CARRIZO OIL & GAS INC - 10-Q Quarterly Report

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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended SEPTEMBER 30, 2002
------------------

[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934

For the transition period from ________ to ________

Commission File Number 000-22915.

CARRIZO OIL & GAS, INC.
(Exact name of registrant as specified in its charter)

TEXAS 76-0415919
----- ----------
(State or other jurisdiction of (IRS Employer Identification No.)
incorporation or organization)

14701 ST. MARY'S LANE, SUITE 800, HOUSTON, TX 77079
- --------------------------------------------- -----
(Address of principal executive offices) (Zip Code)

(281) 496-1352
--------------
(Registrant's telephone number)

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
-- --

The number of shares outstanding of the registrant's common stock, par value
$0.01 per share, as of November 8, 2002, the latest practicable date, was
14,176,716.

CARRIZO OIL & GAS, INC.
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2002
INDEX

CARRIZO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

The accompanying notes are an integral part of these
consolidated financial statements.

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

The accompanying notes are an integral part of these
consolidated financial statements.

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CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

The accompanying notes are an integral part of these
consolidated financial statements.

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CARRIZO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. ACCOUNTING POLICIES:

The consolidated financial statements included herein have been prepared by
Carrizo Oil & Gas, Inc. (the Company), and are unaudited, except for the balance
sheet at December 31, 2001, which has been prepared from the audited financial
statements at that date. The financial statements reflect the accounts of the
Company and its subsidiary after elimination of all significant intercompany
transactions and balances. The financial statements reflect necessary
adjustments, all of which were of a recurring nature, and are in the opinion of
management necessary for a fair presentation. Certain information and footnote
disclosures normally included in financial statements prepared in accordance
with generally accepted accounting principles have been omitted pursuant to the
rules and regulations of the Securities and Exchange Commission (SEC). The
Company believes that the disclosures presented are adequate to allow the
information presented not to be misleading. The financial statements included
herein should be read in conjunction with the audited financial statements and
notes thereto included in the Company's Annual Report on Form 10-K for the year
ended December 31, 2001.

Certain items in the prior years have been reclassified to be consistent with
the current presentation.

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2. EARNINGS PER COMMON SHARE:

Supplemental earnings per share information is provided below:

Net income per common share has been computed by dividing net income by the
weighted average number of shares of common stock outstanding during the
periods. The Company had outstanding 161,500 and 393,833 stock options, zero and
252,632 warrants and zero and 1,090,649 convertible preferred shares during the
three months ended September 30, 2001 and 2002, respectively, which were
antidilutive and were not included in the calculation because the exercise price
of these instruments exceeded the underlying market value of the options and
warrants. The Company also had outstanding 79,500 and 406,833 stock options,
zero and 252,632 warrants and zero and 1,090,649 convertible preferred shares
during the nine months ended September 30, 2001 and 2002, respectively, which
were antidilutive and were not included in the calculation.

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3. DEBT:

At December 31, 2001 and September 30, 2002, debt consisted of the following:

On May 24, 2002, the Company entered into a credit agreement with Hibernia
National Bank (the "Hibernia Facility") which matures on January 31, 2005, and
repaid its existing facility with Compass Bank (the "Compass Facility"). The
Hibernia Facility provides a revolving line of credit of up to $30 million. It
is secured by substantially all of the Company's assets and is guaranteed by all
of the Company's subsidiaries.

The borrowing base will be determined by Hibernia National Bank at least
semi-annually on each October 31 and April 30. The initial borrowing base was
$12 million and the borrowing base as of October 31, 2002 was $13 million. Each
party to the credit agreement can request one unscheduled borrowing base
determination subsequent to each scheduled determination. The borrowing base
will at all times equal the borrowing base most recently determined by Hibernia
National Bank, less quarterly borrowing base reductions required subsequent to
such determination. Hibernia National Bank will reset the borrowing base amount
at each scheduled and each unscheduled borrowing base determination date. The
initial quarterly borrowing base reduction, which commenced on June 30, 2002,
was $1,250,000. The quarterly borrowing base reduction effective January 31,
2003 is $1,750,000.

In November, 2002, the Company received a commitment from Hibernia National Bank
to provide additional availability under the Hibernia Facility in the amount of
$2.5 million which is structured as an additional "Tranche B" under the Hibernia
Facility. As such, upon completion of the amendment to the credit agreement, the
total borrowing base under the Hibernia Facility will be $15.5 million, of which
$6.5 million is currently drawn. The Tranche B bears interest at LIBOR plus
3.375%, is secured by certain leases and working interests in oil and natural
gas wells and matures on April 30, 2003.

If the principal balance of the Hibernia Facility ever exceeds the borrowing
base as reduced by the quarterly borrowing base reduction (as described above),
the principal balance in excess of such reduced borrowing base will be due as of
the date of such reduction. Otherwise, any unpaid principal or interest will be
due at maturity.

If the principal balance of the Hibernia Facility ever exceeds any re-determined
borrowing base, the Company has the option within thirty days to (individually
or in combination): (i) make a lump sum payment curing the deficiency; (ii)
pledge additional collateral sufficient in Hibernia National Bank's opinion to
increase the borrowing base and cure the deficiency; or (iii) begin making equal
monthly principal payments that will cure the deficiency within the ensuing
six-month period. Such payments are in addition to any payments that may come
due as a result of the quarterly borrowing base reductions.

For each tranche of principal borrowed under the revolving line of credit, the
interest rate will be, at the Company's option: (i) the Eurodollar Rate, plus an
applicable margin equal to 2.375% if the amount borrowed is greater than or
equal to 90% of the borrowing base, 2.0% if the amount borrowed is less than
90%, but greater than or equal to 50% of the borrowing base, or 1.625% if the
amount borrowed is less than 50% of the borrowing base; or (ii) the Base Rate,
plus an applicable margin of 0.375% if the amount borrowed is greater than or
equal to 90% of the borrowing base. Interest on Eurodollar Loans is payable on
either the last day of each Eurodollar option period or monthly, whichever is
earlier. Interest on Base Rate Loans is payable monthly.

The Company is subject to certain covenants under the terms of the Hibernia
Facility, including, but not limited to the maintenance of the following
financial covenants: (i) a minimum current ratio of 1.0 to 1.0 (including
availability under the borrowing base), (ii) a minimum quarterly debt services
coverage of 1.25 times, and (iii) a minimum shareholders equity equal to $56
million, plus 100% of all subsequent common and preferred equity contributed by
shareholders, plus 50% of all positive earning occurring subsequent to such
quarter end, all ratios as more particularly discussed in the

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credit facility. The Hibernia Facility also places restrictions on additional
indebtedness, dividends to non-preferred stockholders, liens, investments,
mergers, acquisitions, asset dispositions, asset pledges and mortgages, change
of control, repurchase or redemption for cash of the Company's common or
preferred stock, speculative commodity transactions, and other matters.

At December 31, 2001 and September 30, 2002, amounts outstanding under the
Compass Facility totaled $7,166,000 and zero, respectively, with an additional
$620,000 and zero, respectively, available for future borrowings. At December
31, 2001 and September 30, 2002, amounts outstanding under the Hibernia Facility
totaled zero and $6,500,000, respectively, with an additional zero and
$4,250,000, respectively, available for future borrowings. At December 31, 2001,
one letter of credit was issued and outstanding under the Compass Facility in
the amount of $224,000. At September 30, 2002, one letter of credit was issued
and outstanding under the Hibernia Facility in the amount of $224,000.

On June 29, 2001, CCBM, Inc., a wholly owned subsidiary of the Company ("CCBM"),
issued a non-recourse promissory note payable in the amount of $7,500,000 to
Rocky Mountain Gas, Inc. ("RMG") as consideration for certain interests in oil
and gas leases held by RMG in Wyoming and Montana. The RMG note is payable in
41-monthly principal payments of $125,000 plus interest at 8% per annum
commencing July 31, 2001 with the balance due December 31, 2004. The RMG note is
secured solely by CCBM's interests in the oil and gas leases in Wyoming and
Montana. At December 31, 2001 and September 30, 2002, the outstanding principal
balance of this note was $6,750,000 and $5,625,000, respectively.

In December 2001, the Company entered into a capital lease agreement secured by
certain production equipment in the amount of $243,369. The lease is payable in
one payment of $11,323 and 35 monthly payments of $7,549 including interest at
8.6% per annum. The Company has the option to acquire the equipment at the
conclusion of the lease for $1.

