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, 2001
------------------
[ ] 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, 2001, the latest practicable date, was
14,061,327.
CARRIZO OIL & GAS, INC.
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2001
INDEX
PART I. FINANCIAL INFORMATION PAGE
Item 1. Condensed Consolidated Balance Sheets
- As of December 31, 2000 and September 30, 2001 2
Condensed Consolidated Statements of Operations
- For the three-month and nine-month periods ended
September 30, 2000 and 2001 3
Condensed Consolidated Statements of Cash Flows
- For the nine-month periods ended
September 30, 2000 and 2001 4
Notes to Condensed Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 11
PART II. OTHER INFORMATION
Items 1-6. 18
SIGNATURES 21
CARRIZO OIL & GAS, INC.
CONSOLIDATED CONDENSED BALANCE SHEETS
December 31, September 30,
ASSETS 2000 2001
------------- -------------
CURRENT ASSETS: (Unaudited)
Cash and cash equivalents $ 8,217,427 $ 6,734,193
Accounts receivable, net of allowance for doubtful accounts of
$480,000 at December 31, 2000 and September 30, 2001, respectively 7,392,621 $ 5,886,328
Advances to operators 1,756,396 1,319,638
Risk management assets -- 1,589,838
Deposits 629,460 257,860
Other current assets 401,181 840,159
------------- -------------
Total current assets 18,397,085 16,628,016
PROPERTY AND EQUIPMENT, net (full-cost method of
accounting for oil and gas properties) 72,128,589 98,282,761
INVESTMENT IN MICHAEL PETROLEUM CORPORATION (Note 3) 1,544,180 --
OTHER ASSETS 930,059 744,108
------------- -------------
$ 92,999,913 $ 115,654,885
============= =============
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade $ 3,353,570 $ 6,423,720
Accrued liabilities 1,775,830 1,791,837
Advances for joint operations 376,190 393,869
Current maturities of long-term debt 6,458,310 1,828,009
------------- -------------
Total current liabilities 11,963,900 10,437,435
LONG-TERM DEBT 28,097,490 36,481,741
DEFERRED INCOME TAXES -- 4,883,235
COMMITMENTS AND CONTINGENCIES (Note 6)
SHAREHOLDERS' EQUITY:
Warrants (3,010,189 outstanding at December 31, 2000
and September 30, 2001, respectively) 765,047 765,047
Common stock, par value $.01 (40,000,000 shares authorized
with 14,055,061 and 14,059,727 issued and outstanding
at December 31, 2000 and September 30, 2001, respectively) 140,551 140,597
Additional paid in capital 62,708,100 62,722,602
Accumulated deficit (10,675,175) (1,365,610)
Other comprehensive income -- 1,589,838
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52,938,523 63,852,474
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$ 92,999,913 $ 115,654,885
============= =============
The accompanying notes are an integral part of these
consolidated financial statements.
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CARRIZO OIL & GAS, INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three For the Nine
Months Ended Months Ended
September 30, September 30,
------------------------------- ---------------------------------
2000 2001 2000 2001
----------- ----------- ------------ ------------
OIL AND NATURAL GAS REVENUES $ 8,007,583 $ 6,161,679 $ 18,113,917 $ 21,981,362
COSTS AND EXPENSES:
Oil and natural gas operating expenses 1,297,986 927,893 3,159,174 3,359,025
Depreciation, depletion and amortization 2,011,564 1,672,308 5,420,970 4,987,634
General and administrative 747,383 691,146 2,202,666 2,434,291
Stock option compensation (benefit) 657,525 (55,942) 657,525 (501,623)
----------- ----------- ------------ ------------
Total costs and expenses 4,714,458 3,235,405 11,440,335 10,279,327
----------- ----------- ------------ ------------
OPERATING INCOME 3,293,125 2,926,274 6,673,582 11,702,035
OTHER INCOME AND EXPENSES:
Other income and expenses, net 1,482,372 2,529,231 1,482,372 2,529,231
Interest income 145,416 57,695 420,116 250,722
Interest expense (818,900) (788,269) (2,523,644) (2,218,395)
Interest expense, related parties (50,973) (51,646) (160,118) (152,806)
Capitalized interest 868,984 833,042 2,670,759 2,364,328
----------- ----------- ------------ ------------
INCOME BEFORE INCOME TAXES 4,920,024 5,506,327 8,563,067 14,475,115
INCOME TAXES (Note 5) 25,567 1,960,301 76,634 5,165,550
----------- ----------- ------------ ------------
NET INCOME $ 4,894,457 $ 3,546,026 $ 8,486,433 $ 9,309,565
=========== =========== ============ ============
BASIC EARNINGS PER COMMON SHARE (Note 2) $ 0.35 $ 0.25 $ 0.61 $ 0.66
=========== =========== ============ ============
DILUTED EARNINGS PER COMMON SHARE (Note 2) $ 0.29 $ 0.22 $ 0.51 $ 0.56
=========== =========== ============ ============
The accompanying notes are an integral part of these
consolidated financial statements.
-3-
CARRIZO OIL & GAS, INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine
Months Ended
September 30,
---------------------------------
2000 2001
------------ ------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 8,486,433 $ 9,309,565
Adjustment to reconcile net income (loss) to net
cash provided by operating activities-
Depreciation, depletion and amortization 5,420,970 4,987,634
Discount accretion 23,170 64,007
Stock option compensation (benefit) 657,525 (501,623)
Gain on sale of Michael Petroleum Corporation -- (3,900,723)
Finders' Fee (1,544,180) --
Deferred income taxes -- 5,066,291
Changes in assets and liabilities-
Accounts receivable (2,173,225) 1,506,293
Other current assets (467,802) (250,434)
Other assets (253,031) (52,549)
Accounts payable, trade (278,654) 2,790,061
Other current liabilities 886,616 517,630
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Net cash provided by operating activities 10,757,822 19,536,152
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CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures, accrual basis (13,132,962) (30,903,306)
Proceeds from sale of Michael Petroleum Corporation -- 5,444,903
Proceeds from sale of Metro Project 5,075,127 --
Adjustment to cash basis (186,745) 8,735,333
Advances to operators (688,755) 436,758
Advances for joint operations (1,041,600) 17,679
------------ ------------
Net cash used in investing activities (9,974,935) (16,268,633)
------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from the sale of common stock 86,594 14,548
Debt repayments (2,776,612) (4,765,301)
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Net cash used in financing activities (2,690,018) (4,750,753)
------------ ------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (1,907,131) (1,483,234)
CASH AND CASH EQUIVALENTS, beginning of period 11,345,618 8,217,427
------------ ------------
CASH AND CASH EQUIVALENTS, end of period $ 9,438,487 $ 6,734,193
============ ============
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest (net of amounts capitalized) $ 13,003 $ 6,873
============ ============
The accompanying notes are an integral part of these
consolidated financial statements.
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CARRIZO OIL & GAS, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. ACCOUNTING POLICIES:
The condensed 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, 2000, 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 condensed 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, 2000.
