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 JUNE 30, 2002
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[ ] 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
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(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 August 8, 2002, the latest practicable date, was
14,176,716.

CARRIZO OIL & GAS, INC.
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 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.

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

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

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CARRIZO OIL & GAS, INC.

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.

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 189,833 stock options and zero
and 252,632 warrants during the three months ended June 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

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Company also had outstanding 79,500 and 202,333 stock options and zero and
252,632 warrants during the six months ended June 30, 2001 and 2002,
respectively, which were antidilutive and were not included in the calculation.

3. LONG-TERM DEBT:

At December 31, 2001 and June 30, 2002, long-term 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 Bank"). 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 is $12
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, is $1,250,000.

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, (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 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,

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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 June 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 June 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 June 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 June 30, 2002, the outstanding principal
balance of this note was $6,750,000 and $6,000,000, 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 June 30, 2002, the outstanding balance of the Subordinated Notes had been
increased by $2,552,970 and $3,220,375, 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 $1,256,132
and $600,441 for the three months ended June 30, 2001 and 2002, respectively and
$3,139,076 and $699,980 for the six months ended June 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 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 their lease, remove cloud on title, quiet title to the
property, and for conversion, trespass and punitive damages. ExxonMobil seek
unspecified damages for the lost profits on the sale of the hydrocarbons from
this property, and

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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. The Company, along with GMT and other partners, are attempting to
negotiate a settlement with ExxonMobil that would allow GMT et al (including the
Company) to participate for their respective shares of a working interest in the
Neblett unit, and would allow for the recovery of well costs. 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 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 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.

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 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 June 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 June 30, 2002, the outstanding balance of the Series B Preferred Stock
had 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 six months ended
June 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 at January 1, 2001 and December 31, 2001 and June 30, 2002 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 six months ended
June 30, 2002, $388,988 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 June 30, 2002, $706,000, net of tax of $380,000,
and $317,000 net of tax of $171,000, 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 June 30, 2002, the Company had recorded $108,000 of hedging losses in other
comprehensive income, almost none 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 swap arrangements during the three months ended
June 30, 2001 and 2002 were zero Bbls and 45,500 Bbls, respectively, and 726,000
MMBtu and 728,000 MMBtu, respectively. Income and (losses) realized by the
Company under such swap arrangements were $331,000 and ($377,000) for the three
months ended June 30, 2001 and 2002, respectively. Total oil and natural gas
purchased and sold under swap arrangements during the six months ended June 30,
2001 and 2002 were 18,000 Bbls and 45,500 Bbls, respectively, and 1,719,000
MMBtu and 1,538,000 MMBtu, respectively. Losses realized by the Company under
such swap arrangements were $681,000 and $377,000 for the six months ended June
30, 2001 and 2002, respectively. At June 30, 2001, the Company had outstanding
hedge positions covering 1,731,000 MMBtu and zero Bbls. The 1,731,000 MMBtu of
natural gas hedges had an average floor of $4.10 and an average ceiling of $5.56
for July 2001 through March 2002 production. At June 30, 2002, the Company had
outstanding hedge positions covering 3,350,000 MMBtu and 27,600 Bbls. The
natural gas hedges consisted of 977,000 MMBtu with an average fixed price of
$3.37 for July through December 2002 production and 2,373,000 MMBtu with an
average

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floor of $3.40 and an average ceiling of $5.23 for November 2002 through
December 2003 production. The oil hedges consisted of 27,600 Bbls with a floor
of $22.00 and a ceiling of $25.00 for July 2002 through September 2002
production.