In December 1999, the Company consummated the sale of $22 million principal
amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") to an
investor group led by CB Capital Investors, L.P. (now known as JPMorgan
Partners, LLC) which included certain members of the Board of Directors.
Concurrently, the Company also sold $8 million of Common Stock and Warrants to
this investor group. The Subordinated Notes were sold at a discount of $688,761,
which is being amortized over the life of the notes. Interest payments are due
quarterly commencing on March 31, 2000. The Company may elect, for a period of
up to five years, to increase the amount of the Subordinated Notes for 60% of
the interest which would otherwise be payable in cash. As of December 31, 2001
and September 30, 2002, the outstanding balance of the Subordinated Notes had
been increased by $2,552,970 and $3,560,850, respectively, for such interest
paid in kind.

The Company is subject to certain covenants under the terms under the
Subordinated Notes securities purchase agreement, including but not limited to,
(a) maintenance of a specified tangible net worth, (b) maintenance of a ratio of
EBITDA (earnings before interest, taxes, depreciation and amortization) to
quarterly Debt Service (as defined in the agreement) of not less than 1.00 to
1.00, and (c) a limitation of its capital expenditures to an amount equal to the
Company's EBITDA for the immediately prior fiscal year (unless approved by the
Company's Board of Directors and a JPMorgan Partners, LLC appointed director).

4. INCOME TAXES:

The Company has recorded a provision for deferred income taxes at the rate of
35%, which also approximates its statutory rate. Such provisions were $1,927,215
and $633,378 for the three months ended September 30, 2001 and 2002,
respectively and $5,066,291 and $1,333,358 for the nine months ended September
30, 2001 and 2002, respectively.

5. COMMITMENTS AND CONTINGENCIES:

From time to time, the Company is party to certain legal actions and claims
arising in the ordinary course of business. While the outcome of these events
cannot be predicted with certainty, management does not expect these matters to
have a materially adverse effect on the financial position or results of
operations of the Company.

In July 2001, the Company was notified of a prior lease in favor of a
predecessor of ExxonMobil purporting to be valid and covering the same property
as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part
of a unit in N. La Copita Prospect in which the Company owns a non-operating
interest. The operator of the lease, GMT, filed a petition for, and was granted,
a temporary restraining order against ExxonMobil in the 229th Judicial Court in
Starr County, Texas enjoining ExxonMobil from taking possession of the four
Neblett wells. Pending resolution of the underlying title issue, the temporary
restraining order was extended voluntarily by agreement of the parties,
conditioned on GMT paying the revenues into escrow and agreeing to provide
ExxonMobil with certain discovery materials in this action. ExxonMobil has filed
a counterclaim against GMT and all the non-operators, including the Company, to
establish the validity of its lease, remove cloud on title, quiet title to the
property, and for conversion, trespass and

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punitive damages. ExxonMobil seeks unspecified damages for the lost profits on
the sale of the hydrocarbons from this property, and for a determination of
whether the Company and the other working interest owners were in good faith or
bad faith in trespassing on this lease. If a determination of bad faith is made,
the parties will not be able to recover their costs of developing this property
from the revenues therefrom. While there is always a risk in the outcome of the
litigation, the Company believes there is no question that the Company acted in
good faith and intends to vigorously defend its position. If the case cannot be
settled and the title issue is decided unfavorably, the Company believes that it
will ultimately be able to recover its drilling and operating costs as a good
faith trespasser. A complete loss of the lease in question would result in the
loss to the Company of approximately .6 Bcfe of reported proved reserves as of
December 31, 2000 or .9 Bcfe of reported proved reserves as of June 30, 2001. No
reserves with respect to these properties were included in the Company's
reported proved reserves as of December 31, 2001 and September 30, 2002. At the
time of shut in, the Neblett #1 well was producing at the rate of approximately
45 Mcfe per day, the Neblett #2 was producing at the rate of approximately 90
Mcfe per day and the Neblett #3 well was producing at the rate of approximately
895 Mcfe per day, all net to the Company's interest. The Company believes that
an unfavorable outcome in this matter would not have a material impact on its
financial statements. The Company has recorded revenues only to the extent of
well costs funded by the Company. The Company and the other working interest
owners in the Neblett Unit have reached an agreement in principal with
ExxonMobil and the landowner, pursuant to which the parties will settle their
disputes in this litigation. Drafts of the settlement documents have been
circulated for review. Pursuant to the terms of the settlement, the Company will
transfer its interest in the Neblett Unit leases to ExxonMobil in return for a
payment representing reimbursement of the net, un-recouped costs of drilling,
completing, producing and operating the four Neblett wells. In addition, the
landowner will reimburse the working interest group (including the Company) the
amount of the lease bonus and certain excess royalty payments. There can be no
assurance as to a final settlement or the terms thereof until all settlement
agreements are approved and executed by all parties.

During November 2000, the Company entered into a one-year contract with Grey
Wolf, Inc. for utilization of a 1,500 horsepower drilling rig capable of
drilling wells to a depth of approximately 18,000 feet. The contract provided
for a dayrate of $12,000 per day. The rig was utilized primarily to drill wells
in the Company's focus areas, including the Matagorda Project Area and the
Cabeza Creek Project Area. The contract contained a provision which would allow
the Company to terminate the contract early by tendering payment equal to
one-half the dayrate for the number of days remaining under the term of the
contract as of the date of termination. The contract commenced in February 2001
and expired in February 2002. Steven A. Webster, who is the Chairman of the
Board of Directors of the Company, is a member of the Board of Directors of Grey
Wolf, Inc.

During August 2001, the Company entered into a one year agreement, that was
extended to March 2003, whereby the lessor will provide to the Company up to
$800,000 in financing for production equipment utilizing capital leases. At
December 31, 2001 and September 30, 2002, one lease in the amount of $243,369
had been executed under this facility.

6. CONVERTIBLE PARTICIPATING PREFERRED STOCK:

In February 2002, the Company consummated the sale of $6 million of Convertible
Participating Series B Preferred Stock (the "Series B Preferred Stock") and
warrants to purchase Carrizo common stock to an investor group led by Mellon
Ventures, Inc. which included Steven A. Webster, the Company's Chairman of the
Board of Directors. The Series B Preferred Stock is convertible into common
stock by the investors at a conversion price of $5.70 per share, subject to
adjustments, and is initially convertible into 1,052,632 shares of common stock.
Dividends on the Series B Preferred Stock will be payable in either cash at a
rate of 8% per annum or, at the Company's option, by payment in kind of
additional shares of the same series of preferred stock at a rate of 10% per
annum. At September 30, 2002, the outstanding balance of the Series B Preferred
Stock has been increased by $218,508 (2,185.08 shares) for dividends paid in
kind. The Series B Preferred Stock is redeemable at varying prices in whole or
in part at the holders' option after three years or at the Company's option at
any time. The Series B Preferred Stock will also participate in any dividends
declared on the common stock. Holders of the Series B Preferred Stock will
receive a liquidation preference upon the liquidation of, or certain mergers or
sales of substantially all assets involving, the Company. Such holders will also
have the option of receiving a change of control repayment price upon certain
deemed change of control transactions. The warrants have a five-year term and
entitle the holders to purchase up to 252,632 shares of Carrizo's common stock
at a price of $5.94 per share, subject to adjustments, and are exercisable at
any time after issuance. The warrants may be exercised on a cashless exercise
basis.

Net proceeds of this financing were approximately $5.8 million that were used
primarily to fund the Company's ongoing exploration and development program.

7. COMMON STOCK:

The Company issued 106,472 shares of common stock during the nine months ended
September 30, 2002 at a valuation of $475,006. Of these shares issued, 76,472
were issued as partial consideration for the purchase of an interest in certain
oil and gas properties and 30,000 shares were issued as an advance payment
towards the purchase of certain interests in coalbed methane properties that
closed during July 2002.

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8. CHANGE IN ACCOUNTING PRINCIPLE:

In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative
Instruments and Hedging Activities". This statement, as amended by SFAS No. 137
and SFAS No. 138, establishes standards of accounting for and disclosures of
derivative instruments and hedging activities. This statement requires all
derivative instruments to be carried on the balance sheet at fair value with
changes in a derivative instrument's fair value recognized currently in earnings
unless specific hedge accounting criteria are met. SFAS No. 133 was effective
for the Company beginning January 1, 2001 and was adopted by the Company on that
date. In accordance with the current transition provisions of SFAS No. 133, the
Company recorded a cumulative effect transition adjustment of $2.0 million (net
of related tax expense of $1.1 million) in accumulated other comprehensive
income to recognize the fair value of its derivatives designated as cash flow
hedging instruments at the date of adoption.

