(Mark One)
Commission File No. 0-16741
| NEVADA | 94-1667468 | ||||
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification Number) |
| Common Stock, $.50 Par Value | New York Stock Exchange | ||||
| Preferred Stock Purchase Rights | New York Stock Exchange | ||||
| (Title of class) | (Name of exchange on which registered) |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [ X ] No [ ].
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant ’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K. [ X ]
As of March 25, 2002, there were 28,572,553 shares of common stock outstanding.
As of March 25, 2002, the aggregate market value of the voting stock held by non-affiliates of the registrant was approximately $207.7 million.
Proxy statement for the 2002 annual meeting of stockholders - Part III
COMSTOCK RESOURCES, INC.
ANNUAL REPORT ON FORM 10-K
For the Fiscal Year Ended December 31, 2001
CONTENTS
Page
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Part I
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Items 1 and 2. Business and Properties.........................................5
Item 3. Legal Proceedings..............................................20
Item 4. Submission of Matters to a Vote of Security Holders............20
Part II
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Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters........................................20
Item 6. Selected Financial Data........................................21
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations........................22
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.....27
Item 8. Financial Statements...........................................29
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure................. 29
Part III
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Item 10. Directors and Executive Officers of the Registrant.............30
Item 11. Executive Compensation.........................................30
Item 12. Security Ownership of Certain Beneficial Owners
and Management.............................................30
Item 13. Certain Relationships and Related Transactions................ 30
Part IV
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Item 14. Exhibits and Reports on Form 8-K.............................. 30
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 2002
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" means the registrant, Comstock
Resources, Inc.
"Bbl" means a barrel of 42 U.S. gallons of oil.
"Bcf" means one billion cubic feet of natural gas.
"Bcfe" means one billion cubic feet of natural gas equivalent.
"Btu" means British thermal unit, which is the quantity of heat required to
raise the temperature of one pound of water from 58.5 to 59.5 degrees
Fahrenheit.
"Cash Margin per Mcfe" means the equivalent price per Mcfe less oil and gas
operating expenses per Mcfe and general and administrative expenses per Mcfe.
"Completion" means the installation of permanent equipment for the
production of oil or gas.
"Condensate" means a hydrocarbon mixture that becomes liquid and separates
from natural gas when the gas is produced and is similar to crude oil.
"Development well" means a well drilled within the proved area of an oil or
gas reservoir to the depth of a stratigraphic horizon known to be productive.
2
"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 that is owned by us less royalties and
production due others.
"Oil" means crude oil or condensate.
"Operator" means the individual or company responsible for the exploration,
development, and production of an oil or gas well or lease.
"Present Value of Proved Reserves" means the present value of estimated
future revenues to be generated from the production of proved reserves
calculated in accordance with the Securities and Exchange Commission guidelines,
net of estimated production and future development costs, using prices and costs
as of the date of estimation without future escalation, without giving effect to
non-property related expenses such as general and administrative expenses, debt
service, future income tax expense and depreciation, depletion and amortization,
and discounted using an annual discount rate of 10%.
"Proved developed reserves" means reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery will be included as "proved developed
reserves" only after testing by a pilot project or after the operation of an
installed program has confirmed through production response that increased
recovery will be achieved.
3
"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
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 East Texas/ North
Louisiana, Gulf of Mexico, 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 566.2
Bcfe with an estimated Present Value of Proved Reserves of $540.7 million as of
December 31, 2001. Our reserve base is 82% natural gas and 69% proved developed
on a Bcfe basis as of December 31, 2001. In 2001 we had revenues of $168.4
million and generated earnings before interest, taxes, depreciation and
amortization or "EBITDA" of $131.6 million.
Our proved reserves at December 31, 2001 and our 2001 average daily
production are summarized below:
Reserves at December 31, 2001 2001 Daily Production
--------------------------------- ----------------------------------------
% of % of
Oil Gas Total Total Oil Gas Total Total
-------- ------ ------- ----- -------- -------- -------- ------
(MMBbls) (Bcf) (Bcfe) (MBbls/d) (MMcf/d) (MMcfe/d)
East Texas/North Louisiana 1.3 186.7 194.2 34.3 0.2 23.9 25.0 24.5
Gulf of Mexico ........... 12.1 85.3 158.1 27.9 2.8 21.2 38.2 37.3
Southeast Texas .......... 3.3 103.4 123.1 21.7 1.1 29.8 36.7 35.9
South Texas .............. 0.3 27.0 28.8 5.1 0.1 0.7 1.0 1.0
Other Regions ............ 0.3 59.7 62.0 11.0 -- 1.3 1.3 1.3
------ ------ ------ ----- ---- ----- ------ ------
Total................ 17.3 462.1 566.2 100.0% 4.2 76.9 102.2 100.0%
====== ====== ====== ===== ==== ===== ====== ======
Strengths
Quality Properties. Our operations are focused in four geographically
concentrated areas, the East Texas/ North Louisiana, Gulf of Mexico, Southeast
Texas and South Texas regions, which account for approximately 34%, 28%, 22% and
5% 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 12.0 years
and have extensive development and exploration potential.
Successful Exploration and Development Program. In 2001, we spent $51.4
million on the exploitation and development of our oil and natural gas
properties for development drilling, recompletions, workovers and production
facilities. Overall, we drilled 35 development wells, 18.8 wells net to us, with
a 89% success rate. We also had a successful exploratory drilling program in
2001, spending a total of $33.4 million to drill 17 wells, 5.9 net to us, with a
82% success rate. We spent an additional $8.2 million in acquiring new acreage
and seismic data in 2001 to support our exploration program.
Successful Acquisitions. We have historically grown through acquisitions.
Since 1991, we have added 652.6 Bcfe of proved oil and natural gas reserves from
26 acquisitions at an average cost of $0.88 per Mcfe. Our application of strict
economic and reserve risk criteria enable us to successfully evaluate and
integrate acquisitions.
5
Efficient Operator. We operate 57% of our proved oil and natural gas
reserve base as of December 31, 2001. 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 1,100
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 2001 our average natural gas price was $4.58
per Mcf, which represented a $0.31 premium to the 2001 NYMEX average monthly
settlement price. Also in 2001, our average crude oil price was $25.40 per
barrel, which represented a $2.53 barrel premium to the average monthly West
Texas Intermediate crude oil price for 2001 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 2001, we spent approximately $43.6
million to drill 35 development wells, 18.8 net to us, of which 31 wells, 17.0
net to us, were successful, representing a success rate of 89%. In addition, we
spent approximately $7.8 million for new production facilities, leasehold costs
and for recompletion and workover activities. For 2002, we have budgeted $40.0
million for development drilling and for workover and recompletion activity.
Pursue Exploration Opportunities. We conduct exploration activities to find
additional reserves on our undeveloped acreage and in our core operating areas.
In 2001, we spent approximately $33.4 million to drill 17 exploratory wells, 5.9
net to us, of which 14 wells, 4.8 net to us, were successful, representing a
success rate of 82%. We also spent $8.2 million in acquiring new acreage and
seismic data in 2001 to support our exploration program. We have budgeted $35.0
million in 2002 for exploration activities which will be focused primarily in
the Gulf of Mexico and South Texas regions.
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 $0.87 in 2001. In addition, we have
been able to grow our reserves and production substantially over the past five
years with minimal increase to general and administrative expenses. As a result,
our general and administrative expenses per Mcfe averaged only $0.12 in 2001.
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 652.6 Bcfe of proved oil
and natural gas reserves from 26 acquisitions at a total cost of $577.2 million,
or $0.88 per Mcfe. The acquisitions were acquired at an average of 74% 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.
6
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 $75.0 million on
development and exploration projects in 2002. We intend to primarily use our
operating cash flow to fund our drilling expenditures in 2002. We may also make
additional property acquisitions in 2002 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.
Primary Operating Areas
Our activities are concentrated in four primary operating areas: East
Texas/ North Louisiana, Gulf of Mexico, 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, 2001.
Present
Value of
Net Oil Net Gas Proved
(MBbls) (MMcf) MMcfe % Reserves %
-------- --------- --------- ------- --------- -------
East Texas/ North Louisiana (in thousands)
Gilmer 531 72,515 75,702 $ 51,658
Beckville 206 42,260 43,498 28,412
Logansport 42 14,862 15,113 14,227
Blocker 57 13,331 13,670 11,573
Waskom 200 12,070 13,273 10,191
Box Church 4 7,459 7,485 6,214
Lisbon 54 4,032 4,353 5,153
Longwood 45 5,159 5,429 5,110
Ada 5 5,206 5,235 4,584
Other 110 9,782 10,440 9,636
-------- --------- --------- ---------
1,254 186,676 194,198 34.3 146,758 27.1
-------- --------- --------- ---------
Gulf of Mexico
South Timbalier/ South Pelto 2,305 50,020 63,847 104,884
Ship Shoal 7,038 19,715 61,946 66,699
Main Pass 1,445 2,621 11,294 13,373
West Cameron -- 5,415 5,415 11,576
East White Point 794 3,125 7,890 6,496
Bay Marchand 469 312 3,125 3,282
Other 69 4,077 4,491 5,313
-------- --------- --------- ---------
12,120 85,285 158,008 27.9 211,623 39.1
-------- --------- --------- ---------
Southeast Texas
Double A Wells 2,887 90,518 107,842 104,127
Sugar Creek 231 11,990 13,378 5,167
Other 171 881 1,905 2,362
-------- --------- --------- ---------
3,289 103,389 123,125 21.7 111,656 20.7
-------- --------- --------- ---------
Illinois Basin
-------- --------- --------- ---------
New Albany Shale Gas -- 39,573 39,573 7.0 20,114 3.7
-------- --------- --------- ---------
South Texas
J.C. Martin -- 16,182 16,182 17,172
Other 296 10,818 12,592 11,563
-------- --------- --------- ---------
296 27,000 28,774 5.1 28,735 5.3
-------- --------- --------- ---------
Mid-Continent
N.E. Moorewood 32 5,207 5,398 5,671
Other 150 10,128 11,028 10,278
-------- --------- --------- ---------
182 15,335 16,426 2.9 15,949 3.0
-------- --------- --------- ---------
Other Areas 207 4,827 6,068 1.1 5,844 1.1
-------- --------- --------- ------- --------- -------
Total 17,348 462,085 566,172 100.0 $540,679 100.0
======== ========= ========= ======= ========= =======
7
East Texas/ North Louisiana
Approximately 34% or 194.2 Bcfe of our proved reserves are located in East
Texas and North Louisiana where we own interests in 405 producing wells, 230.4
net to us, in 21 field areas. We operate 250 of these wells. The largest of our
fields in this region are the Gilmer, Beckville and Logansport fields.