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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 seven gross wells through the six months ended June 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 22 gross
wells (9 net) and incurred total drilling costs of $1.1 million through the six
months ended June 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 30 gross (15 net) wells in 2002. Through June 30, 2002, CCBM has satisfied
$1.2 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 June 30, 2002, the Company had recorded $108,000 of
hedging losses in other comprehensive income, almost none 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 swap arrangements during the
three months ended June 30, 2001 and 2002 were zero Bbls and 45,500 Bbls,
respectively, and 726,000 MMBtu and 728,000 MMBtu, respectively. Income and
(losses) realized by the Company under such swap arrangements were $331,000 and
($377,000) for the three months ended June 30, 2001 and 2002, respectively.
Total oil and natural gas purchased and sold under swap arrangements during the
six months ended June 30, 2001 and 2002 were 18,000 Bbls and 45,500 Bbls,
respectively, and 1,719,000 MMBtu and 1,538,000 MMBtu, respectively. Losses
realized by the Company under such swap arrangements were $681,000 and $377,000
for the six months ended June 30, 2001 and 2002, respectively. At June 30, 2001,
the Company had outstanding hedge positions covering 1,731,000 MMBtu and zero
Bbls. The 1,731,000 MMBtu of natural gas hedges had an average floor of $4.10
and an average ceiling of $5.56 for July 2001 through March 2002 production. At
June 30, 2002, the Company had outstanding hedge positions covering 3,350,000
MMBtu and 27,600 Bbls. The natural gas hedges consisted of 977,000 MMBtu with an
average fixed price of $3.37 for July through December 2002 production and
2,373,000 MMBtu with an average floor of $3.40 and an average ceiling of $5.23
for November 2002 through December 2003 production. The oil hedges

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consisted of 27,600 Bbls with a floor of $22.00 and a ceiling of $25.00 for July
2002 through September 2002 production. The Company's gas hedge prices are based
on Houston Ship Channel prices. 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 six months ended
June 30, 2002, $389,000 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 June 30, 2002, $706,000, net of tax of $380,000,
and $317,000 net of tax of $71,000, 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, 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 six months ended June 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 June 30, 2002
Compared to the Three Months Ended June 30, 2001

Production volumes for natural gas during the three months ended June 30, 2002
increased 14% to 1,307,589 Mcf from 1,151,221 Mcf for the same period in 2001.
Average natural gas prices decreased 32% to $3.42 per Mcf in the second quarter
of 2002 from $5.02 per Mcf in the same period in 2001. Production volumes for
oil in the second quarter of 2002 increased 88% to 94,879 Bbls from 50,514 Bbls
for the same period in 2001. Average oil prices decreased 6% to $24.35 per
barrel in the second quarter of 2002 from $25.97 per barrel in the same period
in 2001. Primarily as a result of such lower prices, oil and natural gas
revenues for the three months ended June 30, 2002 decreased 4% to $6,780,000
from $7,092,000 for the same period in 2001. The increase in oil production was
due to a full quarter of production at the Staubach #1 and Riverdale #2 wells
and the commencement of production at the Delta Farms #1 and Riverdale #3 wells,
offset by the natural decline in production of other older wells, primarily at
initial Matagorda County Project wells. The increase in natural gas production
was due primarily to the full quarter of production at the Staubach #1 and
Riverdale #2 wells and the commencement of production at the 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 June 30, 2001 and 2002:

-12-

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

Oil and natural gas operating expenses for the three months ended June 30, 2002
increased 18% to $1,341,000 from $1,132,000 for the same period in 2001
primarily due to increased ad valorem taxes and the addition of more wells,
offset by a reduction in costs on older producing fields. Operating expenses per
equivalent unit decreased 8% to $.71 per Mcfe in the second quarter of 2002 from
$.78 per Mcfe in the same period in 2001 primarily as a result of lower
severance taxes and increased production of oil and natural gas on new, high
rate, lower cost per unit wells, offset by higher ad valorem taxes.

Depreciation, depletion and amortization (DD&A) expense for the three months
ended June 30, 2002 increased 56% to $2,636,000 from $1,686,000 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 June 30, 2002 increased 31% to $1,143,000 from
$873,000 for the same period in 2001 primarily as a result of the addition of
staff to handle increased drilling and production activities.

Income taxes decreased to $641,000 for the three months ended June 30, 2002 from
$1,289,000 for the same period in 2001.

Interest income for the three months ended June 30, 2002 decreased to $8,000
from $73,000 in the second quarter of 2001 primarily as a result of lower
interest rates during 2002. Capitalized interest increased to $776,000 in the
second quarter of 2002 from $729,000 in the second quarter of 2001 primarily due
to increased debt outstanding that resulted in higher interest costs during the
second quarter of 2002.