Upon entering into a derivative contract, the Company designates the derivative
instruments as a hedge of the variability of cash flow to be received (cash flow
hedge). Changes in the fair value of a cash flow hedge are recorded in other
comprehensive income to the extent that the derivative is effective in
offsetting changes in the fair value of the hedged item. Any ineffectiveness in
the relationship between the cash flow hedge and the hedged item is recognized
currently in income. Gains and losses accumulated in other comprehensive income
associated with the cash flow hedge are recognized in earnings as oil and gas
revenues when the forecasted transaction occurs. All of the Company's derivative
instruments were designated and effective as cash flow hedges except for its
positions with an affiliate of Enron Corp. discussed below.

When hedge accounting is discontinued because it is probable that a forecasted
transaction will not occur, the derivative will continue to be carried on the
balance sheet at its fair value and gains and losses that were accumulated in
other comprehensive income will be recognized in earnings immediately. In all
other situations in which hedge accounting is discontinued, the derivative will
be carried at fair value on the balance sheet with future changes in its fair
value recognized in future earnings.

The Company typically uses fixed rate swaps and costless collars to hedge its
exposure to material changes in the price of natural gas and crude oil. The
Company formally documents all relationships between hedging instruments and
hedged items, as well as its risk management objectives and strategy for
undertaking various hedge transactions. This process includes linking all
derivatives that are designated cash flow hedges to forecasted transactions. The
Company also formally assesses, both at the hedge's inception and on an ongoing
basis, whether the derivatives that are used in hedging transactions are highly
effective in offsetting changes in cash flows of hedged transactions.

In November 2001, the Company had no-cost collars with an affiliate of Enron
Corp., designated as hedges, covering 2,553,000 MMBtu of gas production from
December 2001 through December 2002. The value of these derivatives at that time
was $759,000. Because of Enron's financial condition, the Company concluded that
the derivatives contracts were no longer effective and thus did not qualify for
hedge accounting treatment. As required by SFAS No. 133, the value of these
derivative instruments as of November 2001 ($759,000) was recorded in
accumulated other comprehensive income and will be reclassified into earnings
over the original term of the derivative instruments. For the nine months ended
September 30, 2002, $158,700 was reclassified from other comprehensive income
into oil and gas revenues. An allowance for the related asset totaling $759,000,
net of tax of $409,000, was charged to other expense during the fourth quarter
of 2001. At December 31, 2001 and September 30, 2002, $706,000, net of tax of
$380,000, and $159,000 net of tax of $85,000, respectively, remained in
accumulated other comprehensive income related to the deferred gains on these
derivatives. In March 2002, the Company, in accordance with the provisions of
the Enron contracts, formally notified Enron of its default thereunder and
terminated all remaining outstanding contracts with Enron. The Company has filed
a claim in the amount of approximately $1.2 million in the Enron bankruptcy
proceedings.

At September 30, 2002, the Company had recorded $535,000 of hedging losses in
other comprehensive income, substantially all of which is expected to be
reclassified to earnings within the next twelve months. The amount ultimately
reclassified to earnings will vary due to changes in the fair values of the
derivatives designated as cash flow hedges prior to their settlement. Total oil
and natural gas purchased and sold under hedging arrangements during the three
months ended September 30, 2001 and 2002 were 18,000 Bbls and 33,600 Bbls,
respectively, and 8,220,000 MMBtu and 731,000 MMBtu, respectively. Losses
realized by the Company under such hedging arrangements were $1,538,700 and
$78,000 for the three months ended September 30, 2001 and 2002, respectively.
Total oil and natural gas purchased and sold under hedging arrangements during
the nine months ended September 30, 2001 and 2002 were 18,000 Bbls and 79,100
Bbls, respectively, and 2,541,000 MMBtu and 3,094,000 MMBtu, respectively.
Losses realized by the Company under such hedging arrangements were $857,638 and
$447,000 for the nine months ended September 30, 2001 and 2002, respectively. At
September 30, 2001 and 2002, the Company had the following outstanding hedge
positions:

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9. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENT:

In June 2001, the Financial Accounting Standards Board issued SFAS No. 143,
"Accounting for Asset Retirement Obligations". This Statement is effective for
fiscal years beginning after June 15, 2002 and the Company expects to adopt the
Statement effective January 1, 2003. The Company is currently assessing the
impact of the Standard on it's consolidated financial statements.

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ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following is management's discussion and analysis of certain significant
factors that have affected certain aspects of the Company's financial position
and results of operations during the periods included in the accompanying
unaudited financial statements. This discussion should be read in conjunction
with the discussion under "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and the annual financial statements
included in the Company's Annual Report on Form 10-K for the year ended December
31, 2001 and the unaudited financial statements included elsewhere herein.
Unless otherwise indicated by the context, references herein to "Carrizo" or
"Company" mean Carrizo Oil & Gas, Inc., a Texas corporation that is the
registrant.

GENERAL OVERVIEW

The Company began operations in September 1993 and initially focused on the
acquisition of producing properties. As a result of the increasing availability
of economic onshore 3-D seismic surveys, the Company began to obtain 3-D seismic
data and options to lease substantial acreage in 1995 and began to drill its 3-D
based prospects in 1996. The Company drilled 25 gross wells in the Gulf Coast
region in 2001 and 12 gross wells through the nine months ended September 30,
2002. The Company has budgeted to drill up to 16 gross wells (6.6 net) in the
Gulf Coast region in 2002; however, the actual number of wells drilled will vary
depending upon various factors, including the availability and cost of drilling
rigs, land and industry partner issues, Company cash flow, success of drilling
programs, weather delays and other factors. If the Company drills the number of
wells it has budgeted for 2002, depreciation, depletion and amortization, oil
and gas operating expenses and production are expected to increase over levels
incurred in 2001. The Company has typically retained the majority of its
interests in shallow, normally pressured prospects and sold a portion of its
interests in deeper, overpressured prospects.

The Company has primarily grown through the internal development of properties
within its exploration project areas, although the Company has acquired
properties with existing production in the past.

During the second quarter of 2001, the Company formed CCBM, Inc. ("CCBM") as a
wholly-owned subsidiary. CCBM was formed to acquire interests in certain oil and
gas leases in Wyoming and Montana in areas prospective for coalbed methane and
develop such interests. CCBM agreed to spend up to $5 million for drilling costs
on these leases through December 2003, 50% of which would be spent pursuant to
an obligation to fund $2.5 million of drilling costs on behalf of RMG, from whom
the interests in the leases were acquired. CCBM drilled 31 gross wells (12.0
net) and incurred total drilling costs of $819,000 in 2001 and drilled 82 gross
wells (30 net) and incurred total drilling costs of $1.4 million through the
nine months ended September 30, 2002. These wells typically take up to 18 months
to evaluate and determine whether or not they are successful. CCBM has budgeted
to drill 97 gross (33 net) wells in 2002. Through September 30, 2002, CCBM has
satisfied $1.4 million of the drilling obligations on behalf of RMG.

In order to reduce its exposure to short-term fluctuations in the price of oil
and natural gas, and not for speculation purposes, the Company periodically
enters into hedging arrangements. The Company's hedging arrangements apply to
only a portion of its production and provide only partial price protection
against declines in oil and natural gas prices. Such hedging arrangements may
expose the Company to risk of financial loss in certain circumstances, including
instances where production is less than expected, the Company's customers fail
to purchase contracted quantities of oil or natural gas or a sudden, unexpected
event materially impacts oil or natural gas prices. In addition, the Company's
hedging arrangements limit the benefit to the Company of increases in the price
of oil and natural gas. At September 30, 2002, the Company had recorded $535,000
of hedging losses in other comprehensive income, substantially all of which is
expected to be reclassified to earnings within the next twelve months. The
amount ultimately reclassified to earnings will vary due to changes in the fair
values of the derivatives designated as cash flow hedges prior to their
settlement. Total oil and natural gas purchased and sold under hedging
arrangements during the three months ended September 30, 2001 and 2002 were
18,000 Bbls and 33,600 Bbls, respectively, and 8,220,000 MMBtu and 731,000
MMBtu, respectively. Losses realized by the Company under such hedging
arrangements were $1,538,700 and $78,000 for the three months ended September
30, 2001 and 2002, respectively. Total oil and natural gas purchased and sold
under hedging arrangements during the nine months ended September 30, 2001 and
2002 were 18,000 Bbls and 79,100 Bbls, respectively, and 2,541,000 MMBtu and
3,094,000 MMBtu, respectively. Losses realized by the Company under such hedging
arrangements were $857,638 and $447,000 for the nine months ended September 30,
2001 and 2002, respectively. At September 30, 2001 and 2002, the Company had the
following outstanding hedge positions:

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The Company's Board of Directors sets all of the Company's hedging policy,
including volumes, types of instruments and counterparties, on a quarterly
basis. These policies are implemented by management through the execution of
trades by either the President or Chief Financial Officer after consultation and
concurrence by the President, Chief Financial Officer and Chairman of the Board.
The master contracts with the authorized counterparties identify the President
and Chief Financial Officer as the only Company representatives authorized to
execute trades. The Board of Directors also reviews the status and results of
hedging activities quarterly. On January 1, 2001, the Company adopted Statement
of Financial Standards No. 133. See Note 8 to the Financial Statements.