Production from this region averaged 23.9 MMcf of natural gas per day and 181
barrels of oil per day during 2001. 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 2001 we spent $19.8 million drilling 19 wells, 12.6 net to us, and $2.3
million on workovers and recompletions in this region. We have budgeted
approximately $24.0 million in 2002 for this region to drill 21 development
wells and for recompletion and workover activity.
Gilmer
We own interests in 53 natural gas wells, 20.1 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 75.7 Bcfe which
represents 13% of our total reserve base. We acquired our interests in the
Gilmer field in December 2001 through the acquisition of the DevX Energy, Inc.
In 2002 we plan to participate in the drilling of 21 infill development wells in
the Gilmer field, which is expected to cost approximately $22.0 million.
Beckville
Our properties in the Beckville field, located in Panola and Rusk Counties,
Texas, have proved reserves of 43.5 Bcfe which represents approximately 8% of
our total reserves. We operate 72 wells in this field and own interests in four
additional wells. During 2001, production attributable to our interest from this
field averaged 9.4 MMcf of natural gas per day and 17 barrels of oil per day.
The Beckville field produces from the Cotton Valley formation at depths ranging
from 9,000 to 10,000 feet. In 2001, we drilled nine successful development
wells, 7.5 net to us, at Beckville. No additional development drilling is
planned for 2002 in this field unless natural gas prices increase.
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 15.1 Bcfe in the Logansport field represents
approximately 3% of our total reserves. We operate 53 wells in this field and
own interests in 34 additional wells. During 2001, net daily production
attributable to our interest from this field averaged 3.8 MMcf of natural gas
and 18 barrels of oil. We drilled two wells, 0.4 net to us, during 2001 in
Logansport.
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 81 producing wells, 37.6 net to us, in ten field areas, the largest
of which are the South Timbalier/South Pelto area (South Timbalier Blocks 11,
16, 34, 50 and South Pelto Blocks 5 and 15), the Ship Shoal area (Ship Shoal
Blocks 66, 67, 68, 69 and 99 and South Pelto Block 1), the Main Pass area (Main
Pass Blocks 21, 41, 43 and 58) and West Cameron area (West Cameron Blocks 152,
238, 248 and 249). We have 158.0 Bcfe of oil and natural gas reserves in the
Gulf of Mexico region which represents 28% of our reserve base. We operate 23 of
the wells that we own in this region. Production from the region averaged 21.2
MMcf of natural gas per day and 2,823 barrels of oil per day during 2001. We
spent $11.6 million in this region in 2001 drilling eight development wells, 2.3
net to us, and $28.4 million drilling 15 exploratory wells, 4.4 net to us. We
also spent $7.7 million acquiring leases and seismic data and $4.0 million for
production facilities, recompletions and workovers. In 2002, we plan to spend
$39.0 million for development and exploration activities in this region.
South Timbalier/South Pelto
We own working interests ranging from 25% to 33% in 19 producing wells 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 63.8 Bcfe
attributable to this area which is 11% of our total reserves. Production
attributable to our interest averaged 12.1 Mmcf of natural gas per day and 437
barrels of oil per day in 2001. 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
12 wells in the South Timbalier/South Pelto area in 2001. Two of these wells
were successful development wells. The remaining ten wells were exploratory
wells of which eight resulted in new discoveries and two were dry holes.
Ship Shoal
The Ship Shoal area is located in Louisiana state waters and in federal
waters, offshore of Terrebonne Parish and near the state/federal waters
boundary. We own a 99% to 100% working interest in Ship Shoal Blocks 66, 67, and
68 and South Pelto Block 1 and operate these properties. We have a 25% working
interest in Ship Shoal Block 69 and a 60% working interest in Ship Shoal Block
99. In the Ship Shoal area, oil and natural gas are produced from numerous
Miocene sands occurring at depths from 5,800 to 13,500 feet, and in water depths
from 10 to 40 feet. Our properties in the Ship Shoal area have estimated proved
reserves of 61.9 Bcfe, which is 11% of our total reserves. We own interests in
26 producing wells in the Ship Shoal area which averaged 2.3 MMcf of natural gas
per day and 1,568 barrels of oil per day during 2001.
Main Pass
Main Pass Block 21 is located in Louisiana state waters, offshore of
Plaquemines Parish in water with a depth of approximately 12 feet. Our wells in
this area produce from multiple Miocene sands at depths that range from 4,400 to
7,700 feet. We are the operator and own interests in six wells at Main Pass
Block 21. We also own nonoperated interests in 14 producing wells at Main Pass
Blocks 41, 43 and 58 in federal waters with an average depth of 50 feet. Proved
reserves for the total Main Pass area were 11.3 Bcfe, which is 2% of total
reserves at December 31, 2001. Production attributable to our interests from the
Main Pass Area was approximately 1.8 MMcf of natural gas per day and 652 barrels
of oil per day in 2001.
9
West Cameron
We have interests in seven producing wells at West Cameron Blocks 152, 238,
248 and 249 located in federal waters with a depth of approximately 60 feet.
These wells produce from complex multi-pay Pliocene aged sands at depths ranging
from 5,000 to 11,500 feet. Our proved reserves in this field were 5.4 Bcfe which
represents 1% of our total proved reserves. Production from the West Cameron
properties net to our interest averaged 2.9 MMcf of natural gas per day in 2001.
Southeast Texas
Approximately 22% or 123.1 Bcfe of our proved reserves are located in
Southeast Texas, where we own interests in 93 producing wells, 55.4 net to us,
and operate 58 of these wells. Net daily production rates from the area averaged
29.8 MMcf of natural gas and 1,145 barrels of oil during 2001. We spent $12.9
million in the Southeast Texas region in 2001 drilling eight development wells,
3.9 net to us, and spent $4.3 million drilling two exploratory wells, 1.5 net to
us. We also spent $1.2 million to acquire an additional leasehold in this region
and for recompletions and workovers. In 2002, we plan to spend $2.0 million for
exploration activities in this region. Additional development drilling is
planned for this region once natural gas prices increase.
Double A Wells
Substantially all of the reserves in this region are in the Double A Wells
field area in Polk County, Texas. The Double A Wells field is our largest field
area with total estimated proved reserves of 107.8 Bcfe, which is 19% of our
total reserves. Net daily production from the 56 producing wells at Double A
Wells field averaged 28.7 MMcf of natural gas and 1,106 barrels of oil during
2001. 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 the interpretation of 3-D seismic data and drilled 19 successful wells
from 1999 to 2001. In 2001, we drilled six wells, 2.7 net to us, in this field.
Four of the wells, 2.0 net to us, were successful.
South Texas
Approximately 5% or 28.8 Bcfe of our proved reserves are located in South
Texas, where we own interests in 260 producing wells, 46.1 net to us. In 2002,
we plan to spend approximately $10.0 million primarily for exploration activity
in this region.
J.C. Martin
Our largest field in South Texas is the J.C. Martin field which located in
the structurally complex and highly prolific Wilcox Lobo Trend in Zapata County,
Texas on the Mexican border. We own interests in 87 producing wells in the J.C.
Martin field. We acquired our interests in the J.C. Martin field through our
acquisition of DevX Energy, Inc. 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. Wells in this field were drilled to total depths ranging from
9,500 to 10,200 feet.
10
Acquisition Activities
Acquisition Strategy
We have concentrated our acquisition activity in the East Texas/North
Louisiana, Gulf of Mexico, 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 652.6 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 field in South Texas. We also acquired interests in the New
Albany Shale Gas field in Kentucky 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.
11
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, 2001:
Present
Value of
Proved
Oil Gas Total Reserves
(MBbls) (MMcf) (MMcfe) (000's)
-------- -------- -------- ---------
Proved Developed Producing ..... 6,853 240,549 281,666 $301,822
Proved Developed Non-producing.. 5,359 75,230 107,385 119,014
Proved Undeveloped ............. 5,136 146,306 177,121 119,843
-------- -------- -------- --------
Total Proved ............. 17,348 462,085 566,172 $540,679
======== ======== ======== ========
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, 2001. The market price for our
oil production on December 31, 2001, after basis adjustments, was $18.73 per
barrel as compared to $26.34 per barrel on December 31, 2000. The market price
received for our natural gas production on December 31, 2001, after basis
adjustments, was $2.69 per Mcf as compared to $10.51 per Mcf on December 31,
2000.
12
Drilling Activity Summary
During the three-year period ended December 31, 2001, we drilled
development and exploratory wells as set forth in the table below.
Year Ended December 31,
------------------------------------------------
1999 2000 2001
-------------- ------------- -------------
Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- -----
Development Wells:
Oil................... 1 .4 -- -- 2 .7
Gas................... 14 8.8 37 19.7 29 16.3
Dry................... 2 .8 -- -- 4 1.8
----- ----- ----- ----- ----- -----
17 10.0 37 19.7 35 18.8
----- ----- ----- ----- ----- -----
Exploratory Wells:
Oil................... 2 .6 2 1.1 1 .3
Gas................... 5 .9 5 2.2 13 4.5
Dry................... 4 .9 5 1.5 3 1.1
------ ----- ----- ----- ----- -----
11 2.4 12 4.8 17 5.9
------ ----- ----- ----- ----- -----
Total Wells........ 28 12.4 49 24.5 52 24.7
====== ===== ===== ===== ===== =====
In 2002 to the date of this report, we have drilled eight development
wells, 2.7 net to us, and four exploratory wells, 1.0 net to us. All of these
wells were either successful or are still being evaluated by us.