2. EARNINGS PER COMMON SHARE:
Supplemental earnings per share information is provided below:
For the Three Months Ended September 30,
-------------------------------------------------------------------------------
Income Shares Per-Share Amount
----------------------------- ----------------------------- -------------------
2000 2001 2000 2001 2000 2001
-------------- -------------- -------------- -------------- -------------------
Basic Earnings per Share
Net income $ 4,894,457 $ 3,546,026 14,034,913 14,059,216 $ 0.35 $ 0.25
====== ======
Stock Options and Warrants -- -- 2,949,604 2,193,958
------------- ----------- ----------- ----------
Diluted Earnings per Share
Net income available to common
shareholders plus assumed conversions $ 4,894,457 $ 3,546,026 16,984,517 16,253,174 $ 0.29 $ 0.22
============= =========== =========== ========== ====== ======
For the Nine Months Ended September 30,
-----------------------------------------------------------------------------
Income Shares Per-Share Amount
----------------------------- ----------------------------- -----------------
2000 2001 2000 2001 2000 2001
-------------- -------------- -------------- -------------- -----------------
Basic Earnings per Share
Net income $ 8,486,433 $ 9,309,565 14,019,271 14,058,470 $ 0.61 $ 0.66
====== ======
Stock Options and Warrants - - 2,730,401 2,513,617
------------- ----------- ----------- ----------
Diluted Earnings per Share
Net income available to common
shareholders plus assumed conversions $ 8,486,433 $ 9,309,565 16,749,672 16,572,087 $ 0.51 $ 0.56
============= =========== =========== ========== ====== ======
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 zero and 161,500 stock options during the
three months ended September 30, 2000 and 2001, 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 zero and 79,500 stock options during
the nine months ended September 30, 2000 and 2001, respectively, which were
antidilutive and were not included in the calculation.
3. INVESTMENT IN MICHAEL PETROLEUM CORPORATION
In 2000 the Company received a finder's fee valued at $1,544,180 from affiliates
of Donaldson, Lufkin & Jenrette ("DLJ") in connection with their purchase of a
significant minority shareholder interest in Michael Petroleum Corporation
("MPC"). MPC is a privately - held exploration and production company which
focuses on the prolific gas producing Lobo Trend in South Texas. The minority
shareholder interest in MPC was purchased by entities affiliated with DLJ. The
Company elected to receive the fee in the form of 18,947 shares of common stock,
1.9 percent of the outstanding common shares of MPC, which is accounted for as a
cost basis
-5-
investment. Steven A. Webster, who is the Chairman of the Board of the Company,
is also a Managing Director of Global Energy Partners Ltd., a merchant banking
affiliate of DLJ which makes investments in energy companies, and joined the
Board of Directors of MPC in connection with the transaction.
During the third quarter of 2001, the Company agreed to sell its interest in MPC
pursuant to an agreement between MPC and its shareholders for the sale of a
majority interest in MPC to Calpine Natural Gas Company. The Company expects to
receive total cash proceeds of between $5.5 and $5.7 million, of which $5.5
million was paid to the Company during the third quarter of 2001, resulting in a
financial statement gain of $3.9 million being reflected in the third quarter
2001 financial results.
4. LONG-TERM DEBT:
At December 31, 2000 and September 30, 2001, long-term debt consisted of the
following:
December 31, September 30,
2000 2001
------------- -------------
Credit facility:
Borrowing base facility $ 5,426,000 $ 7,166,000
Term loan facility 5,260,000 --
Senior subordinated notes 20,462,797 21,321,668
Senior subordinated notes, related parties 2,208,693 2,369,073
Vendor note payable 1,198,310 328,009
Non-recourse note payable to Rocky Mountain Gas, Inc. -- 7,125,000
------------ ------------
34,555,800 38,309,750
Less: current maturities (6,458,310) (1,828,009)
------------ ------------
$ 28,097,490 $ 36,481,741
============ ============
Carrizo amended its existing credit facility with Compass Bank ("Compass") in
September 1998 to provide for a term loan under the facility (the "Term Loan")
in addition to the then existing revolving credit facility limited by the
Company's borrowing base (the "Borrowing Base Facility") which provided for a
maximum loan amount of $25 million subject to Borrowing Base limitations. The
Borrowing Base Facility was amended in March, 1999 to provide for a maximum loan
amount under such facility of $10 million. Substantially all of Carrizo's oil
and natural gas property and equipment is pledged as collateral under this
facility. The interest rate for both borrowings is calculated at a floating rate
based on the Compass index rate or LIBOR plus 2 percent. The Company's
obligations are secured by certain of its oil and gas properties and cash or
cash equivalents included in the borrowing base. Certain members of the Board of
Directors had provided collateral, primarily in the form of marketable
securities, to secure the revolving credit loans. This collateral was released
during April 2001. The Borrowing Base Facility and the Term Loan are referred to
collectively as the "Company Credit Facility". Proceeds from the Borrowing Base
portions of this credit facility have been used to provide funding for
exploration and development activity. In April 2001, the maturity date of the
Borrowing Base Facility was extended from February 2002 to April 2003.
Under the Borrowing Base Facility, Compass, in its sole discretion, will make
semiannual borrowing base determinations based upon the proved oil and natural
gas properties of the Company. Compass may also redetermine the borrowing base
and the monthly borrowing base reduction at any time at its discretion. The
latest borrowing base determination was done effective September 1, 2001 and the
next review is scheduled for March 1, 2002. The Company may also request
borrowing base redeterminations in addition to the required semiannual reviews
at the Company's cost.
At December 31, 2000 and September 30, 2001, amounts outstanding under the
Borrowing Base Facility totaled $5,426,000 and $7,166,000, with an additional
$2,676,884 and $2,360,000 respectively, available for future borrowings. The
Borrowing Base totaled $8,326,884 and $9,750,000 at December 31, 2000 and
September 30, 2001, respectively. The Borrowing Base Facility was also available
for letters of credit, one of which has been issued for $224,000 at December 31,
2000 and September 30, 2001. The Borrowing Base facility was amended in November
2000 to provide up to $2 million of Guidance Line letters of credit (the
"Guidance Line letters of credit") relating exclusively to the Company's
outstanding hedge positions. At December 31, 2000 and September 30, 2001, the
Company had one and zero Guidance Line letters of credit outstanding amounting
to $180,000 and zero, respectively.
-6-
The Term Loan was initially due and payable upon maturity in September 1999. In
March 1999, the maturity date of the Term Loan was amended to provide for twelve
monthly installments of $750,000 beginning January 1, 2000. The repayment terms
were also amended to provide for $1.74 million of principal due ratably over the
last six months of 2000, $2.64 million of principal due ratably over the first
six months of 2001, and the balance due in July 2001. During 2001, the repayment
schedule was amended to provide for $4.84 million of principal due ratably over
the first eleven months of 2001, and the balance due December 2001. Certain
members of the Board of Directors guaranteed the Term Loan. The Term Loan was
paid in full in September 2001. At December 31, 2000 and September 30, 2001,
$5,260,000 and none respectively, was outstanding under the Term Loan.
