently, we have a significant
degree of flexibility to adjust the level of such expenditures according to
market conditions. We anticipate spending approximately $100.0 million on
development and exploration projects in 2003. We intend to primarily use
operating cash flow to fund our drilling expenditures in 2003. We may also make
additional property acquisitions in 2003 that would require additional sources
of funding. Such sources may include borrowings under our bank credit facility
or sales of our equity or debt securities.
7
Primary Operating Areas
Our activities are concentrated in four primary operating areas: Gulf of
Mexico, East Texas / North Louisiana, Southeast Texas and South Texas. The
following table summarizes the estimated proved oil and natural gas reserves for
our 20 largest fields as of December 31, 2002.
Present
Value of
Net Oil Net Gas Proved
(MBbls) (MMcf) MMcfe % Reserves %
-------- --------- --------- ------- ---------- -------
Gulf of Mexico (in thousands)
Ship Shoal.................... 8,696 36,448 88,626 $ 208,146
South Timbalier / South Pelto. 4,371 51,918 78,143 224,288
Main Pass..................... 1,359 1,991 10,148 24,017
East White Point.............. 750 2,107 6,605 8,517
Other......................... 410 3,685 6,144 17,565
-------- --------- --------- ----------
15,586 96,149 189,666 30.9 482,533 37.7
-------- --------- --------- ----------
East Texas / North Louisiana
Gilmer........................ 399 64,377 66,769 124,434
Beckville..................... 116 46,126 46,821 78,350
Logansport.................... 43 15,268 15,523 30,742
Waskom........................ 210 13,186 14,446 24,275
Blocker....................... 42 11,324 11,576 17,813
Box Church.................... 4 6,408 6,430 11,565
Ada........................... 5 6,003 6,033 14,955
Other......................... 257 19,319 20,869 42,582
-------- --------- --------- ----------
1,076 182,011 188,467 30.7 344,716 26.9
-------- --------- --------- ----------
Southeast Texas
Double A Wells................ 2,840 97,973 115,012 259,388
Sugar Creek................... 95 8,584 9,155 13,400
Other......................... 135 553 1,361 3,517
-------- --------- --------- ----------
3,070 107,110 125,528 20.4 276,305 21.6
-------- --------- --------- ----------
South Texas
J. C. Martin.................. -- 18,383 18,383 34,995
North Markham................. 474 13,432 16,277 35,825
Ball Ranch.................... 80 5,368 5,847 13,940
Lopeno........................ 39 4,748 4,981 6,859
Other......................... 131 5,045 5,835 10,975
-------- --------- --------- ----------
724 46,976 51,323 8.4 102,594 8.0
-------- --------- --------- ----------
Illinois Basin
New Albany Shale Gas.......... -- 35,486 35,486 5.8 32,578 2.5
-------- --------- --------- ----------
Mid-Continent
Glick......................... 8 5,890 5,935 9,499
N. E. Moorewood............... 17 4,990 5,090 9,215
Other......................... 155 7,070 8,005 14,733
-------- --------- --------- ----------
180 17,950 19,030 3.1 33,447 2.6
-------- --------- --------- ----------
Other Areas................... 213 3,102 4,379 0.7 8,120 0.7
-------- --------- --------- ------ ---------- ------
Total 20,849 488,784 613,879 100.0 $1,280,293 100.0
======== ========= ========= ====== ========== ======
8
Gulf of Mexico
Our Gulf of Mexico operating region includes properties located offshore of
Louisiana and Texas, in state and federal waters of the Gulf of Mexico. We own
interests in 108 producing wells, 47.5 net to us, in nine field areas, the
largest of which are the Ship Shoal area (Ship Shoal Blocks 66, 67, 68, 69, 99,
107, 113 and 146 and South Pelto Block 1), and the South Timbalier / South Pelto
area (South Timbalier Blocks 11, 16, 34, 50 and South Pelto Blocks 5 and 15). We
have 189.7 Bcfe of oil and natural gas reserves in the Gulf of Mexico region
which represents 31% of our reserve base. We operate 46 of the wells that we own
in this region. Production from the region averaged 20.7 MMcf of natural gas per
day and 2,158 barrels of oil per day during 2002. We spent $5.3 million in this
region in 2002 drilling three development wells, 1.2 net to us, and $21.7
million drilling 8 exploratory wells, 3.0 net to us. We also spent $8.7 million
for production facilities, recompletions and workovers. In 2003, we plan to
spend $54.0 million for development and exploration activities in this region.
Ship Shoal
The Ship Shoal area is located in Louisiana state waters and in federal
waters, offshore of Terrebonne Parish. In the this area, oil and natural gas are
produced from numerous Miocene sands occurring at depths from 5,800 to 13,500
feet, and in water depths from 10 to 60 feet. We own interests in 50 wells in
this area, 27.1 net to us, in Ship Shoal Blocks 66, 67, 68, 69, 99, 107, 113 and
146 and in South Pelto Block 1. We operate 38 of these wells. Our properties in
the Ship Shoal area have estimated proved reserves of 88.6 Bcfe, which is 14% of
our total reserves. Production from the Ship Shoal area net to our interest
averaged 2.1 MMcf of natural gas per day and 1,110 barrels of oil per day during
2002. We drilled two exploratory wells at Ship Shoal in 2002. One was successful
and one was a dry hole.
South Timbalier / South Pelto
We own interests in 21 producing wells, 6.4 net to us, in Louisiana state
waters and in federal waters in the South Timbalier / South Pelto area located
offshore of Terrebonne and Lafourche Parishes in water depths ranging from 20 to
60 feet. We have estimated proved reserves totaling 78.1 Bcfe attributable to
this area which is 13% of our total reserves. Production attributable to our
interest averaged 14.5 MMcf of natural gas per day and 506 barrels of oil per
day in 2002. These wells produce from numerous sands of Pliocene to Upper
Miocene age, at depths ranging from 2,000 to 12,000 feet as well as a
geopressured Miocene section at a depth below 16,000 feet. We drilled seven
wells in the South Timbalier / South Pelto area in 2002. Six of these wells were
successful with one exploratory dry hole.
East Texas / North Louisiana
Approximately 31% or 188.5 Bcfe of our proved reserves are located in East
Texas and North Louisiana where we own interests in 415 producing wells, 229.7
net to us, in 21 field areas. We operate 241 of these wells. The largest of our
fields in this region are the Gilmer, Beckville, Logansport, Waskom and Blocker
fields. Production from this region averaged 32.4 MMcf of natural gas per day
and 287 barrels of oil per day during 2002. Most of the reserves in this area
produce from the Cretaceous aged Travis Peak/Hosston formation and the Jurassic
aged Cotton Valley formation. The total thickness of these formations range from
2,000 to 4,000 feet of sand, shale and limestone sequences in the East Texas
Basin and the North Louisiana Salt Basin, at depths ranging from 6,000 to 12,000
feet. In 2002 we spent $16.7 million drilling 18 wells, 7.0 net to us, and $0.8
million on workovers and recompletions in this region. We have budgeted
approximately $8.0 million in 2003 for development activities in this region.
9
Gilmer
We own interests in 70 natural gas wells, 26.6 net to us, in the Gilmer
field in Upshur County in East Texas. These wells produce from the Cotton Valley
Lime formation at a depth of approximately 11,500 feet to 12,000 feet. Proved
reserves attributable to our interests in the Gilmer field are 66.8 Bcfe which
represents 11% of our total reserve base. During 2002 production attributable to
our interest from this field averaged 11.9 MMcf of natural gas per day and 142
barrels of oil per day. In 2002, we drilled 15 sucessful development wells at
Gilmer, 5.7 net to us.
Beckville
Our properties in the Beckville field, located in Panola and Rusk Counties,
Texas, have proved reserves of 46.8 Bcfe which represents approximately 8% of
our total reserves. We operate 72 wells in this field and own interests in four
additional wells for a total of 76 wells, 55.6 net to us. During 2002,
production attributable to our interest from this field averaged 7.9 MMcf of
natural gas per day and 10 barrels of oil per day. The Beckville field produces
from the Cotton Valley formation at depths ranging from 9,000 to 10,000 feet.
Logansport
The Logansport field produces from multiple sands in the Hosston formation
at an average depth of 8,000 feet and is located in DeSoto Parish, Louisiana.
Our proved reserves of 15.5 Bcfe in the Logansport field represents
approximately 3% of our total reserves. We own interests in 82 wells, 38.6 net
to us, and operate 48 of these wells. During 2002, net daily production
attributable to our interest from this field averaged 3.1 MMcf of natural gas
and 17 barrels of oil.
Waskom
The Waskom field, located in Harrison and Panola Counties in Texas,
represented approximately 2% (14.4 Bcfe) of our proved reserves as of December
31, 2002. We own interests in 52 wells in this field, 26.7 net to us, and
operate 29 wells in this field. During 2002, net daily production attributable
to our interest averaged 1.0 MMcf of natural gas and 22 barrels of oil. The
Waskom field produces from the Cotton Valley formation at depths ranging from
9,000 to 10,000 feet.
Blocker
We own interests in 26 wells, 25.2 net to us, in the Blocker field in
Harrison County, Texas and we operate 25 of these wells. These wells produce
primarily from the Cotton Valley formation from depths ranging from 8,600 feet
to 10,000 feet and the Pettit and Travis Peak formations from depths of 6,000
feet to 7,800 feet. At December 31, 2002, we had 11.6 Bcfe of proved reserves in
this field. Production from this field attributable to our interest averaged 2.9
MMcf of natural gas and 14 barrels of oil per day in 2002.
Southeast Texas
Approximately 20% or 125.5 Bcfe of our proved reserves are located in
Southeast Texas, where we own interests in 86 producing wells, 49.8 net to us,
and operate 59 of these wells. Net daily production rates from the area averaged
24.3 MMcf of natural gas and 871 barrels of oil during 2002. We spent $4.3
million in the Southeast Texas region in 2002 drilling three exploratory wells,
1.7 net to us. In 2003, we plan to spend $14.0 million for development and
exploration activities in this region. Substantially all of the reserves in this
region are in the Double A Wells field area in Polk County, Texas.
10
Double A Wells
The Double A Wells field is our largest field area with total estimated
proved reserves of 115.0 Bcfe, which is 19% of our total reserves. We own
interests in and operate 57 producing wells, 28.6 net to us, in this field in
Polk County, Texas. Net daily production from Double A Wells area averaged 22.2
MMcf of natural gas and 791 barrels of oil during 2002. These wells typically
produce from the Woodbine formation at an average depth of 14,300 feet. In 1999,
we began a redevelopment program in this field based on our interpretation of
3-D seismic data and drilled 19 successful wells from 1999 to 2001. In 2002 we
extended the reserves to the south with two successful exploratory wells. The
first discovery well is currently producing from a depth of about 14,700 feet.
The other successful well also found productive pay in the Woodbine formation
and is awaiting pipeline connection and completion.
South Texas
Approximately 8% or 51.3 Bcfe of our proved reserves are located in South
Texas, where we own interests in 251 producing wells, 53.5 net to us. We own
interests in seven fields in the region. The largest of which are the J.C.
Martin and the North Markham fields. Net daily production rates from the area
averaged 6.5 MMcf of natural gas and 78 barrels of oil during 2002. We spent
$7.7 million in this region in 2002 primarily to drill eight exploration wells,
2.3 net to us. All but one of these wells were successful. In 2003, we plan to
spend approximately $21.0 million primarily for exploration activity in this
region.
J.C. Martin
Our largest field in South Texas is the J.C. Martin field which is located
in the structurally complex and highly prolific Wilcox Lobo trend in Zapata
County, Texas on the Mexican border. We own interests in 82 wells in this field,
13.1 net to us, with proved reserves of 18.4 Bcfe or 3% of our total reserves.
During 2002, net daily production attributable to our interest from this field
averaged 4.4 MMcf of natural gas. This field produces primarily from Eocene
Wilcox Lobo sands at depths ranging from 7,000 to 9,000 feet. The Lobo section
is characterized by geopressured, multiple pay sands occurring in a highly
faulted area.
North Markham
The North Markham / North Bay City field is located in Matagorda County,
Texas. We own interests in and operate 15 producing wells, 15.0 net to us, in
the Ohio-Sun Unit. We purchased these interests from Marathon Oil Company in
December 2002 and plan to redevelop this field beginning in 2003. The field's
estimated proved reserves of 16.3 Bcfe represent 3% of our total reserves. The
field's active wells produce from more than twenty reservoirs of Oligocene Frio
age at depths ranging from 6,500 to 9,000 feet.
11
Acquisition Activities
Acquisition Strategy
We have concentrated our acquisition activity in the Gulf of Mexico, East
Texas / North Louisiana, Southeast Texas and South Texas regions. Using a
strategy that capitalizes on our knowledge of and experience in these regions,
we seek to selectively pursue acquisition opportunities where we can evaluate
the assets to be acquired in detail prior to completion of the transaction. We
evaluate 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
us to obtain operating control.
Major Property Acquisitions
As a result of our acquisitions, we have added 711.7 Bcfe of proved oil and
natural gas reserves since 1991.
Our largest acquisitions are the following:
DevX Energy Acquisition. In December 2001, we completed the acquisition of
DevX Energy, Inc. ("DevX") by acquiring 100% of the common stock of DevX for
$92.6 million. The total purchase price including debt and other liabilities
assumed in the acquisition was $160.8 million. As a result of the acquisition of
DevX, we acquired interests in 600 producing oil and natural gas wells located
onshore primarily in East and South Texas, Kentucky, Oklahoma and Kansas. Major
fields acquired in the acquisition include the Gilmer field in East Texas and
the J.C. Martin, Ball Ranch and Lopeno fields in South Texas. We also acquired
interests in the New Albany Shale Gas field in Kentucky, the Glick field in
Kansas and the N.E. Moorewood field in Oklahoma in this transaction. DevX's
properties had 1.2 MMBbls of oil reserves and 156.5 Bcf of natural gas reserves
at the time of the acquisition.
Bois d' Arc Acquisition. In December 1997, we acquired working interests in
certain producing offshore Louisiana oil and gas properties as well as interests
in undeveloped offshore oil and natural gas leases for approximately $200.9
million from Bois d' Arc Resources and certain of its affiliates and working
interest partners. We acquired interests in 43 wells, 29.6 net to us, 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 Block
21, Ship Shoal Blocks 66, 67, 68 and 69 and South Pelto Block 1. The net proved
reserves acquired in this acquisition were estimated at 14.3 MMBbls of oil and
29.4 Bcf of natural gas.
Black Stone Acquisition. In May 1996, we 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. We acquired
interests in 19 wells, 7.7 net to us, that were located in the Double A Wells
field in Polk County, Texas and became the operator of most of the wells in the
field. The net proved reserves acquired in this acquisition were estimated at
5.9 MMBbls of oil and 100.4 Bcf of natural gas.
Sonat Acquisition. In July 1995, we purchased interests in certain
producing oil and gas properties located in East Texas and North Louisiana from
Sonat Inc. for $48.1 million. We acquired interests in 319 producing wells,
188.0 net to us. The acquisition included interests in the Beckville,
Logansport, Waskom, and Longwood fields. The net proved reserves acquired in
this acquisition were estimated at 0.8 MMBbls of oil and 104.7 Bcf of natural
gas.
12
Oil and Natural Gas Reserves
The following table sets forth our estimated proved oil and natural gas
reserves and the Present Value of Proved Reserves as of December 31, 2002:
Present
Value of
Proved
Oil Gas Total Reserves
(MBbls) (MMcf) (MMcfe) (000's)
------ ------- ------- ----------
Proved Developed Producing......... 7,030 244,909 287,087 $ 607,970
Proved Developed Non-producing..... 6,907 74,246 115,692 236,722
Proved Undeveloped................. 6,912 169,629 211,100 435,601
------ ------- ------- ----------
Total Proved................. 20,849 488,784 613,879 $1,280,293
====== ======= ======= ==========
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 we acquire properties
containing proved reserves or conduct successful exploration and development
activities, our proved reserves will decline as reserves are produced. Our
future oil and natural gas production is highly dependent upon the level of
success in acquiring or finding additional reserves.
The Present Value of Proved Reserves was determined based on the market
prices for oil and natural gas on December 31, 2002. The market price for our
oil production on December 31, 2002, after basis adjustments, was $30.07 per
barrel as compared to $18.73 per barrel on December 31, 2001. The market price
received for our natural gas production on December 31, 2002, after basis
adjustments, was $5.04 per Mcf as compared to $2.69 per Mcf on December 31,
2001.
13
Drilling Activity Summary
During the three-year period ended December 31, 2002, we drilled
development and exploratory wells as set forth in the table below.
Year Ended December 31,
------------------------------------------------
2000 2001 2002
-------------- ------------- -------------
Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- -----
Development Wells:
Oil................... -- -- 2 .7 -- --
Gas................... 37 19.7 29 16.3 26 10.7
Dry................... -- -- 4 1.8 1 1.0
----- ----- ----- ----- ----- -----
37 19.7 35 18.8 27 11.7
----- ----- ----- ----- ----- -----
Exploratory Wells:
Oil................... 2 1.1 1 .3 2 .8
Gas................... 5 2.2 13 4.5 13 4.5
Dry................... 5 1.5 3 1.1 5 2.3
----- ----- ----- ----- ----- -----
12 4.8 17 5.9 20 7.6
----- ----- ----- ----- ----- -----
Total Wells........ 49 24.5 52 24.7 47 19.3
====== ===== ===== ===== ===== =====
In 2003 to the date of this report, we have drilled seven development
wells, 6.4 net to us, and four exploratory wells, 1.5 net to us. All development
wells were either successful or are still being evaluated by us. Three of the
exploratory wells were successful and one was a dry hole. As of the date of this
report, we have three wells, 0.8 net to us, that are 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 we owned an interest at December 31, 2002.