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, 2001.
Oil Gas
------------- -------------
Gross Net Gross Net
----- ---- ----- -----
Colorado ...................... -- -- 1 .3
Kansas ........................ -- -- 12 4.5
Kentucky ...................... -- -- 64 54.7
Louisiana ..................... 9 4.9 189 89.3
Mississippi ................... 1 .1 1 .2
Offshore Gulf of Mexico ....... 41 22.1 40 15.5
Oklahoma ...................... 3 .3 139 16.7
Texas ......................... 97 25.6 499 217.2
Wyoming ....................... -- -- 29 2.1
----- ---- ----- -----
Total Wells ............. 151 53.0 974 400.5
===== ==== ===== =====
We operate 404 of the 1,125 producing wells presented in the above table.
13
Acreage
The following table summarizes our developed and undeveloped leasehold
acreage at December 31, 2001. We have excluded acreage in which our interest is
limited to a royalty or overiding royalty interests.
Developed Undeveloped
------------------- -------------------
Gross Net Gross Net
------- ------- ------- -------
Colorado ....................... 320 80 -- --
Kansas ......................... 6,400 4,064 -- --
Kentucky ....................... 9,107 6,666 13,265 12,192
Louisiana ...................... 77,792 57,109 7,923 1,807
Mississippi .................... 1,360 210 -- --
New Mexico ..................... -- -- 171,816 75,598
Offshore Gulf of Mexico ........ 41,981 17,970 20,765 6,596
Oklahoma ....................... 37,440 5,336 -- --
Texas .......................... 218,968 136,467 59,850 31,102
Wyoming ........................ 13,440 927 -- --
------- ------- ------- -------
Total ................ 406,808 228,829 273,619 127,295
======= ======= ======= =======
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.
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 2001 to HPL accounted
for approximately 24% of our total 2001 oil and gas sales.
A significant portion of our offshore Gulf of Mexico natural gas production
in 2001 was sold to Adams Resources Marketing, Ltd. ("ARM"). Total natural gas
sales in 2001 to ARM accounted for approximately 16% of our total 2001 oil and
natural gas sales. Reliant Energy Services, Inc. is another significant
purchaser of our natural gas production accounting for approximately 12% of our
total 2001 oil and gas sales.
14
All of our oil production is sold at the well site at prices tied to the
spot oil markets. Through October 2001, we sold our oil production from our
offshore Gulf of Mexico properties and from the Double A Wells field to
Williams-GulfMark Energy Company. Sales to Williams-GulfMark Energy accounted
for approximately 19% of our total 2001 oil and gas sales.
Competition
The oil and gas industry is highly competitive. Competitors include major
oil companies, other independent energy companies and individual producers and
operators, many of which have financial resources, personnel and facilities
substantially greater than 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 states we operate in 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.
15
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.
Environmental
Various federal, state and local laws and regulations governing the
discharge of materials into the environment, or otherwise relating to the
protection of the environment, health and safety, affect 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.
16
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 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.
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. We also have a lease
for office space formally used by DevX. The lease covers 9,573 square feet at a
monthly rate of $19,458. This lease expires on December 3, 2003. We are
currently attempting to sublease this office space. We also own production
offices and pipe yard facilities near Marshall and Livingston, Texas, near
Logansport, Louisiana and near Guston, Kentucky.
17
Employees
As of December 31, 2001, we had 60 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............... 46 President, Chief Executive Officer and
Chairman of the Board of Directors
Roland O. Burns.............. 42 Senior Vice President, Chief Financial Officer,
Secretary, Treasurer and Director
Mack D. Good................. 51 Vice President of Operations
Stephen E. Neukom............ 52 Vice President of Marketing
Richard G. Powers............ 47 Vice President of Land
Daniel K. Presley............ 41 Vice President of Accounting and Controller
Michael W. Taylor............ 49 Vice President of Corporate Development
David K. Lockett............. 47 Director
Cecil E. Martin, Jr.......... 60 Director
David W. Sledge.............. 45 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.
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.
18
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
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 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.
Outside Directors
David K. Lockett, was appointed to our board of directors on July 17, 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 of since 1988. From 1973
to 1991 he served as chairman of a public accounting firm in Richmond, Virginia.
Mr. Martin also serves as a director for CareerShop.com. Mr. Martin holds a
B.B.A. degree from Old Dominion University and is a Certified Public Accountant.
David W. Sledge was elected to our board of directors in 1996. Mr. Sledge
served as president of Gene Sledge Drilling Corporation, a privately held
contract drilling company based in Midland, Texas, until its sale in October
1996. Mr. Sledge served Gene Sledge Drilling Corporation in various capacities
from 1979 to 1996. Mr. Sledge is a past director of the International
Association of Drilling Contractors and is a past chairman of the Permian Basin
chapter of this association. He received a B.B.A. degree from Baylor University
in 1979.
19
ITEM 3. LEGAL PROCEEDINGS
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 2001.
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
------ ------
2000 - First Quarter.... $ 5.94 $ 2.44
Second Quarter... 9.13 4.06
Third Quarter.... 13.13 6.13
Fourth Quarter... 15.00 8.13
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
As of March 25, 2002, we had 28,572,553 shares of common stock outstanding,
which were held by 462 holders of record and approximately 7,400 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.
20
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, 2001 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."
Year Ended December 31,
-------------------------------------------------------------
1997 1998 1999 2000 2001
--------- --------- --------- --------- ---------
Statement of Operations Data: ($ in thousands, except per share data)
Revenues:
Oil and gas sales ........................... $ 88,555 $ 92,961 $ 90,103 $ 169,350 $ 167,689
Gain on sales of property ................... 85 -- 130 33 12
Other income ................................ 704 274 1,911 319 699
--------- --------- --------- --------- ---------
Total revenues ......................... 89,344 93,235 92,144 169,702 168,400
--------- --------- --------- --------- ---------
Expenses:
Oil and gas operating (1) ................... 17,919 24,747 23,714 29,707 32,417
Exploration ................................. 2,810 8,301 1,832 3,192 4,215
Depreciation, depletion and amortization .... 26,235 51,005 45,171 44,958 49,191
General and administrative, net ............. 2,668 1,617 2,399 3,537 4,351
Interest .................................... 5,934 16,977 23,361 24,611 20,737
Impairment of oil and gas properties ........ -- 17,000 -- -- 1,400
--------- --------- --------- --------- ---------
Total expenses ......................... 55,566 119,647 96,477 106,005 112,311
--------- --------- --------- --------- ---------
Income (loss) before income taxes .............. 33,778 (26,412) (4,333) 63,697 56,089
Income tax benefit (expense) ................ (11,622) 9,244 1,517 (22,294) (19,631)
--------- --------- --------- --------- ---------
Net income (loss) .............................. 22,156 (17,168) (2,816) 41,403 36,458
Preferred stock dividends ................... (410) -- (1,853) (2,471) (1,604)
--------- --------- --------- --------- ---------
Net income (loss) attributable to common stock.. $ 21,746 $ (17,168) $ (4,669) $ 38,932 $ 34,854
========= ========= ========= ========= =========
Weighted average shares outstanding:
Basic........................................ 24,186 24,275 24,601 26,290 29,030
========= ========= ========= ========= =========
Diluted...................................... 26,008 34,219 34,552
========= ========= =========
Earnings per share:
Basic........................................ $ 0.90 $ (0.71) $ (0.19) $ 1.48 $ 1.20
Diluted...................................... 0.85 1.21 1.06
Other Financial Data:
EBITDA(2)..................................... $ 68,757 $ 66,871 $ 66,031 $ 136,458 $ 131,632
Ratio of EBITDA to interest expense (3)....... 11.3 3.5 2.8 5.5 6.3
As of December 31,
-------------------------------------------------------------
1997 1998 1999 2000 2001
--------- --------- --------- --------- ---------
Balance Sheet Data:
Cash and cash equivalents..................... $ 14,504 $ 5,176 $ 7,648 $ 7,105 $ 6,122
Property and equipment, net................... 410,781 404,017 395,862 434,913 638,576
Total assets.................................. 456,800 429,672 434,973 489,930 683,071
Total debt.................................... 260,000 278,104 254,131 234,101 372,464
Stockholders' equity.......................... 124,594 109,663 137,174 180,173 215,662
-------------------
(1) Includes lease operating costs and production and ad valorem taxes.
(2) EBITDA means income (loss) from continuing operations before income taxes,
plus interest, depreciation, depletion and amortization, exploration
expense and impairment of oil and gas properties. EBITDA is a financial
measure commonly used in our industry and should not be considered in
isolation or as a substitute for net income, cash flow provided by
operating activities or other income or cash flow data prepared in
accordance with generally accepted accounting principles or as a measure of
a company's profitability or liquidity.
(3) For the purpose of this calculation interest expense includes capitalized
interest of $230,000 in 2001.