The Company is subject to certain covenants under the terms of the Company
Credit Facility, including but not limited to (a) maintenance of specified
tangible net worth, (b) a ratio of quarterly EBITDA (earnings before interest,
taxes, depreciation and amortization) to quarterly debt service of not less than
1.25 to 1.00, and (c) a specified minimum amount of working capital. The Company
Credit Facility also places restrictions on, among other things, (a) incurring
additional indebtedness, guaranties, loans and liens, (b) changing the nature of
business or business structure, (c) selling assets and (d) paying dividends. In
March 1999, the Company Credit Facility was amended to decrease the required
specified tangible net worth covenant. The Company is currently in compliance
with the covenants under the Company Credit Facility.
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 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 eight percent 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 November 1999, certain members of the Board of Directors provided a bridge
loan in the amount of $2,000,000 to the Company secured by certain oil and
natural gas properties. This bridge loan bore interest at 14 percent per annum.
Also, in consideration for the bridge loan, the Company assigned to those
members of the Board of Directors an Overriding Royalty Interest in certain of
the Company's producing properties. The bridge loan was repaid from the proceeds
of the sale of Subordinated Notes, Common Stock and Warrants in 1999.
In December 1999, the Company consummated the sale of $22 million principal
amount of 9 percent Senior Subordinated Notes due 2007 (the "Subordinated
Notes") to an investor group led by CB Capital Investors, L.P. (now known as
J.P. Morgan Partners, LLC) which included certain members of the Board of
Directors. The Company also sold 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. Quarterly interest payments began 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 percent of the interest
which would otherwise be payable in cash. As of December 31, 2000 and September
30, 2001, the outstanding balance of the Subordinated Notes had been increased
by $1,227,325 and $2,182,569, respectively, for such interest.
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 a specified amount for
the year ended December 31, 2000 and thereafter equal to the Company's EBITDA
for the immediately prior fiscal year (unless approved by the Company's Board of
Directors and a JP Morgan Partners director).
During 1999, Carrizo restructured certain current accounts payable into vendor
notes, extending the payment dates through 2001. One note was outstanding in the
amount of $1,198,310 and $328,009 at December 31, 2000 and September 30, 2001,
respectively, which bears interest at the prime rate.
5. INCOME TAXES:
The Company provided deferred income taxes at the rate of 35 percent, which also
approximates its statutory rate, that amounted to $1,927,215 and $5,066,291 for
the three and nine months ended September 30, 2001, respectively. In the first
three quarters of 2000, the Company decreased the valuation allowance associated
with $8,563,067 of its net operating loss carryforwards as management had
determined that it was more likely than not that such carryforwards would be
utilized based upon the Company's estimate of future taxable income at that
date. As a result of this determination, the Company realized a deferred tax
benefit in the amount of $1,722,008 and $2,997,006 for the three and nine months
ended September 30, 2000, respectively.
-7-
6. 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.
Settlement of Litigation. The Company, as one of three plaintiffs, filed a
lawsuit against BNP Petroleum Corporation ("BNP"), Seiskin Interests, LTD,
Pagenergy Company, LLC and Gap Marketing Company, LLC, as defendants, in the
229th Judicial District Court of Duval County, Texas, for fraud and breach of
contract in connection with an agreement between plaintiffs and defendants
whereby the defendants were obligated to drill a test well in an area known as
the Slick Prospect in Duval County, Texas. The allegations of the Company in
this litigation were that BNP gave the Company inaccurate and incomplete
information on which the Company relied in making its decision not to
participate in the test well and the prospect, resulting in the loss of the
Company's interest in the lease, the test well and four subsequent wells drilled
in the prospect. The Company sought to enforce its approximate 23.68 percent
interest in the prospect and sought damages or rescission, as well as costs and
attorneys' fees. The case was originally filed in Duval County, Texas on
February 25, 2000.
In mid March, 2000, the defendants filed an original answer and certain
counterclaims against plaintiffs, seeking unspecified damages for slander of
title, tortious interference with business relations, and exemplary damages. The
case proceeded to trial before the Court (without a jury) on June 19, 2000 after
the plaintiffs' were found by the court to have failed to comply with procedural
requirements regarding the request for a jury. After several days of trial the
case was recessed and later resumed on September 5, 2000. The court at that time
denied the plaintiffs' motion for mistrial based on the court's denial of a jury
trial. The court also ordered that the defendants' counterclaims would be the
subject of a separate trial that would commence on December 11, 2000. The
parties proceeded to try issues related to the plaintiffs' claims on September
5, 2000. All parties rested on the plaintiffs' claims on September 13, 2000. The
court took the matter under advisement. Defendants filed a second amended answer
and counterclaim and certain supplemental responses to request for disclosure in
which they stated that they were seeking damages in the amount of $33.5 million
by virtue of an alleged lost sale of the subject properties, $17 million in
alleged lost profits from other prospective contracts, and unspecified
incidental and consequential damages from the alleged wrongful suspension of
funds under their gas sales contract with the gas purchaser on the properties,
alleged damage to relationships with trade creditors and financial institutions,
including the inability to leverage the Slick Prospect, and attorneys' fees at
prevailing hourly rates in Duval County, Texas incurred in defending against
plaintiffs' claims and for 40 percent of any aggregate recovery in prosecuting
their counterclaims. In subsequent testimony, the defendants verbally alleged
$26 million of damages by virtue of the alleged lost sale of the properties (as
opposed to the $33.5 million previously sought), $7.5 million of damages by
virtue of loss of a lease development opportunity and $100 million of damages by
virtue of the loss of a business opportunity related to BNP's alleged inability
to participate in a 3-D seismic project.
The Company had also alleged that BNP Petroleum Corporation, Seiskin Interests,
LTD and Pagenergy Company, LLC breached a contract with the plaintiffs by
obtaining oil and gas leases within an area restricted by that contract. This
breach of contract allegation was the subject of an additional lawsuit by
plaintiffs in the 165th District Court in Harris County, Texas. The defendants
took the position that the claim must be tried in the Duval County case. The
Duval County court, without issuing a formal ruling, took the position that this
claim should be considered in the Duval County case. The Company was seeking
damages as a result of defendants' actions as well as costs and attorneys' fees.
On December 8, 2000 the Company entered into a Compromise and Settlement
Agreement ("Settlement Agreement") with the defendants with regard to the above
described litigation. Under the terms of the Settlement Agreement, the Company
and the defendants agreed to enter into an Agreed Order of Dismissal with
Prejudice of the litigation and, among other things, agreed as follows:
1. Should a co-plaintiff to the Duval County litigation secure a final
judgment (without regard to appeals, new trials or other such actions)
in the trial court in Duval County that results in such plaintiff being
entitled to recover a five percent or greater undivided interest in the
Slick Prospect, BNP will pay to Carrizo, at BNP's option, either
$500,000 or an amount equal to the judgment rendered in favor of such
plaintiff.