Oil Gas
------------- -------------
Gross Net Gross Net
----- ---- ----- -----
Colorado....................... -- -- 1 .3
Kansas......................... -- -- 12 4.5
Kentucky....................... -- -- 86 76.4
Louisiana...................... 6 2.3 171 76.3
Mississippi.................... 1 .1 1 .2
Offshore Gulf of Mexico........ 36 17.4 72 30.1
Oklahoma....................... 2 .3 134 16.0
Texas.......................... 109 40.5 497 218.3
Wyoming........................ -- -- 31 2.3
----- ---- ----- -----
Total Wells............. 154 60.6 1,005 424.4
===== ==== ===== =====
We operate 454 of the 1,159 producing wells presented in the above table.
14
Acreage
The following table summarizes our developed and undeveloped leasehold
acreage at December 31, 2002. We have excluded acreage in which our interest is
limited to a royalty or overiding royalty interest.
Developed Undeveloped
----------------- -----------------
Gross Net Gross Net
------- ------- ------- -------
Colorado .............. 320 80 -- --
Kansas ................ 6,400 4,064 -- --
Kentucky .............. 13,689 11,964 9,358 9,199
Louisiana ............. 76,972 56,830 7,415 1,442
Mississippi ........... 1,360 210 -- --
New Mexico ............ -- -- 151,442 66,634
Offshore Gulf of Mexico 92,232 42,471 28,768 11,671
Oklahoma .............. 37,440 5,336 -- --
Texas ................. 220,197 139,346 71,268 30,761
Wyoming ............... 13,440 927 -- --
------- ------- ------- -------
Total ....... 462,050 261,228 268,251 119,707
======= ======= ======= =======
Title to our 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 our oil and natural gas properties are pledged as collateral under our bank
credit facility. As is customary in the oil and gas industry, we are generally
able to retain our 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 us depends on factors beyond
our 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.
All of our oil production is sold at the well site at prices tied to the
spot oil markets. Substantially all of our natural gas production is sold either
on the spot natural gas market under short-term contracts at prevailing spot
market prices or under long-term contracts based on current spot market gas
prices. A portion of the natural gas production from our Double A Wells field is
sold under a long-term contract to Houston Pipe Line Company LP, a subsidiary of
American Electric Power Company, Inc. ("HPL"). The contract with HPL expires on
October 31, 2004 with pricing based on spot natural gas prices for natural gas
delivered to the Houston Ship Channel. Total natural gas sales in 2002 to HPL
accounted for approximately 15% of our total 2002 oil and gas sales. Reliant
Energy Services, Inc. ("Reliant") is another significant purchaser of our
natural gas production accounting for approximately 16% of our total 2002 oil
and gas sales. We discontinued sales to Reliant beginning in November 2002.
15
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 we do. We face intense competition for the
acquisition of oil and natural gas properties.
Regulation
Our 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. We 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 our
business or financial condition.
Our sales of natural gas are not regulated and are made at market prices.
However, the Federal Energy Regulatory Commission regulates interstate and
certain intrastate natural gas transportation rates and service conditions,
which affect the marketing of natural gas produced by us, as well as the
revenues received by us for sales of such production. Since the mid-1980s, the
Federal Energy Regulatory Commission has issued a series of orders, culminating
in Order Nos. 636, 636-A and 636-B, that have significantly altered the
marketing and transportation of natural gas. These regulations mandated a
fundamental restructuring of interstate pipeline sales and transportation
service, including the unbundling by interstate pipelines of the sales,
transportation, storage and other components of the city-gate sales services
such pipelines previously performed. One of the Federal Energy Regulatory
Commission purposes in issuing these regulations was to increase competition
within all phases of the natural gas industry. Generally, these regulatory
orders have eliminated or substantially reduced the interstate pipelines'
traditional role as wholesalers of natural gas and have substantially increased
competition and volatility in natural gas markets.
Our sales of oil and natural gas liquids are not regulated and are made at
market prices. The price we receive from the sale of these products is affected
by the cost of transporting the products to market.
Our 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 our cost of doing business and affects our profitability. Because such
rules and regulations are frequently amended or reinterpreted, we are unable to
predict the future cost or impact of complying with such laws.
Most of the states in which we operate require permits for drilling
operations, drilling bonds and the filing of reports concerning operations and
impose other requirements relating to the exploration and production of oil and
gas. These states also have statutes or regulations addressing conservation
matters, including provisions for the unitization or pooling of oil and natural
gas properties, the establishment of maximum rates of production from oil and
gas wells and the regulation of spacing, plugging and abandonment of such wells.
The statutes and regulations of certain states limit the rate at which oil and
gas can be produced from our properties.
We are required to comply with various federal and state regulations
regarding plugging and abandonment of oil and natural gas wells. We provide
reserves for the estimated costs of plugging and abandoning our wells, to the
extent such costs exceed the estimated salvage value of the wells, on a unit of
production basis.
16
Environmental Regulation
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 our operations and
costs. These laws and regulations sometimes require governmental authorization
before conducting certain activities, limit or prohibit other activities because
of protected areas or species, create the possibility of substantial liabilities
for pollution related to our operations or properties and provide penalties for
noncompliance. In particular, our drilling and production operations, our
activities in connection with storage and transportation of crude oil and other
liquid hydrocarbons and its use of facilities for treating, processing or
otherwise handling hydrocarbons and related exploration and production wastes
are subject to stringent environmental regulation. As with the industry in
general, compliance with existing and anticipated regulations increases our
overall cost of business. While these regulations affect our capital
expenditures and earnings, we believe that such regulations do not affect our
competitive position in the industry because our competitors are similarly
affected by environmental regulatory programs. Environmental regulations have
historically been subject to frequent change and, therefore, we cannot predict
with certainty the future costs or other future impacts of environmental
regulations on our future operations. A discharge of hydrocarbons or hazardous
substances into the environment could subject us 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 us and our operations.
Water. The Oil Pollution Act was enacted in 1990 and amends provisions of
the Federal Water Pollution Control Act of 1972 and other statutes as they
pertain to the prevention of and response to major oil spills. The Oil Pollution
Act subjects owners of facilities to strict, joint and potentially unlimited
liability for removal costs and certain other consequences of an oil spill along
shorelines or that enters navigable waters. In the event of an oil spill into
such waters, substantial liabilities could be imposed upon us. Recent
regulations developed under the Oil Pollution Act require companies that own
offshore facilities, including us, to demonstrate oil spill financial
responsibility for removal costs and damage caused by oil discharge. States in
which we operate have also enacted similar laws. Regulations are currently being
developed under the Oil Pollution Act and similar state laws that may also
impose additional regulatory burdens upon us.
The Federal Water Pollution Control Act 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 Federal Water Pollution Control Act provides for
civil, criminal and administrative penalties for any unauthorized discharges
and, along with the Oil Pollution Act, 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 Oil
Pollution Act and the Federal Water Pollution Control Act have not historically
been material to our operations, but there can be no assurance that changes in
federal, state or local water pollution control programs will not materially
adversely affect us in the future. Although no assurances can be given, we
believe that compliance with existing permits and compliance with foreseeable
new permit requirements will not have a material adverse effect on our financial
condition or results of operations.
17
Air Emissions. The Federal Clean Air Act and comparable state programs
require many industrial operations in the United States to incur capital
expenditures in order to meet air emissions control standards developed by the
United States Environmental Protection Agency (the "EPA") and state
environmental agencies. Although no assurances can be given, we believe that
compliance with the Clean Air Act and comparable state laws will not have a
material adverse effect on our financial condition or results of operations.
Solid Waste. We generate non-hazardous solid wastes that are subject to the
requirements of the Federal Resource Conservation and Recovery Act and
comparable state statutes. The EPA and the states in which we operate are
considering the adoption of stricter disposal standards for the type of
non-hazardous wastes generated by us. The Resource Conservation and Recovery Act
also governs the generation, management, and disposal of hazardous wastes. At
present, we are not required to comply with a substantial portion of the
requirements under this law because our operations generate minimal quantities
of hazardous wastes. However, it is possible that additional wastes, which could
include wastes currently generated during our 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 us.
Superfund. The Comprehensive Environmental Response, Compensation, and
Liability Act 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. Superfund 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, we may have managed substances that may fall within Superfund's
definition of a "hazardous substance." Therefore, we may be jointly and
severally liable under the Superfund for all or part of the costs required to
clean up sites where we disposed of or arranged for the disposal of these
substances. This potential liability extends to properties that we previously
owned or operated, as well as to properties owned and operated by others at
which disposal of our hazardous substances occurred.
We currently own or lease numerous properties that for many years have been
used for the exploration and production of oil and gas. Although we believe we
have 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 us on or under the properties owned or leased by us. 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 Superfund and analogous state laws, we 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
Our executive offices are located at 5300 Town and Country Blvd., Suite 500
in Frisco, Texas 75034 and our telephone number is (972) 668-8800.
18
We make available free of charge on our website our annual report on Form
10-K, our quarterly reports on Form 10-Q, our current reports on Form 8-K, and
amendments to these reports, as soon as reasonably practicable after we file
such material with, or furnish it to, the SEC. The Internet address of our
website is www.comstockresources.com, and such website contains additional
information about us; however, such information does not constitute part of this
Annual Report.
We lease office space in Frisco, Texas covering 20,046 square feet at a
monthly rate of $34,706. The lease expires on May 31, 2006. In addition to our
leased office space in Frisco, Texas, we leased 2,329 square feet of office
space in Houston, Texas at a monthly rate of $3,299 beginning April 1, 2003.
This lease expires on March 31, 2007. We also have a lease for office space
formally used by DevX Energy, Inc. The lease covers 9,573 square feet at a
monthly rate of $19,458. This lease expires on December 3, 2003. We also own
production offices and pipe yard facilities near Marshall and Livingston, Texas,
near Logansport, Louisiana and near Guston, Kentucky.
Employees
As of December 31, 2002, we had 62 employees and utilized contract
employees for certain of our field operations. We consider our employee
relations to be satisfactory.
Directors, Executive Officers and Other Management
The following table sets forth certain information concerning our executive
officers and directors.
Name Age Position with Company
- ----------------------- ------- -----------------------------------------
M. Jay Allison......... 47 President, Chief Executive Officer and
Chairman of the Board of Directors
Roland O. Burns........ 43 Senior Vice President, Chief Financial Officer,
Secretary, Treasurer and Director
Mack D. Good........... 52 Vice President of Operations
Stephen E. Neukom...... 53 Vice President of Marketing
Richard G. Powers...... 48 Vice President of Land
Daniel K. Presley...... 42 Vice President of Accounting and Controller
Michael W. Taylor...... 50 Vice President of Corporate Development
David K. Lockett....... 48 Director
Cecil E. Martin, Jr.... 61 Director
David W. Sledge........ 46 Director
Executive Officers
M. Jay Allison has been one of our directors since 1987, and our President
and Chief Executive Officer since 1988. Mr. Allison was elected chairman of the
board of directors in 1997. From 1987 to 1988, Mr. Allison served as our vice
president and secretary. From 1981 to 1987, he was a practicing oil and gas
attorney with the firm of Lynch, Chappell & Alsup in Midland, Texas. In 1983,
Mr. Allison co-founded a private independent oil and gas company, Midwood
Petroleum, Inc., which was active in the acquisition and development of oil and
gas properties from 1983 to 1987. He received B.B.A., M.S. and J.D. degrees from
Baylor University in 1978, 1980 and 1981, respectively. Mr. Allison currently
serves on the Board of Regents for Baylor University.
19
Roland O. Burns has been our senior vice president since 1994, chief
financial officer and treasurer since 1990 and our secretary since 1991. Mr.
Burns was elected one of our directors in June 1999. From 1982 to 1990, Mr.
Burns was employed by the public accounting firm, Arthur Andersen LLP. During
his tenure with Arthur Andersen LLP, Mr. Burns worked primarily in the firm's
oil and gas audit practice. Mr. Burns received B.A. and M.A. degrees from the
University of Mississippi in 1982 and is a Certified Public Accountant.
Mack D. Good was appointed our vice president of operations in March 1999.
From August 1997 until his promotion, Mr. Good served as our district engineer
for the East Texas / North Louisiana region. From 1983 until July 1997, Mr. Good
was with Enserch Exploration, Inc. serving in various operations management and
engineering positions. Mr. Good received a B.S. of Biology/Chemistry from
Oklahoma State University in 1975 and a B.S. of Petroleum Engineering from the
University of Tulsa in 1983. He is a Registered Professional Engineer in the
State of Texas.
Stephen E. Neukom has been our vice president of marketing since December
1997 and has served as our 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., our former wholly owned gas marketing subsidiary.
Prior to joining us, 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 us as Land Manager in October 1994 and has been
our vice president of land since December 1997. Mr. Powers has over 20 years of
experience as a petroleum landman. Prior to joining us, Mr. Powers was employed
for 10 years as land manager for Bridge Oil (U.S.A.), Inc. and its predecessor
Pinoak Petroleum, Inc. Mr. Powers received a B.B.A. degree in 1976 from Texas
Christian University.
Daniel K. Presley has been our vice president of accounting since December
1997 and has been with us since December 1989, serving as controller since 1991.
Prior to joining us, Mr. Presley had six years of experience with several
independent oil and gas companies including AmBrit Energy, Inc. Prior thereto,
Mr. Presley spent two and one-half years with B.D.O. Seidman, a public
accounting firm. Mr. Presley has a B.B.A. from Texas A & M University.
Michael W. Taylor has been our vice president of corporate development
since December 1997 and has served us in various capacities since September
1994. Mr. Taylor has 28 years of experience in the oil and gas business. For 15
years prior to joining us, he had been an independent oil and gas producer and
petroleum consultant. Before that time, he worked in various engineering and
executive capacities for a major oil company, a small independent producer and
an international oil and gas consulting company. Mr. Taylor is a Registered
Professional Engineer in the State of Texas and he received a B.S. degree in
Petroleum Engineering from Texas A & M University in 1974.
20
Outside Directors
David K. Lockett was appointed to our board of directors in 2001. Mr.
Lockett is currently a vice president of Dell Computer Corp. and heads up Dell's
Small and Medium Business group. Mr. Lockett has been employed by Dell Computer
Corp. for the last ten years and has spent the past twenty five years in the
technology industry. Mr. Lockett received a B.B.A. degree from Texas A&M
University in 1976.
Cecil E. Martin, Jr. has been one of our directors since 1988. Mr. Martin
has been an independent commercial real estate developer since 1991. From 1973
to 1991 he served as Chairman of a public accounting firm in Richmond, Virginia.
Mr. Martin holds a B.B.A. degree from Old Dominion University and is a Certified
Public Accountant.
David W. Sledge was elected to our board of directors in 1996. Since 1996,
he has been investing in oil and gas exploration activities. Mr. Sledge served
as President of Gene Sledge Drilling Corporation, a privately held contract
drilling company based in Midland, Texas until its sale in October 1996. Mr.
Sledge served Gene Sledge Drilling Corporation in various capacities from 1979
to 1996. Mr. Sledge is a past director of the International Association of
Drilling Contractors and is a past chairman of the Permian Basin chapter of this
association. He received a B.B.A. degree from Baylor University in 1979.
ITEM 3. LEGAL PROCEEDINGS
We are not a party to any legal proceedings which management believes will
have a material adverse effect on our 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 our security holders during the
fourth quarter of 2002.
21
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Our common stock is listed for trading on the New York Stock Exchange under
the symbol "CRK." The following table sets forth, on a per share basis for the
periods indicated, the high and low sales prices by calendar quarter for the
periods indicated as reported by the New York Stock Exchange.
High Low
-------- --------
2001 - First Quarter................. $ 14.63 $ 9.65
Second Quarter................ 12.48 8.95
Third Quarter................. 10.12 5.00
Fourth Quarter................ 8.15 5.26
2002 - First Quarter................. $ 7.95 $ 5.70
Second Quarter................ 9.47 6.65
Third Quarter................. 8.10 5.50
Fourth Quarter................ 9.74 6.61
As of March 26, 2003, we had 28,934,561 shares of common stock outstanding,
which were held by 472 holders of record and approximately 6,000 beneficial
owners who maintain their shares in "street name" accounts.
We have never paid cash dividends on our common stock. We presently intend
to retain any earnings for the operation and expansion of our business and we do
not anticipate paying cash dividends in the foreseeable future. Any future
determination as to the payment of dividends will depend upon the results of our
operations, capital requirements, our financial condition and such other factors
as our board of directors may deem relevant. In addition, we are limited under
our bank credit facility, the terms of the indenture for our senior notes due in
2007 and the terms of our 1999 Series A Preferred Stock from paying or declaring
cash dividends.
The following table summarizes securities issuable and authorized by the
stockholders under certain equity compensation plans:
Number of securities Weighted average Number of securities
to be issued upon exercise price of authorized for future
exercise of outstanding issuance under equity
outstanding options options compensation plans
------------------- ------------------ ----------------------
Equity compensation
plans approved by
stockholders 4,170,525 $8.18 352,786 (1)
- ----------
(1) Plus 1% of the outstanding shares of common stock each year beginning
on January 1, 2003.
22
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, 2002 are derived
from our consolidated financial statements. The financial results are not
necessarily indicative of our future operations or future financial results. The
data presented below should be read in conjunction with our consolidated
financial statements and the notes thereto and "Management's Discussion and
Analysis of Financial Condition and Results of Operations." Our consolidated
financial statements as of and for the four years ended December 31, 2001, have
been restated. For a further discussion of the restatement, see "Management's
Discussion and Analysis of Financial Condition and Results of Operations--
Restatement of Previously Issued Financial Statements," and our audited
consolidated financial statements and notes thereto, including Note 13.