In November 2001, the Company had no-cost collars with an affiliate of Enron
Corp., designated as hedges, covering 2,553,000 MMBtu of gas production from
December 2001 through December 2002. The value of these derivatives at that time
was $759,000. Because of Enron's financial condition, the Company concluded that
the derivatives contracts were no longer effective and thus did not qualify for
hedge accounting treatment. As required by SFAS No. 133, the value of these
derivative instruments as of November 2001 ($759,000) was recorded in
accumulated other comprehensive income and will be reclassified into earnings
over the original term of the derivative instruments. For the nine months ended
September 30, 2002, $548,000 was reclassified from other comprehensive income
into oil and gas revenues. An allowance for the related asset totaling $759,000,
net of tax of $409,000, was charged to other expense during the fourth quarter
of 2001. At December 31, 2001 and September 30, 2002, $706,000, net of tax of
$380,000, and $159,000 net of tax of $85,000, respectively, remained in
accumulated other comprehensive income related to the deferred gains on these
derivatives. In March 2002, the Company, in accordance with the provisions of
the Enron contracts, formally notified Enron of its default thereunder and
terminated all remaining outstanding contracts with Enron. The Company has filed
a claim in the amount of approximately $1.2 million in the Enron bankruptcy
proceedings.

The Company uses the full-cost method of accounting for its oil and gas
properties. Under this method, all acquisition, exploration and development
costs, including any general and administrative costs that are directly
attributable to the Company's acquisition, exploration and development
activities, are capitalized in a "full-cost pool" as incurred. The Company
records depletion of its full-cost pool using the unit-of-production method. To
the extent that such capitalized costs in the full-cost pool (net of
depreciation, depletion and amortization and related deferred taxes) exceed the
present value (using a 10% discount rate) of estimated future net after-tax cash
flows from proved oil and gas reserves, such excess costs are charged to
operations in the form of a "ceiling test write-down". Primarily as a result of
depressed oil and natural gas prices, and the resulting downward reserve
quantities revisions, the Company recorded a ceiling test write-down of $20.3
million in 1998. Based on oil and gas prices in effect on December 31, 2001, the
unamortized cost of oil and gas properties exceeded the cost center ceiling. As
permitted by full cost accounting rules,

-13-

improvements in pricing subsequent to December 31, 2001 removed the necessity to
record a ceiling writedown. Using prices in effect on December 31, 2001 the
pretax writedown would have been approximately $700,000. Because of the
volatility of oil and gas prices, no assurance can be given that the Company
will not experience a ceiling test writedown in future periods. A ceiling test
write-down was not required for the three months and nine months ended September
30, 2002 or 2001. Once incurred, a write-down of oil and gas properties is not
reversible at a later date.

RESULTS OF OPERATIONS

Three Months Ended September 30, 2002
Compared to the Three Months Ended September 30, 2001

Production volumes for oil in the third quarter of 2002 increased 159% to
113,000 Bbls from 44,000 Bbls for the same period in 2001. Average oil prices
decreased 4% to $23.82 per barrel in the third quarter of 2002 from $24.75 per
barrel in the same period in 2001. Production volumes for natural gas during the
three months ended September 30, 2002 increased 1% to 1,137,000 Mcf from
1,124,000 Mcf for the same period in 2001. Average natural gas prices decreased
21% to $3.57 per Mcf in the third quarter of 2002 from $4.52 per Mcf in the same
period in 2001. As a result of higher production, partially offset by lower
prices, oil and natural gas revenues for the three months ended September 30,
2002 increased 10% to $6,753,000 from $6,162,000 for the same period in 2001.
The increase in oil production was due primarily to new production from the
Staubach #1, Burkhart #1R, and Delta Farms #1 wells, offset by the natural
decline in production of other older wells, primarily at initial Matagorda
County Project wells and the Riverdale #2 well. The increase in natural gas
production was due primarily to new production at the Staubach #1, Burkhart #1R,
Delta Farms #1 and Riverdale #3 wells, offset by the natural decline in
production of other older wells. Oil and natural gas revenues include the impact
of hedging activities as discussed above under "General Overview."

The following table summarizes production volumes, average sales prices and
operating revenues for the Company's oil and natural gas operations for the
three months ended September 30, 2001 and 2002:

- ------------------
(1) Includes impact of hedging activities.

Oil and natural gas operating expenses for the three months ended September 30,
2002 increased 44% to $1,334,000 from $928,000 for the same period in 2001
primarily due to increased severance taxes and the addition of more wells,
offset by a reduction in costs on older producing fields. Operating expenses per
equivalent unit increased to $.74 per Mcfe in the third quarter of 2002 from
$.67 per Mcfe in the same period in 2001 primarily as a result of higher
severance taxes, partially offset by increased production of oil and natural gas
on new, high rate, lower cost per unit wells.

Depreciation, depletion and amortization (DD&A) expense for the three months
ended September 30, 2002 increased 63% to $2,726,000 from $1,672,000 for the
same period in 2001. This increase was due to increased production and the
addition of costs to the proved property cost pool. General and administrative
expense for the three months ended September 30, 2002 increased 43% to $990,000
from $691,000 for the same period in 2001 primarily as a result of the addition
of staff to handle increased drilling and production activities.

-14-

Other income and expenses for the three months ended September 30, 2001 includes
a gain on the sale of the investment in Michael Petroleum Corporation of $3.9
million offset by a charge and related legal expenses in respect of the final
settlement of the litigation with BNP Petroleum Corporation.

Income taxes decreased to $674,000 for the three months ended September 30, 2002
from $2.0 million for the same period in 2001.

Interest income for the three months ended September 30, 2002 decreased to
$16,000 from $58,000 in the third quarter of 2001 primarily as a result of lower
interest rates during 2002. Capitalized interest decreased to $648,000 in the
third quarter of 2002 from $833,000 in the third quarter of 2001 primarily due
to lower interest rates that resulted in lower interest costs during the third
quarter of 2002.

Income before income taxes for the three months ended September 30, 2002
decreased to $1.9 million from $5.5 million in the same period in 2001. Net
income for the three months ended September 30, 2002 decreased to $1.1 million
from $3.5 million for the same period in 2001 primarily as a result of the
factors described above.

Nine Months Ended September 30, 2002,
Compared to the Nine Months Ended September 30, 2001

Production volumes for oil in the first nine months of 2002 increased 98% to
261,031 Bbls from 131,593 Bbls for the same period in 2001. Average oil prices
decreased 9% to $23.34 per barrel in the first nine months of 2002 from $25.77
per barrel in the same period in 2001. Production volumes for natural gas during
the nine months ended September 30, 2002 increased 3% to 3,543,000 Mcf from
3,436,000 Mcf for the same period in 2001. Average natural gas prices decreased
40% to $3.24 per Mcf in the first nine months of 2002 from $5.41 per Mcf in the
same period in 2001. Primarily as a result of such lower prices, oil and natural
gas revenues for the nine months ended September 30, 2002 decreased 20% to
$17,559,000 from $21,981,000 for the same period in 2001. The increase in oil
production was due primarily to the commencement of production at the Delta
Farms #1, Riverdale #2, Staubach #1 and Burkhart #1R wells offset by the natural
decline in production of other older wells. The increase in natural gas
production was due primarily to the commencement of production at the Delta
Farms #1, Riverdale #2, Staubach #1 and Burkhart #1R wells offset by the natural
decline in production at other wells, primarily from the initial Matagorda
County Project wells. Oil and natural gas revenues include the impact of hedging
activities as discussed above under "General Overview."

The following table summarizes production volumes, average sales prices and
operating revenues for the Company's oil and natural gas operations for the nine
months ended September 30, 2001 and 2002:

- ------------------
(2) Includes impact of hedging activities.