21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Results of Operations
Our operating data for the last three years is summarized below:
Year Ended December 31,
--------------------------------------
1999 2000 2001
---------- ---------- ----------
Net Production Data:
Oil (MBbls) ........................... 2,128 1,807 1,534
Natural gas (MMcf) .................... 23,872 26,990 28,083
Natural gas equivalent (MMcfe) ........ 36,642 37,833 37,287
Average Sales Price:
Oil (MBbls) ........................... $ 17.35 $ 30.02 $ 25.40
Natural gas (MMcf) .................... 2.23 4.26 4.58
Average equivalent price (per Mcfe).... 2.47 4.48 4.50
Expenses ($ per Mcfe):
Oil and gas operating(1) .............. $ 0.65 $ 0.79 $ 0.87
0.07 0.09 0.12
General and administrative
Depreciation, depletion and
amortization(2) .................... $ 1.20 $ 1.15 $ 1.28
Cash Margin ($ per Mcfe)(3) ............... $ 1.75 $ 3.60 $ 3.51
-----------
(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, 2001 Compared to Year Ended December 31, 2000
Our oil and gas sales decreased $1.7 million or 1%, in 2001 to $167.7
million from $169.4 million in 2000. The slight decrease in sales is due to a 1%
decrease in our oil and natural gas production in 2001. Our oil production in
2001 decreased by 15% 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. On an equivalent unit basis, our average price received for
our production in 2001 was $4.50 per Mcfe, which was almost the same as our
average price in 2000 of $4.48 per Mcfe.
Our other income in 2001 increased to $699,000 from $319,000 in 2000. The
increase is mostly due to a non-cash gain from the change in the fair value of
our derivative financial instruments in 2001 of $255,000.
Our oil and gas operating expenses, which includes production taxes,
increased $2.7 million or 9%, to $32.4 million in 2001 from $29.7 million in
2000. Our oil and gas operating expenses per equivalent Mcf produced increased
by $0.08 to $0.87 in 2001 from $0.79 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.
In 2001, we had $4.2 million in exploration expense which represents the
write-off of three offshore exploratory dry holes. Exploration expense for 2000
was $3.2 million which related to the write-off of five dry holes.
22
Our depreciation, depletion and amortization increased $4.2 to $49.2
million in 2001 from $45.0 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 $1.15 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 of $34.8 million, after deducting preferred stock
dividends of $1.6 million, in 2001. These results compared to net income of
$38.9 million, after deducting preferred stock dividends of $2.5 million, in
2000. Our income per share for 2001 was $1.06 on diluted weighted average shares
outstanding of 34.6 million as compared to net income per share of $1.21 for
2000 on diluted weighted average shares outstanding of 34.2 million.
Year Ended December 31, 2000 Compared to Year Ended December 31, 1999
Our oil and gas sales increased by $79.2 million or 88% in 2000 to a record
high level of $169.4 million from $90.1 million in 1999. The substantial
increase in our sales is due to significantly higher oil and gas prices in 2000
combined with a 3% increase in our production. In 2000, our average oil price
increased by 73% and our average natural gas price increased by 91% from 1999.
Our oil production decreased in 2000 by 15% and our natural gas production in
2000 increased by 13%.
Our other income in 2000 decreased by $1.6 million to $319,000 from $1.9
million in 1999. Included in other income for 1999 was an insurance recovery in
the amount of $1.7 that we received.
Our oil and gas operating expenses, which includes production taxes,
increased by $6.0 million or 25% in 2000 to $29.7 million from $23.7 million in
1999. Our oil and gas operating expenses per equivalent Mcf produced in 2000
increased by $0.14 to $0.79 from $0.65 for 1999. The increase is related to
higher production taxes resulting from the higher oil and gas prices we realized
in 2000 as well as an increase of $3.6 million in our field level lifting costs
for new wells put into production in 2000.
In 2000, we had $3.2 million in exploration expense which related to our
write-off of five offshore exploratory dry holes. Our exploration expense in
1999 was $1.8 million which related to our write-off of four dry holes drilled
in 1999.
Our depreciation, depletion and amortization decreased $213,000 to $45.0
million in 2000 from $45.2 million in 1999. Depreciation, depletion and
amortization per equivalent Mcf produced averaged $1.15 in 2000, which decreased
from $1.20 in 1999.
23
Our general and administrative expenses, which are reported net of overhead
reimbursements that we receive, increased $1.1 million or 47% to $3.5 million in
2000 from $2.4 million in 1999. This increase was primarily due to higher
compensation paid to our employees in 2000.
Our interest expense increased by $1.2 million to $24.6 million in 2000
from $23.4 million in 1999. This increase relates to the higher average interest
rate on our debt. The 11 1/4% interest rate on our senior notes, issued to
refinance $150.0 million of indebtedness under our bank credit facility on April
29, 1999, was significantly higher than the interest rates charged under our
bank credit facility. Our weighted average interest rate under our bank credit
facility was 6.9% in 2000, a decrease from the weighted average rate of 7.2% in
1999.
For 2000 we reported net income of $38.9 million, after preferred stock
dividends of $2.5 million. This compares to a net loss of $4.7 million that we
reported for 1999, after deducting preferred stock dividends of $1.9 million.
Our net income per share for 2000 was $1.21 on diluted weighted average shares
outstanding of 34.2 million as compared to a net loss per share of $0.19 for
1999 on weighted average shares outstanding of 24.6 million.
Acquisition of DevX Energy, Inc.
On December 17, 2001, we completed the acquisition of DevX by acquiring
100% of the common stock of DevX for $92.6 million though a cash tender offer
and subsequent merger into a wholly owned subsidiary. As a result of the
acquisition, DevX became a wholly owned subsidiary. 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. One of the primary reasons we acquired DevX was to add to our existing
producing property base in our East Texas and South Texas regions. We are
currently evaluating whether to divest the DevX properties in the Illinois Basin
and Mid-Continent regions, which are not part of our core operating areas. The
DevX acquisition added approximately 163.4 Bcfe of natural gas reserves to our
reserve base. Subsequent to the acquisition, we repurchased approximately $49.8
million of DevX's publicly held 12 1/2% senior notes for 110% of the principal
amount plus accrued interest.
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 2001, our net
cash flow provided by operating activities totaled $110.1 million. Our other
primary funding source in 2001 was borrowings of $261.0 million under our
previous and current revolving credit facilities.
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 2001, we incurred capital
expenditures of $189.6 million for development and exploration activities and
for the acquisition of DevX. We also repaid or refinanced $178.0 million of our
long-term debt. In connection with the acquisition of DevX, we assumed $55.0
million of debt and a working capital deficit of $0.7 million.
24
Our annual capital expenditure activity is summarized in the following
table:
Year Ended December 31,
--------------------------------
1999 2000 2001
-------- -------- --------
Acquisitions of oil and gas properties ..... $ 4,458 $ 9,684 $160,794
Other leasehold costs ...................... 2,258 6,964 9,541
Workovers and recompletions ................ 4,472 10,252 5,563
Offshore production facilities ............. 4,462 1,629 907
Development drilling ....................... 11,521 35,047 43,646
Exploratory drilling ....................... 8,126 19,202 33,382
Other ...................................... 684 616 172
-------- -------- --------
Total .................................. $ 35,981 $ 83,394 $254,005
======== ======== ========
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 $30.8 million, $73.1 million and
$93.0 million on development and exploration activities in 1999, 2000 and 2001,
respectively. We have budgeted approximately $75.0 million for development and
exploration projects in 2002. 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. To the
extent that natural gas prices do not recover from their current level, we
anticipate reducing our spending on development and exploration activities by
$10.0 million to $20.0 million in order to match these expenditures with our
cash flow provided by operations.
We spent $4.5 million, $9.7 million and $160.8 million on acquisition
activities in 1999, 2000 and 2001, respectively. We do not have a specific
acquisition budget for 2002 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.
In connection with the completion of the DevX acquisition, we entered into
a new $350.0 million revolving credit facility on December 17, 2001 with Toronto
Dominion (Texas), Inc. as administrative agent. The new bank credit facility is
a three year revolving credit line with an initial borrowing base of $270.0
million. The bank credit facility was used primarily to refinance our prior bank
credit facility, to finance the DevX acquisition and to repurchase the DevX
senior notes.
Indebtedness under the new 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 will
be 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 base rate 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.
25
The following table summarizes our aggregate liabilities and commitments by
year of maturity:
2002 2003 2004 2005 2006 2007 2008 Total
-------- -------- -------- -------- -------- -------- -------- --------
(in thousands)
Bank credit facility ... $ -- $ -- $ -- $227,000 $ -- $ -- $ -- $227,000
Senior notes ........... -- -- -- -- -- 145,000 -- 145,000
Other debt ............. 229 -- -- -- -- -- 235 464
Operating leases ....... 661 656 452 477 198 -- -- 2,444
Derivative liabilities . 798 1,053 -- -- -- -- -- 1,851
Preferred stock (1) .... -- -- -- 5,858 5,858 5,857 -- 17,573
-------- -------- -------- -------- -------- -------- -------- --------
$ 1,688 $ 1,709 $ 452 $233,335 $ 6,056 $150,857 $ 235 $394,332
======== ======== ======== ======== ======== ======== ======== ========
(1) Represents 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 our available borrowings
under the new 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.
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 (the "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 were outstanding. The
net proceeds were used to reduce amounts outstanding under our bank credit
facility and the borrowing base under the credit facility was reduced to $240.0
million. The Notes are unsecured obligations of Comstock and are guaranteed by
all of our subsidiaries.
Federal Taxation
At December 31, 2001, we had federal income tax net operating loss
carryforwards of approximately $98.6 million. We have established an $23.0
million valuation allowance against part of the net operating loss carryforwards
acquired from DevX due to a "change in control" limitation which will prevent us
from fully realizing the DevX carryforwards. The carryforwards expire from 2018
through 2021. 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 selected to use the more conservative
successful efforts method to account for our oil and gas activities and we do
not capitalize any of our general and administrative expenses.
26
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 Securities and Exchange Commission and the Financial
Accounting Standards Board. 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, 2001, we used an initial oil price of
$19.86 per barrel and an initial natural gas price of $2.39 per Mcf. Such prices
were escalated each year 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, the $1.4 million impairment provision recorded in 2001 could
have been significantly higher.
Related Party Transactions
In recent years we have not entered into any significant 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 2001, 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 $1.6 million and a $1.00 change in the price per Mcf of
natural gas would have changed our cash flow by approximately $26.9 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
27
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 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, generally we 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.
In connection with the DevX acquisition, we assumed certain derivative
financial instruments entered into by DevX to manage natural gas price risks.