Income before income taxes for the three months ended June 30, 2002 decreased to
$1,716,000 from $3,589,000 in the same period in 2001. Net income for the three
months ended June 30, 2002 decreased to $906,000 from $2,300,000 for the same
period in 2001 primarily as a result of the factors described above.

Six Months Ended June 30, 2002,
Compared to the Six Months Ended June 30, 2001

Production volumes for natural gas during the six months ended June 30, 2002
decreased 4% to 2,406,205 Mcf from 2,312,271 Mcf for the same period in 2001.
Average natural gas prices decreased 47% to $3.08 per Mcf in the first six
months of 2002 from $5.84 per Mcf in the same period in 2001. Production volumes
for oil in the first six months of 2002 increased 68% to 148,088 Bbls from
87,974 Bbls for the same period in 2001. Average oil prices decreased 13% to
$22.97 per barrel in the first six months of 2002 from $26.28 per barrel in the
same period in 2001. Primarily as a result of such lower prices, oil and natural
gas revenues for the six months ended June 30, 2002 decreased 32% to $10,807,000
from $15,820,000 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 and the Staubach #1 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 and Staubach
#1 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."

-13-

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

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

Oil and natural gas operating expenses for the six months ended June 30, 2002
decreased 3% to $2,353,000 from $2,431,000 for the same period in 2001 primarily
due to lower severance taxes offset by the addition of more wells and increased
ad valorem taxes. Operating expenses per equivalent unit decreased 17% to $.71
per Mcfe in the first six months of 2002 from $.86 per Mcfe in the same period
in 2001 primarily as a result of the addition of higher rate, lower cost per
unit wells, and lower severance taxes offset by higher ad valorem taxes and
decreased production of natural gas as wells naturally decline.

Depreciation, depletion and amortization (DD&A) expense for the six months ended
June 30, 2002 increased 39% to $4,606,000 from $3,315,000 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 six months ended June
30, 2002 increased 18% to $2,059,000 from $1,743,000 for the same period in 2001
primarily as a result of the addition of staff to handle increased drilling and
production activities.

Income taxes decreased to $782,000 for the six months ended June 30, 2002 from
$3,205,000 for the same period in 2001.

Interest income for the six months ended June 30, 2002 decreased to $28,000 from
$193,000 in the first six months of 2001 primarily as a result of lower interest
rates during 2002. Capitalized interest decreased to $1,420,000 in the first six
months of 2002 from $1,531,000 in the first six months of 2001 primarily due to
lower interest costs during the first six months of 2002.

Income before income taxes for the six months ended June 30, 2002 decreased to
$2,000,000 from $8,969,000 in the same period in 2001. Net income for the six
months ended June 30, 2002 decreased to $1,218,000 from $5,764,000 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 2002
operating cash flow will provide sufficient capital to carry out the Company's
2002 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.

-14-

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
Palace Agreement that 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
$6,454,000 and $4,083,000 for the six months ended June 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 six months of 2001.

The Company has budgeted capital expenditures for the year ended December 31,
2002 of approximately $17.7 million of which $2.8 million is expected to be used
to fund 3-D seismic surveys and land acquisitions and $14.9 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 30 gross (15 net) CCBM coalbed methane wells in
2002. 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 $11.1 million for the six months ended June 30, 2002,
which included $2.0 million of capitalized interest and general and
administrative costs. 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 all seven gross
wells (2.7 net) drilled during the six months ended June 30, 2002. All of the 22
gross wells (9.0 net) drilled by CCBM 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 Bank"). 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 is $12
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, is $1,250,000.

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, (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 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 June 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 June 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 June 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 RMG
as consideration for certain interest in oil and gas leases held by RMG in
Wyoming and

-15-

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 June 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 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 $29,000,000 net proceeds of this financing, $12,060,000 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, $2,025,000 was used to repay the bridge loan extended to the Company
by its outside directors, $2 million was used to repay a portion of the Compass
Term Loan, $1 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 $6,000,000 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
June 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.