Oil and natural gas operating expenses for the nine months ended September 30,
2002 increased 10% to $3,687,000 from $3,359,000 for the same period in 2001
primarily due to the addition of more wells and increased ad valorem taxes.
Operating expenses per equivalent unit decreased to $.72 per Mcfe in the first
nine months of 2002 from $.80 per Mcfe in the same period in 2001 primarily as a
result of the addition of higher rate, lower cost per unit wells, offset by
higher ad valorem taxes and decreased production of natural gas as older wells
naturally decline.

-15-

Depreciation, depletion and amortization (DD&A) expense for the nine months
ended September 30, 2002 increased 47% to $7.3 million from $5.0 million for the
same period in 2001. This increase was due to increased production and
additional seismic and drilling costs. General and administrative expense for
the nine months ended September 30, 2002 increased 25% to $3.0 million from $2.4
million for the same period in 2001 primarily as a result of the addition of
staff to handle increased drilling and production activities.

Other income and expenses for the nine months ended September 30, 2001 includes
a gain on the sale of the investment in Michael Petroleum Corporation of $3.9
million offset by a charge and related legal expenses in respect of the final
settlement of the litigation with BNP Petroleum Corporation.

Income taxes decreased to $1.5 million for the nine months ended September 30,
2002 from $5.2 million for the same period in 2001.

Interest income for the nine months ended September 30, 2002 decreased to
$44,000 from $251,000 in the first nine months of 2001 primarily as a result of
lower interest rates during 2002. Capitalized interest decreased to $2.1 million
in the first nine months of 2002 from $2.4 million in the first nine months of
2001 primarily due to lower interest costs during the first nine months of 2002.

Income before income taxes for the nine months ended September 30, 2002
decreased to $3.9 million from $14.5 million in the same period in 2001. Net
income for the nine months ended September 30, 2002 decreased to $2.4 million
from $9.3 million for the same period in 2001 primarily as a result of the
factors described above.

LIQUIDITY AND CAPITAL RESOURCES

The Company has made and is expected to make oil and gas capital expenditures in
excess of its net cash flow from operations in order to complete the exploration
and development of its existing properties. The Company will require additional
sources of financing to fund drilling expenditures on properties currently owned
by the Company and to fund leasehold costs and geological and geophysical costs
on its active exploration projects.

While the Company believes that the current cash balances and anticipated
operating cash flow will provide sufficient capital to carry out the Company's
near term exploration plans, management of the Company continues to seek
financing for its capital program from a variety of sources. No assurance can be
given that the Company will be able to obtain additional financing on terms that
would be acceptable to the Company. The Company's inability to obtain additional
financing could have a material adverse effect on the Company. Without raising
additional capital, the Company anticipates that it may be required to limit or
defer its planned oil and gas exploration and development program, which could
adversely affect the recoverability and ultimate value of the Company's oil and
gas properties.

The Company's primary sources of liquidity have included funds generated by
operations, equity capital contributions, proceeds from the 1997 initial public
offering, the 1998 sale of shares of Series A Preferred Stock and Warrants, the
December 1999 sale of Subordinated Notes, Common Stock and Warrants, the 2002
sale of shares of Series B Convertible Participating Preferred Stock and
Warrants, borrowings (primarily under revolving credit facilities) and the sale
of promoted interests under the Palace Agreement and to other industry partners
that have provided a portion of the funding for the Company's 1999, 2000, 2001
and 2002 drilling program in return for participation in certain wells.

Cash flows provided by operations (after changes in working capital) were $19.5
million and $12.3 million for the nine months ended September 30, 2001 and 2002,
respectively. The decrease in cash flows provided by operations in 2002 as
compared to 2001 was due primarily to higher prevailing oil and natural gas
prices during the first nine months of 2001 and the timing of accounts payable.

The Company has budgeted capital expenditures for the year ended December 31,
2002 of approximately $31.0 million of which $5.8 million is expected to be used
to fund 3-D seismic data acquisition and land acquisitions and $21.2 million of
which is expected to be used for drilling activities in the Company's project
areas. The Company has budgeted to drill up to approximately 16 gross wells (6.6
net) in the Gulf Coast region and up to 69 gross (27 net) CCBM coalbed methane
wells in 2002. As of September 30, 2002 the Company had drilled 12 gross wells
(4.9 net) in the Gulf Coast region and 58 gross wells (22 net) CCBM coalbed
methane wells. The actual number of wells drilled and capital expended is
dependent upon available financing, cash flow, availability and cost of drilling
rigs, land and partner issues and other factors.

The Company has continued to reinvest a substantial portion of its cash flows
into increasing its 3-D supported drilling prospect portfolio, improving its 3-D
seismic interpretation technology and funding its drilling program. Oil and gas
capital expenditures were $20.8 million for the nine months ended September 30,
2002, which included $2.9 million of capitalized interest and general and
administrative costs.

During the third quarter of 2002, the Company incurred net capital expenditures
of $2.4 million for seismic data and

-16-

increased its 3-D seismic data library from approximately 2,800 to 4,800 square
miles. The Company recorded a current liability of approximately $2.2 million
and a non-current liability of approximately $800,000 related to third quarter
2002 acquisitions. The Company's drilling efforts in the Gulf Coast region
resulted in the successful completion of 20 gross wells (5.9 net) during the
year ended December 31, 2001 and the successful completion of 10 gross wells
(3.8 net) drilled during the nine months ended September 30, 2002. Of the 82
gross wells (30 net) drilled by CCBM, 24 gross wells (8 net) are currently
producing and 59 gross wells (22 net) are awaiting evaluation before a
determination can be made as to their success.

FINANCING ARRANGEMENTS

On May 24, 2002, the Company entered into a credit agreement with Hibernia
National Bank (the "Hibernia Facility") which matures on January 31, 2005, and
repaid its existing facility with Compass Bank (the "Compass Facility"). The
Hibernia Facility provides a revolving line of credit of up to $30 million. It
is secured by substantially all of the Company's assets and is guaranteed by all
of the Company's subsidiaries.

The borrowing base will be determined by Hibernia National Bank at least
semi-annually on each October 31 and April 30. The initial borrowing base was
$12 million and the borrowing base as of October 31, 2002 was $13 million. Each
party to the credit agreement can request one unscheduled borrowing base
determination subsequent to each scheduled determination. The borrowing base
will at all times equal the borrowing base most recently determined by Hibernia
National Bank, less quarterly borrowing base reductions required subsequent to
such determination. Hibernia National Bank will reset the borrowing base amount
at each scheduled and each unscheduled borrowing base determination date. The
initial quarterly borrowing base reduction, which commenced on June 30, 2003,
was $1,250,000. The quarterly borrowing base reduction effective January 31,
2003 is $1,750,000.

In November, 2002, the Company received a commitment from Hibernia National Bank
to provide additional availability under the Hibernia Facility in the amount of
$2.5 million which is structured as an additional "Tranche B" under the Hibernia
Facility. As such, upon completion of the amendment to the credit agreement, the
total borrowing base under the Hibernia Facility will be $15.5 million, of which
$6.5 million is currently drawn. The Tranche B bears interest at LIBOR plus
3.375%, is secured by certain leases and working interests in oil and natural
gas wells and matures on April 30, 2003.

If the principal balance of the Hibernia Facility ever exceeds the borrowing
base as reduced by the quarterly borrowing base reduction (as described above),
the principal balance in excess of such reduced borrowing base will be due as of
the date of such reduction. Otherwise, any unpaid principal or interest will be
due at maturity.

If the principal balance of the Hibernia Facility ever exceeds any re-determined
borrowing base, the Company has the option within thirty days to (individually
or in combination): (i) make a lump sum payment curing the deficiency; (ii)
pledge additional collateral sufficient in Hibernia National Bank's opinion to
increase the borrowing base and cure the deficiency; or (iii) begin making equal
monthly principal payments that will cure the deficiency within the ensuing
six-month period. Such payments are in addition to any payments that may come
due as a result of the quarterly borrowing base reductions.

For each tranche of principal borrowed under the revolving line of credit, the
interest rate will be, at the Company's option: (i) the Eurodollar Rate, plus an
applicable margin equal to 2.375% if the amount borrowed is greater than or
equal to 90% of the borrowing base, 2.0% if the amount borrowed is less than
90%, but greater than or equal to 50% of the borrowing base, or 1.625% if the
amount borrowed is less than 50% of the borrowing base; or (ii) the Base Rate,
plus an applicable margin of 0.375% if the amount borrowed is greater than or
equal to 90% of the borrowing base. Interest on Eurodollar Loans is payable on
either the last day of each Eurodollar option period or monthly, whichever is
earlier. Interest on Base Rate Loans is payable monthly.