Statement of Operations Data:
Year Ended December 31,
-------------------------------------------------------------
1998 1999 2000 2001 2002
---------- ---------- ---------- ---------- ----------
(Restated) (Restated) (Restated) (Restated)
(Unaudited) (Unaudited)
(In thousands, except per share data)
Oil and gas sales ............................ $ 91,373 $ 88,833 $ 168,084 $ 166,118 $ 142,085
Operating expenses:
Oil and gas operating (1) ................. 23,971 23,117 29,277 31,855 33,499
Exploration ............................... 8,901 2,248 3,505 6,611 5,479
Depreciation, depletion and amortization .. 50,301 44,801 44,472 48,790 54,405
Impairment ................................ 16,942 -- -- 1,400 --
General and administrative, net ........... 1,617 2,399 3,537 4,351 5,113
--------- -------- --------- --------- ---------
Total operating expenses ............. 101,732 72,565 80,791 93,007 98,496
--------- -------- --------- --------- ---------
Income (loss) from operations ................ (10,359) 16,268 87,293 73,111 43,589
Other income (expenses):
Interest income ........................... 201 134 230 196 62
Interest expense .......................... (16,977) (23,361) (24,611) (20,737) (30,002)
Gain (loss) from derivatives .............. -- -- -- 243 (2,326)
Other income .............................. 73 1,907 122 272 8,027
--------- -------- --------- --------- ---------
(16,703) (21,320) (24,259) (20,026) (24,239)
--------- -------- --------- --------- ---------
Income (loss) from continuing operations
before income taxes expense ............ (27,062) (5,052) 63,034 53,085 19,350
Income tax benefit (expense) ................. 9,471 1,769 (22,061) (18,579) (6,773)
--------- -------- --------- --------- ---------
Net income (loss) from continuing operations . (17,591) (3,283) 40,973 34,506 12,577
Discontinued operations including loss on
disposal, net of income taxes ............. 33 197 227 396 (1,072)
--------- -------- --------- --------- ---------
Net income (loss) ............................ (17,558) (3,086) 41,200 34,902 11,505
Preferred stock dividends .................... -- (1,853) (2,471) (1,604) (1,604)
--------- -------- --------- --------- ---------
Net income (loss) attributable to common stock $ (17,558) $ (4,939) $ 38,729 $ 33,298 $ 9,901
========= ======== ========= ========= =========
Net income (loss) per share from
continuing operations:
Basic ..................................... $ (0.72) $ (0.21) $ 1.46 $ 1.13 $ 0.38
========= ======== ========= ========= =========
Diluted.................................... $ 1.20 $ 1.00 $ 0.37
========= ========= =========
Net income (loss) per share:
Basic...................................... $ (0.72) $ (0.20) $ 1.47 $ 1.15 $ 0.34
========= ======== ========= ========= =========
Diluted.................................... $ 1.20 $ 1.01 $ 0.34
========= ========= =========
Weighted average shares outstanding:
Basic...................................... 24,275 24,601 26,290 29,030 28,764
========== ========= ========= ========= =========
Diluted.................................... 34,219 34,552 33,901
========= ========= =========
- -------------------------
(1) Includes lease operating costs and production and ad valorem taxes.
23
Balance Sheet Data:
As of December 31,
-----------------------------------------------------
1998 1999 2000 2001 2002
-------- -------- -------- --------- ---------
(Restated) (Restated) (Restated) (Restated)
(Unaudited) (Unaudited) (Unaudited)
(In thousands)
Cash and cash equivalents ............ $ 5,176 $ 7,648 $ 7,105 $ 6,122 $ 1,682
Property and equipment, net .......... 403,652 394,497 434,065 636,274 664,208
Total assets ......................... 429,307 433,956 489,082 680,769 711,053
Total debt ........................... 278,104 254,131 234,101 372,464 366,272
Redeemable convertible preferred stock -- 30,000 17,573 17,573 17,573
Stockholders' equity ................. 109,273 106,512 161,735 195,668 208,427
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Restatement of Previously Issued Financial Statements
Subsequent to the issuance of our Annual Report for the year ended December
31, 2001, we determined that certain outstanding advances made by us to our
partner under our joint exploration venture in the Gulf of Mexico for seismic
data acquisition should have been charged to exploration expense rather than
reflected on the balance sheet as an asset. As a result of changing our
accounting treatment for the advances used for seismic data acquisition, we
determined that our financial statements for 1998, 1999, 2000 and 2001 should be
restated. The effect of the restatement is a reduction to previously reported
net income by $0.4 million, $0.3 million, $0.2 million and $1.6 million for the
years 1998, 1999, 2000 and 2001, respectively, as a result of the additional
exploration expense in each year. These changes primarily affect the timing of
our recognition of exploration expense. As reimbursements are received for the
advances we have made, our future exploration expense will be reduced. In
addition, we have reclassified our Series 1999 Preferred Stock from
stockholder's equity at December 31, 2001 to temporary equity. The adjustments
to previously reported net income relating to the restatement are summarized in
the following table:
Year Ended December 31,
---------------------------------------------
1998 1999 2000 2001
-------- -------- -------- --------
(In thousands)
Net income (loss) attributable to
common stock as previously reported $(17,168) $ (4,669) $ 38,932 $ 34,854
Adjustment to exploration expense (600) (416) (313) (2,396)
Income tax effect .................. 210 146 110 840
-------- -------- -------- --------
Net income (loss) attributable to
common stock as restated........... $(17,558) $ (4,939) $ 38,729 $ 33,298
======== ======== ======== ========
24
The following balance sheet accounts as of December 31, 2001 were affected
by the restatement:
Year Ended December 31,
2001
--------------------------
Previously
Reported Restated
----------- -----------
(In thousands)
Unevaluated oil and gas properties ................. $ 13,416 $ 11,609
Oil and gas properties ............................. 901,206 900,711
Net property and equipment ......................... 638,576 636,274
Total assets ....................................... 683,071 680,769
Accounts payable and accrued expenses .............. 37,389 38,812
Total current liabilities .......................... 38,416 39,839
Deferred taxes payable ............................. 47,911 46,607
Retained earnings .................................. 54,183 51,762
Redeemable preferred stock ......................... -- 17,573
Total stockholders' equity ......................... 215,662 195,668
Total liabilities and stockholders' equity ......... 683,071 680,769
The following presents the impact of the restatement on the operating
results and cash flows for the years ended December 31, 2000 and 2001:
Year Ended Year Ended
December 31, 2000 December 31, 2001
---------------------- ---------------------
Previously Previously
Reported (1) Restated Reported (1) Restated
----------- ---------- ----------- ---------
(In thousands, except per share amounts)
Exploration expense ............................ $ 3,192 $ 3,505 $ 4,215 $ 6,611
Total operating expenses ....................... 80,478 80,791 90,611 93,007
Income from continuing operations
before income taxes ......................... 63,347 63,034 55,481 53,085
Income tax expense ............................. (22,171) (22,061) (19,419) (18,579)
Net income from continuing operations .......... 41,176 40,973 36,062 34,506
Net income ..................................... 41,403 41,200 36,458 34,902
Net income attributable to common stock ........ 38,932 38,729 34,854 33,298
Net income per share from continuing operations:
Basic...................................... $1.48 $1.46 $1.20 $1.13
Diluted.................................... $1.21 $1.20 $1.06 $1.00
Net income per share:
Basic...................................... $1.48 $1.47 $1.20 $1.15
Diluted.................................... $1.21 $1.20 $1.06 $1.01
Net cash provided by operating activities....... $104,556 $105,073 $ 110,090 $ 108,636
Net cash used for investing activities.......... $(83,361) $(83,878) $(189,601) $(188,147)
25
The following presents the impact related to the restatement on the
quarterly results for the year ended December 31, 2001:
Three Months Ended March 31, 2001
---------------------------------------
Previously
Reported (1) Adjustment Restated
----------- ------------ -----------
(In thousands, except per share amounts)
Exploration expense ......................... $ 2,831 $ 1,053 $ 3,884
Total expenses .............................. 30,485 1,053 31,538
Income from continuing operations
before income taxes ...................... 36,572 (1,053) 35,519
Income tax expense .......................... (12,800) 369 (12,431)
Net income from continuing operations ....... 23,772 (684) 23,088
Net income .................................. 23,974 (684) 23,290
Net income attributable to common stock ..... 23,578 (684) 22,894
Net income per share from continuing operations:
Basic................................... $0.82 ($0.02) $0.80
Diluted................................. $0.68 ($0.02) $0.66
Net income per share:
Basic................................... $0.83 ($0.02) $0.81
Diluted................................. $0.68 ($0.02) $0.66
Three Months Ended June 30, 2001
--------------------------------------
Previously
Reported (1) Adjustment Restated
----------- ------------ ----------
(In thousands, except per share amounts)
Exploration expense.......................... $ 477 $ 782 $ 1,259
Total expenses............................... 26,601 782 27,383
Income from continuing operations
before income taxes....................... 19,517 (782) 18,735
Income tax expense........................... (6,831) 274 (6,557)
Net income from continuing operations........ 12,686 (508) 12,178
Net income................................... 12,838 (508) 12,330
Net income attributable to common stock...... 12,438 (508) 11,930
Net income per share from continuing operations:
Basic................................... $0.42 ($0.02) $0.40
Diluted................................. $0.36 ($0.02) $0.34
Net income per share:
Basic................................... $0.43 ($0.02) $0.41
Diluted................................. $0.37 ($0.02) $0.35
Three Months Ended September 30, 2001
----------------------------------------
Previously
Reported (1) Adjustment Restated
----------- ------------ ------------
(In thousands, except per share amounts)
Exploration expense.......................... $ 63 $ (82) $ (19)
Total expenses............................... 25,061 (82) 24,979
Income from continuing operations
before income taxes....................... 4,357 82 4,439
Income tax expense........................... (1,525) (29) (1,554)
Net income from continuing operations........ 2,832 53 2,885
Net income................................... 2,890 53 2,943
Net income attributable to common stock...... 2,486 53 2,539
Net income per share from continuing operations:
Basic................................... $0.08 $0.00 $0.08
Diluted................................. $0.08 $0.00 $0.08
Net income per share:
Basic................................... $0.09 $0.00 $0.09
Diluted................................. $0.09 $0.00 $0.09
- ------------
(1) Previously reported amounts have been adjusted for the effects of
discontinued operations.
26
Results of Operations
Our operating data for the last three years is summarized below:
Year Ended December 31,
----------------------------------
2000 2001 2002
-------- -------- --------
Net Production Data:
Oil (MBbls) ....................... 1,792 1,510 1,303
Natural gas (MMcf) ................ 26,799 27,859 33,171
Natural gas equivalent (MMcfe) .... 37,548 36,918 40,986
Average Sales Price:
Oil (MBbls) ....................... $ 30.04 $ 25.46 $ 24.95
Natural gas (MMcf) ................ 4.26 4.58 3.30
Average equivalent price (per Mcfe) 4.48 4.50 3.47
Expenses ($ per Mcfe):
Oil and gas operating(1) .......... $ 0.78 $ 0.86 $ 0.82
General and administrative ........ 0.09 0.12 0.12
Depreciation, depletion and
amortization(2) ................ 1.14 1.28 1.29
Cash Margin ($ per Mcfe)(3) ........... $ 3.61 $ 3.52 $ 2.53
- -----------
(1)Includes lease operating costs and production and ad valorem taxes.
(2)Represents depreciation, depletion and amortization of oil and gas properties
only.
(3)Represents average equivalent price per Mcfe less oil and gas operating
expenses per Mcfe and general and administrative expenses per Mcfe.
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
Our oil and gas sales decreased $24.0 million or 14% in 2002 to $142.1
million from $166.1 million in 2001. The decrease in sales is mostly due to the
lower natural gas prices in 2002. Our average natural gas price decreased by 28%
and our average oil price decreased by 2%. On an equivalent unit basis, our
average price received for our production in 2002 was $3.47 per Mcfe, which was
23% lower than our average price in 2001 of $4.50 per Mcfe. Our average natural
gas price in 2002 was $0.04 higher as a result of gains from hedging activities.
Without the hedging gains, our natural gas price would have averaged $3.26 in
2002. The lower prices were partially offset by an 11% increase in production.
Our natural gas production was up 19% while our oil production fell by 14%. The
natural gas production increase is related to our acquisition of DevX Energy,
Inc. which we completed in December 2001. The oil production decrease was due to
normal depletion of our oil properties.
Our oil and gas operating expenses, which includes production taxes,
increased $1.6 million or 5%, to $33.5 million in 2002 from $31.9 million in
2001. The increase is due to the higher production level in 2002. Our oil and
gas operating expenses per equivalent Mcf produced decreased by $0.04 to $0.82
in 2002 from $0.86 for 2001. The decrease in per unit lifting costs is primarily
related to lower production taxes resulting from the lower oil and natural gas
prices in 2002.
27
In 2002, we had $5.5 million in exploration expense, which primarily
related to the write-off of four exploratory dry holes. Exploration expense for
2001 was $6.6 million (as restated) which related to the write-off of three dry
holes and the expensing of $2.4 million in advances made by us to our joint
venture partner for seismic data acquisition.
Our depreciation, depletion and amortization increased $5.6 million (12%)
to $54.4 million in 2002 from $48.8 million in 2001. The increase is
attributable to our higher production level in 2002. Our depreciation, depletion
and amortization per equivalent Mcf produced increased to $1.29 in 2002 from
$1.28 in 2001.
Our general and administrative expenses, which are reported net of overhead
reimbursements that we receive, increased $762,000 or 18%, to $5.1 million in
2002 from $4.4 million in 2001. The increase was primarily due to an increase in
the number of employees and higher compensation paid to our employees in 2002.
Our interest expense increased $9.3 million or 45% to $30.0 million in 2002
from $20.7 million for 2001. The increase is due to the higher debt level we had
as a result of the acquisition of DevX Energy, Inc. in December 2001. In
addition, in March 2002 we issued an additional $75.0 million of our 11 1/4%
Senior Notes which refinanced amounts that were borrowed under our bank credit
facility. In 2002, we averaged $172.0 million outstanding under our bank credit
facility at a weighted average interest of 3.6%. In 2001, our average
outstanding balance was $65.2 million under the bank credit facility with a
weighted average interest rate of 5.6%.
Our other income in 2002 increased to $8.0 million from $272,000 in 2001.
Included in other income in 2002 was $7.7 million related to refunds of
severance taxes paid in prior years.
For 2002 we reported net income from continuing operations of $11.0
million, after deducting preferred stock dividends of $1.6 million. These
results compared to net income in 2001 of $32.9 million (as restated), after
deducting preferred stock dividends of $1.6 million. Our income from continuing
operations per share for 2002 was $0.37 on diluted weighted average shares
outstanding of 33.9 million as compared to net income from continuing operations
per share of $1.00 (as restated) for 2001 on diluted weighted average shares
outstanding of 34.6 million. In April 2002 and July 2002, we sold certain oil
and gas properties, which resulted in a loss of $1.8 million. The operating
results of these properties have been reflected as discontinued operations in
the consolidated financial statements including the losses on disposal.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
Our oil and gas sales decreased $2.0 million or 1% in 2001 to $166.1
million from $168.1 million in 2000. The slight decrease in sales is due to a 2%
decrease in our oil and natural gas production in 2001. Our oil production in
2001 decreased by 16% and natural gas production increased by 4%. Our average
oil price in 2001 decreased by 15% which was offset by a 8% increase to our
average natural gas price. On an equivalent unit basis, our average price
received for our production in 2001 was $4.50 per Mcfe, 1% higher than our
average price in 2000 of $4.48 per Mcfe.
Our oil and gas operating expenses, which includes production taxes,
increased $2.6 million or 9%, to $31.9 million in 2001 from $29.3 million in
2000. Our oil and gas operating expenses per equivalent Mcf produced increased
by $0.08 to $0.86 in 2001 from $0.78 for 2000. The increase is due to higher
field level operating costs including additional treating fees paid in 2001 to
process our Btu rich natural gas.
28
In 2001, we had $6.6 million (as restated) in exploration expense which
represents the write-off of three offshore exploratory dry holes and the
expensing of $2.4 million in advances made by us to our joint venture partner
for seismic data acquisition. Exploration expense for 2000 was $3.5 million (as
restated) which primarily related to the write-off of five dry holes.
Our depreciation, depletion and amortization increased $4.3 to $48.8
million in 2001 from $44.5 million in 2000. The increase is attributable to
higher capitalized costs on our properties which increased our amortization rate
in 2001. Our depreciation, depletion and amortization per equivalent Mcf
produced increased to $1.28 in 2001 from $1.14 in 2000.
Our general and administrative expenses, which are reported net of overhead
reimbursements that we receive, increased $814,000 or 23%, to $4.4 million in
2001 from $3.5 million in 2000. The increase was primarily due to an increase in
the number of employees and higher compensation paid to our employees in 2001.
Our interest expense decreased $3.9 million or 16% to $20.7 million in 2001
from $24.6 million for 2000. The decrease is due to lower average borrowings
outstanding under our bank credit facility as well as a lower average interest
rate under the bank credit facility. In 2001, we had a $65.6 million average
outstanding balance under the bank credit facility at a weighted average
interest of 5.6%. In 2000, our average outstanding balance was $104.2 million
under the bank credit facility with a weighted average interest rate 6.9%.
We reported net income from continuing operations of $32.9 million (as
restated), after deducting preferred stock dividends of $1.6 million, in 2001.
These results compared to net income from continuing operations of $38.5 million
(as restated), after deducting preferred stock dividends of $2.5 million, in
2000. Our income from continuing operations per share for 2001 was $1.00 (as
restated) on diluted weighted average shares outstanding of 34.6 million as
compared to net income from continuing operations per share of $1.20 (as
restated) for 2000 on diluted weighted average shares outstanding of 34.2
million.
Liquidity and Capital Resources
Funding for our activities has historically been provided by our operating
cash flow, debt or equity financings or asset dispositions. In 2002, our net
cash flow provided by operating activities totaled $79.3 million. Our other
primary funding source in 2002 were proceeds from the sale of $75.0 million of
our senior notes and borrowings of $31.0 million under our bank credit facility.
Our primary needs for capital, in addition to funding our ongoing
operations, relate to the acquisition, development and exploration of our oil
and gas properties and the repayment of our debt. In 2002, we incurred capital
expenditures of $83.4 million for development and exploration activities and for
the acquisitions. We also repaid $112.9 million of our long-term debt.