2. Should the defendants secure a final judgment (without regard to
appeals, new trials or other such actions) in the trial court in Duval
County against a co-plaintiff, the Company will be obligated to pay BNP
an amount equal to five percent of any percentage of the total judgment
apportioned to the Company in the case, such payment being limited
however to no more than five percent of 47.2 percent of the total
judgment entered in the case.
3. In the event the defendants and such co-plaintiff reach a full and
final settlement prior to the entry of a written final judgment in the
trial court in Duval County (including but not limited to any type of
agreed judgment or any agreement that such co-
-8-
plaintiff will not be ultimately liable to BNP for the full amount of
any judgment rendered in favor of the defendants), the obligations
described in (1) and (2) above will be null and void. Also, in the
event BNP and such co-plaintiff both only obtain take nothing judgments
in the case, such obligations will be null and void.
4. Both the Company and the defendants released each other from any and
all claims, demands, actions or causes of action relating to or arising
out of the litigation.
The case proceeded to trial on the counterclaims on December 11, 2000 in the
Duval County court. BNP presented evidence that its damages were in the amounts
of $19.6 million for the alleged lost sale of the properties, $35 million for
loss of the lease development opportunity, and $308 million for loss of the
opportunity related to participation in the 3-D seismic project. During the
course of the trial, the co-plaintiff presented its motion for summary judgment
on the counterclaims based on the doctrine of absolute judicial proceeding
privilege. The court partially granted the co-plaintiff's motion for summary
judgment as it related to the filing of a lis pendens, but denied it with regard
to the other allegations of BNP. The court also granted the co-plaintiff's plea
in abatement relating to the breach of contract allegation, ruling that the
District Court in Harris County has dominant jurisdiction of that issue. Upon
completion of the trial, the court announced that it would take the case under
advisement.
On November 5, 2001, the court filed with the clerk a final judgment that had
been signed by the court on October 26, 2001. Pursuant to the terms of the
judgment, the Company, and its co-plaintiffs take nothing on their claims
against BNP and are denied any recovery of their interest in the lease, the
prospect, or the wells of the Slick Prospect. Instead, the court confirmed title
in the lease, prospect, and wells in BNP's affiliate. In addition, the Company
and its co-defendants were found to have tortiously and maliciously interfered
with two different BNP contracts or prospective contracts, the business of BNP
and its affiliate, causing damages with respect to the loss of a sale and the
loss of a lease. Under the terms of the Settlement Agreement, the Company owes
$472,000 to BNP. This amount was remitted to BNP on November 12, 2001 in final
settlement of the litigation. The settlement amount, along with the related
legal fees, has been included as other expense in the accompanying financial
statements.
In July 2001, the Company was notified of a potential title problem related to
our lease on certain properties in Starr County, Texas known as the North La
Copita prospect. The prospect includes four Neblett wells, three of which have
been completed and one of which is waiting on completion. At this time, the
ultimate outcome of the potential title problem and the impact of such outcome
on the Company is uncertain. 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, 2001 or .9 Bcfe of reported proved reserves as of
June 30, 2001. On August 10, 2001, the North La Copita wells were shut in,
pending further resolution of this matter. At the time of shut in, the Neblett
#1 well was producing at the 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 condition.
COMMITMENTS
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, which
commenced in February 2001, provides for a dayrate of $12,000 per day. The rig
is being utilized primarily to drill wells in the Company's focus areas,
including the Matagorda Project Area and the Cabeza Creek Project Area. The
contract contains 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.
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.
The Company, through CCBM (a wholly-owned subsidiary) acquired interests in
certain oil and gas leases in Wyoming and Montana in areas prospective for
coalbed methane. CCBM plans to spend up to $5 million for drilling costs on
these leases through December 2002, 50 percent 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.
7. CHANGE IN ACCOUNTING PRINCIPLE:
In June 1998, The Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards No. 133 "Accounting for Derivative Instruments
and Hedging Activities". This statement, as amended by SFAS No. 137 and SFAS No.
138, established standards of accounting for and disclosures of derivative
instruments and hedging activities. This statement required all derivative
instruments to be carried on the balance sheet at fair value and was effective
for the Company beginning January 1, 2001.
The Company adopted SFAS No. 133 on January 1, 2001. In accordance with the
current transition provisions of SFAS No. 133, the Company recorded a net-of-tax
cumulative-effect transition adjustment of $2.0 million (net of related tax
expense of $1.1 million) in
-9-
accumulated other comprehensive income to recognize the fair value of its
derivatives designated as cash-flow hedging instruments at the date of adoption.
All of the Company's derivative instruments are recognized on the balance
sheet at their fair value. The Company typically uses fixed rate swaps and no
cost collars to hedge its exposure to material changes in the price of natural
gas and crude oil.
Upon entering into a derivative contract, the Company designates its derivative
as a hedge of the variability of a 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 when the
forecasted transaction occurs. All of the Company's derivative instruments at
January 1, 2001 and October 1, 2001 were designated as cash-flow hedges.
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.
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 then current earnings.
At September 30, 2001, the Company had recorded $1.6 million of hedging gains 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, 2000 and 2001 were 18,000 Bbls and zero Bbls,
respectively, and 420,000 MMBtu and 822,000 MMBtu, respectively. Income and
(losses) realized by the Company under such hedging arrangements were $(336,437)
and $1,538,700 for the three months ended September 30, 2000 and 2001,
respectively. Total oil and natural gas purchased and sold under hedging
arrangements during the nine months ended September 30, 2000 and 2001 were
36,000 Bbls and 18,000 Bbls, respectively, and 900,000 MMBtu and 2,541,000
MMBtu, respectively. Income and (losses) realized by the Company under such
hedging arrangements were $(772,337) and $857,638 for the nine months ended
September 30, 2000 and 2001, respectively. At September 30, 2000, the Company
had 1,800,000 MMBtu and 36,400 Bbls of outstanding hedge positions (at an
average price of $4.67 per MMBtu and $30.00 per Bbl) for October through March
2001 production. At September 30, 2001, the Company had the following
outstanding hedge positions:
<Table>
<Caption>
Collar Arrangements
Contract ----------------------------
Volumes Average Average
(MMBtu) Fixed Price Floor Price Ceiling Price
-------- ----------- ----------- -------------
2001:
Fourth Quarter 639,000 $ - $4.44 $5.44
========
2002:
First Quarter 270,000 $4.25 $5.15
540,000 $3.20
--------
810,000
========
Second Quarter 546,000 $3.20
========
Third Quarter 552,000 $3.20
========
Fourth Quarter 552,000 $3.20
========
</Table>
Comprehensive income was $468,000 and $1.6 million for the three months and nine
months ended September 30, 2001, respectively. Comprehensive income includes
accumulated other comprehensive income of $468,000 and $1.6 million related to
derivative and hedging activities in the three months and nine months ended
September 30, 2001, respectively.
On June 29, 2001, the FASB approved its proposed SFAS No. 141, ("FAS 141")
"Business Combinations," and SFAS No. 142 ("FAS 142"), "Goodwill and Other
Intangible Assets." Under FAS 141, all business combinations should be
accounted for using the purchase method of accounting; use of the
pooling-of-interests method is prohibited. The provisions of the statement
will apply to all business combinations initiated after June 30, 2001.