The Company is subject to certain covenants under the terms of the Hibernia
Facility, including, but not limited to the maintenance of the following
financial covenants: (i) a minimum current ratio of 1.0 to 1.0 (including
availability under the borrowing base), (ii) a minimum quarterly debt services
coverage of 1.25 times, and (iii) a minimum shareholders equity equal to $56
million, plus 100% of all subsequent common and preferred equity contributed by
shareholders, plus 50% of all positive earning occurring subsequent to such
quarter end, all ratios as more particularly discussed in the credit facility.
The Hibernia Facility also places restrictions on additional indebtedness,
dividends to non-preferred stockholders, liens, investments, mergers,
acquisitions, asset dispositions, asset pledges and mortgages, change of
control, repurchase or redemption for cash of the Company's common or preferred
stock, speculative commodity transactions, and other matters.

At December 31, 2001 and September 30, 2002, amounts outstanding under the
Compass Facility totaled $7,166,000 and zero, respectively, with an additional
$620,000 and zero, respectively, available for future borrowings. At December
31, 2001 and September 30, 2002, amounts outstanding under the Hibernia Facility
totaled zero and $6,500,000, respectively, with an additional zero and
$4,250,000, respectively, available for future borrowings. At December 31, 2001,
one letter of credit was issued and outstanding under the Compass Facility in
the amount of $224,000. At September 30, 2002, one letter of credit was issued
and outstanding under the Hibernia Facility in the amount of $224,000.

-17-

On June 29, 2001, CCBM, Inc., a wholly owned subsidiary of the Company ("CCBM"),
issued a non-recourse promissory note payable in the amount of $7,500,000 to RMG
as consideration for certain interest in oil and gas leases held by RMG in
Wyoming and Montana. The RMG note is payable in 41-monthly principal payments of
$125,000 plus interest at 8% per annum commencing July 31, 2001 with the balance
due December 31, 2004. The RMG note is secured solely by CCBM's interests in the
oil and gas leases in Wyoming and Montana.

In December 2001, the Company entered into a capital lease agreement secured by
certain production equipment in the amount of $243,369. The lease is payable in
one payment of $11,323 and 35 monthly payments of $7,549 including interest at
8.6% per annum. The Company has the option to acquire the equipment at the
conclusion of the lease for $1.

In December 1999, the Company consummated the sale of $22 million principal
amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") to an
investor group led by CB Capital Investors, L.P. (now JPMorgan Partners, LLC)
which included certain members of the Board of Directors. The Subordinated Notes
were sold at a discount of $688,761 which is being amortized over the life of
the notes. Interest is payable quarterly beginning March 31, 2000. The Company
may elect, for a period of five years, to increase the amount of the
Subordinated Notes for up to 60% of the interest which would otherwise be
payable in cash. The Subordinated Notes were increased by $2,552,970 and
$3,220,375 for such interest as of December 31, 2001 and September 30, 2002,
respectively. Concurrent with the sale of the notes, the Company consummated the
sale of 3,636,364 shares of Common Stock at a price of $2.20 per share and
Warrants to purchase up to 2,760,189 shares of the Company's Common Stock at an
exercise price of $2.20 per share. For accounting purposes, the Warrants are
valued at $0.25 per Warrant. The Warrants have an exercise price of $2.20 per
share and expire in December 2007.

The Company is subject to certain covenants under the terms under the related
Securities Purchase Agreement, including but not limited to, (a) maintenance of
a specified Tangible Net Worth, (b) maintenance of a ratio of EBITDA (earnings
before interest, taxes depreciation and amortization) to quarterly Debt Service
(as defined in the agreement) of not less than 1.00 to 1.00, and (c) limit its
capital expenditures to an amount equal to the Company's EBITDA for the
immediately prior fiscal year (unless approved by the Company's Board of
Directors and a JPMorgan Partners, LLC appointed director), as well as limits on
the Company's ability to (i) incur indebtedness, (ii) incur or allow liens,
(iii) engage in mergers, consolidation, sales of assets and acquisitions, (iv)
declare dividends and effect certain distributions (including restrictions on
distributions upon the Common Stock), (v) engage in transactions with affiliates
(vi) make certain repayments and prepayments, including any prepayment of the
Company's Term Loan, any subordinated debt, indebtedness that is guaranteed or
credit-enhanced by any affiliate of the Company, and prepayments that effect
certain permanent reductions in revolving credit facilities.

Of the approximately $29.0 million net proceeds of this financing, $12.1 million
was used to fund the repurchase from certain Enron Corp. affiliates of all the
outstanding shares of Series A Preferred Stock and 750,000 Warrants and related
expenses, $2.0 million was used to repay the bridge loan extended to the Company
by its outside directors, $2.0 million was used to repay a portion of the
Compass Term Loan, $1.0 million was used to repay a portion of the Compass
Borrowing Base Facility, and the remaining proceeds were used to fund the
Company's ongoing exploration and development program and general corporate
purposes.

In February 2002, the Company consummated the sale of 60,000 shares of Series B
Preferred Stock and 2002 Warrants to purchase 252,632 shares of Common Stock for
an aggregate purchase price of $6.0 million to an investor group led by Mellon
Ventures, L.P. which included Steven A. Webster, the Company's Chairman of the
Board of Directors. The Series B Preferred Stock is convertible into Common
Stock by the investors at a conversion price of $5.70 per share, subject to
adjustment, and is initially convertible into 1,052,632 shares of Common Stock.
The net proceeds of this financing were approximately $5.8 million and were used
to fund the Company's ongoing exploration and development program and general
corporate purposes.

Dividends on the Series B Preferred Stock will be payable in either cash at a
rate of 8% per annum or, at the Company's option, by payment in kind of
additional shares of the Series B Preferred Stock at a rate of 10% per annum. At
September 30, 2002 the outstanding balance of the Series B Preferred Stock had
been increased by $128,508 (2,185.08 shares) for dividends paid in kind. In
addition to the foregoing, if the Company declares a cash dividend on the Common
Stock of the Company, the holders of shares of Series B Preferred Stock are
entitled to receive for each share of Series B Preferred Stock a cash dividend
in the amount of the cash dividend that would be received by a holder of the
Common Stock into which such share of Series B Preferred Stock is convertible on
the record date for such cash dividend. Unless all accrued dividends on the
Series B Preferred Stock shall have been paid and a sum sufficient for the
payment thereof set apart, no distributions may be paid on any Junior Stock
(which includes the Common Stock) (as defined in the Statement of Resolutions
for the Series B Preferred Stock) and no redemption of any Junior Stock shall
occur other than subject to certain exceptions.

-18-

The Series B Preferred Stock is required to be redeemed by the Company at any
time after the third anniversary of the initial issuance of the Series B
Preferred Stock (the "Issue Date") upon request from any holder at a price per
share equal to Purchase Price/Dividend Preference (as defined below). The
Company may redeem the Series B Preferred Stock after the third anniversary of
the Issue Date, at a price per share equal to the Purchase Price/Dividend
Preference and, prior to that time, at varying preferences to the Purchase
Price/Dividend Purchase. "Purchase Price/Dividend Preference" is defined to
mean, generally, $100 plus all cumulative and accrued dividends on such share of
Series B Preferred Stock.

In the event of any dissolution, liquidation or winding up or certain mergers or
sales or other disposition by the Company of all or substantially all of its
assets (a "Liquidation"), the holder of each share of Series B Preferred Stock
then outstanding will be entitled to be paid out of the assets of the Company
available for distribution to its shareholders, the greater of the following
amounts per share of Series B Preferred Stock: (i) $100 in cash plus all
cumulative and accrued dividends and (ii) in certain circumstances, the
"as-converted" liquidation distribution, if any, payable in such Liquidation
with respect to each share of Common Stock.

Upon the occurrence of certain events constituting a "Change of Control" (as
defined in the Statement of Resolutions), the Company is required to make a
offer to each holder of Series B Preferred Stock to repurchase all of such
holder's Series B Preferred Stock at an offer price per share of Series B
Preferred Stock in cash equal to 105% of the Change of Control Purchase Price,
which is generally defined to mean $100 plus all cumulative and accrued
dividends.

The 2002 Warrants have a five-year term and entitle the holders to purchase up
to 252,632 shares of Carrizo's Common Stock at a price of $5.94 per share,
subject to adjustment, and are exercisable at any time after issuance. For
accounting purposes, the 2002 Warrants are valued at $0.06 per 2002 Warrant.