29
Our annual capital expenditure activity is summarized in the following table:
Year Ended December 31,
----------------------------
2000 2001 2002
------- -------- -------
(In thousands)
Acquisitions of proved oil and gas properties . $ 9,684 $160,794 $11,435
Acquisitions of unproved oil and gas properties 5,863 7,113 4,268
Developmental leasehold costs ................. 1,618 974 98
Workovers and recompletions ................... 10,252 5,563 7,414
Offshore production facilities ................ 1,629 907 4,867
Development drilling .......................... 35,047 43,646 22,893
Exploratory drilling .......................... 19,202 33,382 31,074
Other ......................................... 616 172 1,332
------- -------- -------
Total ..................................... $83,911 $252,551 $83,381
======= ======== =======
The timing of most of our capital expenditures is discretionary because we
have no material long-term capital expenditure commitments. Consequently, we
have a significant degree of flexibility to adjust the level of our capital
expenditures as circumstances warrant. We spent $73.6 million, $91.6 million and
$70.6 million on development and exploration activities in 2000, 2001 and 2002,
respectively. We have budgeted approximately $100.0 million for development and
exploration projects in 2003. We expect to use internally generated cash flow to
fund development and exploration activity. Our operating cash flow is highly
dependent on oil and natural gas prices, especially natural gas prices.
We spent $9.7 million, $160.8 million and $11.4 million on acquisition
activities in 2000, 2001 and 2002, respectively. We do not have a specific
acquisition budget for 2003 since the timing and size of acquisitions are not
predictable. We intend to use borrowings under our bank credit facility, or
other debt or equity financings to the extent available, to finance significant
acquisitions. The availability and attractiveness of these sources of financing
will depend upon a number of factors, some of which will relate to our financial
condition and performance and some of which will be beyond our control, such as
prevailing interest rates, oil and natural gas prices and other market
conditions.
We entered into a $350.0 million revolving credit facility on December 17,
2001 with Toronto Dominion (Texas), Inc. as administrative agent. The bank
credit facility is a three year revolving credit line with a current borrowing
base of $240.0 million. Indebtedness under the bank credit facility is secured
by substantially all of our assets. All of our subsidiaries are guarantors of
this indebtedness. The revolving credit line is subject to borrowing base
availability, which is redetermined semiannually based on the banks' estimates
of the future net cash flows of our oil and gas properties. The borrowing base
may be affected by the performance of our properties and changes in oil and gas
prices. The determination of the borrowing base is at the sole discretion of the
administrative agent and the bank group. The revolving credit line bears
interest, based on the utilization of the borrowing base, at our option at
either (i) LIBOR plus 1.5% to 2.375% or (ii) the corporate base rate (generally
the federal funds rate plus 0.5%) plus 0.5% to 1.375%. The bank credit facility
matures on January 2, 2005 and contains covenants that, among other things,
restrict our ability to pay cash dividends, limit the amount of our consolidated
debt and limit our ability to make certain loans and investments. Financial
covenants include the maintenance of a current ratio, maintenance of tangible
net worth and maintenance of an interest coverage ratio.
30
On March 7, 2002, we closed the sale in a private placement of $75.0
million of our 11 1/4% senior notes due 2007 at a net price of 97.25% after the
placements agents' discount. As a result of this transaction, $220.0 million of
aggregate principal amount of our senior notes are outstanding. The net proceeds
were used to reduce amounts outstanding under our bank credit facility. These
notes are unsecured obligations of Comstock and are guaranteed by all of our
subsidiaries. On July 19, 2002, we filed a registration statement on Form S-4 to
register the $75.0 million of these notes for resale. This registration
statement was declared effective by the SEC on August 5, 2002.
The following table summarizes our aggregate liabilities and commitments by
year of maturity:
2003 2004 2005 2006 2007 2008 Total
-------- -------- -------- --------- --------- -------- --------
(In thousands)
Bank credit facility ... $ -- $ -- $146,000 $ -- $ -- $ -- $146,000
Senior notes ........... -- -- -- -- 220,000 -- 220,000
Other debt ............. 270 -- -- -- -- 2 272
Operating leases ....... 656 452 477 198 -- -- 1,783
Derivative liabilities . 57 -- -- -- -- -- 57
Preferred stock (1) .... -- -- 5,858 5,858 5,857 -- 17,573
-------- -------- -------- -------- -------- -------- --------
$ 983 $ 452 $152,335 $ 6,056 $225,857 $ 2 $385,685
======== ======== ======== ======== ======== ======== ========
- ------------
(1) Represents the redemption of our Series A 1999 Convertible Preferred Stock,
which at our option, can be paid in shares of our common stock.
We believe that our cash flow from operations and available borrowings
under the bank credit facility will be sufficient to fund our operations and
future growth as contemplated under our current business plan. However, if our
plans or assumptions change or if our assumptions prove to be inaccurate, we may
be required to seek additional capital. We cannot provide any assurance that we
will be able to obtain such capital, or if such capital is available, that we
will be able to obtain it on acceptable terms.
Federal Taxation
At December 31, 2002, we had federal income tax net operating loss
carryforwards of approximately $123.0 million. We have established a $23.0
million valuation allowance against part of the net operating loss carryforwards
acquired from DevX Energy, Inc. due to a "change in control" limitation which
will prevent us from fully realizing these carryforwards. The carryforwards
expire from 2018 through 2022. The value of these carryforwards depends on our
ability to generate future taxable income in order to utilize these
carryforwards.
Critical Accounting Policies
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires us to make estimates
and use assumptions that can affect the reported amounts of assets, liabilities,
revenues or expenses. We are also required to select among alternative
acceptable accounting policies. There are two generally acceptable methods for
accounting for oil and gas producing activities. The full cost method allows the
capitalization of all costs associated with finding oil and gas reserves,
including certain general and administrative expenses. The successful efforts
method allows only for the capitalization of costs associated with developing
proven oil and gas properties as well as exploration costs associated with
successful exploration projects. Costs related to exploration that are not
successful are expensed when it is determined that commercially productive oil
and gas reserves were not found. We have elected to use the successful efforts
method to account for our oil and gas activities and we do not capitalize any of
our general and administrative expenses.
31
The determination of depreciation, depletion and amortization expense as
well as impairments that are recognized on our oil and gas properties are highly
dependent on the estimates of the proved oil and natural gas reserves
attributable to our properties. There are numerous uncertainties inherent in
estimating oil and natural gas reserves and their values, including many factors
beyond our control. 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. The estimates of our proved oil and gas reserves used
in preparation of our financial statements were determined by an independent
petroleum engineering consulting firm and were prepared in accordance with the
rules promulgated by the SEC and the Financial Accounting Standards Board
(the "FASB"). The determination of impairment of our oil and gas reserves is
based on the oil and gas reserve estimates using projected future oil and
natural gas prices that we have determined to be reasonable. The projected
prices that we employ represent our long- term oil and natural gas price
forecast and may be higher or lower than current market prices for crude oil and
natural gas. For the impairment review of our oil and gas properties that we
conducted as of December 31, 2002, we used an initial oil price of $30.00 per
barrel and an initial natural gas price of $5.00 per Mcf. Such prices were
reduced to $25.00 per barrel for oil and $4.00 per Mcf for gas in the second
year and escalated each year thereafter to a maximum price of $40.00 per barrel
for oil and $5.00 per Mcf for natural gas. To the extent we had used lower
prices in our impairment review, an impairment could have been indicated on
certain of our oil and gas properties.
New Accounting Standards
In August 2001, the FASB issued Statement of Financial Accounting Standards
No. 143 ("SFAS 143") "Accounting for Asset Retirement Obligations," which we
adopted effective January 1, 2003. This statement requires us to record a
liability in the period in which an asset retirement obligation ("ARO") is
incurred. Upon recognition of an ARO liability, additional asset cost would be
capitalized to equal the amount of the liability. Upon the initial adoption of
SFAS 143, we recognized a liability for any existing AROs not already provided
for in our reserve for future abandonment costs. We also recognized additional
capitalized cost related to the additional liability and accumulated
depreciation on the additional capitalized cost.
Under SFAS 143, we estimate that our total ARO for our oil and natural gas
properties is approximately $15.2 million which was $1.5 million less than the
liability that we had provided for in our reserve for future abandonment as of
December 31, 2002. The impact of adopting SFAS 143, which will be recorded as
the cumulative effect of an accounting change was an increase to net income of
approximately $0.7 million, net of tax.
In June 2002, the FASB issued Statement of Financial Accounting Standards
146, "Accounting for Costs Associated with Exit or Disposal Activities" ("SFAS
146"). The Statement establishes accounting and reporting standards that are
effective for exit or disposal activities beginning after December 31, 2002
which require that a liability be recognized for an exit or disposal activity
when that liability is incurred. We have not determined the effect, if any, that
the adoption of SFAS 146 will have on our financial statements.
In January 2003, the FASB issued Interpretation ("FIN") No. 45,
"Guarantor's Accounting and Disclosure Requirement for Guarantees, including
Indirect Guarantees of Indebtedness of Others." FIN 45 requires an entity to
recognize a liability for the obligations it has undertaken in issuing a
guarantee. This liability would be recorded at the inception of a guarantee and
32
would be measured at fair value. Certain guarantees are excluded from the
measurement and disclosure provisions while certain other guarantees are
excluded from the measurement provisions of the interpretation. The measurement
provisions of this statement apply prospectively to guarantees issued or
modified after December 31, 2002. The disclosure provisions of the statement
apply to financial statements for periods ending after December 15, 2002. The
adoption of the statement is not expected to have a material effect on our
financial statements when adopted.
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities." FIN 46 requires an entity to consolidate a variable
interest entity if it is designated as the primary beneficiary of that entity
even if the entity does not have a majority of voting interests. A variable
interest entity is generally defined as an entity where its equity is unable to
finance its activities or where the owners of the entity lack the risk and
rewards of ownership. The provisions of this statement apply at inception for
any entity created after January 31, 2003. For an entity created before February
1, 2003, the provisions of this interpretation must be applied at the beginning
of the first interim or annual period beginning after June 15, 2003. Comstock is
not the primary beneficiary of any variable interest entities, and accordingly,
the adoption of FIN 46 is not expected to have a material effect on our
financial statements when adopted.
Related Party Transactions
In recent years we have not entered into any material transactions with our
officers or directors apart from the compensation they are provided for their
services. We also have not entered into any business transactions with our
significant stockholders or any other related parties.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS
Oil and Natural Gas Prices
Our financial condition, results of operations and capital resources are
highly dependent upon the prevailing market prices of oil and natural gas. These
commodity prices are subject to wide fluctuations and market uncertainties due
to a variety of factors that are beyond our control. Factors influencing oil and
natural gas prices include the level of global demand for crude oil, the foreign
supply of oil and natural gas, the establishment of and compliance with
production quotas by oil exporting countries, weather conditions which determine
the demand for natural gas, the price and availability of alternative fuels and
overall economic conditions. It is impossible to predict future oil and natural
gas prices with any degree of certainty. Sustained weakness in oil and natural
gas prices may adversely affect our financial condition and results of
operations, and may also reduce the amount of oil and natural gas reserves that
we can produce economically. Any reduction in our oil and natural gas reserves,
including reductions due to price fluctuations, can have an adverse affect on
our ability to obtain capital for our exploration and development activities.
Similarly, any improvements in oil and natural gas prices can have a favorable
impact on our financial condition, results of operations and capital resources.
Based on our oil and natural gas production in 2002, a $1.00 change in the price
per barrel of oil would have resulted in a change in our cash flow for such
period by approximately $1.2 million and a $1.00 change in the price per Mcf of
natural gas would have changed our cash flow by approximately $31.8 million.
We periodically use hedging transactions with respect to a portion of our
oil and natural gas production to mitigate our exposure to price changes. While
the use of these hedging arrangements limits the downside risk of price
declines, such use may also limit any benefits which may be derived from price
increases. We use swaps, floors and collars to hedge oil and natural gas prices.
Swaps are settled monthly based on differences between the prices specified in
the instruments and the settlement prices of futures contracts quoted on the
33
New York Mercantile Exchange. Generally, when the applicable settlement price is
less than the price specified in the contract, we receive a settlement from the
counterparty based on the difference multiplied by the volume hedge. Similarly,
when the applicable settlement price exceeds the price specified in the
contract, we pay the counterparty based on the difference. We generally receive
a settlement from the counterparty for floors when the applicable settlement
price is less than the price specified in the contract, which is based on the
difference multiplied by the volumes hedged. For collars, we generally receive a
settlement from the counterparty when the settlement price is below the floor
and pay a settlement to the counterparty when the settlement price exceeds the
cap. No settlement occurs when the settlement price falls between the floor and
cap.
The following table sets out the derivative financial instruments
outstanding at December 31, 2002 which are held for natural gas price risk
management:
Volume Type Floor
Period Beginning Period Ending (MMBtu) of Instrument Price
- ----------------- ----------------- ----------- -------------- ----------
January 1, 2003 December 31, 2003 2,250,000 Floor $2.00
The fair value of the commodity price derivative financial instruments at
December 31, 2002 was a net asset of $3,000.
In 2002, we hedged a portion of our natural gas production for the period
April 2002 through October 2002, in order to increase the predictability of our
cash flow from operations in order to support our 2002 drilling program. We
entered into price swaps covering 50 MMBtus per day of our natural gas
production at an average price of $3.46 for April 2002 to October 2002. We
realized a $1.3 million gain on this hedge position in 2002, which was included
in oil and gas sales and increased our average natural gas price realization
from $3.26 per Mcf to $3.30 per Mcf.
Interest Rates
At December 31, 2002, we had long-term debt of $366.0 million. Of this
amount, $220.0 million bears interest at a fixed rate of 11 1/4%. The fair
market value of the fixed rate debt as of December 31, 2002 was $233.2 million
based on the market price of 106% of the face amount. We had $146.0 million
outstanding under our bank credit facility, which is subject to floating market
rates of interest. Borrowings under the bank credit facility bear interest at a
fluctuating rate that is tied to LIBOR or the corporate base rate, at our
option. Any increases in these interest rates can have an adverse impact on our
results of operations and cash flow. Based on borrowings outstanding at December
31, 2002, a 100 basis point change in interest rates would change our interest
expense on our variable rate debt by approximately $1.5 million. From January 1,
2002 to April 30, 2002 we had an interest rate swap in place which fixed our
LIBOR rate on $25.0 million of our floating rate debt at 4.5%. As a result of
this interest rate swap, we realized a loss of $218,000 in 2002. In December
2002 we entered into an interest rate swap agreement to hedge the impact of
interest rate changes on $25.0 million of our floating rate debt beginning on
January 1, 2003 and expiring on December 31, 2003. This interest rate swap fixed
LIBOR at 1.7%. The fair value of this interest rate derivative financial
instrument was a net liability of $57,000 at December 31, 2002.
34
ITEM 8. FINANCIAL STATEMENTS
Our consolidated financial statements are included on pages F-1 to F-29 of
this report.
We have prepared these financial statements in conformity with generally
accepted accounting principles. We are 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 for
us to make informed estimates and judgments based on currently available
information on the effects of certain events and transactions.
We maintain accounting and other controls which we believe provide
reasonable assurances that our financial records are reliable, our assets are
safeguarded, and that transactions are properly recorded in accordance with
management's authorizations. However, limitations exist in any system of
internal controls based upon the recognition that the cost of the system should
not exceed benefits derived.
Our independent public accountants, KPMG LLP, are engaged to audit our
financial statements and to express an opinion thereon. Their audit is conducted
in accordance with auditing standards generally accepted in the United States to
enable them to report whether the financial statements present fairly, in all
material respects, our financial position and results of operations in
accordance with accounting principles generally accepted in the United States.
The audit committee of our board of directors is composed of three
directors who are not our employees. This committee meets periodically with our
independent public accountants and management. Our 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 our financial reporting.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Our Audit Committee annually considers and recommends to our board of
directors the selection of our independent public accountants. As recommended by
the Audit Committee, on April 22, 2002, the board of directors decided to no
longer engage Arthur Andersen LLP as our independent public accountants and
engaged KPMG LLP to serve as our independent public accountants for 2002.
Arthur Andersen LLP's reports on our consolidated financial statements for
the past two years did not contain an adverse opinion or disclaimer of opinion,
nor were they qualified or modified as to uncertainty, audit scope or accounting
principles.
During our two most recent fiscal years and through the date of their
appointment, there were no disagreements with Arthur Andersen LLP on any matters
of accounting principles or practices, financial statement disclosure, or
auditing scope or procedure which, if not resolved to Arthur Andersen LLP's
satisfaction, would have caused them to make reference to the subject matter in
connection with their report on our consolidated financial statements for such
years; and there were no reportable events, as listed in Item 304 (a) (l) (v) of
Regulation S-K.
During our two most recent fiscal years and through April 22, 2002, we did
not consult KPMG LLP with respect to the application of accounting principles to
a specified transaction, either completed or proposed, or the type of audit
opinion that might be rendered on our consolidated financial statements, or any
other matters or reportable events listed in Items 304 (a) (2) (i) and (ii) of
Regulation S-K.
35
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item is incorporated herein by reference
to our definitive proxy statement which will be filed with the Securities and
Exchange Commission within 120 days after December 31, 2002.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is incorporated herein by reference
to our definitive proxy statement which will be filed with the Securities and
Exchange Commission within 120 days after December 31, 2002.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The information required by this item is incorporated herein by reference
to our definitive proxy statement which will be filed with the Securities and
Exchange Commission within 120 days after December 31, 2002.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is incorporated herein by reference
to our definitive proxy statement which will be filed with the Securities and
Exchange Commission within 120 days after December 31, 2002.
ITEM 14. CONTROLS AND PROCEDURES
Within 90 days prior to the date of this report, we carried out an
evaluation, under the supervision and with the participation of the chief
executive officer and chief financial officer, of the effectiveness of the
design and operation of our disclosure controls and procedures. Based on this
evaluation, the chief executive officer and chief financial officer concluded
that our disclosure controls and procedures are effective in timely alerting
them to material information required to be included in our periodic SEC
reports.
In addition, we reviewed our internal controls and there has been no
significant changes in our internal controls or in other factors, including any
corrective actions with regard to significant deficiencies and material
weaknesses, that could significantly affect those controls subsequent to the
date of their last evaluation.