FAS 142 will apply to all acquired intangible assets whether acquired singly,
as part of a group, or in a business combination. The statement will supersede
Accounting Principals Board, ("APB"), Opinion No. 17, "Intangible Assets," and
will carry forward provisions in APB Opinion No. 17 related to internally
developed intangible assets. Adoption of FAS 142 will result in ceasing
amortization of goodwill. All of the provisions of the statement should be
applied in fiscal years beginning after December 15, 2001 to all goodwill and
other intangible assets recognized in an entity's statement of financial
position at that date, regardless of when those assets were initially
recognized. The Company does not have any goodwill or intangible assets
recorded as of September 30, 2001 and does not expect the adoption of this
standard to have a material impact on its financial position or results of
operations.
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." The statement requires entities to record the fair value of a
liability for legal obligations associated with the retirement of obligations of
tangible long-lived assets in the period in which it is incurred. When the
liability is initially recorded, the entity increases the carrying amount of the
related long-lived asset. Accretion of the liability is recognized each period,
and the capitalized cost is depreciated over the useful life of the related
asset. Upon settlement of the liability, an entity either settles the obligation
for its recorded amount or incurs a gain or loss upon settlement. The standard
is effective for fiscal years beginning after June 15, 2002, with earlier
application encouraged. The Company is currently evaluating the effect of
adopting Statement No. 143 on its financial statements and had not determined
the timing of adoption and does not expect the adoption of this standard to have
a material impact on its financial position or results of operations.
-10-
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 condensed 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, 2000 and the unaudited condensed 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 39 gross wells in 2000 and 30 gross
wells through the nine months ended September 30, 2001. The Company has budgeted
to drill 54 gross wells (14.8 net) in 2001; 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 2001, depreciation, depletion and
amortization, oil and gas operating expenses and production are expected to
increase. 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 acquired properties
with existing production in the Camp Hill Project in late 1993, the Encinitas
Project in early 1995 and the La Rosa Project in 1996. The Company made these
acquisitions through the use of limited partnerships with Carrizo or Carrizo
Production, Inc. as the general partner. In addition, in November 1998, the
Company acquired assets in Wharton County, Texas in the Jones Branch project
area for $3,000,000.
During the second quarter of 2001, the Company formed 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 plans to spend up to $5 million for drilling costs on these
leases through December 2002, 50 percent 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's drilling costs through
September 30, 2001 amounted to $425,000.
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, 2001, the Company had recorded $1.6
million of hedging gains 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, 2000 and 2001 were
18,000 Bbls and zero Bbls, respectively, and 420,000 MMBtu and 822,000 MMBtu,
respectively. Income and (losses) realized by the Company under such hedging
arrangements were $(336,437) and $1,538,700 for the three months ended September
30, 2000 and 2001, respectively. Total oil and natural gas purchased and sold
under hedging arrangements during the nine months ended September 30, 2000 and
2001 were 36,000 Bbls and 18,000 Bbls, respectively, and 900,000 MMBtu and
2,541,000 MMBtu, respectively. Income and (losses) realized by the Company under
such hedging arrangements were $(772,337) and $857,638 for the nine months ended
September 30, 2000 and 2001, respectively. At September 30, 2000, the Company
had 1,800,000 MMBtu and 36,400 Bbls of outstanding hedge positions (at an
average price of $4.67 per MMBtu and $30.00 per Bbl) for October through March
2001 production. At September 30, 2001, the Company had the following
outstanding hedge positions:
<Table>
<Caption>
Collar Arrangements
Contract ---------------------------
Volumes Average Average
(MMBtu) Fixed Price Floor Price Ceiling Price
------- ----------- ----------- -------------
2001:
Fourth Quarter 639,000 $ - $4.44 $5.44
=======
2002:
First Quarter 270,000 $4.25 $5.15
540,000 $3.20
-------
810,000
=======
Second Quarter 546,000 $3.20
=======
Third Quarter 552,000 $3.20
=======
Fourth Quarter 552,000 $3.20
=======
</Table>
The Company's 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
-11-
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 Accounting Standards No. 133.
See Note 7 to the Financial Statements.
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 percent discount rate) of estimated future net
after-tax cash flows from proved oil and gas reserves, such excess costs are
charged to operations. 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. A ceiling test
write-down was not required for the nine months ended September 30, 2001 and
2000. 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, 2001,
Compared to the Three Months Ended September 30, 2000
Oil and natural gas revenues for the three months ended September 30, 2001
decreased 23 percent to $6,162,000 from $8,008,000 for the same period in 2000.
Production volumes for natural gas during the three months ended September 30,
2001 decreased 25 percent to 1,123,724 Mcf from 1,501,402 Mcf for the same
period in 2000. Average natural gas prices increased four percent to $4.52 per
Mcf in the third quarter of 2001 from $4.34 per Mcf in the same period in 2000.
Production volumes for oil in the third quarter of 2001 decreased 13 percent to
43,619 Bbls from 49,997 Bbls for the same period in 2000. Average oil prices
decreased 17 percent to $24.75 per barrel in the third quarter of 2001 from
$29.79 per barrel in the same period in 2000. The decrease in oil production was
due to the natural decline in production primarily at the Jones Branch wells and
the initial Matagorda Project wells offset by the commencement of production at
the Pitchfork Ranch well. The decrease in natural gas production was due
primarily to the sale of the Metro Project during 2000 and the natural decline
in production primarily at the initial Matagorda Project wells offset by the
commencement of production at the additional Cedar Point Project wells, the West
Bay Project well and the Pitchfork Ranch well. 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, 2000 and 2001:
2001 Period
Compared to 2000 Period
September 30, -----------------------------
----------------------------- Increase % Increase
2000 2001 (Decrease) (Decrease)
------------ ----------- ------------- ----------
Production volumes -
Oil and condensate (Bbls) 49,997 43,619 (6,378) (13%)
Natural gas (Mcf) 1,501,402 1,123,724 (377,678) (25%)
Average sales prices - (1)
Oil and condensate (per Bbls) $ 29.79 $ 24.75 $ (5.04) (17%)
Natural gas (per Mcf) 4.34 4.52 0.18 4%
Operating revenues -
Oil and condensate $1,489,225 $1,079,384 $ (409,841) (28%)
Natural gas 6,518,358 5,082,295 (1,436,063) (22%)
---------- ---------- -----------
Total $8,007,583 $6,161,679 $(1,845,904) (23%)
========== ========== ===========
- ------------------
(1) Includes impact of hedging activities.
Oil and natural gas operating expenses for the three months ended September 30,
2001 decreased 29 percent to $928,000 from $1,298,000 for the same period in
2000 primarily due to lower severance taxes offset by higher ad valorem taxes
and the addition of
-12-
new production. Operating expenses per equivalent unit decreased seven percent
to $.67 per Mcfe in the third quarter of 2001 from $.72 per Mcfe in the same
period in 2000 primarily as a result of 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 three months
ended September 30, 2001 decreased 17 percent to $1,672,000 from $2,012,000 for
the same period in 2000. This decrease was due to decreased production offset by
additional seismic and drilling costs. General and administrative expense for
the three months ended September 30, 2001 decreased eight percent to $691,000
from $747,000 for the same period in 2000 primarily as a result of additional
salaries allocated to specific projects.