EFFECTS OF INFLATION AND CHANGES IN PRICE

The Company's results of operations and cash flows are affected by changing oil
and gas prices. If the price of oil and gas increases (decreases), there could
be a corresponding increase (decrease) in the operating cost that the Company is
required to bear for operations, as well as an increase (decrease) in revenues.
Inflation has had a minimal effect on the Company.

CRITICAL ACCOUNTING POLICIES

Oil and Natural Gas Properties

Investments in oil and natural gas properties are accounted for using the
full-cost method of accounting. All costs directly associated with the
acquisition, exploration and development of oil and natural gas properties are
capitalized. Such costs include lease acquisitions, seismic surveys, and
drilling and completion equipment. The Company proportionally consolidates its
interests in oil and gas properties. Additionally, the Company capitalized
compensation costs for employees working directly on exploration activities of
$763,475 and $703,180, respectively, for the nine months ended September 30,
2001 and 2002.

Oil and natural gas properties are amortized based on the unit-of-production
method using estimates of proved reserve quantities. Investments in unproved
properties are not amortized until proved reserves associated with the projects
can be determined or until impairment occurs. Unevaluated properties are
evaluated periodically for impairment on a property-by-property basis. If the
results of an assessment indicate that the properties are impaired, the amount
of impairment is added to the proved oil and natural gas property costs to be
amortized. The amortizable base includes estimated future development costs and,
where significant, dismantlement, restoration and abandonment costs, net of
estimated salvage values. The depletion rate per thousand cubic feet equivalent
(Mcfe) for the nine months ended September 30, 2001 and 2002, was $1.18 and
$1.44, respectively.

Dispositions of oil and gas properties are accounted for as adjustments to
capitalized costs with no gain or loss recognized, unless such adjustments would
significantly alter the relationship between capitalized costs and proved
reserves.

The net capitalized costs of proved oil and gas properties are subject to a
"ceiling test," which limits such costs to the estimated present value,
discounted at a 10% interest rate, of future net revenues from proved reserves,
based on current economic and operating conditions. If net capitalized costs
exceed this limit, the excess is charged to operations through depreciation,
depletion and amortization. No write-down of the Company's oil and natural gas
assets was necessary for the three months and six months ended June 30, 2001 and
2002. Based on oil and gas prices in effect on December 31, 2001, the
unamortized cost of oil and gas properties exceeded the cost center ceiling. As
permitted by full cost accounting rules, improvements in pricing subsequent to
December 31, 2001 removed the necessity to record a ceiling writedown. Using
prices in effect on December 31, 2001 the pretax writedown would

-19-

have been approximately $700,000. Because of the volatility of oil and gas
prices, no assurance can be given that the Company will not experience a ceiling
test writedown in future periods.

Depreciation of other property and equipment is provided using the straight-line
method based on estimated useful lives ranging from five to 10 years.

Stock-Based Compensation

The Company accounts for employee stock-based compensation using the intrinsic
value method prescribed by Accounting Principles Board (APB) Opinion No. 25,
"Accounting for Stock Issued to Employees" and related interpretations. Under
this method, the Company records no compensation expense for stock options
granted when the exercise price of those options is equal to or greater than the
market price of the Company's common stock on the date of grant. Repriced
options are accounted for as compensatory options using variable accounting
treatment. Under variable plan accounting, compensation expense is adjusted for
increases or decreases in the fair market value of the Company's common stock.
Variable plan accounting is applied to the repriced options until the options
are exercised, forfeited, or expired unexercised.

Derivative Instruments and Hedging Activities

In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative
Instruments and Hedging Activities". This statement, as amended by SFAS No. 137
and SFAS No. 138, establishes standards of accounting for and disclosures of
derivative instruments and hedging activities. This statement requires all
derivative instruments to be carried on the balance sheet at fair value with
changes in a derivative instrument's fair value recognized currently in earnings
unless specific hedge accounting criteria are met. SFAS No. 133 was effective
for the Company beginning January 1, 2001 and was adopted by the Company on that
date. In accordance with the current transition provisions of SFAS No. 133, the
Company recorded a cumulative effect transition adjustment of $2.0 million (net
of related tax expense of $1.1 million) in accumulated other comprehensive
income to recognize the fair value of its derivatives designated as cash-flow
hedging instruments at the date of adoption.

Upon entering into a derivative contract, the Company designates the derivative
instruments as a hedge of the variability of cash flow to be received (cash flow
hedge). Changes in the fair value of a cash flow hedge are recorded in other
comprehensive income to the extent that the derivative is effective in
offsetting changes in the fair value of the hedged item. Any ineffectiveness in
the relationship between the cash flow hedge and the hedged item is recognized
currently in income. Gains and losses accumulated in other comprehensive income
associated with the cash flow hedge are recognized in earnings as oil and gas
revenues when the forecasted transaction occurs. All of the Company's derivative
instruments at January 1, 2001, December 31, 2001 and September 30, 2002 were
designated and effective as cash flow hedges except for its positions with an
affiliate of Enron Corp. as discussed in Note 8 to the Consolidated Financial
Statements. All of the Enron positions were terminated by the Company in March
2002 pursuant to the terms of the contracts.

When hedge accounting is discontinued because it is probable that a forecasted
transaction will not occur, the derivative will continue to be carried on the
balance sheet at its fair value and gains and losses that were accumulated in
other comprehensive income will be recognized in earnings immediately. In all
other situations in which hedge accounting is discontinued, the derivative will
be carried at fair value on the balance sheet with future changes in its fair
value recognized in future earnings.

The Company typically uses fixed rate swaps and costless collars to hedge its
exposure to material changes in the price of natural gas and crude oil. The
Company formally documents all relationships between hedging instruments and
hedged items, as well as its risk management objectives and strategy for
undertaking various hedge transactions. This process includes linking all
derivatives that are designated cash flow hedges to forecasted transactions. The
Company also formally assesses, both at the hedge's inception and on an ongoing
basis, whether the derivatives that are used in hedging transactions are highly
effective in offsetting changes in cash flows of hedged transactions.

The Company's Board of Directors sets all of the Company's hedging policy,
including volumes, types of instruments and counterparties, on a quarterly
basis. These policies are implemented by management through the execution of
trades by either the President or Chief Financial Officer after consultation and
concurrence by the President, Chief Financial Officer and Chairman of the Board.
The master contracts with the authorized counterparties identify the President
and Chief Financial Officer as the only Company representatives authorized to
execute trades. The Board of Directors also reviews the status and results of
hedging activities quarterly.

-20-

Use of Estimates

The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting periods.
Actual results could differ from these estimates. Significant estimates include
depreciation, depletion and amortization of proved oil and natural gas
properties and future income taxes. Oil and natural gas reserve estimates, which
are the basis for unit-of-production depletion and the ceiling test, are
inherently imprecise and are expected to change as future information becomes
available.

Concentration of Credit Risk

Substantially all of the Company's accounts receivable result from oil and
natural gas sales or joint interest billings to third parties in the oil and
natural gas industry. This concentration of customers and joint interest owners
may impact the Company's overall credit risk in that these entities may be
similarly affected by changes in economic and other conditions. Historically,
the Company has not experienced credit losses on such receivables.

FORWARD LOOKING STATEMENTS

The statements contained in all parts of this document, including, but not
limited to, those relating to the Company's schedule, targets, estimates or
results of future drilling, budgeted wells, increases in wells, budgeted and
other future capital expenditures, use of offering proceeds, outcome and effects
of litigation, recovery of well costs in litigation, expected production or
reserves, increases in reserves, acreage working capital requirements, hedging
activities, the ability of expected sources of liquidity to implement its
business strategy, and any other statements regarding future operations,
financial results, business plans and cash needs and other statements that are
not historical facts are forward looking statements. When used in this document,
the words "anticipate," "estimate," "expect," "may," "project," "believe" and
similar expression are intended to be among the statements that identify forward
looking statements. Such statements involve risks and uncertainties, including,
but not limited to, those relating to the Company's dependence on its
exploratory drilling activities, the volatility of oil and natural gas prices,
the need to replace reserves depleted by production, operating risks of oil and
natural gas operations, the Company's dependence on its key personnel, factors
that affect the Company's ability to manage its growth and achieve its business
strategy, risks relating to, limited operating history, technological changes,
significant capital requirements of the Company, the potential impact of
government regulations, litigation, competition, the uncertainty of reserve
information and future net revenue estimates, property acquisition risks,
availability of equipment, weather and other factors detailed in the Company's
Annual Report on Form 10-K for the year ended December 31, 2001 and other
filings with the Securities and Exchange Commission. Should one or more of these
risks or uncertainties materialize, or should underlying assumptions prove
incorrect, actual outcomes may vary materially from those indicated.