The following table sets out the derivative financial instruments outstanding at
December 31, 2001 which are held for natural gas price risk management:
Volume Type Floor Ceiling Swap
Period Beginning Period Ending (MMBtu) of Instrument Price Price Price
---------------- ----------------- ----------- -------------- ------------ ----------- ----------
January 1, 2002 December 31, 2002 640,000 Floor $1.90 -- --
January 1, 2002 December 31, 2002 2,550,000 Floor $2.00 -- --
January 1, 2002 December 31, 2002 1,600,000 Swap -- -- $2.40
January 1, 2002 December 31, 2002 900,000 Collar $4.00 $6.75 --
-----------
5,690,000
-----------
January 1, 2003 December 31, 2003 560,000 Floor $1.90 -- --
January 1, 2003 December 31, 2003 2,250,000 Floor $2.00 -- --
January 1, 2003 December 31, 2003 1,400,000 Swap -- -- $2.40
-----------
4,210,000
-----------
9,900,000
===========
The counterparty for the $1.90 floor position and $2.40 swap price position
is a subsidiary of Enron Corporation, which has filed for bankruptcy protection.
The net liability owed to Enron as of December 31, 2001 was $1.6 million. We
intend to monitor this position and will assess the credit exposure to the
extent this position becomes a net asset.
The fair value of the commodity price derivative financial instruments at
December 31, 2001 was a net liability of $42,000. As of December 31, 2001, we
have not designated these derivative financial instruments as cash flow hedges.
Accordingly, all changes in fair value of these derivatives will be recorded in
earnings unless we elect to designate these instruments as cash flow hedges.
On March 21 and 22, 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 planned
2002 drilling program. The hedges cover approximately 45% to 50% of our expected
2002 natural gas production from April 2002 to October 2002. We entered into
price swaps covering 50 MMBtus per day of our natural gas production at an
average price of $3.46. The price swaps will be settled using the closing index
price for natural gas delivered to the Houston Ship Channel for 38.2 MMBtus per
day and the closing contract price for natural gas delivered to the Henry Hub on
the New York Mercantile Exchange for 11.8 MMBtus per day.
28
Interest Rates
At December 31, 2001, we had long-term debt of $372.2 million. Of this
amount, $145.0 million bears interest at a fixed rate of 11 1/4%. The fair
market value of the fixed rate debt as of December 31, 2001 was $142.1 million
based on the market price of 98% of the face amount. We had $227.0 million
outstanding under our revolving bank credit facility, which is subject to
floating market rates of interest. Borrowings under the bank credit facility
bear interest at a fluctuating rate that is linked to LIBOR or the corporate
base rate, at our option. Any increases in these interest rates can have an
adverse impact on our results of operations and cash flow. In March 2001, 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 April 30,
2001 and expiring on April 30, 2002. As a result of this interest rate swap, we
realized a loss of $199,000 in 2001. The fair value of this interest rate
derivative financial instrument was a net liability of $214,000 at December 31,
2001.
ITEM 8. FINANCIAL STATEMENTS
Our consolidated financial statements are included on pages F-1 to F-26 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, Arthur Andersen 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
Not applicable.
29
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item is incorporated herein by reference
to our definitive proxy statement which will be filed with the Securities and
Exchange Commission within 120 days after December 31, 2001.
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, 2001.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
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, 2001.
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, 2001.
PART IV
ITEM 14. 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).
31
Exhibit No. Description
------------- ------------------------------------------------------------
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 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).
4.4 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).
4.5 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).
4.6 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).
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.
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.
10.4 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).
10.5 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).
10.6# Employment Agreement dated May 16, 2000, by and between
Comstock and M. Jay Allison (incorporated herein by
reference to Exhibit 10.4 to our Quarterly Report on Form
10-Q for the quarter ended June 30, 2000).
10.7# Employment Agreement dated May 16, 2000, by and between
Comstock and Roland O. Burns (incorporated herein by
reference to Exhibit 10.5 to our Quarterly Report on Form
10-Q for the quarter ended June 30, 2000).
10.8# 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).
10.9# 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).
31
Exhibit No. Description
------------- ------------------------------------------------------------
10.10# 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).
10.11 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).
10.12 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).
10.13 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).
21* Subsidiaries of the Company.
23* Consent of Arthur Andersen LLP.
99.1* Letter to the Securities and Exchange Commission regarding
Arthur Andersen LLP Audit.
* Filed herewith.
# Management contract or compensatory plan document.
Reports on Form 8-K:
Form 8-K Reports filed subsequent to September 30, 2001 are as follows:
Date Item Description
----------------- -------- -----------------------------------------------
November 13, 2001 5 Entered into Agreement and Plan of Merger
with DevX Energy, Inc.
December 21, 2001 2 Completed Acquisition of DevX Energy, Inc
and Entered into a New Bank Credit Facility.
February 6, 2002 2 Historical and Proforma Financial Information
of DevX Energy, Inc.
March 12, 2002 5 Issued $75 Million of 11 1/4% Senior Notes
due 2007.
32
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
COMSTOCK RESOURCES, INC.
By:/s/M. JAY ALLISON
-----------------
M. Jay Allison
President and Chief Executive Officer
Date: March 25, 2002 (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 25, 2002
----------------- Chairman of the Board of Directors
M. Jay Allison (Principal Executive Officer)
/s/ROLAND O. BURNS Senior Vice President, Chief March 25, 2002
------------------ Financial Officer, Secretary, Treasurer
Roland O. Burns and Director
(Principal Financial and Accounting Officer)
/s/DAVID K. LOCKETT Director March 25, 2002
-------------------
David K. Lockett
/s/CECIL E. MARTIN, JR. Director March 25, 2002
----------------------
Cecil E. Martin, Jr.
/s/DAVID W. SLEDGE Director March 25, 2002
------------------
David W. Sledge
33
CONSOLIDATED FINANCIAL STATEMENTS OF
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
INDEX
Report of Independent Public Accountants.....................................F-2
Consolidated Balance Sheets as of December 31, 2000 and 2001.................F-3
Consolidated Statements of Operations for the Years Ended
December 31, 1999, 2000 and 2001.....................................F-4
Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 1999, 2000 and 2001.....................................F-5
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1999, 2000 and 2001.....................................F-6
Notes to Consolidated Financial Statements...................................F-7
F-1
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders
of Comstock Resources, Inc.:
We have audited the accompanying consolidated balance sheets of Comstock
Resources, Inc. (a Nevada corporation) and subsidiaries as of December 31, 2000
and 2001, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 2001. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Comstock Resources, Inc. and
subsidiaries as of December 31, 2000 and 2001, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.
As explained in Note 1 of the financial statements effective January 1,
2001, the Company changed its method of accounting for derivative instruments.
ARTHUR ANDERSEN LLP
Dallas, Texas,
March 8, 2002
F-2
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31, 2000 and 2001
ASSETS
December 31,
----------------------
2000 2001
--------- ---------
(In thousands)
Cash and Cash Equivalents ................................ $ 7,105 $ 6,122
Accounts Receivable:
Oil and gas sales .................................... 34,637 20,015
Joint interest operations ............................ 4,574 4,717
Derivatives .............................................. -- 1,342
Other Current Assets ..................................... 2,842 7,418
--------- ---------
Total current assets ......................... 49,158 39,614
Property and Equipment:
Unevaluated oil and gas properties ................... 5,206 13,416
Oil and gas properties, successful efforts method .... 659,505 901,206
Other ................................................ 2,589 2,633
Accumulated depreciation, depletion and amortization . (232,387) (278,679)
--------- ---------
Net property and equipment ................... 434,913 638,576
Derivatives .............................................. -- 254
Other Assets ............................................. 5,859 4,627
--------- ---------
$ 489,930 $ 683,071
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Portion of Long-Term Debt ........................ $ 101 $ 229
Accounts Payable and Accrued Expenses .................... 45,544 37,389
Derivatives .............................................. -- 798
--------- ---------
Total current liabilities .................... 45,645 38,416
Long-Term Debt, less current portion ..................... 234,000 372,235
Deferred Taxes Payable ................................... 22,555 47,911
Derivatives .............................................. -- 1,053
Reserve for Future Abandonment Costs ..................... 7,557 7,794
Stockholders' Equity:
Preferred stock--$10.00 par, 5,000,000 shares
authorized, 1,757,310 shares outstanding
at December 31, 2000 and 2001 ...................... 17,573 17,573
Common stock--$0.50 par, 50,000,000 shares authorized,
28,837,755 and 28,552,553 shares outstanding at
December 31, 2000 and 2001, respectively ........... 14,419 14,276
Additional paid-in capital ........................... 129,896 130,956
Retained earnings .................................... 19,329 54,183
Deferred compensation-restricted stock grants ........ (1,044) (1,187)
Accumulated other comprehensive loss ................. -- (139)
--------- ---------
Total stockholders' equity ................... 180,173 215,662
--------- ---------
$ 489,930 $ 683,071
========= =========
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, 1999, 2000 and 2001
1999 2000 2001
--------- --------- ---------
(In thousands, except per share amounts)
Revenues:
Oil and gas sales ....................... $ 90,103 $ 169,350 $ 167,689
Gain on sales of property ............... 130 33 12
Other income ............................ 1,911 319 699
--------- --------- ---------
Total revenues ................. 92,144 169,702 168,400
--------- --------- ---------
Expenses:
Oil and gas operating ................... 23,714 29,707 32,417
Exploration ............................. 1,832 3,192 4,215
Depreciation, depletion and amortization 45,171 44,958 49,191
General and administrative, net ......... 2,399 3,537 4,351
Interest ................................ 23,361 24,611 20,737
Impairment of oil and gas properties .... -- -- 1,400
--------- --------- ---------
Total expenses ................. 96,477 106,005 112,311
--------- --------- ---------
Income (loss) before income taxes ............ (4,333) 63,697 56,089
Income tax benefit (expense) ................. 1,517 (22,294) (19,631)
--------- --------- ---------
Net income (loss) ............................ (2,816) 41,403 36,458
Preferred stock dividends .................... (1,853) (2,471) (1,604)
--------- --------- ---------
Net income (loss) attributable to common stock $ (4,669) $ 38,932 $ 34,854
========= ========= =========
Net income (loss) per share:
Basic........................... $ (0.19) $ 1.48 $ 1.20
========= ========= =========
Diluted......................... $ 1.21 $ 1.06
========= =========
Weighted average shares outstanding:
Basic........................... 24,601 26,290 29,030
========= ========= =========
Diluted........................ 34,219 34,552
========= =========
The accompanying notes are an integral part of these statements.