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
$3,900,723 offset by a charge and related legal expenses in respect of the final
settlement of the litigation with BNP Petroleum Corporation. During the third
quarter of 2000, the Company earned a fee in the amount of $1,544,180 in
connection with activities related to a potential acquisition, which was paid in
common shares of Michael Petroleum Corporation.
Income taxes increased to $1,960,000 for the three months ended September 30,
2001 from $26,000 for the same period in 2000. The Company provided deferred
income taxes at 35 percent during the third quarter of 2001 compared to none in
the third quarter of 2000 as a result of an adjustment to its valuation reserve
on net operating loss carryforwards in 2000.
Interest income for the three months ended September 30, 2001 decreased to
$58,000 from $145,000 in the third quarter of 2000 primarily as a result of
lower cash balances during the third quarter of 2001. Capitalized interest
decreased to $833,000 in the third quarter of 2001 from $870,000 in the third
quarter of 2000 primarily due to lower interest costs as a result of the term
loan repayments during the third quarter of 2001 and lower interest rates.
Income before income taxes for the three months ended September 30, 2001
increased to $5,506,000 from $4,920,000 in the same period in 2000. Net income
for the three months ended September 30, 2001 decreased to $3,546,000 from
$4,894,000 for the same period in 2000 primarily as a result of the factors
described above.
Nine Months Ended September 30, 2001,
Compared to the Nine Months Ended September 30, 2000
Oil and natural gas revenues for the nine months ended September 30, 2001
increased 21 percent to $21,981,000 from $18,114,000 for the same period in
2000. Production volumes for natural gas during the nine months ended September
30, 2001 decreased 16 percent to 3,435,995 Mcf from 4,078,706 Mcf for the same
period in 2000. Average natural gas prices increased 59 percent to $5.41 per Mcf
in the first nine months of 2001 from $3.41 per Mcf in the same period in 2000.
Production volumes for oil in the first nine months of 2001 decreased 15 percent
to 131,593 Bbls from 154,238 Bbls for the same period in 2000. Average oil
prices decreased six percent to $25.77 per barrel in the first nine months of
2001 from $27.30 per barrel in the same period in 2000. The decrease in oil
production was due to the natural decline in production primarily at the Jones
Branch wells, the initial Matagorda Project wells offset the commencement of
production of the Pitchfork Ranch well. The decrease in natural gas production
was due primarily to the sale of the Metro Project during 2000 and the natural
decline in production primarily at the initial Matagorda Project wells offset by
the commencement of production at the additional Cedar Point Project wells, the
West Bay Project well and the Pitchfork Ranch well. 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 nine
months ended September 30, 2000 and 2001:
2001 Period
Compared to 2000 Period
September 30, -----------------------------
----------------------------- Increase % Increase
2000 2001 (Decrease) (Decrease)
------------ ----------- ------------- ----------
Production volumes -
Oil and condensate (Bbls) 154,238 131,593 (22,645) (15%)
Natural gas (Mcf) 4,078,706 3,435,995 (642,711) (16%)
Average sales prices - (1)
Oil and condensate (per Bbls) $ 27.30 $ 25.77 $ (1.53) (6%)
Natural gas (per Mcf) 3.41 5.41 2.00 59%
Operating revenues -
Oil and condensate $ 4,210,635 $ 3,391,277 $ (819,358) (19%)
Natural gas 13,903,282 18,590,085 4,686,803 34%
----------- ----------- -----------
Total $18,113,917 $21,981,362 $ 3,867,445 21%
=========== =========== ===========
- ------------------
(2) Includes impact of hedging activities.
Oil and natural gas operating expenses for the nine months ended September 30,
2001 increased six percent to $3,359,000 from $3,159,000 for the same period in
2000 primarily due to higher severance and ad valorem taxes and the addition of
new production. Operating expenses per equivalent unit increased 26 percent to
$0.79 per Mcfe in the first nine months of 2001 from $.63 per Mcfe in the same
period in 2000 primarily as a result of higher severance and ad valorem taxes
and decreased production of natural gas as wells naturally decline.
Depreciation, depletion and amortization (DD&A) expense for the nine months
ended September 30, 2001 decreased eight percent to $4,988,000 from $5,421,000
for the same period in 2000. This decrease was due to decreased production
offset by additional seismic and drilling costs. General and administrative
expense for the nine months ended September 30, 2001 increased 11 percent to
$2,434,000 from $2,203,000 for the same period in 2000 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
$3,900,723 offset by a charge and related legal expenses in respect of the final
settlement of the litigation with BNP Petroleum Corporation. During the third
quarter of 2000 the Company earned a fee in the amount of $1,544,180 in
connection with activities related to a potential acquisition, which was paid in
common shares of Michael Petroleum Corporation.
Interest income for the nine months ended September 30, 2001 decreased to
$251,000 from $420,000 in the first nine months of 2000 primarily as a result of
lower cash balances during the first nine months of 2001. Capitalized interest
decreased to $2,364,000 in the first nine months of 2001 from $2,671,000 in the
first nine months of 2000 primarily due to lower interest costs as a result of
the term loan repayments during the first nine months of 2001 and lower
interests rates.
Income taxes increased to $5,166,000 for the nine months ended September 30,
2001 from $77,000 for the same period in 2000. The Company provided deferred
income taxes at 35 percent during the first nine months of 2001 compared to none
in the first nine months of 2000 as a result of an adjustment to its valuation
reserve on net operating loss carryforwards.
Income before income taxes for the nine months ended September 30, 2001
increased to $14,475,000 from $8,563,000 in the same period in 2000. Net income
for the nine months ended September 30, 2001 increased to $9,310,000 from
$8,486,000 for the same period in 2000 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
-14-
geophysical costs on its active exploration projects.
While the Company believes that the current cash balances and anticipated 2001
operating cash flow will provide sufficient capital to carry out the Company's
2001 exploration plan, 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 proceeds from the 1997
initial public offering, from the December 1999 sale of Subordinated Notes,
Common Stock and Warrants, the 1998 sale of shares of Preferred Stock and
Warrants, funds generated by operations, equity capital contributions,
borrowings (primarily under revolving credit facilities) and the Palace
Agreement that provided a portion of the funding for the Company's 1999, 2000
and 2001 drilling program in return for participation in certain wells.
Cash flows provided by operations (after changes in working capital) were
$10,758,000 and $19,536,000 for the nine months ended September 30, 2000 and
2001, respectively. The increase in cash flows provided by operations in 2001 as
compared to 2000 was due primarily to additional revenue as a result of higher
oil and natural gas prices during the first nine months of 2001.