36
PART IV
ITEM 15. EXHIBITS AND REPORTS ON FORM 8-K
Exhibits:
The following exhibits are included this report.
Exhibit No. Description
- ------------ -----------------------------------------------------------------
2.1 Agreement and Plan of Merger among Comstock, Comstock Holdings,
Inc., Comstock Acquisition Inc. and DevX Energy, Inc. dated as of
November 12, 2001 (incorporated by reference to Exhibit 2.1 to
our Current Report on Form 8-K filed on November 13, 2001).
3.1(a) Restated Articles of Incorporation (incorporated by reference to
Exhibit 3.1 to our Annual Report on Form 10-K for the year ended
December 31, 1995).
3.1(b) Certificate of Amendment to the Restated Articles of
Incorporation dated July 1, 1997 (incorporated herein by
reference to Exhibit 3.1 to our Quarterly Report on Form 10-Q for
the quarter ended June 30, 1997).
3.2 Bylaws (incorporated by reference to Exhibit 3.2 to our
Registration Statement on Form S-3, dated October 25, 1996).
4.1 Rights Agreement dated as of December 14, 2000, by and between
Comstock and American Stock Transfer and Trust Company, as Rights
Agent (incorporated herein by reference to Exhibit 1 to our
Registration Statement on Form 8-A dated January 11, 2001).
4.2 Certificate of Voting Powers, Designations, Preferences, and
Relative, Participating, Optional or Other Special Rights of the
Series A 1999 Convertible Preferred Stock and Series B 1999
Non-Convertible Preferred Stock (incorporated herein by reference
to Exhibit 4.1 to our Current Report on Form 8-K dated April 29,
1999).
4.3* Articles of Amendment to the Certificate of Voting Powers,
Designations, Preferences, and Relative, Participating, Optional
or Other Special Rights of Series A 1999 Convertible Preferred
Stock and Series B 1999 Non-Convertible Preferred Stock.
4.4 Stock Purchase Agreement dated April 29, 1999 between Comstock
and certain purchasers (incorporated herein by reference to
Exhibit 10.1 to our Current Report on Form 8-K dated April 29,
1999).
4.5 Certificate of Designation, Preferences and Rights of Series B
Junior Participating Preferred Stock (incorporated herein by
reference to Exhibit 2 to our Registration Statement on Form 8-A
dated January 11, 2001).
4.6 Indenture dated April 29, 1999 between Comstock and U.S. Trust
Company of Texas, N.A., Trustee for the 11 1/4% Senior Notes due
2007 (incorporated herein by reference to Exhibit 10.5 to our
Current Report on Form 8-K dated April 29, 1999).
4.7 First Supplemental Indenture, dated March 7, 2002, by and between
Comstock and U.S. Trust Company of Texas, N.A., Trustee for the
11 1/4% Senior Notes due 2007 (incorporated by reference to
Exhibit 4.1 to our Current Report on Form 8-K dated March 12,
2002).
10.1 Credit Agreement, dated as of December 17, 2001, by and among
Comstock, as borrower, each lender from time to time party
thereto, Toronto Dominion (Texas), Inc., as administrative agent,
and Toronto-Dominion Bank, as Issuing Bank (incorporated by
reference to Exhibit 10.1 to our Current Report on Form 8-K dated
December 21, 2001).
37
Exhibit No. Description
- ------------ -----------------------------------------------------------------
10.2 Amendment No.1 dated December 26, 2001 to the Credit Agreement,
dated as of December 17, 2001, by and among Comstock, as
borrower, each lender from time to time party thereto, Toronto
Dominion (Texas), Inc., as administrative agent, and
Toronto-Dominion Bank, as Issuing Bank (incorporated by reference
to Exhibit 10.2 to our Annual Report on Form 10-K for the year
ended December 31, 2001).
10.3 Amendment No. 2 dated February 4, 2002 to the Credit Agreement,
dated as of December 17, 2001, by and among Comstock, as
borrower, each lender from time to time party thereto, Toronto
Dominion (Texas), Inc., as administrative agent, and
Toronto-Dominion Bank, as Issuing Bank (incorporated by reference
to Exhibit 10.3 to our Annual Report on Form 10-K for the year
ended December 31, 2001).
10.4 Amendment No. 3 dated April 15, 2002 to the Credit Agreement,
dated as of December 17, 2001, by and among Comstock, as
borrower, each lender from time to time party thereto, Toronto
Dominion (Texas), Inc., as administrative agent, and
Toronto-Dominion Bank, as Issuing Bank (incorporated by reference
to Exhibit 10.1 to our Quarterly Report for the quarter ended
March 31, 2002).
10.5 Placement Agreement dated February 28, 2002, by and between
Comstock and Morgan Stanley & Co. Incorporated, TD Securities
(USA), inc. and BMO Nesbitt Burns Corp. (incorporated herein by
reference to Exhibit 10.1 to our Current Report on Form 8-K filed
on March 12, 2002).
10.6 Registration Rights Agreements dated March 7, 2002, by and
between Comstock and Morgan Stanley & Co. Incorporated, TD
Securities (USA), Inc. and BMO Nesbitt Burns Corp. (incorporated
herein by reference to Exhibit 10.2 to our Current Report on Form
8-K filed on March 12, 2002).
10.7# Employment Agreement dated June 1, 2002, by and between Comstock
and M. Jay Allison (incorporated herein by reference to Exhibit
10.1 to our Quarterly Report on Form 10-Q for the quarter ended
June 30, 2002).
10.8# Employment Agreement dated June 1, 2002, by and between Comstock
and Roland O. Burns (incorporated herein by reference to Exhibit
10.2 to our Quarterly Report on Form 10-Q for the quarter ended
June 30, 2002).
10.9# Comstock Resources, Inc. 1999 Long-term Incentive Plan
(incorporated herein by reference to Exhibit 10.1 to our
Quarterly Report on Form 10-Q for the quarter ended June 30,
1999).
10.10# Form of Nonqualified Stock Option Agreement between Comstock and
certain officers and directors of Comstock (incorporated herein
by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q
for the year ended June 30, 1999).
10.11# Form of Restricted Stock Agreement between Comstock and certain
officers of Comstock (incorporated herein by reference to Exhibit
10.3 to our Quarterly Report on Form 10-Q for the quarter ended
June 30, 1999).
10.12 Exploration Agreement dated July 31, 2001 by and between Comstock
and Bois 'd Arc Offshore Ltd. (incorporated by reference to
Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter
ended June 30, 2001).
10.13 Warrant Agreement dated July 31, 2001 by and between Comstock and
Gary W. Blackie and Wayne L. Laufer (incorporated herein by
reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q
for the quarter ended June 30, 2001).
10.14* Supplement to the 2001 Exploration Agreement dated December 20,
2002 by and between Comstock and Bois 'd Arc Offshore Ltd.
38
Exhibit No. Description
- ------------ -----------------------------------------------------------------
10.15 Office Lease Agreement dated August 12, 1997 between Comstock and
Briar Center LLC (incorporated by reference to Exhibit 10.2 to
our Quarterly Report on Form 10-Q for the quarter ended September
30, 1997).
16 Letter of Arthur Andersen LLP to the Securities and Exchange
Commission dated April 26, 2002 (incorporated by reference to
Exhibit 16 to our Current Report on Form 8-K dated April 22,
2002).
99.1* Certification for the Chief Executive Officer as required by
Section 906 of the Sarbanes-Oxley Act of 2002.
99.2* Certification for the Chief Financial Officer as required by
Section 906 of the Sarbanes-Oxley Act of 2002.
21* Subsidiaries of the Company.
23* Consent of KPMG LLP.
- ---------------
*Filed herewith.
# Management contract or compensatory plan document.
Reports on Form 8-K:
Form 8-K Reports filed subsequent to September 30, 2002 are as follows:
Date Item Description
- ----------------- ---- ------------------------------------------------------
February 18, 2002 5 Operating results for the fourth quarter and year
ended December 31, 2002 and restatement of previously
reported financial results for years ended
December 31, 1998, 1999, 2000 and 2001.
March 21, 2003 5 Disclosure of the delivery of required notice to
executive officers and directors under Regulation BTR.
39
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
Date: March 26, 2003 (Principal Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
/s/ M. JAY ALLISON President, Chief Executive Officer and March 26, 2003
- ------------------ Chairman of the Board of Directors
M. Jay Allison (Principal Executive Officer)
/s/ ROLAND O. BURNS Senior Vice President, Chief Financial Officer, March 26, 2003
- ------------------- Secretary, Treasurer and Director
Roland O. Burns (Principal Financial and Accounting Officer)
/s/ DAVID K. LOCKETT Director March 26, 2003
- --------------------
David K. Lockett
/s/ CECIL E. MARTIN, JR. Director March 26, 2003
- -----------------------
Cecil E. Martin, Jr.
/s/ DAVID W. SLEDGE Director March 26, 2003
- -------------------
David W. Sledge
40
CERTIFICATIONS
I, M. Jay Allison, Chief Executive Officer, certify that:
1. I have reviewed this annual report on Form 10-K of Comstock Resources,
Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements and other financial
information included in this annual report, fairly present in all material
respects the consolidated financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this annual
report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit committee
of registrant's board of directors (or persons performing the equivalent
functions):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: March 26, 2003 By: /s/ M. Jay ALLISON
-------------------
M. Jay Allison, Chief Executive Officer
41
CERTIFICATIONS
I, Roland O. Burns, Chief Financial Officer, certify that:
1. I have reviewed this annual report on Form 10-K of Comstock Resources,
Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements and other financial
information included in this annual report, fairly present in all material
respects the consolidated financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this annual
report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit committee
of registrant's board of directors (or persons performing the equivalent
functions):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: March 26, 2003 By: /s/ ROLAND O. BURNS
-------------------
Roland O. Burns, Chief Financial Officer
42
CONSOLIDATED FINANCIAL STATEMENTS OF
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
INDEX
Independent Auditors' Report................................................F-2
Consolidated Balance Sheets as of December 31, 2001 and 2002................F-3
Consolidated Statements of Operations for the Years Ended
December 31, 2000, 2001 and 2002...................................F-4
Consolidated Statements of Stockholders' Equity and Comprehensive Income
for the Years Ended December 31, 2000, 2001 and 2002..............F-5
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2000, 2001 and 2002..................................F-6
Notes to Consolidated Financial Statements..................................F-7
F-1
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Comstock Resources, Inc.:
We have audited the accompanying consolidated balance sheets of Comstock
Resources, Inc. and subsidiaries as of December 31, 2001 and 2002, and the
related consolidated statements of operations, stockholders' equity and
comprehensive income, and cash flows for each of the three years in the period
ended December 31, 2002. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. 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, 2001 and 2002, and the results of their
operations and their cash flows for each of the years in the three year period
ended December 31, 2002, in conformity with accounting principles generally
accepted in the United States of America.
As explained in Note 1 of the financial statements effective January 1, 2001,
the Company changed its method of accounting for derivative instruments.
As discussed in Note 13 to the accompanying consolidated financial statements,
the Company has restated the consolidated balance sheet as of December 31, 2001,
and the related consolidated statements of operations, stockholders' equity and
comprehensive income, and cash flows for the two year period then ended, which
consolidated financial statements were previously audited by other independent
auditors who have ceased operations.
KPMG LLP
Dallas, Texas
March 19, 2003
F-2
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31, 2001 and 2002
ASSETS
December 31,
----------------------
2001 2002
--------- ---------
Restated
(In thousands)
Cash and Cash Equivalents ................................................. $ 6,122 $ 1,682
Accounts Receivable:
Oil and gas sales ............................................... 20,015 30,135
Joint interest operations ....................................... 4,717 5,407
Derivatives ............................................................... 1,342 --
Other Current Assets ...................................................... 7,418 2,678
--------- ---------
Total current assets ............................................ 39,614 39,902
Property and Equipment:
Unevaluated oil and gas properties .............................. 11,609 14,880
Oil and gas properties, successful efforts method ............... 900,711 961,562
Other ........................................................... 2,633 2,570
Accumulated depreciation, depletion and amortization ............ (278,679) (314,804)
--------- ---------
Net property and equipment ...................................... 636,274 664,208
Derivatives ............................................................... 254 3
Other Assets .............................................................. 4,627 6,940
--------- ---------
$ 680,769 $ 711,053
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Portion of Long-Term Debt ......................................... $ 229 $ 270
Accounts Payable and Accrued Expenses ..................................... 38,812 49,470
Derivatives ............................................................... 798 57
--------- ---------
Total current liabilities ....................................... 39,839 49,797
Long-Term Debt, less current portion ...................................... 372,235 366,002
Deferred Taxes Payable .................................................... 46,607 52,577
Derivatives ............................................................... 1,053 --
Reserve for Future Abandonment Costs ...................................... 7,794 16,677
Redeemable Convertible Preferred Stock--$10.00 par, liquidation value
of $17,573,000, 5,000,000 shares authorized, 1,757,310 shares issued
and outstanding ...................................................... 17,573 17,573
Stockholders' Equity:
Common stock--$0.50 par, 50,000,000 shares authorized,
28,552,553 and 28,919,561 shares issued and outstanding at
December 31, 2001 and 2002, respectively ..................... 14,276 14,460
Additional paid-in capital ...................................... 130,956 133,828
Retained earnings ............................................... 51,762 61,663
Deferred compensation-restricted stock grants ................... (1,187) (1,487)
Accumulated other comprehensive loss ............................ (139) (37)
--------- ---------
Total stockholders' equity ...................................... 195,668 208,427
--------- ---------
$ 680,769 $ 711,053
========= =========
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, 2000, 2001 and 2002
2000 2001 2002
--------- --------- ---------
(Restated) (Restated)
(In thousands, except per share amounts)
Oil and gas sales ........................... $ 168,084 $ 166,118 $ 142,085
Operating expenses:
Oil and gas operating .................. 29,277 31,855 33,499
Exploration ............................ 3,505 6,611 5,479
Depreciation, depletion and amortization 44,472 48,790 54,405
Impairment ............................. -- 1,400 --
General and administrative, net ........ 3,537 4,351 5,113
--------- --------- ---------
Total operating expenses ...... 80,791 93,007 98,496
--------- --------- ---------
Income from operations ...................... 87,293 73,111 43,589
Other income (expenses):
Interest income ........................ 230 196 62
Interest expense ....................... (24,611) (20,737) (30,002)
Gain (loss) from derivatives ........... -- 243 (2,326)
Other income ........................... 122 272 8,027
--------- --------- ---------
(24,259) (20,026) (24,239)
--------- --------- ---------
Income from continuing operations
before income tax expense ....... 63,034 53,085 19,350
Income tax expense .......................... (22,061) (18,579) (6,773)
--------- --------- ---------
Net income from continuing operations ....... 40,973 34,506 12,577
Discontinued operations including loss on
disposal, net of income taxes .......... 227 396 (1,072)
--------- --------- ---------
Net income .................................. 41,200 34,902 11,505
Preferred stock dividends ................... (2,471) (1,604) (1,604)
--------- --------- ---------
Net income attributable to common stock ..... $ 38,729 $ 33,298 $ 9,901
========= ========= =========
Net income per share from
continuing operations:
Basic.......................... $ 1.46 $ 1.13 $ 0.38
========= ========= =========
Diluted........................ $ 1.20 $ 1.00 $ 0.37
========= ========= =========
Net income per share:
Basic.......................... $ 1.47 $ 1.15 $ 0.34
========= ========= =========
Diluted........................ $ 1.20 $ 1.01 $ 0.34
========= ========= =========
Weighted average shares outstanding:
Basic.......................... 26,290 29,030 28,764
========= ========= =========
Diluted........................ 34,219 34,552 33,901
========= ========= =========
The accompanying notes are an integral part of these statements.