F-4
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Years Ended December 31, 1999, 2000 and 2001
Deferred Accumulated
Additional Retained Compensation Other
Preferred Common Paid-In Earnings Restricted Comprehensive
Stock Stock Capital (Deficit) Stock Grants Loss Total
--------- --------- --------- --------- --------- --------- ---------
(In thousands)
Balance at December 31, 1998... $ -- $ 12,175 $ 112,432 $ (14,934) $ (10) $ -- $ 109,663
Issuance of preferred stock.. 30,000 -- -- -- -- -- 30,000
Issuance of common stock..... -- 400 1,166 -- -- -- 1,566
Value of stock options issued
for exploration prospects -- 498 -- -- -- 498
Restricted stock grants...... -- 113 759 -- (756) -- 116
Net loss attributable to
common stock.............. -- -- -- (4,669) -- -- (4,669)
--------- --------- --------- --------- --------- --------- ---------
Balance at December 31, 1999... 30,000 12,688 114,855 (19,603) (766) -- 137,174
--------- --------- --------- --------- --------- --------- ---------
Conversion of preferred stock (12,427) 1,553 10,874 -- -- -- --
Issuance of common stock .... -- 150 706 -- -- -- 856
Value of stock options issued
for exploration prospects -- -- 2,990 -- -- -- 2,990
Restricted stock grants...... -- 28 471 -- (278) -- 221
Net income attributable to
common stock.............. -- -- -- 38,932 -- -- 38,932
--------- --------- --------- --------- --------- --------- ---------
Balance at December 31, 2000... 17,573 14,419 129,896 19,329 (1,044) -- 180,173
--------- --------- --------- --------- --------- --------- ---------
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 ............. -- -- -- 34,854 -- -- 34,854
Unrealized hedge losses...... -- -- -- -- -- (139) (139)
---------
Comprehensive income....... -- -- -- -- -- -- 34,715
--------- --------- --------- --------- --------- --------- ---------
Balance at December 31, 2001... $ 17,573 $ 14,276 $ 130,956 $ 54,183 $ (1,187) $ (139) $ 215,662
========= ========= ========= ========= ========= ========= =========
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, 1999, 2000 and 2001
1999 2000 2001
--------- --------- ---------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) ............................... $ (2,816) $ 41,403 $ 36,458
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Compensation paid in common stock ............. 247 314 244
Depreciation, depletion and amortization ...... 45,171 44,958 49,191
Impairment of oil and gas properties .......... -- -- 1,400
Deferred income taxes ......................... (1,517) 22,294 18,851
Exploration ................................... 1,832 3,192 4,215
Gain on sales of property ..................... (130) (33) (12)
Gain on Derivatives ........................... -- -- (254)
--------- --------- ---------
Working capital provided by operations ...... 42,787 112,128 110,093
Decrease (increase) in accounts receivable ...... (5,754) (15,596) 18,371
Decrease (increase) in other current assets ..... 548 (1,933) (1,229)
Increase (decrease) in accounts payable and
accrued expenses .............................. 935 9,957 (17,145)
--------- --------- ---------
Net cash provided by operating activities ... 38,516 104,556 110,090
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sales of properties ............... 778 33 45
Capital expenditures and acquisitions ........... (35,981) (83,394) (189,646)
--------- --------- ---------
Net cash provided by operating activities ... (35,203) (83,361) (189,601)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings ...................................... 10,378 18,408 261,730
Proceeds from senior notes offering ............. 149,221 -- --
Debt issuance costs ............................. (5,671) -- --
Principal payments on debt ...................... (184,351) (38,438) (178,355)
Proceeds from preferred stock offering .......... 30,000 -- --
Proceeds from common stock issuances ............ 296 763 1,989
Stock issuance costs ............................ (714) -- --
Repurchases of common stock ..................... -- -- (5,232)
Dividends paid on preferred stock ............... -- (2,471) (1,604)
--------- --------- ---------
Net cash provided by financing activities ....... (841) (21,738) 78,528
--------- --------- ---------
Net increase (decrease) in cash and cash
equivalents ............................... 2,472 (543) (983)
Cash and cash equivalents, beginning of year 5,176 7,648 7,105
--------- --------- ---------
Cash and cash equivalents, end of year ...... $ 7,648 $ 7,105 $ 6,122
========= ========= =========
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") 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.
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
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.
F-7
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
In accordance with the Statement of Financial Accounting Standards No. 121
"Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to Be
Disposed Of,"("SFAS 121")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. No impairment was required in 1999
or 2000. 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.
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 No.
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 which are included in Note 6.
Segment Reporting
Comstock presently operates in one business segment.
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 No. 133 requires that changes in the derivative's fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met. Since Comstock had no outstanding derivatives on January 1, 2001 there was
no effect on the financial statements as a result of such adoption.
F-8
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Major Purchasers
In 2001, Comstock had four 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 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. In 1999, Comstock had two purchasers which
accounted for 33% and 20% of total 1999 oil and gas sales.
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.
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.
Earnings Per Share
Basic and diluted earnings per share for 1999, 2000 and 2001 were
determined as follows:
Year Ended December 31,
----------------------------------------------------------------------------------------------
1999 2000 2001
----------------------------- ----------------------------- -----------------------------
Income Per Income Per Income Per
(Loss) Shares Share (Loss) Shares Share (Loss) Shares Share
-------- ------- ------- -------- ------- ------- -------- -------- -------
Basic Earnings Per Share:
Income (Loss) ............. $ (2,816) 24,601 $ 41,403 26,290 $ 36,458 29,030
Less Preferred Stock
Dividends ................ (1,853) -- (2,471) -- (1,604) --
-------- ------- -------- ------- -------- --------
Net Income (Loss) Available
to Common Stockholders ... $ (4,669) 24,601 $ (0.19) 38,932 26,290 $ 1.48 34,854 29,030 $ 1.20
======== ====== ======= ======== ======
Diluted Earning Per Share:
Effect of Dilutive Securities:
Stock Options............ -- 1,184 -- 1,129
Convertible Preferred Stock 2,471 6,745 1,604 4,393
-------- ------- -------- --------
Net Income Available to
Common Stockholders and
Assumed Conversions.... $ 41,403 34,219 $ 1.21 $ 36,458 34,552 $ 1.06
======== ======= ======== ======== ======= ======
F-9
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
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. For the year ended December 31, 2001, Comstock's
comprehensive income differed from net income by approximately $139,000, due to
the recognition in comprehensive income of unrealized losses related to certain
of Comstock's derivative instruments which have been designated as hedges. For
the years ended December 31, 1999 and 2000, there were no differences between
Comstock's net income or net loss and comprehensive income.
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,
-------------------------------
1999 2000 2001
--------- --------- ---------
(in thousands)
Noncash activities -
Common stock issued for compensation ...... $ 131 $ 93 $ 26
Value of vested stock options under
exploration venture ................... 498 2,990 3,028
Common stock issued in payment
of preferred stock dividends .......... 1,853 -- --
Cash payments -
Interest payments ......................... 20,840 24,731 20,607
Income tax payments ....................... -- -- 243
F-10
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
New Accounting Standards
In July 2001, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 141 ("SFAS 141") "Business Combinations."
SFAS 141 requires the purchase method of accounting for all business
combinations initiated after June 30, 2001 and eliminates the
pooling-of-interests method.
In July 2001, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 142 ("SFAS 142") "Goodwill and Other
Intangible Assets." SFAS 142 requires the discontinuance of goodwill
amortization. In addition, the SFAS 142 includes provisions regarding the
reclassification of certain existing recognized intangibles as goodwill,
reassessment of the useful lives of existing recognized intangibles,
reclassification of certain intangibles out of previously reported goodwill and
the testing for impairment of existing goodwill and other intangibles. SFAS 142
is required to be applied for fiscal years beginning after December 15, 2001,
with certain early adoption permitted. Comstock does not expect the adoption of
SFAS 142 to have a material effect on its financial condition or results of
operations.
In August 2001, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 143 ("SFAS 143") "Accounting for Asset
Retirement Obligations," which Comstock will be required to adopt as of 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 initial adoption of SFAS 143, Comstock will recognize
(1) a liability for any existing AROs not already provided for in Comstock's
reserve for future abandonment costs (2) capitalized cost related to the
additional liability and (3) accumulated depreciation on the additional
capitalized cost. Comstock has not determined the effect, if any, the adoption
of SFAS 143 will have on its financial statements.
In October 2001, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 144 ("SFAS 144") "Accounting for the
Impairment or Disposal of Long-Lived Assets," which supercedes SFAS 121. SFAS
144 addresses financial accounting and reporting for the impairment of
long-lived assets and for long-lived assets to be disposed of. However, SFAS 144
retains the fundamental provisions of SFAS No. 121 for recognition and
measurement of the impairment of long-lived assets to be held and used, and
measurement of long-lived assets to be disposed of by sale. SFAS 144 is
effective for fiscal years beginning after December 15, 2001. Comstock is in the
process of assessing the effect of adopting SFAS 144, which will be effective
for its first quarter of 2002.
F-11
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
(2) Acquisitions
Acquisition of DevX Energy, Inc.