The Company expects to incur capital expenditures for the year ended December
31, 2001 of approximately $35.6 million as follows:
<Table>
<Caption>
Land/Property
Drilling Acquisitions Seismic Total
-------- ------------- ------- -----
(in millions)
Gulf Coast Region $ 21.2 $ 3.7 $ 1.8 $ 26.7
CCBM, Inc. 1.3 7.6 -- 8.9
------ ------- ------ ------
$ 22.5 $ 11.3 $ 1.8 $ 35.6
====== ======= ====== ======
</Table>
The Company expects to drill up to approximately 54 gross wells (14.8 net)
in 2001 as follows:
<Table>
<Caption>
Gross Net
------ ----
Gulf Coast Region 26.0 8.0
CCBM, InC. 28.0 6.8
---- ----
54.0 14.8
==== ====
</Table>
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 $30.6 million for the nine months ended September 30,
2001 which included $7.5 million of oil and gas interest acquired from RMG and
$3.0 million of capitalized interest and general and administrative costs. The
Company's drilling efforts resulted in the successful completion of 24 gross
wells (6.6 net) during the year ended December 31, 2000 and 25 gross wells (6.7
net) during the nine months ended September 30, 2001.
FINANCING ARRANGEMENTS
In connection with Carrizo's initial public offering in 1997, Carrizo entered
into an amended revolving credit facility with Compass Bank (the "Company Credit
Facility"), to provide for a maximum loan amount of $25 million, subject to
borrowing base limitations. The principal outstanding is due and payable in
April 2003, with interest due monthly. The Company Credit Facility was amended
in March 1999 to provide for a maximum loan amount under such facility of $10
million. The interest rate on all revolving credit loans is calculated, at the
Company's option, at a floating rate based on the Compass index rate or LIBOR
plus 2 percent. The Company's obligations are secured by substantially all of
its oil and gas properties and cash or cash equivalents included in the
borrowing base. Certain members of the Board of Directors had provided
collateral, primarily in the form of marketable securities, to secure the
revolving credit loans. This collateral was released during April 2001.
Under the Company Credit Facility, Compass, in its sole discretion, will make
semiannual borrowing base determinations based upon the proved oil and natural
gas properties of the Company. Compass may also redetermine the borrowing base
and the monthly borrowing base reduction at any time at its discretion. The
latest borrowing base determination was done effective September 1, 2001 and the
next review is scheduled for March 1, 2002. The Company may also request
borrowing base redeterminations in addition to the required semiannual reviews
at the Company's cost.
In September 1998, the Company Credit Facility was further amended to provide
for an additional $7 million term loan bearing interest at the Index Rate, of
which $7 million was borrowed in the fourth quarter of 1998. In March 1999, the
Company Credit Facility was further amended to increase the $7 million term loan
by $2 million. In December 1999, $2 million principal amount of the term loan
was repaid with proceeds from the sale from the Subordinated Notes, Common Stock
and Warrants.
Certain members of the Board of Directors guaranteed the Term Loan. Interest on
the Term Loan was payable monthly, bearing interest at the Index Rate. Unless
preceded by the Term Loan Maturity Date (as defined below), principal payments
on the Term Loan were not due until June 1, 2000, whereupon the Term Loan was
repayable in consecutive monthly installments in the amount $290,000 each,
beginning July 1, 2000 through December 1, 2000, and
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thereafter in the amount of $440,000, beginning January 1, 2001 until the Term
Loan Maturity Date, when the entire principal balance, plus interest, is
payable. The Term Loan was paid in full in September 2001. Term Loan Maturity
Date means the earlier of: (1) the date of closing of the issuance of additional
equity of the Company, if the net proceeds of such issuance are sufficient to
repay in full the term loan; (2) the date of closing of the issuance of
convertible subordinated debt of the Company, if the proceeds of such issuance
are sufficient to repay in full the term loan; (3) the date of repayment of the
revolving credit loans and the termination of the revolving commitment; and (4)
December 1, 2001. As of September 30, 2001 and December 31, 2000, the
outstanding principal balance under the Term Loan was none and $5,260,000,
respectively.
The Company is subject to certain covenants under the terms of the Company
Credit Facility, including but not limited to (a) maintenance of specified
tangible net worth, (b) a ratio of quarterly EBITDA (earnings before interest,
taxes, depreciation and amortization) to quarterly debt service of not less than
1.25 to 1.00, and (c) a specified minimum amount of working capital. The Company
Credit Facility also places restrictions on, among other things, (a) incurring
additional indebtedness, guaranties, loans and liens, (b) changing the nature of
business or business structure, (c) selling assets and (d) paying dividends.
Proceeds of the revolving credit loans have been used to provide funding for
exploration and development activity. At December 31, 2000 and September 30,
2001, outstanding revolving credit loans totaled $5,426,000, and $7,166,000,
respectively with an additional $2,676,884 and $2,360,000, respectively,
available for future borrowings. The Company Credit Facility also provides for
the issuance of letters of credit, one of which has been issued for $224,000 at
December 31, 2000 and September 30, 2001. The Borrowing Base facility was
amended in November 2000 to provide up to $2 million of Guidance Line letters of
credit (the "Guidance Line letters of credit") relating exclusively to the
Company's outstanding hedge positions. At December 31, 2000 and September 30,
2001, the Company had one and zero Guidance Line letters of credit outstanding
amounting to $180,000 and zero, respectively.
On June 29, 2001, CCBM a wholly owned subsidiary of the Company, issued a
non-recourse promissory note payable in the amount of $7,500,000 to Rocky
Mountain Gas, Inc. ("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 eight percent 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 1999, the Company consummated the sale of $22 million principal
amount of 9 percent Senior Subordinated Notes due 2007 (the "Subordinated
Notes") to an investor group led by CB Capital Investors, L.P. 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 percent of the interest which would otherwise be payable in cash. The
Subordinated Notes were increased by $1,227,325 and $2,182,569 for such interest
as of December 31, 2000 and September 30, 2001, 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 sale was made to an investor group led by CB Capital Investors, L.P. which
included certain members of the Board of Directors. 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 a specified amount for the year ended December 31, 2000,
and thereafter 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 JP
Morgan Partners 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
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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 Enron Repurchase described below 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 December 1999, the Company consummated the repurchase from certain Enron
Corporation affiliates of all the outstanding shares of Preferred Stock and
750,000 Warrants for $12 million. At the same time, the Company reduced the
exercise price of the remaining 250,000 Warrants from $11.50 per share to $4.00
per share.
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.
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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.
Settlement of Litigation. The Company, as one of three plaintiffs,
filed a lawsuit against BNP Petroleum Corporation ("BNP"), Seiskin Interests,
LTD, Pagenergy Company, LLC and Gap Marketing Company, LLC, as defendants, in
the 229th Judicial District Court of Duval County, Texas, for fraud and breach
of contract in connection with an agreement between plaintiffs and defendants
whereby the defendants were obligated to drill a test well in an area known as
the Slick Prospect in Duval County, Texas. The allegations of the Company in
this litigation were that BNP gave the Company inaccurate and incomplete
information on which the Company relied in making its decision not to
participate in the test well and the prospect, resulting in the loss of the
Company's interest in the lease, the test well and four subsequent wells drilled
in the prospect. The Company sought to enforce its approximate 23.68% interest
in the prospect and sought damages or rescission, as well as costs and
attorneys' fees. The case was originally filed in Duval County, Texas on
February 25, 2000.