F-4
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
AND COMPREHENSIVE INCOME
For the Years Ended December 31, 2000, 2001 and 2002
Deferred Accumulated
Additional Retained Compensation Other
Common Paid-In Earnings Restricted Comprehensive
Stock Capital (Deficit) Stock Grants Loss Total
--------- --------- --------- ------------ --------- --------
(In thousands)
Balance at December 31, 1999... $ 12,688 $ 114,855 $ (19,603) $ (766) $ -- $ 107,174
Adjustment................... -- -- (662) -- -- (662)
--------- --------- --------- --------- --------- --------
Balance at
December 31, 1999 (Restated) 12,688 114,855 (20,265) (766) -- 106,512
Conversion of preferred stock.. 1,553 10,874 -- -- -- 12,427
Issuance of common stock....... 150 706 -- -- -- 856
Value of stock options issued
for exploration prospects.. -- 2,990 -- -- -- 2,990
Restricted stock grants......... 28 471 -- (278) -- 221
Net income attributable to
common stock (Restated).... -- -- 38,729 -- -- 38,729
--------- --------- --------- --------- --------- ---------
Balance at
December 31, 2000 (Restated) 14,419 129,896 18,464 (1,044) -- 161,735
--------- --------- --------- --------- --------- ---------
Issuance of common stock...... 283 3,538 -- -- -- 3,821
Value of stock options issued
for exploration prospects.. -- 1,968 -- -- -- 1,968
Restricted stock grants.......... 28 333 -- (143) -- 218
Repurchases of common stock...... (454) (4,779) (5,233)
Net income attributable to
common stock (Restated).... -- -- 33,298 -- -- 33,298
Unrealized hedge losses.......... -- -- -- -- (139) (139)
---------
Comprehensive income (Restated). -- -- -- -- -- 33,159
--------- --------- --------- --------- --------- ---------
Balance at
December 31, 2001 (Restated) 14,276 130,956 51,762 (1,187) (139) 195,668
--------- --------- --------- --------- --------- ---------
Issuance of common stock....... 156 1,547 -- -- -- 1,703
Value of stock options issued
for exploration prospects.. -- 836 -- -- -- 836
Restricted stock grants.......... 28 489 -- (300) -- 217
Net income attributable to
common stock............... -- -- 9,901 -- -- 9,901
Unrealized hedge gains........... -- -- -- -- 102 102
---------
Comprehensive income........... -- -- -- -- -- 10,003
--------- --------- --------- --------- --------- ---------
Balance at December 31, 2002..... $ 14,460 $ 133,828 $ 61,663 $ (1,487) $ (37) $ 208,427
========= ========= ========= ========= ========= =========
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, 2000, 2001 and 2002
2000 2001 2002
--------- --------- ---------
(Restated) (Restated)
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ..................................................... $ 41,200 $ 34,902 $ 11,505
Adjustments to reconcile net income to net cash
provided by operating activities, net of acquisition effects:
Compensation paid in common stock ............................ 314 244 218
Depreciation, depletion and amortization ..................... 44,472 48,790 54,405
Impairment of oil and gas properties ......................... -- 1,400 --
Deferred income taxes ........................................ 22,061 17,799 6,773
Dry hole costs ............................................... 3,192 4,215 5,139
Gain on sales of property .................................... (33) (12) --
Unrealized gain on derivatives ............................... -- (254) (119)
Non-cash effect of discontinued operations, net .............. 608 614 1,395
--------- --------- ---------
Working capital provided by operations ..................... 111,814 107,698 79,316
Decrease (increase) in accounts receivable ..................... (15,596) 18,371 (10,810)
Decrease (increase) in other current assets .................... (1,585) (1,229) 4,740
Increase (decrease) in accounts payable and
accrued expenses ............................................. 10,440 (16,204) 11,191
--------- --------- ---------
Net cash provided by operating activities .................. 105,073 108,636 84,437
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sales of properties .............................. 33 45 3,478
Capital expenditures and acquisitions .......................... (83,911) (188,192) (83,381)
--------- --------- ---------
Net cash used for investing activities ..................... (83,878) (188,147) (79,903)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings ..................................................... 18,408 261,730 31,736
Proceeds from senior notes offering ............................ -- -- 75,000
Debt issuance costs ............................................ -- -- (2,267)
Principal payments on debt ..................................... (38,438) (178,355) (112,928)
Proceeds from common stock issuances ........................... 763 1,989 1,089
Repurchases of common stock .................................... -- (5,232) --
Dividends paid on preferred stock .............................. (2,471) (1,604) (1,604)
--------- --------- ---------
Net cash provided by (used for) financing activities ....... (21,738) 78,528 (8,974)
--------- --------- ---------
Net decrease in cash and cash equivalents .................. (543) (983) (4,440)
Cash and cash equivalents, beginning of year ............... 7,648 7,105 6,122
--------- --------- ---------
Cash and cash equivalents, end of year ..................... $ 7,105 $ 6,122 $ 1,682
========= ========= =========
The accompanying notes are an integral part of these statements.
F-6
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Summary of Significant Accounting Policies
Accounting policies used by Comstock Resources, Inc. ("Comstock" or the
"Company") reflect oil and natural gas industry practices and conform to
accounting principles generally accepted in the United States of America.
Basis of Presentation and Principles of Consolidation
Comstock is engaged in oil and natural gas exploration, development and
production, and the acquisition of producing oil and natural gas properties. The
consolidated financial statements include the accounts of Comstock and its
wholly owned subsidiaries. All significant intercompany accounts and
transactions have been eliminated in consolidation.
Use of Estimates in the Preparation of Financial Statements
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 amounts could differ from those estimates. Changes in
the future estimated oil and natural gas reserves or the estimated future cash
flows attributable to the reserves that are utilized for impairment analysis
could have a significant impact on the future results of operations.
Other Current Assets
Other current assets at December 31, 2001 and 2002 consists of the
following:
As of December 31,
----------------------
2001 2002
------ ------
(In thousands)
Prepaid expenses .................. $3,602 $1,109
Income tax receivable ............. 3,347 --
Insurance claims receivable ....... 58 1,125
Inventory ......................... 411 444
------ ------
$7,418 $2,678
====== ======
Property and Equipment
Comstock follows the successful efforts method of accounting for its oil
and natural gas properties. Acquisition costs for proved oil and natural gas
properties, costs of drilling and equipping productive wells, and costs of
unsuccessful development wells are capitalized and amortized on an equivalent
unit-of- production basis over the life of the remaining related oil and gas
reserves. Equivalent units are determined by converting oil to natural gas at
the ratio of six barrels of oil for one thousand cubic feet of natural gas. Cost
centers for amortization purposes are determined on a field area basis. The
estimated future costs of dismantlement, restoration and abandonment are
included on the balance sheet in the reserve for future abandonment and accrued
as part of depreciation, depletion and amortization expense. Costs incurred to
F-7
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
acquire oil and gas leasehold are capitalized. Unproved oil and gas properties
are periodically assessed and any impairment in value is charged to exploration
expense. The costs of unproved properties which are determined to be productive
are transferred to proved oil and gas properties and amortized on an equivalent
unit of production basis. Exploratory expenses, including geological and
geophysical expenses and delay rentals for unevaluated oil and gas properties,
are charged to expense as incurred. Exploratory drilling costs are initially
capitalized as unproved property but charged to expense if and when the well is
determined not to have found proved oil and gas reserves.
In accordance with the Statement of Financial Accounting Standards No. 144
"Accounting for the Impairment or Disposal of Long-Lived Assets," ("SFAS 144")
Comstock assesses the need for an impairment of the costs capitalized of its oil
and gas properties on a property or cost center 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 based on escalated prices and including probable
reserves, where appropriate. No impairment was required in 2000 or 2002. In 2001
Comstock provided an impairment of $1.4 million for certain of its oil and gas
properties.
Other property and equipment consists primarily of work boats, gas
gathering systems, computer equipment and furniture and fixtures which are
depreciated over estimated useful lives on a straight-line basis.
Other Assets
Other assets primarily consists of deferred costs associated with issuance
of Comstock's 11 1/4% senior notes. These costs are amortized over the eight
year life of the senior notes on a straight-line basis which approximates the
amortization that would be calculated using an effective interest rate method.
Stock Options
Comstock applies the intrinsic value-based method of accounting prescribed
by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees," ("APB 25") and related interpretations, in accounting for its
incentive plan stock options. As such, compensation expense would be recorded on
the date of grant only if the current market price of the underlying stock
exceeded the exercise price. Statement of Financial Accounting Standards 123,
"Accounting for Stock-Based Compensation," ("SFAS 123") established accounting
and disclosure requirements using a fair value-based method of accounting for
stock- based employee compensation plans. As allowed by SFAS 123, Comstock has
elected to continue to apply the intrinsic value-based method of accounting
described above, and has adopted the disclosure requirements of SFAS 123.
F-8
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following table illustrates the effect on net income if the
fair-value-based method had been applied to all outstanding stock options in
each period.
Year Ended December 31,
-------------------------------
2000 2001 2002
-------- -------- -------
(Restated) (Restated)
(In thousands, except per share amounts)
Net income, as reported ........................ $ 38,729 $ 33,298 $ 9,901
Add stock-based employee compensation expense
included in reported net income, net of tax 204 159 142
Deduct total stock-based employee compensation
expense determined under fair-value-based
method for all rewards, net of tax ........ (2,178) (1,845) (1,066)
-------- -------- -------
Pro forma net income ............... $ 36,755 $ 31,612 $ 8,977
======== ======== =======
Basic earnings per share: As Reported......... $1.47 $1.15 $0.34
Pro Forma........... $1.40 $1.09 $0.31
Diluted earnings per share: As Reported......... $1.20 $1.01 $0.34
Pro Forma........... $1.15 $0.96 $0.31
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 2000, 2001 and 2002, respectively: average
risk-free interest rates of 6.2, 4.9 and 3.8 percent; average expected lives of
7.8, 7.4 and 5.9 years; average expected volatility factors of 66.4, 67.2 and
68.9; 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 Plans was $5.98 in 2000, $6.80 in 2001 and $5.88 in 2002.
Segment Reporting
Comstock presently operates in one business segment, the exploration and
production of oil and natural gas.
Derivative Instruments and Hedging Activities
On January 1, 2001, Comstock adopted Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" ("SFAS 133") which requires that every derivative instrument
(including certain derivative instruments embedded in other contracts) be
recorded on the balance sheet as either an asset or liability measured at its
fair value. SFAS 133 requires that changes in the derivative's fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met. Comstock estimates fair value based on quotes obtained from the
counterparties to the derivative contract. The fair value of derivative
contracts that expire in less than one year are recognized as current assets or
liabilities. Those that expire in more than one year are recognized as long-term
F-9
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
assets or liabilities. Derivative financial instruments that are not accounted
for as hedges are adjusted to fair value through income. If the derivative is
designated as a cash flow hedge, changes in fair value are recognized in other
comprehensive income until the hedged item is recognized in earnings.
Major Purchasers
In 2002, Comstock had two purchasers of its oil and natural gas production
which individually accounted for more than 10% of total oil and gas sales. Such
purchasers accounted for 16% and 15% of total 2002 oil and gas sales.
In 2001, Comstock had four purchasers which accounted for 24%, 19%, 16% and
12% of total 2001 oil and gas sales. In 2000, Comstock had three purchasers
which accounted for 29%, 21% and 11% of total 2000 oil and gas sales.
Revenue Recognition and Gas Balancing
Comstock utilizes the sales method of accounting for natural gas revenues
whereby revenues are recognized based on the amount of gas sold to purchasers.
The amount of gas sold may differ from the amount to which the Company is
entitled based on its revenue interests in the properties. Comstock did not have
any significant imbalance positions at December 31, 2000, 2001 or 2002.
General and Administrative Expenses
General and administrative expenses are reported net of reimbursements of
overhead costs that are allocated to working interest owners of the oil and gas
properties operated by Comstock.
Other Income
Included in other income in 2002 was $7.7 million related to refunds
received in 2002 of severance taxes paid in prior years.
Income Taxes
Comstock accounts for income taxes using the asset and liability method,
whereby deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial statement
carrying amounts of assets and liabilities and their respective tax bases, as
well as the future tax consequences attributable to the future utilization of
existing tax net operating loss and other types of carryforwards. Deferred tax
assets and liabilities are measured using enacted tax rates expected to apply to
taxable income in the years in which those temporary differences and
carryforwards are expected to be recovered or settled. The effect on deferred
tax assets and liabilities of a change in tax rates is recognized in income in
the period that includes the enactment date.
Comprehensive Income
Comprehensive income is defined as the change in equity of a business
enterprise during a period from transactions and other events and circumstances
from non-owner sources.
F-10
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
For the years ended December 31, 2001 and 2002,Comstock's comprehensive
income differed from net income by approximately $139,000 and $102,000,
respectively due to the recognition in comprehensive income of unrealized gains
or losses related to certain of Comstock's derivative instruments which have
been designated as hedges. For the year ended December 31, 2000, there were no
differences between Comstock's net income or net loss and comprehensive income.
Earnings Per Share
Basic and diluted earnings per share for 2000, 2001 and 2002 were
determined as follows:
Year Ended December 31,
----------------------------------------------------------------------------------------------
2000 2001 2002
----------------------------- ----------------------------- -----------------------------
Per Per Per
Income Shares Share Income Shares Share Income Shares Share
-------- ------- ------- -------- ------- ------- -------- ------- -------
(Restated) (Restated)(Restated) (Restated)
(In thousands except per share data)
Basic Earnings Per Share:
Income from
Continuing Operations.. $ 40,973 26,290 $ 34,506 29,030 $ 12,577 28,764
Less Preferred Stock
Dividends.............. (2,471) -- (1,604) -- (1,604) --
-------- ------- -------- ------- -------- --------
Net Income from
Continuing Operations
Available to Common
Stockholders..... 38,502 26,290 $1.46 32,902 29,030 $1.13 10,973 28,764 $0.38
======= ======= ========
Income from
Discontinued Operations 227 26,290 0.01 396 29,030 0.02 (1,072) 28,764 (0.04)
-------- ======= ------ -------- ======= ------- -------- ======== -------
Net Income Available to
Common Stockholders.... $ 38,729 26,290 $1.47 $ 33,298 29,030 $1.15 $ 9,901 28,764 $0.34
======== ======= ====== ======== ======= ======= ======== ======== =======
Diluted Earnings Per Share:
Income from
Continuing Operations $ 40,973 26,290 $ 34,506 29,030 $ 12,577 28,764
Effect of Dilutive
Securities:
Stock Options.............. -- 1,184 -- 1,129 -- 744
Convertible Preferred Stock -- 6,745 -- 4,393 -- 4,393
-------- ------- -------- ------- -------- --------
Net Income from
Continuing Operations
Available to Common
Stockholders With
Assumed Conversions.... 40,973 34,219 $1.20 34,506 34,552 $1.00 12,577 33,901 $0.37
======= ======= ========
Income from
Discontinued Operations. 227 34,219 -- 396 34,552 0.01 (1,072) 33,901 (0.03)
-------- ======== ------ -------- ======= -------- -------- ======== -------
Net Income Available to
Common Stockholders...... $ 41,200 34,219 $1.20 $ 34,902 34,552 $1.01 $ 11,505 33,901 $0.34
======== ======== ====== ======== ======= ======== ======== ======== =======
Stock options and warrants to purchase common stock at exercise prices in excess
of the average actual stock price for the period that were anti-dilutive and
that were excluded from the determination of diluted earnings per share are as
follows:
2000 2001 2002
-------------- --------------- ----------------
(In thousands except per share data)
Stock options and warrants to
purchase common stock.......... 2,979 2,559 2,737
Exercise Price.................... $8.88 - $14.00 $9.63 - $14.00 $8.06 - $14.00
F-11
Statements of Cash Flows
For the purpose of the consolidated statements of cash flows, Comstock
considers all highly liquid investments purchased with an original maturity of
three months or less to be cash equivalents.
The following is a summary of all significant noncash investing and
financing activities and cash payments made for interest and income taxes:
Year Ended December 31,
--------------------------
2000 2001 2002
------- ------- -------
(in thousands)
Noncash activities -
Common stock issued for director compensation................. $ 93 $ 26 $ --
Value of vested stock options under exploration venture....... 2,990 3,028 1,286
Cash payments -
Interest payments............................................. $24,731 $20,837 $28,987
Income tax payments........................................... -- 243 --
New Accounting Standards
In August 2001, the Financial Accounting Standards Board (the "FASB")
issued Statement of Financial Accounting Standards No. 143 ("SFAS 143")
"Accounting for Asset Retirement Obligations," which Comstock adopted effective
January 1, 2003. This statement requires Comstock to record a liability in the
period in which an asset retirement obligation ("ARO") is incurred. Upon
recognition of an ARO liability, additional asset cost would be capitalized to
equal the amount of the liability. Upon the initial adoption of SFAS 143,
Comstock recognized a liability for any existing AROs not already provided for
in Comstock's reserve for future abandonment costs. Comstock also recognized
additional capitalized cost related to the additional liability and accumulated
depreciation on the additional capitalized cost.
Under SFAS 143, Comstock estimates that its total ARO for its oil and
natural gas properties is approximately $15.2 million which was $1.5 million
less than the liability that Comstock had provided for in its reserve for future
abandonment as of December 31, 2002. The impact of adopting SFAS 143, which will
be recorded as the cumulative effect of an accounting change, was an increase to
net income of approximately $0.7 million, net of tax.
In June 2002, the FASB issued Statement of Financial Accounting Standards
146, "Accounting for Costs Associated with Exit or Disposal Activities" ("SFAS
146"). The Statement establishes accounting and reporting standards that are
effective for exit or disposal activities beginning after December 31, 2002
which require that a liability be recognized for an exit or disposal activity
when that liability is incurred. Comstock has not determined the effect, if any,
that the adoption of SFAS 146 will have on its financial statements.
F-12
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
In December 2002, the FASB issued Statement of Financial Accounting
Standards No. 148, "Accounting for Stock-Based Compensation - Transition and
Disclosure, an amendment of FASB Statement No. 123". This Statement amends No.
123, "Accounting for Stock-Based Compensation," to provide alternative methods
of transition for a voluntary change to the fair value method of accounting for
stock-based employee compensation. In addition, this statement amends the
disclosure requirements of SFAS 123 to require prominent disclosures in both
annual and interim financial statements. Certain of the disclosure modifications
are included in the notes to these consolidated financial statements.
In January 2003, the FASB issued Interpretation ("FIN") No. 45,
"Guarantor's Accounting and Disclosure Requirement for Guarantees, including
Indirect Guarantees of Indebtedness of Others." FIN 45 requires an entity to
recognize a liability for the obligations it has undertaken in issuing a
guarantee. This liability would be recorded at the inception of a guarantee and
would be measured at fair value. Certain guarantees are excluded from the
measurement and disclosure provisions while certain other guarantees are
excluded from the measurement provisions of the interpretation. The measurement
provisions of this statement apply prospectively to guarantees issued or
modified after December 31, 2002. The disclosure provisions of the statement
apply to financial statements for periods ending after December 15, 2002. The
adoption of the statement is not expected to have a material effect on the
Company's financial statements when adopted.
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities." FIN 46 requires an entity to consolidate a variable
interest entity if it is designated as the primary beneficiary of that entity
even if the entity does not have a majority of voting interests. A variable
interest entity is generally defined as an entity where its equity is unable to
finance its activities or where the owners of the entity lack the risk and
rewards of ownership. The provisions of this statement apply at inception for
any entity created after January 31, 2003. For an entity created before February
1, 2003, the provisions of this interpretation must be applied at the beginning
of the first interim or annual period beginning after June 15, 2003. Comstock is
not the primary beneficiary of any variable interest entities, and accordingly,
the adoption of FIN 46 is not expected to have a material effect on the
Company's financial statements when adopted.
(2) Acquisitions
In December 2002, Comstock acquired interests in the Ship Shoal 113 Unit
for $7.8 million. The acquisition included interest in 26 producing wells, 11.7
net wells, and seven production facilities in the Gulf of Mexico. Comstock also
acquired interests in a South Texas field for $1.7 million in December 2002. The
acquisition included interest in 15 producing wells, 15 net wells, and over
7,000 acres. Comstock plans to redevelop these fields in the future.