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. One of the primary reasons
Comstock acquired DevX was to add to its existing producing property base in the
East Texas and South Texas regions. Comstock is currently evaluating whether to
divest of the DevX properties in the Illinois Basin and Mid Continent regions,
which are not part of its core operating areas. The DevX acquisition added
approximately 163.4 billion cubic feet equivalent of natural gas reserves to
Comstock's reserve base. Subsequent to the acquisition, Comstock repurchased
approximately $49.8 million of DevX's publically held 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 &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
========
F-12
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Pro Forma Information (Unaudited)
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.
Year Ended December 31,
2000 2001
--------- ---------
(In thousands,
except per share amounts)
Revenues:
Oil and gas sales ...................... $ 211,555 $ 206,288
Change in fair value of derivatives .... 442 2,870
Other income ........................... -- 1,164
--------- ---------
Total revenues ......................... 211,997 210,322
--------- ---------
Expenses:
Oil and gas operating .................. 37,648 40,534
Exploration ............................ 3,992 4,751
Depreciation, depletion and amortization 58,431 60,880
Impairment ............................. -- 1,400
General and administrative, net ........ 3,537 4,351
Interest ............................... 35,099 28,981
Change in fair value of derivatives .... 1,945 --
--------- ---------
Income before income taxes .................. 71,345 69,425
Provision for income taxes .................. (24,971) (24,299)
--------- ---------
Income ...................................... 46,374 45,126
Preferred stock dividends ................... (2,471) (1,604)
--------- ---------
Net income attributable to common stock ..... $ 43,903 $ 43,522
========= =========
Net income per share:
Basic................................. $ 1.67 $ 1.49
========= =========
Diluted............................... $ 1.36 $ 1.29
========= =========
F-13
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
(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,
-----------------------
2000 2001
--------- ---------
(In thousands)
Proved properties .............. $ 659,505 $ 901,206
Unproved properties ............ 5,206 13,416
Accumulated depreciation,
depletion and amortization (231,667) (277,670)
--------- ---------
$ 433,044 $ 636,952
========= =========
Costs Incurred
For the Year Ended December 31,
--------------------------------
1999 2000 2001
-------- -------- --------
(In thousands)
Property acquisitions
Proved properties..... $ 4,458 $ 11,302 $160,794
Unproved properties... 2,258 5,346 8,210
Development costs ....... 20,455 46,928 51,447
Exploration costs ....... 8,126 19,202 33,382
-------- -------- --------
$ 35,297 $ 82,778 $253,833
======== ======== ========
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, Comstock capitalized interest expense of $0.2 million on its
unproved properties which is included in the unproved property acquisition costs
in 2001.
F-14
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
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,
-----------------------------------
1999 2000 2001
--------- --------- ---------
(In thousands)
Oil and gas sales ........................ $ 90,103 $ 169,350 $ 167,689
Production costs ......................... (23,714) (29,707) (32,417)
Exploration .............................. (1,832) (3,192) (4,215)
Depreciation, depletion and amortization . (44,118) (43,478) (47,541)
Impairment of oil and gas properties ..... -- -- (1,400)
--------- --------- ---------
Operating income ................... 20,439 92,973 82,116
Income tax expense ....................... (7,154) (32,541) (28,741)
--------- --------- ---------
Results of operations of oil and gas
producing activities ......... $ 13,285 $ 60,432 $ 53,375
========= ========= =========
(4) Long-Term Debt
Long-term debt is comprised of the following:
As of December 31,
----------------------
2000 2001
--------- ---------
(In thousands)
Revolving Bank Credit Facility... $ 84,000 $ 227,000
11 1/4% Senior Notes due 2007.... 150,000 145,000
Other ........................... 101 464
--------- ---------
234,101 372,464
Less current portion ............ (101) (229)
--------- ---------
$ 234,000 $ 372,235
========= =========
On December 17, 2001, Comstock entered into a new 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 acquisition of DevX and the repurchase of the DevX
's senior notes were funded by borrowings under the new bank credit facility.
The bank credit facility was also used to refinance Comstock's existing bank
debt. The new 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
F-15
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
at December 31, 2001 was $270.0 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 base rate 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 assets and
Comstock's corporate 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.
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. The fair
market value of the Notes as of December 31, 2001 was $142.1 million based on
the market price of 98% of the face amount as of December 31, 2001.
On March 7, 2002, Comstock closed the sale in a private placement of $75.0
million of 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 were outstanding. The net proceeds were used to reduce amounts
outstanding under the bank credit facility. The borrowing base under the bank
credit facility was reduced to $240.0 million in connection with the issuance of
the additional Notes.
(5) Lease Commitments
Comstock rents office space under noncancellable leases. Minimum future
payments under the leases are as follows:
(In thousands)
2002............ $ 661
2003............ 656
2004............ 452
2005............ 477
2006............ 198
------
$2,444
======
(6) Stockholders' Equity
The authorized capital stock of Comstock consists of 10 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.
On April 29, 1999, Comstock issued 3,000,000 shares of convertible
preferred stock in a private placement and received proceeds of $30.0 million.
F-16
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The 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.
Each share of the 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 preferred stock are outstanding, Comstock is
obligated to redeem an amount of shares of preferred stock equal to one-third of
the shares of the preferred stock outstanding on May 1, 2005 at $10.00 per share
plus accrued and unpaid dividends. The mandatory redemption price may be paid
either in cash or in shares of Common Stock. Comstock has the option to redeem
the shares of preferred stock upon payment to the holders of the preferred stock
at a specified rate of return on the initial purchase. Upon a change of control
of Comstock, the holders of the preferred stock have the right to require
Comstock to purchase all or a portion of the preferred stock.
In September and October 2000, holders of 1,242,690 shares of the
convertible preferred stock converted their shares into 3,106,725 shares of
Common Stock. As a result of these conversions, $12.4 million of preferred
stockholders' equity was transferred to common stockholders' equity.
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, 2001 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
of 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 44,255, 8,182 and 5,342 shares of Common Stock in 1999, 2000 and 2001
respectively, in payment of fees aggregating $130,000, $93,000 and $26,000 for
1999, 2000 and 2001 respectively.
The outstanding preferred stock series provides that Comstock can issue
Common Stock in lieu of cash for payment of quarterly dividends. In 1999,
Comstock issued 640,525 shares of Common Stock in payment of dividends on its
preferred stock of $1.9 million. Comstock paid the preferred stock dividends in
cash in 2000 and 2001.
F-17
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Options and warrants to purchase Common Stock were exercised to purchase
115,000 shares, 291,400 shares and 560,606 shares in 1999, 2000 and 2001,
respectively. Such exercises yielded net proceeds of approximately $295,000,
$763,000 and $2.0 million in 1999, 2000 and 2001, respectively.
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, 2001, the Incentive Plans provide for future awards of stock options or
restricted stock grants of up to 264,260 shares of Common Stock plus 1% of the
outstanding shares of Common Stock each year beginning on January 1, 2002.
The following table summarizes stock option activity during 1999, 2000 and
2001 under the Incentive Plans:
Weighted
Number Average
of Shares Exercise Price Exercise Price
---------- --------------- --------------
Outstanding at December 31, 1998 3,890,500 $2.00 to $12.38 $ 7.81
Granted ................ 1,010,000 $3.88 3.88
Exercised .............. (115,000) $2.00 to $3.00 2.57
Forfeited .............. (155,500) $3.00 to $12.38 7.81
----------
Outstanding at December 31, 1999 4,630,000 $2.00 to $12.38 7.08
Granted ................ 351,250 $6.69 to $8.88 8.24
Exercised............... (291,400) $2.00 to $4.81 2.62
----------
Outstanding at December 31, 2000 4,689,850 $2.00 to $12.38 7.45
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
==========
Exercisable at December 31, 2001 2,995,400 $2.50 to $12.38 8.26
==========
F-18
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following table summarizes information about the Incentive Plans stock
options outstanding at December 31, 2001:
Number of Number of
Shares Weighted Average Shares
Exercise Price Outstanding Remaining Life Exercisable
-------------- ------------ ---------------- -------------
(Years)
$2.50 20,000 0.5 20,000
3.44 481,625 5.8 413,875
3.88 975,525 6.3 498,025
6.42 437,750 7.1 175,000
6.69 84,000 5.6 43,500
6.94 150,000 2.0 150,000
7.40 20,000 4.6 20,000
8.88 249,250 7.5 --
9.63 80,000 0.5 80,000
11.00 1,269,000 3.7 1,269,000
11.12 33,500 6.0 20,000
11.94 30,000 1.3 30,000
12.38 559,000 3.5 276,000
---------- ------ -------------
4,389,650 4.9 2,995,400
========== ====== =============
Comstock accounts for the stock options issued under the Incentive Plans
under APB 25, under which no compensation cost has been recognized. Had
compensation cost for these plans been determined consistent with SFAS 123, net
income attributable to common stock and earnings per share would have been
reduced to the following pro forma amounts:
1999 2000 2001
--------- -------- --------
(In thousands, except per share amounts)
Net income (loss): As Reported $ (4,669) $ 38,932 $ 34,854
Pro Forma (6,644) 36,958 33,168
Basic earnings per share: As Reported (0.19) 1.48 1.20
Pro Forma (0.27) 1.41 1.14
Diluted earnings per share: As Reported 1.21 1.06
Pro Forma 1.15 1.01
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 1999, 2000 and 2001, respectively: average
risk-free interest rates of 5.7, 6.2 and 4.9 percent; average expected lives of
8.8, 7.8 and 7.4 years; average expected volatility factors of 64.2, 66.4 and
67.2; and no dividend yield. The estimated weighted average fair value of
options to purchase one share of common stock issued under the Company's
Incentive Plans was $2.86 in 1999, $5.98 in 2000 and $6.80 in 2001.
F-19
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
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 667,500 shares have been awarded under
the Incentive Plans. As of December 31, 2001, 470,625 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, 1999, 2000 and 2001 was $116,000, $221,000 and
$218,000, respectively.