In mid March, 2000, the defendants filed an original answer and certain
counterclaims against plaintiffs, seeking unspecified damages for slander of
title, tortious interference with business relations, and exemplary damages. The
case proceeded to trial before the Court (without a jury) on June 19, 2000 after
the plaintiffs' were found by the court to have failed to comply with procedural
requirements regarding the request for a jury. After several days of trial the
case was recessed and later resumed on September 5, 2000. The court at that time
denied the plaintiffs' motion for mistrial based on the court's denial of a jury
trial. The court also ordered that the defendants' counterclaims would be the
subject of a separate trial that would commence on December 11, 2000. The
parties proceeded to try issues related to the plaintiffs' claims on September
5, 2000. All parties rested on the plaintiffs' claims on September 13, 2000. The
court took the matter under advisement. Defendants filed a second amended answer
and counterclaim and certain supplemental responses to request for disclosure in
which they stated that they were seeking damages in the amount of $33.5 million
by virtue of an alleged lost sale of the subject properties, $17 million in
alleged lost profits from other prospective contracts, and unspecified
incidental and consequential damages from the alleged wrongful suspension of
funds under their gas sales contract with the gas purchaser on the properties,
alleged damage to relationships with trade creditors and financial institutions,
including the inability to leverage the Slick Prospect, and attorneys' fees at
prevailing hourly rates in Duval County, Texas incurred in defending against
plaintiffs' claims and for 40% of any aggregate recovery in prosecuting their
counterclaims. In subsequent testimony, the defendants verbally alleged $26
million of damages by virtue of the alleged lost sale of the properties (as
opposed to the $33.5 million previously sought), $7.5 million of damages by
virtue of loss of a lease development opportunity and $100 million of damages by
virtue of the loss of a business opportunity related to BNP's alleged inability
to participate in a 3-D seismic project.
The Company had also alleged that BNP Petroleum Corporation, Seiskin
Interests, LTD and Pagenergy Company, LLC breached a contract with the
plaintiffs by obtaining oil and gas leases within an area restricted by that
contract. This breach of contract allegation was the subject of an additional
lawsuit by plaintiffs in the 165th District Court in Harris County, Texas. The
defendants took the position that the claim must be tried in the Duval County
case. The Duval County court, without issuing a formal ruling, took the position
that this claim should be included in the Duval County case. The Company was
seeking damages as a result of defendants' actions as well as costs and
attorneys' fees.
On December 8, 2000 the Company entered into a Compromise and
Settlement Agreement ("Settlement Agreement") with the defendants with regard to
the above described litigation. Under the terms of the Settlement Agreement, the
Company and the defendants agreed to enter into an Agreed Order of Dismissal
with Prejudice of the litigation and, among other things, agreed as follows:
1. Should a co-plaintiff to the Duval County litigation secure a final
judgment (without regard to appeals, new trials or other such actions)
in the trial court in Duval County that results in such plaintiff being
entitled to recover a five percent or greater undivided interest in the
Slick Prospect, BNP will pay to Carrizo, at BNP's option, either
$500,000 or an amount equal to the judgment rendered in favor of such
plaintiff.
2. Should the defendants secure a final judgment (without regard to
appeals, new trials or other such actions) in the trial court in Duval
County against a co-plaintiff, the Company will be obligated to pay BNP
an amount equal to five percent of any
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percentage of the total judgment apportioned to the Company in the
case, such payment being limited however to no more than five percent
of 47.2 percent of the total judgment entered in the case.
3. In the event the defendants and such co-plaintiff reach a full and
final settlement prior to the entry of a written final judgment in the
trial court in Duval County (including but not limited to any type of
agreed judgment or any agreement that such co-plaintiff will not be
ultimately liable to BNP for the full amount of any judgment rendered
in favor of the defendants), the obligations described in (1) and (2)
above will be null and void. Also, in the event BNP and such
co-plaintiff both only obtain take nothing judgments in the case, such
obligations will be null and void.
4. Both the Company and the defendants released each other from any and
all claims, demands, actions or causes of action relating to or arising
out of the litigation.
The case proceeded to trial on the counterclaims on December 11, 2000.
BNP presented evidence that its damages were in the amounts of $19.6 million for
the alleged lost sale of the properties, $35 million for loss of the lease
development opportunity, and $308 million for loss of the opportunity related to
participation in the 3-D seismic project. During the course of the trial, the
co-plaintiff presented its motion for summary judgment on the counterclaims
based on the doctrine of absolute judicial proceeding privilege. The court
partially granted the co-plaintiff's motion for summary judgment as it related
to the filing of a lis pendens, but denied it with regard to the other
allegations of BNP. The court also granted to co-plaintiff's plea in abatement
relating to the breach of contract allegation, ruling that the District Court in
Harris County has dominant jurisdiction of that issue. Upon completion of the
trial, the court announced that it would take the case under advisement.
On November 5, 2001, the court filed with the clerk a final judgment that had
been signed by the court on October 26, 2001. Pursuant to the terms of the
judgment, the Company and its co-plaintiffs take nothing on their claims against
BNP and are denied any recovery of their interest in the lease, the prospect, or
the wells of the Slick Prospect. Instead, the court confirmed title in the
lease, prospect, and wells in BNP's affiliate. In addition, the Company and its
co-defendants were found to have tortiously and maliciously interfered with two
different BNP contracts or prospective contracts, the business of BNP and its
affiliate, causing damages with respect to the loss of a sale and the loss of
a lease. Under the terms of the Settlement Agreement, the Company owes $472,000
to BNP. This amount was remitted to BNP on November 12, 2001 in final settlement
of the litigation. The settlement amount, along with the related legal fees, has
been included as other expense in the accompanying financial statements.
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
None.
Item 5 - Other Information
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, CCBM's planned expenditures for drilling
costs on leases in Wyoming and Montana, use of offering proceeds, effects of
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, effect and timing of
the sale of shares in MPC, outcome, effects and timing of title problems 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, outcome of title issues, 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
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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 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 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) and 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).
4.1 -- Twelfth Amendment to the First Amended, Restated and Combined
Loan Agreement by and between Carrizo Oil & Gas, Inc. and
Compass Bank dated July 25, 2001.
+ Incorporated herein by reference as indicated.
Reports on Form 8-K
None
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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, 2001 By: /s/ S. P. Johnson, IV
----------------------------------------
President and Chief Executive Officer
(Principal Executive Officer)
Date: November 14, 2001 By: /s/ Frank A. Wojtek
----------------------------------------
Chief Financial Officer
(Principal Financial and
Accounting Officer)
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EXHIBIT INDEX
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) and 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).
4.1 -- Twelfth Amendment to the First Amended, Restated and Combined
Loan Agreement by and between Carrizo Oil & Gas, Inc. and
Compass Bank dated July 25, 2001.
+ Incorporated herein by reference as indicated.