F-13
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
On December 17, 2001, Comstock completed the acquisition of DevX Energy,
Inc. ("DevX") by acquiring 100% of the common stock of DevX for $92.6 million
through a cash tender offer and subsequent merger into a wholly owned
subsidiary. As a result of the acquisition, DevX became a wholly owned
subsidiary of Comstock. DevX is an independent energy company engaged in the
exploration, development and acquisition of oil and gas properties. DevX owns
interests in 600 producing oil and gas wells located onshore primarily in East
and South Texas, Kentucky, Oklahoma and Kansas. The DevX acquisition added
approximately 163.4 billion cubic feet equivalent of natural gas reserves to
Comstock's reserve base (unaudited). Subsequent to the acquisition, Comstock
repurchased approximately $49.8 million of DevX's 12 1/2% senior notes which
were due in 2008 for 110% of the principal amount plus accrued interest.
DevX's operations have been included in the consolidated financial
statements since December 17, 2001.
The following table summarizes the estimated fair values of the assets
acquired and liabilities assumed at the date of the acquisition.
December 17, 2001
-----------------
(in thousands)
Current assets .......... $ 8,317
Oil and gas properties .. 160,794
Derivatives ............. 1,577
--------
Total assets acquired ... 170,688
--------
Current liabilities ..... 8,990
Long-term debt .......... 54,988
Deferred tax liability .. 7,324
Derivatives ............. 1,873
--------
Total liabilities assumed 73,175
--------
Net assets acquired ..... $ 97,513
========
Set forth in the following table is certain unaudited pro forma financial
information for the years ended December 31, 2000 and 2001. This information has
been prepared assuming the DevX acquisition was consummated on January 1, 2000
and is based on estimates and assumptions deemed appropriate by Comstock. The
pro forma information is presented for illustrative purposes only. If the
transactions had occurred in the past, Comstock's operating results might have
been different from those presented in the following table. The pro forma
information should not be relied upon as an indication of the operating results
that Comstock would have achieved if the transactions had occurred on January 1,
2000. The pro forma information also should not be used as an indication of the
future results that Comstock will achieve after the acquisition. Adjustments
were made to adjust the historical operating results of DevX (i) to conform DevX
to the successful efforts method of accounting for oil and gas activities; (ii)
to reverse the costs of the closed Dallas and Ottawa corporate offices of DevX;
and (iii) to record the pro forma interest expense based on Comstock's average
interest rate under its bank credit facility.
F-14
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Year Ended December 31,
------------------------
2000 2001
--------- ---------
(Restated) (Restated)
(In thousands,
except per share amounts)
Oil and gas sales ........................ $ 210,289 $ 204,717
Total operating expenses ................. (103,005) (113,349)
Total other income (expenses) ............ (36,602) (24,947)
--------- ---------
Income from continuing operations
before income taxes ........... 70,682 66,421
Provision for income taxes ............... (24,738) (23,247)
--------- ---------
Income from continuing operations ... 45,944 43,174
Discontinued operations .................. 227 396
--------- ---------
Net income .......................... 46,171 43,570
Preferred stock dividends ................ (2,471) (1,604)
--------- ---------
Net income from continuing operations
attributable to common stock $ 43,700 $ 41,966
========= =========
Net income from continuing
operations per share:
Basic................................. $ 1.65 $ 1.42
========= =========
Diluted............................... $ 1.34 $ 1.24
========= =========
Net income per share:
Basic................................. $ 1.66 $ 1.45
========= =========
Diluted............................... $ 1.35 $ 1.26
========= =========
(3) Oil and Gas Producing Activities
Set forth below is certain information regarding the aggregate capitalized
costs of oil and gas properties and costs incurred by Comstock for its oil and
gas property acquisition, development and exploration activities:
Capitalized Costs
As of December 31,
-----------------------
2001 2002
--------- ---------
(Restated)
(In thousands)
Proved properties .............. $ 900,711 $ 961,562
Unproved properties ............ 11,609 14,880
Accumulated depreciation,
depletion and amortization (277,670) (313,608)
--------- ---------
$ 634,650 $ 662,834
========= =========
F-15
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Costs Incurred
For the Year Ended December 31,
-----------------------------------
2000 2001 2002
-------- -------- -------
(Restated) (Restated)
(In thousands)
Property acquisitions
Proved properties ............... $ 9,684 $160,794 $11,435
Unproved properties ............. 5,863 7,113 4,268
Development costs ..................... 48,546 51,090 35,272
Exploration costs ..................... 19,515 35,778 31,414
-------- -------- -------
$ 83,608 $254,775 $82,389
======== ======== =======
Due to the tax-free nature of the merger between Comstock and DevX in
December 2001, additional deferred tax liabilities of $7.3 million were
allocated to proved oil and gas properties and are included in the proved
property acquisition costs in 2001.
In 2001 and 2002, Comstock capitalized interest expense of $230,000 and
$281,000, respectively, on its unproved properties under development which is
included in the unproved property acquisition costs in each year.
Results of Operations for Oil and Gas Producing Activities
The following table includes revenues and expenses associated directly with
Comstock's oil and natural gas producing activities. The amounts presented do
not include any allocation of Comstock's interest costs or general corporate
overhead and, therefore, are not necessarily indicative of the contribution to
net earnings of Comstock's oil and gas operations. Income tax expense has been
calculated by applying statutory income tax rates to oil and gas sales after
deducting costs, including depreciation, depletion and amortization and after
giving effect to permanent differences.
For the Year Ended December 31,
----------------------------------
2000 2001 2002
--------- --------- ---------
(Restated) (Restated)
(In thousands)
Oil and gas sales ............................................. $ 168,084 $ 166,118 $ 142,085
Oil gas operating ............................................. (29,277) (31,855) (33,499)
Exploration ................................................... (3,505) (6,611) (5,479)
Depreciation, depletion and amortization ...................... (42,992) (47,140) (52,869)
Impairment .................................................... -- (1,400) --
--------- --------- ---------
Income from continuing operations ......................... 92,310 79,112 50,238
Provision for income taxes .................................... (32,309) (27,689) (17,583)
--------- --------- ---------
Income from continuing operations, after tax .............. 60,001 51,423 32,655
Discontinued operations, including loss on disposal,
net of income taxes ...................... 227 396 (1,072)
--------- --------- ---------
Results of operations of oil and gas producing activities . $ 60,228 $ 51,819 $ 31,583
========= ========= =========
F-16
(4) Long-Term Debt
Long-term debt is comprised of the following:
As of December 31,
2001 2002
--------- ---------
(In thousands)
Revolving Bank Credit Facility ............. $ 227,000 $ 146,000
11 1/4% Senior Notes due 2007 .............. 145,000 220,000
Other ...................................... 464 272
--------- ---------
372,464 366,272
Less current portion ....................... (229) (270)
--------- ---------
$ 372,235 $ 366,002
========= =========
On December 17, 2001, Comstock entered into a bank credit facility which
consists of a $350.0 million three year revolving credit commitment provided by
a syndicate of banks for which Toronto Dominion (Texas), Inc. serves as
administrative agent. The bank credit facility is subject to borrowing base
availability, which is redetermined semiannually based on the banks' estimates
of the future net cash flows of Comstock's oil and natural gas properties. The
borrowing base at December 31, 2002 was $240.0 million. The revolving credit
line bears interest, based on the utilization of the borrowing base, at the
option of Comstock at either (i) LIBOR plus 1.5% to 2.375% or (ii) the corporate
base rate (generally the federal funds rate plus 0.5%) plus 0.5% to 1.375%. The
facility matures on January 2, 2005. Indebtedness under the bank credit facility
is secured by substantially all of Comstock's and its subsidiaries' assets and
Comstock's subsidiaries are guarantors of the bank credit facility. The bank
credit facility contains covenants that, among other things, restrict the
payment of cash dividends, limit the amount of consolidated debt and limit
Comstock's ability to make certain loan and investments. Financial covenants
include the maintenance of a current ratio, maintenance of tangible net worth
and maintenance of an interest coverage ratio. The Company was in compliance
with these covenants as of December 31, 2002.
Comstock issued $150.0 million in aggregate principal amount of 11 1/4%
Senior Notes due in 2007 (the "Notes") on April 29, 1999. Interest on the Notes
is payable semiannually on May 1 and November 1, commencing on November 1, 1999.
The Notes are unsecured obligations of Comstock and are guaranteed by all of its
principal operating subsidiaries. Comstock repurchased $5.0 million of the Notes
in July 2001. The Notes can be redeemed beginning on May 1, 2004. On March 7,
2002, Comstock closed the sale in a private placement of $75.0 million of
additional Notes at a net price of 97.25% after the placements agents' discount.
As a result of this transaction, $220.0 million of aggregate principal amount of
the Notes are outstanding. The fair market value of the Notes as of December 31,
2002 was $233.2 million based on the market price of 106% of the face amount as
of December 31, 2002.
F-17
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following table summarizes our debt by year of maturity:
2003 2004 2005 2006 2007 Thereafter Total
------- -------- -------- -------- -------- -------- --------
(In thousands)
Bank credit facility $ -- $ -- $146,000 $ -- $ -- $ -- $146,000
Senior notes ....... -- -- -- -- 220,000 -- 220,000
Other debt ......... 270 -- -- -- -- 2 272
------- -------- -------- -------- -------- -------- --------
$ 270 -- $146,000 -- $220,000 $ 2 $366,272
======= ======== ======== ======== ======== ======== ========
(5) Commitments and Contingencies
Lease Commitments
Comstock rents office space under noncancelable leases. Rent expense for
the years ended December 31, 2000, 2001 and 2002 was $432,000, $526,000 and
$495,000, respectively. Minimum future payments under the leases are as follows:
(In thousands)
2003 $ 656
2004 452
2005 477
2006 198
2007 --
------
$1,783
======
Contingencies
From time to time Comstock is involved in certain litigation that arises in
the normal course of its operations. The Company records a loss contingency for
these matters when it is probable that a liability has been incurred and the
amount of the loss can be reasonably estimated. In 2002, Comstock accrued $1.5
million related to its estimate of losses to be incurred in resolving certain
contingencies. After consideration of amounts accrued, the Company does not
believe the resolution of these matters will have a material effect on the
Company's financial position or results of operations.
(6) Convertible Preferred Stock
On April 29, 1999, Comstock issued 3,000,000 shares of convertible
preferred stock (the "Series 1999 Preferred Stock") in a private placement and
received proceeds of $30.0 million. The Series 1999 Preferred Stock accrues
dividends at an annual rate of 9% which are payable quarterly in cash or
Comstock has the option to issue shares of Common Stock. Dividends paid per
share have been $0.91 per share in each of 2000, 2001 and 2002. Each share of
the Series 1999 Preferred Stock is convertible, at the option of the holder,
into 2.5 shares of Common Stock. On May 1, 2005 and on each May 1, thereafter,
so long as any shares of the Series 1999 Preferred Stock are outstanding,
Comstock is obligated to redeem an amount of shares of the Series 1999 Preferred
Stock equal to one-third of the shares of the Series 1999 Preferred Stock
outstanding on May 1, 2005 at $10.00 per share plus accrued and unpaid
dividends. The mandatory redemption amounts of the Series 1999 Preferred Stock
F-18
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
total $5.9 million per year for each of the years ended December 31, 2005, 2006
and 2007. The mandatory redemption price may be paid either in cash or in shares
of Common Stock, at the option of the Company. The fair value of the Series 1999
Preferred Stock at issuance date was equal to the mandatory redemption value.
Comstock has the option to redeem the shares of Series 1999 Preferred Stock upon
payment to the holders of the Series 1999 Preferred Stock at a specified rate of
return on the initial purchase. Upon a change of control of Comstock, the
holders of the Series 1999 Preferred Stock have the right to require Comstock to
purchase all or a portion of the Series 1999 Preferred Stock for cash. Due to
the change of control provision, the Series 1999 Preferred Stock has been
classified as temporary equity. The financial statements for prior years have
been reclassified to reflect the Series 1999 Preferred Stock outside of
stockholders' equity. On March 19, 2003, the terms of the Series 1999 Preferred
Stock were modified to allow the payment of the redemption after a change of
control in shares of Common Stock at the option of the Company. The holders of
the Series 1999 Preferred Stock similarly have the right to require the Company
to satisfy the redemption obligation with shares of Common Stock. Accordingly,
the Series 1999 Preferred Stock will be classified as part of the stockholders'
equity after this date.
In September and October 2000, holders of 1,242,690 shares of the Series
1999 Preferred Stock converted their shares into 3,106,725 shares of Common
Stock. As a result of these conversions, $12.4 million of preferred stock was
transferred to common stockholders' equity.
(7) Stockholders' Equity
The authorized capital stock of Comstock consists of 50 million shares of
common stock, par value $.50 per share (the "Common Stock"), and 5 million
shares of preferred stock, par value $10.00 per share. The preferred stock may
be issued in one or more series, and the terms and rights of such stock will be
determined by the Board of Directors.
Comstock's Board of Directors has designated 500,000 shares of the
preferred stock as Series B Junior Participating Preferred Stock (the "Series B
Junior Preferred Stock") in connection with the adoption of a shareholder rights
plan. At December 31, 2002 there were no shares of Series B Junior Preferred
Stock issued or outstanding. The Series B Junior Preferred Stock is entitled to
receive cumulative quarterly dividends per share equal to the greater of $1.00
or 100 times the aggregate per share amount of all dividends (other than stock
dividends) declared on Common Stock since the immediately preceding quarterly
dividend payment date or, with respect to the first payment date, since the
first issuance of Series B Junior Preferred Stock. Holders of the Series B
Junior Preferred Stock are entitled to 100 votes per share (subject to
adjustment to prevent dilution) on all matters submitted to a vote of the
stockholders. The Series B Junior Preferred Stock is neither redeemable nor
convertible. The Series B Junior Preferred Stock ranks prior to the Common Stock
but junior to all other classes of preferred 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, Comstock
issued 8,182 and 5,342 shares of Common Stock in 2000 and 2001, respectively, in
payment of fees aggregating $93,000 and $26,000 for 2000 and 2001, respectively.
Stock options were exercised to purchase 291,400 shares, 560,606 shares and
310,758 shares in 2000, 2001, and 2002, respectively. Such exercises yielded net
proceeds of approximately $763,000, $2.0 million and $1.1 million in 2000, 2001,
and 2002, respectively.
F-19
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
During 2001, Comstock repurchased 907,400 shares of Common Stock in open
market purchases totaling $5.2 million. Such shares were retired upon
repurchase.
Stock Options
On June 23, 1999, the stockholders approved the 1999 Long-term Incentive
Plan for the management including officers, directors and managerial employees
which replaced the 1991 Long-term Incentive Plan. The 1999 Long-term Incentive
Plan together with the 1991 Long-term Incentive Plan (the "Incentive Plans")
authorize the grant of non-qualified stock options and incentive stock options
and the grant of restricted stock to key executives of Comstock. As of December
31, 2002, the Incentive Plans provide for future awards of stock options or
restricted stock grants of up to 352,786 shares of Common Stock plus 1% of the
outstanding shares of Common Stock each year beginning on January 1, 2003.
The following table summarizes information about the Incentive Plans stock
options outstanding at December 31, 2002:
Number of Number of
Shares Weighted Average Shares
Exercise Price Outstanding Remaining Life Exercisable
-------------- ----------- ---------------- --------------
(Years)
$3.44 246,375 4.8 246,375
3.88 926,900 5.4 688,150
6.42 437,750 6.1 175,000
6.69 74,000 5.3 47,000
6.94 150,000 1.0 150,000
7.40 20,000 3.6 20,000
8.70 30,000 4.4 30,000
8.88 249,250 6.5 --
9.20 273,750 6.0 --
11.00 1,150,000 3.0 1,150,000
11.12 33,500 5.0 20,000
11.94 20,000 0.9 20,000
12.38 559,000 2.0 559,000
----------- ----------
4,170,525 4.3 3,105,525
=========== ==========
F-20
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following table summarizes stock option activity during 2000, 2001 and
2002 under the Incentive Plans:
Number Weighted Average
of Shares Exercise Price Exercise Price
-------------- ----------------- ----------------
Outstanding at December 31, 1999......... 4,630,000 $2.00 to $12.38 $7.08
Granted.......................... 351,250 $6.69 to $8.88 8.24
Exercised................................ (291,400) $2.00 to $4.81 2.62
--------------
Outstanding at December 31, 2000......... 4,689,850 $2.00 to $12.38 7.45
Granted.......................... 493,250 $6.42 to $11.12 6.80
Exercised................................ (580,450) $2.00 to $11.94 3.86
Forfeited........................ (213,000) $6.56 to $11.12 6.61
--------------
Outstanding at December 31, 2001......... 4,389,650 $2.50 to $12.38 7.89
Granted.......................... 303,750 $8.70 to $9.20 9.15
Exercised................................ (313,875) $2.50 to $6.69 3.55
Forfeited........................ (209,000) $9.63 to $11.94 10.52
--------------
Outstanding at December 31, 2002......... 4,170,525 $3.44 to $12.38 8.18
==============
Exercisable at December 31, 2002......... 3,105,525 $3.44 to $12.38 8.51
==============
Restricted Stock Grants
Under the Incentive Plans, officers and managerial employees may be granted
a right to receive shares of Common Stock without cost to the employee. The
shares vest over a specified period with credit given for past service rendered
to Comstock. Restricted stock grants for 56,250 shares were made in each of the
years 2000, 2001 and 2002. In the aggregate, 723,750 restricted stock grants
have been awarded under the Incentive Plans. As of December 31, 2002, 526,875
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, 2000, 2001 and 2002 was
$221,000, $218,000 and $217,000, respectively.