Exploration Venture Warrants
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 establishes 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 venture, Bois
d'Arc generates exploration prospects in the Gulf of Mexico utilizing 3-D
seismic data and their extensive geological expertise in this region. Comstock
advances funds for the acquisition of 3-D seismic data and leases as needed.
After a prospect is identified, Comstock is reimbursed for the costs that were
advanced and is entitled to a 40% non-promoted working interest in each
prospect. 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.
During 2001, Bois d' Arc earned warrants to purchase 360,000 shares at
$7.32 per share under the exploration agreement. 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. Such cost was capitalized as a cost of oil and gas
properties in 2001. 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 for the warrants earned under the prior exploraton agreement
which was capitalized to oil and gas properties was $1.5 million in 1998, $0.5
million in 1999, $3.0 million in 2000 and $1.0 million in 2001.
F-20
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
(7) 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 $79,000, $84,000 and $96,000 for the years ended December 31, 1999,
2000 and 2001, respectively.
(8) Income Taxes
The tax effects of significant temporary differences representing the net
deferred tax liability at December 31, 2000 and 2001 were as follows:
2000 2001
-------- --------
(In thousands)
Net deferred tax assets (liabilities):
Property and equipment .................. $(36,562) $(75,269)
Net operating loss carryforwards ........ 13,457 34,504
Valuation allowance on net operating
loss carryforwar.................... -- (8,043)
Other carryforwards ..................... 550 897
-------- --------
$(22,555) $(47,911)
======== ========
The following is an analysis of the consolidated income tax expense:
2000 2001
-------- --------
(In thousands)
Current................................ $ -- $ --
Deferred............................... 22,294 19,631
-------- --------
$ 22,294 $ 19,631
======== ========
There were no significant differences between income taxes computed using
the statutory rate of 35% and Comstock's effective tax rate in 2000 and 2001 of
35%.
F-21
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
At December 31, 2001, Comstock had the following carryforwards available to
reduce future income taxes:
Years of
Types of Carryforward Carryforward Amounts
----------------------------------- ------------ ---------
($ in thousands)
Net operations loss -U.S. federal 2018 - 2021 $ 98,583
Alternative Minimum tax credits Unlimited 792
Charitable contribution carryforward 2003 - 2006 324
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 has been
established for Comstock's estimate of the 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.
(9) 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-22
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
In connection with the DevX acquisition, Comstock assumed certain
derivative financial instruments entered into by DevX to manage natural gas
price risk. The following table sets out the derivative financial instruments
outstanding at December 31, 2001 which are held for natural gas price risk
management:
Volume Type Floor Ceiling Swap
Period Beginning Period Ending (MMBtu) of Instrument Price Price Price
---------------- ----------------- ----------- ------------- --------- ---------- --------
January 1, 2002 December 31, 2002 640,000 Floor $1.90 -- --
January 1, 2002 December 31, 2002 2,550,000 Floor $2.00 -- --
January 1, 2002 December 31, 2002 1,600,000 Swap -- -- $2.40
January 1, 2002 December 31, 2002 900,000 Collar $4.00 $6.75 --
-----------
5,690,000
-----------
January 1, 2003 December 31, 2003 560,000 Floor $1.90 -- --
January 1, 2003 December 31, 2003 2,250,000 Floor $2.00 -- --
January 1, 2003 December 31, 2003 1,400,000 Swap -- -- $2.40
------------
4,210,000
------------
9,900,000
============
The counterparty for the $1.90 floor position and $2.40 swap price position
is a subsidiary of Enron Corporation who has filed for bankruptcy protection.
The net liability owed to Enron as of December 31, 2001, was $1.6 million.
Comstock intends to monitor this position and will assess the credit exposure to
the extent this position becomes a net asset.
As a result of certain hedging transactions for natural gas price risk,
Comstock has realized the following gains and losses which were included in oil
and gas sales:
1999 2000 2001
-------- -------- --------
(In thousands)
Realized Gains $ 248 $ -- $ --
Realized Losses (5,178) -- --
Comstock periodically enters into interest rate swap agreements to hedge
the impact of interest rate changes on its floating rate long-term debt. As of
December 31, 2001, Comstock had an interest rate swap agreement covering $25.0
million of its floating rate debt which fixed the LIBOR rate at 4.5% for the
period April 2001 through April 2002. Comstock has designated this position as a
hedge. As a result of certain hedging transaction for interest rates, Comstock
has realized the following gains or losses which were included in interest
expense:
1999 2000 2001
-------- -------- --------
(In thousands)
Realized Gains $ 169 $ 988 $ --
Realized Losses -- -- (199)
F-23
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Effective January 1, 2001, Comstock adopted SFAS 133 which required that
all derivative financial instruments are to be included on the balance sheet at
the fair value. 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
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.
Comstock has not designated any of the natural gas price derivative
financial instruments acquired in the DevX acquisition as hedges. The change in
fair value of these derivative contracts resulted in a gain of $254,000 which is
included in other income in 2001. The interest rate swap has been designated
swap as a cash flow hedge. As a result the change in fair value of this
instrument of an unrealized after tax loss of $139,000 was recognized in other
comprehensive income.
(10) Supplementary Quarterly Financial Data (Unaudited)
First Second Third Fourth Total
-------- -------- -------- -------- --------
(In thousands, except per share amounts)
2000 -
Total revenues ........ $ 33,143 $ 38,634 $ 44,987 $ 52,938 $169,702
======== ======== ======== ======== ========
Net income attributable
to common stock .... $ 4,085 $ 7,934 $ 12,135 $ 14,778 $ 38,932
======== ======== ======== ======== ========
Net income per share:
Basic .............. $ 0.16 $ 0.31 $ 0.47 $ 0.52 $ 1.48
======== ======== ======== ======== ========
Diluted ............ $ 0.14 $ 0.25 $ 0.37 $ 0.44 $ 1.21
======== ======== ======== ======== ========
2001 -
Total revenues ........ $ 67,546 $ 46,575 $ 29,781 $ 24,498 $168,400
======== ======== ======== ======== ========
Net income attributable
to common stock .... $ 23,578 $ 12,439 $ 2,486 $ (3,649) $ 34,854
======== ======== ======== ======== ========
Net income per share:
Basic .............. $ 0.81 $ 0.43 $ 0.09 ($ 0.13) $ 1.20
======== ======== ======== ======== ========
Diluted ............ $ 0.68 $ 0.37 $ 0.09 $ 1.06
======== ======== ======== ========
F-24
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
(11) 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, 2001.
1999 2000 2001
-------------------- -------------------- --------------------
Oil Gas Oil Gas Oil Gas
(MBbls) (MMcf) (MBbls) (MMcf) (MBbls) (MMcf)
-------- -------- -------- -------- -------- --------
Proved Reserves:
Beginning of year ............ 20,245 250,402 19,467 258,121 17,451 297,835
Revisions of previous
estimates ............... (1,695) (14,272) (1,725) 1,205 (1,177) (10,959)
Extensions and discoveries ... 3,029 39,534 1,599 54,574 1,395 46,777
Purchases of minerals in place 16 6,329 416 11,059 1,213 156,515
Sales of minerals in place ... -- -- (499) (134) -- --
Production ................... (2,128) (23,872) (1,807) (26,990) (1,534) (28,083)
-------- -------- -------- -------- -------- --------
End of year .................. 19,467 258,121 17,451 297,835 17,348 462,085
======== ======== ======== ======== ======== ========
Proved Developed Reserves:
Beginning of year ............ 16,585 182,955 14,379 184,123 12,290 200,349
======== ======== ======== ======== ======== ========
End of year .................. 14,379 184,123 12,290 200,349 12,212 315,779
======== ======== ======== ======== ======== ========
The following table sets forth the standardized measure of discounted
future net cash flows relating to proved reserves at December 31, 2000 and 2001:
2000 2001
----------- -----------
(In thousands)
Cash Flows Relating to Proved Reserves:
Future Cash Flows ................................. $ 3,590,711 $ 1,566,781
Future Costs:
Production .................................... (527,939) (453,416)
Development ................................... (126,904) (156,906)
----------- -----------
Future Net Cash Flows Before Income Taxes ......... 2,935,868 956,459
Future Income Taxes ............................... (825,033) (179,098)
----------- -----------
Future Net Cash Flows ............................. 2,110,835 777,361
10% Discount Factor ............................... (822,071) (270,257)
----------- -----------
Standardized Measure of Discounted Future Net Cash Flows $ 1,288,764 $ 507,104
=========== ===========
F-25
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
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, 1999, 2000 and 2001:
1999 2000 2001
----------- ----------- -----------
(In thousands)
Standardized Measure, Beginning of Year ............ $ 304,993 $ 468,713 $ 1,288,764
Net Change in Sales Price, Net of Production Costs.. 179,042 1,141,880 (1,298,310)
Development Costs Incurred During the Year Which
Were Previously Estimated ........................ 5,303 17,340 26,627
Revisions of Quantity Estimates .................... (35,727) (44,256) (21,339)
Accretion of Discount .............................. 30,531 51,506 173,747
Changes in Future Development Costs ................ (437) (41,525) (6,571)
Changes in Timing and Other ........................ (2,271) (166,410) (141,843)
Extensions and Discoveries ......................... 91,911 375,632 86,026
Purchases of Reserves in Place ..................... 7,787 62,621 120,147
Sales of Reserves in Place ......................... -- (3,355) --
Sales, Net of Production Costs ..................... (66,389) (139,643) (135,272)
Net Changes in Income Taxes ........................ (46,030) (433,739) 415,128
----------- ----------- -----------
Standardized Measure, End of Year .................. $ 468,713 $ 1,288,764 $ 507,104
=========== =========== ===========
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.
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:
1999 2000 2001
------- ------- -------
Crude Oil (Per Barrel)........ $ 24.56 $ 26.34 $ 18.73
======= ======= =======
Natural Gas (Per Mcf) ........ $ 2.51 $ 10.51 $ 2.69
======= ======= =======
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-26