ITEM 3A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For information regarding our exposure to certain market risks, see
"Quantitative and Qualitative Disclosures about Market Risk" in Item 7A of our
Annual Report on Form 10-K for the year ended December 31, 2001. There have
been no material changes to the disclosure regarding our exposure to certain
market risks made in the Annual Report. For additional information regarding
our long-term debt, see Note 3 of the Notes to Unaudited Consolidated Financial
Statements in Item 1 of Part I of this Quarterly Report on Form 10-Q.

ITEM 4 - CONTROLS AND PROCEDURES

Within the 90 days prior to the date of this report, the Company carried out an
evaluation, under the supervision and with the participation of the Company's
management, including the Chief Executive Officer and Chief Financial and
Accounting Officer, of the effectiveness of the design and operation of the
Company's disclosure controls and procedures pursuant to Exchange Act Rule
13a-14. Based on that evaluation, the Chief Executive Officer and the Chief
Financial and Accounting Officer concluded that the Company's disclosure
controls and procedures are effective in timely alerting them to material
information relating to the Company (including its consolidated subsidiaries)
required to be included in the Company's periodic filings with the Securities
and Exchange Commission. Subsequent to the date of their evaluation, there
were no significant changes in the Company's internal controls or in other
factors that could significantly affect the internal controls, including any
corrective actions with regard to significant deficiencies and material
weaknesses.

-21-

PART II. OTHER INFORMATION

Item 1 - Legal Proceedings

From time to time, the Company is party to certain legal actions and
claims arising in the ordinary course of business. While the outcome of these
events cannot be predicted with certainty, management does not expect these
matters to have a materially adverse effect on the financial position or results
of operations of the Company.

In July 2001, the Company was notified of a prior lease in favor of a
predecessor of ExxonMobil purporting to be valid and covering the same property
as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part
of a unit in N. La Copita in which the Company owns a non-operating interest.
The operator of the lease, GMT, filed a petition for, and was granted, a
temporary restraining order against ExxonMobil in the 229th Judicial Court in
Starr County, Texas enjoining ExxonMobil from taking possession of the four
Neblett wells. Pending resolution of the underlying title issue, the temporary
restraining order was extended voluntarily by agreement of the parties,
conditioned on GMT paying the revenues into escrow and agreeing to provide
ExxonMobil with certain discovery materials in this action. ExxonMobil has filed
a counterclaim against GMT and all the non-operators, including the Company, to
establish the validity of its lease, remove cloud on title, quiet title to the
property, and for conversion, trespass and punitive damages. ExxonMobil seeks
unspecified damages for the lost profits on the sale of the hydrocarbons from
this property, and for a determination of whether the Company and the other
working interest owners were in good faith or bad faith in trespassing on this
lease. If a determination of bad faith is made, the parties will not be able to
recover their costs of developing this property from the revenues therefrom.
While there is always a risk in the outcome of the litigation, the Company
believes there is no question that the Company acted in good faith and intends
to vigorously defend its position. If the case cannot be settled and the title
issue is decided unfavorably, the Company believes that it will ultimately be
able to recover its drilling and operating costs as a good faith trespasser. A
complete loss of the lease in question would result in the loss to the Company
of approximately .6 Bcfe of reported proved reserves as of December 31, 2000 or
..9 Bcfe of reported proved reserves as of June 30, 2001. No reserves with
respect to these properties were included in the Company's reported proved
reserves as of December 31, 2001 and June 30, 2002. At the time of shut in, the
Neblett #1 well was producing at a rate of approximately 45 Mcfe per day, the
Neblett #2 well was producing at the rate of approximately 90 Mcfe per day and
the Neblett #3 well was producing at the rate of approximately 895 Mcfe per day,
all net to the Company's interest. The Company believes that an unfavorable
outcome in this matter would not have a material impact on its financial
statements. The Company has recorded revenues only to the extent of well costs
funded by the Company. The Company and the other working interest owners in
the Neblett Unit have reached an agreement in principal with ExxonMobil and the
landowner, pursuant to which the parties will settle their disputes in this
litigation. Drafts of the settlement documents have been circulated for review.
Pursuant to the terms of the settlement, the Company will transfer its interest
in the Neblett Unit leases to ExxonMobil in return for a payment representing
reimbursement of the net, un-recouped costs of drilling, completing, producing
and operating the four Neblett wells. In addition, the landowner will reimburse
the working interest group (including the Company) the amount of the lease
bonus and certain excess royalty payments. There can be no assurance as to a
final settlement or the terms thereof until all settlement agreements are
approved and executed by all parties.

Item 2 - Changes in Securities and Use of Proceeds

None

Item 3 - Defaults Upon Senior Securities

None

Item 4 - Submission of Matters to a Vote of Security Holders

At the Annual Meeting of Carrizo Oil & Gas, Inc. held on May 22, 2002,
there were represented by person or by proxy 7,635,211 shares out of 14,140,549
entitled to vote as of the record date, constituting a quorum.

The matters submitted to a vote of shareholders were (i) the reelection
of Steven A. Webster, Christopher C. Behrens, Bryan R. Martin, Douglas A.P.
Hamilton, Paul B. Loyd, Jr., F. Gardner Parker, S.P. Johnson IV and Frank A.
Wojtek as directors, (ii) the approval of the amendment to the incentive plan
increasing the number of shares of common stock available for issuance and (iii)
the approval of the appointment of Ernst & Young, LLP as Independent Public
Accountants for the fiscal year ended December 31, 2002. With respect to the
election of directors, the following number of votes were cast for the nominees:
7,611,358 for Mr. Webster and 23,844 withheld; 7,611,358 for Mr. Behrens and
23,844 withheld; 7,601,258 for Mr. Martin and 33,944 withheld; 7,611,358 for Mr.
Hamilton and 23,844 withheld; 7,611,358 for Mr. Loyd and 23,844 withheld;
7,611,217 for Mr. Parker and 23,985 withheld; 7,611,358 for Mr. Johnson and
23,844 withheld; and 7,611,358 for Mr. Wojtek and 23,844 withheld. There were no
abstentions in the election of directors. With respect to the amendment to the
incentive plan, 7,307,865 votes were cast for the amendment, 238,781 votes were
against and 88,565 were abstained. With respect to the appointment of Ernst &
Young, LLP as Independent Public Accountants, 7,617,492 votes were cast for the
appointment, 14,033 votes were against, and 14,033 votes abstained.

Item 5 - Other Information

-22-

None

Item 6 - Exhibits and Reports on Form 8-K

Exhibits

+ Incorporated herein by reference as indicated.

Reports on Form 8-K

In a Current Report on Form 8-K filed with the SEC on August 14, 2002,
we (i) reported pursuant to Item 9 on Form 8-K that we had filed executive
sworn statements pursuant to SEC Order N. 4-460 and executive certifications
required pursuant to Section 906 of the Sarbannes-Oxley Act of 2002 and (ii)
filed the related executive sworn statements and certifications pursuant to
Item 7 of Form 8-K.

-23-

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.

Carrizo Oil & Gas, Inc.
(Registrant)

Date: November 14, 2002 By: /s/ S. P. Johnson, IV
--------------------------------------------
President and Chief Executive Officer
(Principal Executive Officer)

Date: November 14, 2002 By: /s/ Frank A. Wojtek
--------------------------------------------
Chief Financial Officer
(Principal Financial and Accounting Officer)

-24-

CERTIFICATIONS

Principal Executive Officer

I, S.P. Johnson IV, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Carrizo Oil &
Gas, Inc..

2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:

a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this quarterly report (the "Evaluation
Date"); and

c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
fulfilling the equivalent function);

a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and

6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.

Date: November 14, 2002 /s/ S.P. Johnson
----------------------------
S.P. Johnson
Chief Executive Officer

Principal Financial Officer

I, Frank A. Wojtek, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Edge Petroleum
Corporation.

2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:

a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this quarterly report (the "Evaluation
Date"); and

c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
fulfilling the equivalent function);

a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and

6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in
internal controls or in other factors that

could significantly affect internal controls subsequent to the date of
our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

Date: November 14, 2002 /s/ Frank A. Wojtek
-------------------------------
Senior Vice President and Chief
Financial Officer