(8) Exploration Venture
On July 31, 2001, Comstock entered into a new exploration agreement with
Bois d' Arc Offshore, Ltd. and its principals ("Bois d' Arc"), which replaces an
exploration agreement entered into on December 8, 1997. The 2001 Exploration
Agreement established a joint exploration venture between Comstock and Bois d'
Arc covering the state coastal waters of Louisiana and Texas and corresponding
federal offshore waters in the Gulf of Mexico. The new venture was effective
April 1, 2001 and will end on December 31, 2006. Under the joint exploration
venture, Bois d' Arc generates exploration prospects in the Gulf of Mexico
utilizing 3-D seismic data and their extensive geological expertise in the
region. Comstock advances 100% of the funds for the acquisition of 3 D seismic
data and leases as needed. Comstock recovers its advances based on Bois d' Arc's
ability to sell interests in drillable prospects. Upon a sale of a successful
prospect by Bois d' Arc, Comstock is reimbursed for the costs that were advanced
and is entitled to a 40% non-promoted working interest in each prospect
generated. Comstock capitalizes advances made for leases as unevaluated
properties and expenses advances made for seismic costs as exploration costs.
F-21
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Under the exploration agreement, Bois d' Arc has the opportunity to earn
warrants to purchase up to 1,620,000 shares of Common Stock. Warrants to
purchase 60,000 shares are earned by Bois d' Arc for each prospect which results
in a successful discovery. The exercise price on the new warrants is determined
based on the current market price for the Common Stock on a semiannual basis
each year that the venture is in operation. The agreement requires that Comstock
must fund a minimum of $5.0 million for the acquisition of seismic data over the
term of the agreement or Bois d' Arc has the right to terminate the agreement.
Bois d' Arc earned warrants to purchase 360,000 and 240,000 shares under
the exploration agreement in 2001 and 2002, respectively. The warrants are
exercisable at a weighted average price of $7.51. The value of the warrants
based on the Black-Scholes option pricing model was $5.64 per option share or an
aggregate of $2.0 million in 2001 and $5.36 per option share or an aggregate of
$1.3 million in 2002. Such costs were capitalized as a cost of oil and gas
properties.
Bois d' Arc had also earned warrants to purchase 600,000 shares of Common
Stock at $14.00 per share under the prior exploration agreement during the
period from January 1998 to April 2001. The value of these warrants based on the
Black-Scholes option pricing model was $9.97 per option share. The estimated
value of $6.0 million for the warrants earned under the prior exploration
agreement were capitalized to oil and gas properties in 1998 through 2001.
(9) Retirement Plan
Comstock has a 401(k) Profit Sharing Plan which covers all of its
employees. At its discretion, Comstock may match a certain percentage of the
employees' contributions to the plan. The matching percentage is determined
annually by the Board of Directors. Comstock's matching contributions to the
plan were $84,000, $96,000 and $116,000 for the years ended December 31, 2000,
2001 and 2002, respectively.
(10) Income Taxes
The tax effects of significant temporary differences representing the net
deferred tax liability at December 31, 2001 and 2002 were as follows:
2001 2002
-------- --------
(Restated)
(In thousands)
Net deferred tax assets (liabilities):
Property and equipment ............. $(73,965) $(88,931)
Net operating loss carryforwards ... 34,504 43,037
Valuation allowance on net operating
loss carryforwards ............... (8,043) (8,043)
Other carryforwards ................ 897 1,360
-------- --------
$(46,607) $(52,577)
======== ========
F-22
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following is an analysis of the consolidated income tax expense:
2001 2002
------- -------
(Restated)
(In thousands)
Current.............. $ -- $ --
Deferred ............ 18,579 6,773
------- ------
$18,579 $6,773
======= ======
There were no significant differences between income taxes computed using
the statutory rate of 35% and Comstock's effective tax rate in 2000, 2001 and
2002 of 35%.
At December 31, 2002, Comstock had the following carryforwards available to
reduce future income taxes:
Years of
Expiration
Types of Carryforward Carryforward Amounts
- ----------------------------------------- ----------------- ---------------
(In thousands)
Net operating loss - U.S. federal........ 2018 - 2022 $122,964
Alternative minimum tax credits.......... Unlimited 1,220
Charitable contributions carryforward.... 2003 - 2007 400
The utilization of $42.9 million of the net operating loss carryforwards of
DevX are limited to approximately $1.1 million per year pursuant to a prior
change of control. Accordingly, a valuation allowance of $23.0 million, with a
tax effect of $8.0 million, has been established for Comstock's estimate of
DevX's net operating loss carryforwards that it will not be able to utilize.
Realization of Comstock's and DevX's net operating carryforwards requires
Comstock to generate taxable income within the carryforward period.
(11) Derivatives and Hedging Activities
Comstock uses swaps, floors and collars to hedge oil and natural gas
prices. Swaps are settled monthly based on differences between the prices
specified in the instruments and the settlement prices of futures contracts
quoted on the New York Mercantile Exchange. Generally, when the applicable
settlement price is less than the price specified in the contract, Comstock
receives a settlement from the counterparty based on the difference multiplied
by the volume hedge. Similarly, when the applicable settlement price exceeds the
price specified in the contract, Comstock pays the counterparty based on the
difference. Comstock generally receives a settlement from the counterparty for
floors when the applicable settlement price is less than the price specified in
the contract, which is based on the difference multiplied by the volumes hedged.
For collars, generally Comstock receives a settlement from the counterparty when
the settlement price is below the floor and pays a settlement to the
counterparty when the settlement price exceeds the cap. No settlement occurs
when the settlement price falls between the floor and cap.
F-23
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following table sets out the derivative financial instruments
outstanding at December 31, 2002 which are held for natural gas price risk
management:
Volume Type Floor
Period Beginning Period Ending (MMBtu) of Instrument Price
- ------------------ ------------------ ------------ -------------- ---------
January 1, 2003 December 31, 2003 2,250,000 Floor $2.00
The fair value of the commodity price derivative financial instruments at
December 31, 2002 was a net asset of $3,000. In 2002, Comstock hedged a portion
of its natural gas production for the period April 2002 through October 2002.
The Company entered into price swaps covering 50 MMBtus per day of its natural
gas production at an average price of $3.46 for April 2002 to October 2002.
Comstock realized a $1.3 million gain on this hedge position in 2002, which was
included in oil and gas sales and increased its average natural gas price
realization from $3.26 per Mcf to $3.30 per Mcf.
Comstock assumed certain natural gas price derivative financial instruments
in connection with the acquisition of DevX. These derivative financial
instruments were not designated as cash flow hedges. Comstock had an unrealized
gain of $243,000 on these contracts in 2001. In 2002, Comstock realized a loss
of $2.3 million related to these instruments.
Comstock periodically enters into interest rate swap agreements to hedge
the impact of interest rate changes on its floating rate long-term debt. As a
result of certain hedging transaction for interest rates, Comstock has realized
the following gains or losses which were included in interest expense:
2000 2001 2002
-------- -------- --------
(In thousands)
Realized Gains (Losses).......... $ 988 $ (199) $ (218)
As of December 31, 2002, Comstock had an interest rate swap agreement
covering $25.0 million of its floating rate debt which fixed the LIBOR rate at
1.7% for the period January 2003 through December 2003. Comstock has designated
this position as a hedge. The change in fair value of this instrument resulted
in an unrealized after tax loss of $139,000 was recognized in other
comprehensive income.
(12) Discontinued Operations
In April and July 2002, Comstock sold certain marginal oil and gas
properties for cash proceeds of $3.5 million plus forgiveness of certain
accounts payable related to the properties. The properties sold include various
interests in nonoperated properties in Nueces, Hardeman, Montague and Wharton
counties in Texas. Comstock realized a loss of $1.8 million ($1.2 million, after
tax) on these property sales. The results of operations of these sold
properties, including the losses on disposal, have been presented as
discontinued operations in the accompanying consolidated statements of
operations.
F-24
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Prior year results have also been reclassifed to report the results of
operations of the properties as discontinued operations. Results for these
properties reported as discontinued operations were as follows:
Year Ended December 31,
------------------------------
2000 2001 2002
------- ------- -------
(In thousands)
Oil and gas sales ............................. $ 1,266 $ 1,571 $ 390
Operating expenses ............................ (916) (963) (264)
Loss on disposal ........................ -- -- (1,778)
------- ------- -------
Income (loss) before taxes .............. 350 608 (1,652)
Income tax provision (benefit) ................ 123 212 (580)
------- ------- -------
Income (loss) from discontinued operations .... $ 227 $ 396 $(1,072)
======= ======= =======
(13) Restatement of Previously Issued Financial Statements
Subsequent to the issuance of its Annual Report for the year ended December
31, 2001, Comstock determined that certain outstanding advances made by the
Company to its joint venture partner under its joint exploration venture in the
Gulf of Mexico for seismic data acquisition should have been charged to
exploration expense rather than reflected on the balance sheet as an asset. As a
result of changing the accounting treatment for the advances used for seismic
data, the Company determined that its financial statements for 1998, 1999, 2000
and 2001 should be restated. The effect of the restatement is a reduction to
previously reported net income by $0.2 million and $1.6 million for the years
2000 and 2001, respectively, as a result of the additional exploration expense
in each year. Management believes these changes primarily affect the timing of
Comstock's recognition of exploration expense. If reimbursements are received
for the advances made, future exploration expense will be reduced. In addition,
the Series 1999 Preferred Stock has been reclassified from shareholders' equity
at December 31, 2001 to temporary equity.
The following balance sheet accounts as of December 31, 2001 were affected
by the restatement:
Year Ended December 31, 2001
----------------------------
Previously
Reported Restated
----------- -----------
(In thousands)
Unevaluated oil and gas properties ............ $ 13,416 $ 11,609
Oil and gas properties ........................ 901,206 900,711
Net property and equipment .................... 638,576 636,274
Total assets .................................. 683,071 680,769
Accounts payable and accrued expenses ......... 37,389 38,812
Total current liabilities ..................... 38,416 39,839
Deferred taxes payable ........................ 47,911 46,607
Retained earnings ............................. 54,183 51,762
Redeemable preferred stock .................... -- 17,573
Total stockholders' equity .................... 215,662 195,668
Total liabilities and stockholders' equity .... 683,071 680,769
F-25
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following presents the impact of the restatement on the operating
results and cash flows for the years ended December 31, 2000 and 2001:
Year Ended Year Ended
December 31, 2000 December 31, 2001
--------------------- -----------------------
Previously Previously
Reported (1) Restated Reported (1) Restated
----------- --------- ------------ ---------
(In thousands, except per share amounts)
Exploration expense ................... $ 3,192 $ 3,505 $ 4,215 $ 6,611
Total operating expenses .............. 80,478 80,791 90,611 93,007
Income from continuing operations
before income taxes ................ 63,347 63,034 55,481 53,085
Income tax expense .................... (22,171) (22,061) (19,419) ( 18,579)
Net income from continuing operations . 41,176 40,973 36,062 34,506
Net income ............................ 41,403 41,200 36,458 34,902
Net income attributable to common stock 38,932 38,729 34,854 33,298
Net income per share from
continuing operations:
Basic............................. $1.48 $1.46 $1.20 $1.13
Diluted........................... $1.21 $1.20 $1.06 $1.00
Net income per share:
Basic............................. $1.48 $1.47 $1.20 $1.15
Diluted........................... $1.21 $1.20 $1.06 $1.01
Net cash provided by
operating activities............... $104,556 $105,073 $ 110,090 $ 108,626
Net cash used for investing activities. $(83,361) $(83,878) $(189,601) $(188,147)
- -------------
(1) Previously reported amounts have been adjusted for the effects of
discontinued operations.
(14) Supplementary Quarterly Financial Data (Unaudited)
2001-
First Second Third Fourth Total
-------- -------- -------- -------- --------
(In thousands, except per share amounts)
Total oil and gas sales ...................... $ 66,910 $ 45,997 $ 29,305 $ 23,906 $166,118
======== ======== ======== ======== ========
Net income (loss) from continuing operations
attributable to common stock (As Restated) $ 22,692 $ 11,779 $ 2,482 $ (4,051) $ 32,902
======== ======== ======== ======== ========
Net income (loss) attributable
to common stock (As Restated)............. $ 22,894 $ 11,931 $ 2,539 $ (4,066) $ 33,298
======== ======== ======== ======== ========
Net income (loss) from continuing operations
per share (As Restated):
Basic................................ $0.79 $0.40 $0.09 ($0.14) $1.13
======== ======== ======== ========= ========
Diluted.............................. $0.66 $0.35 $0.08 $1.00
======== ======== ======== ========
Net income (loss) per share (As Restated):
Basic................................ $0.80 $0.41 $0.09 ($0.13) $1.15
======== ======== ======== ========= ========
Diluted.............................. $0.66 $0.35 $0.09 $1.01
======== ======== ======== ========
F-26
2002 -
First Second Third Fourth Total
-------- -------- -------- -------- --------
(In thousands, except per share amounts)
Total oil and gas sales....................... $ 26,490 $ 38,004 $ 35,550 $ 42,041 $142,085
======== ======== ======== ======== ========
Net income (loss) from continuing operations
attributable to common stock.............. $ (4,698) $ 3,206 $ 2,970 $ 9,495 $ 10,973
======== ======== ======== ======== ========
Net income (loss) attributable
to common stock........................... $ (5,423) $ 2,804 $ 3,025 $ 9,777 $ 9,901
======== ======== ======== ======== ========
Net income (loss) from continuing
operations per share:
Basic................................ ($0.16) $0.11 $0.10 $0.33 $0.38
======== ======== ======== ======== ========
Diluted.............................. $0.11 $0.10 $0.29 $0.37
======== ======== ======== ========
Net income (loss) per share:
Basic................................ ($0.19) $0.10 $0.10 $0.33 $0.34
======== ======== ======== ======== ========
Diluted.............................. $0.09 $0.10 $0.29 $0.34
======== ======== ======== ========
(15) Oil and Gas Reserves Information (Unaudited)
Set forth below is a summary of the changes in Comstock's net quantities of
crude oil and natural gas reserves for each of the three years ended December
31, 2002.
2000 2001 2002
-------------------- -------------------- --------------------
Oil Gas Oil Gas Oil Gas
(MBbls) (MMcf) (MBbls) (MMcf) (MBbls) (MMcf)
-------- -------- -------- -------- -------- --------
Proved Reserves:
Beginning of year ............ 19,467 258,121 17,451 297,835 17,348 462,085
Revisions of previous
estimates ............... (1,725) 1,205 (1,177) (10,959) (11) (5,182)
Extensions and discoveries ... 1,599 54,574 1,395 46,777 2,360 39,467
Purchases of minerals in place 416 11,059 1,213 156,515 2,637 29,651
Sales of minerals in place ... (499) (134) -- -- (182) (4,066)
Production ................... (1,807) (26,990) (1,534) (28,083) (1,303) (33,171)
-------- -------- -------- -------- -------- --------
End of year .................. 17,451 297,835 17,348 462,085 20,849 488,784
======== ======== ======== ======== ======== ========
Proved Developed Reserves:
Beginning of year ............ 14,379 184,123 12,290 200,349 12,212 315,779
======== ======== ======== ======== ======== ========
End of year .................. 12,290 200,349 12,212 315,779 13,937 319,155
======== ======== ======== ======== ======== ========
F-27
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following table sets forth the standardized measure of discounted
future net cash flows relating to proved reserves at December 31, 2001 and 2002:
2001 2002
----------- -----------
(In thousands)
Cash Flows Relating to Proved Reserves:
Future Cash Flows ................................. $ 1,566,780 $ 3,088,593
Future Costs:
Production .................................... (453,416) (646,018)
Development and Abandonment ................... (156,906) (190,534)
----------- -----------
Future Net Cash Flows Before Income Taxes ......... 956,458 2,252,041
Future Income Taxes ............................... (177,551) (639,286)
----------- -----------
Future Net Cash Flows ............................. 778,907 1,612,755
10% Discount Factor ............................... (331,634) (691,640)
----------- -----------
Standardized Measure of Discounted Future Net Cash Flows $ 447,273 $ 921,115
=========== ===========
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, 2000, 2001 and 2002:
2000 2001 2002
----------- ----------- ---------
(In thousands)
Standardized Measure, Beginning of Year ........... $ 468,713 $ 1,288,764 $ 447,273
Net Change in Sales Price, Net of Production Costs 1,141,880 (1,298,306) 590,290
Development Costs Incurred During the Year Which
Were Previously Estimated ....................... 17,340 26,627 35,272
Revisions of Quantity Estimates ................... (44,256) (21,342) (11,636)
Accretion of Discount ............................. 51,506 173,747 54,068
Changes in Future Development and Abandonment Costs (41,525) (6,571) (12,052)
Changes in Timing and Other ....................... (166,410) (141,844) (58,022)
Extensions and Discoveries ........................ 375,632 86,026 150,317
Purchases of Reserves in Place .................... 62,621 120,147 105,206
Sales of Reserves in Place ........................ (3,355) -- (5,243)
Sales, Net of Production Costs .................... (139,643) (135,272) (108,586)
Net Changes in Income Taxes ....................... (433,739) 355,297 (265,772)
----------- ----------- ---------
Standardized Measure, End of Year ................. $ 1,288,764 $ 447,273 $ 921,115
=========== =========== =========
The estimates of proved oil and gas reserves utilized in the preparation of
the financial statements were estimated by independent petroleum consultants of
Lee Keeling and Associates 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 Comstock's reserves are located onshore in or
offshore to the continental United States of America.
F-28
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Future cash inflows are calculated by applying year-end prices adjusted for
transportation and other charges to the year-end quantities of proved reserves,
except in those instances where fixed and determinable price changes are
provided by contractual arrangements in existence at year-end.
Comstock's average yearend prices used in the reserve estimates were as
follows:
2000 2001 2002
------- ------- -------
Crude Oil (Per Barrel)................. $ 26.34 $ 18.73 $ 30.07
Natural Gas (Per Mcf).................. $ 10.51 $ 2.69 $ 5.04
Future development and production costs are computed by estimating the
expenditures to be incurred in developing and producing proved oil and gas
reserves at the end of the year, based on year-end costs and assuming
continuation of existing economic conditions. Future income tax expenses are
computed by applying the appropriate statutory tax rates to the future pre-tax
net cash flows relating to proved reserves, net of the tax basis of the
properties involved. The future income tax expenses give effect to permanent
differences and tax credits, but do not reflect the impact of future operations.
F-29