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

-16-

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
$525,000 and $441,000, respectively, for the six months ended June 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 six months ended June 30, 2001 and 2002, was $1.09 and $1.39,
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 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.

-17-

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 June 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.

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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.

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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 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 their 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. The Company, along with GMT and other
partners, are attempting to negotiate a settlement with ExxonMobil that would
allow GMT et al (including the Company) to participate for their respective
shares of a working interest in the Neblett unit, and would allow for the
recovery of well costs. 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 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.

Item 2 - Changes in Securities and Use of Proceeds

In June 2002 the Company issued 30,000 shares of Common Stock to
several individuals as part of the purchase of an interest in certain coalbed
methane properties. This sale of shares is exempt from the registration
requirements of the Securities Act of 1933, as amended, by virtue of Section
4(2) thereof as a transaction not involving a public offer.

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, 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; 7,611,217 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.

-20-

Item 5 - Other Information

On June 7, 2002, George Canjar resigned from his role as Vice
President, Exploration. On August 5, 2002 the Company announced that Jeremy T.
Greene had been appointed Vice President, Exploration.

Item 6 - Exhibits and Reports on Form 8-K

Exhibits

Exhibit
Number Description
------- -----------

+2.1 -- Combination Agreement by and among the Company, Carrizo
Production, Inc., Encinitas Partners Ltd., La Rosa Partners
Ltd., Carrizo Partners Ltd., Paul B. Loyd, Jr., Steven A.
Webster, S.P. Johnson IV, Douglas A.P. Hamilton and Frank A.
Wojtek dated as of September 6, 1997 (incorporated herein by
reference to Exhibit 2.1 to the Company's Registration
Statement on Form S-1 (Registration No. 333-29187)).

+3.1 -- Amended and Restated Articles of Incorporation of the Company
(incorporated herein by reference to Exhibit 3.1 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1997).

+3.2 -- Amended and Restated Bylaws of the Company, as amended by
Amendment No. 1 (incorporated herein by reference to Exhibit
3.2 to the Company's Registration Statement on Form 8-A
(Registration No. 000-22915) Amendment No. 2 (incorporated
herein by reference to Exhibit 3.2 to the Company's Current
Report on Form 8-K dated December 15, 1999) and Amendment No. 3
(Incorporated herein by reference to Exhibit 3.1 to the
Company's Current Report on Form 8-K dated February 20, 2002).

+3.3 -- Statement of Resolution dated February 20, 2002 establishing
the Series B Convertible Participating Preferred Stock
providing for the designations, preferences, limitations and
relative rights, voting, redemption and other rights thereof
(Incorporated herein by reference to Exhibit 99.2 to the
Company's Current Report on Form 8-K dated February 20, 2002).

3.4 -- Credit Agreement dated as of May 24, 2002 by and between
Carrizo Oil & Gas, Inc., CCBM, Inc. and Hibernia National Bank.

3.5 -- Revolving Note by and between Carrizo Oil & Gas, Inc. and
Hibernia National Bank dated May 24, 2002.

3.6 -- Commercial Guarantee by and between CCBM, Inc. and Hibernia
National Bank dated May 24, 2002.

3.7 -- Stock Pledge and Security Agreement by and between Carrizo Oil
& Gas, Inc. and Hibernia National Bank dated May 24, 2002.

3.8 -- First Amendment to Credit Agreement dated July 9, 2002 to the
Credit Agreement by and between Carrizo Oil & Gas, Inc. and
Hibernia National Bank dated May 24, 2002.

10.1 -- Amendment No. 1 to the Amended and Restated Incentive Plan of
the Company.

10.2 -- Employment Agreement between the Company and Jeremy T. Greene.

+ Incorporated herein by reference as indicated.

Reports on Form 8-K

None

-21-

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: August 13, 2002 By: /s/ S. P. Johnson, IV
--------------------------------------------
President and Chief Executive Officer
(Principal Executive Officer)

Date: August 13, 2002 By: /s/ Frank A. Wojtek
--------------------------------------------
Chief Financial Officer
(Principal Financial and Accounting Officer)

-22-