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 MARCH 31, 2002
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ________ to _________
Commission File Number 000-22915.
CARRIZO OIL & GAS, INC.
(Exact name of registrant as specified in its charter)
TEXAS 76-0415919
(State or other jurisdiction of (IRS Employer Identification No.)
incorporation or organization)
14701 ST. MARY'S LANE, SUITE 800, HOUSTON, TX 77079
(Address of principal executive offices) (Zip Code)
(281) 496-1352
(Registrant's telephone number)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports) and (2) has been subject to such filing
requirements for the past 90 days. Yes X. No __
The number of shares outstanding of the registrant's common stock, par value
$0.01 per share, as of May 3, 2002, the latest practicable date, was 14,140,549.
CARRIZO OIL & GAS, INC.
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2002
INDEX
PART I. FINANCIAL INFORMATION PAGE
Item 1. Consolidated Balance Sheets
- As of December 31, 2001 and March 31, 2002 2
Consolidated Statements of Operations
- For the three-month periods ended March 31, 2002
and 2001 3
Consolidated Statements of Cash Flows - For the
three-month periods ended March 31, 2002
and 2001 4
Notes to Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 10
PART II. OTHER INFORMATION
Items 1-6. 18
SIGNATURES 20
CARRIZO OIL & GAS, INC.
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
December 31, March 31,
ASSETS 2001 2002
----------------- -----------------
CURRENT ASSETS:
Cash and cash equivalents $3,235,712 $5,264,559
Accounts receivable, net of allowance for doubtful accounts of
$480,000 at December 31, 2001 and March 31, 2002, respectively 8,111,482 5,561,208
Advances to operators 508,563 1,036,520
Deposits 47,901 48,124
Other current assets 599,882 592,941
----------------- -----------------
Total current assets 12,503,540 12,503,352
PROPERTY AND EQUIPMENT, net (full-cost method of
accounting for oil and gas properties) 104,132,392 108,013,400
OTHER ASSETS 755,731 727,684
----------------- -----------------
$117,391,663 $121,244,436
================= =================
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade $10,263,176 $7,321,605
Accrued liabilities 347,778 838,558
Advances for joint operations 367,942 1,485,300
Current maturities of long-term debt 2,107,030 1,574,980
------------------ -----------------
Total current liabilities 13,085,926 11,220,443
LONG-TERM DEBT 36,081,057 36,033,209
DEFERRED INCOME TAXES 5,020,576 5,120,115
COMMITMENTS AND CONTINGENCIES (Note 5)
CONVERTIBLE PARTICIPATING PREFERRED STOCK (10,000,000 shares of
preferred stock authorized, of which 150,000 are shares designated
as convertible participating shares, with 60,000 convertible
participating shares issued and outstanding at March 31, 2002)
(Note 6)
Issued and outstanding - 5,790,736
Accrued dividends - 68,388
SHAREHOLDERS' EQUITY:
Warrants (3,010,189 and 3,262,821 outstanding at December 31, 2001
and March 31, 2002, respectively) 765,047 780,047
Common stock, par value $.01, (40,000,000 shares authorized with
14,064,077 and 14,140,549 issued and outstanding at December 31,
2001 and March 31, 2002, respectively) (Note 7) 140,641 141,406
Additional paid in capital 62,735,659 63,059,900
Accumulated deficit (1,143,634) (1,073,969)
Other comprehensive income 706,391 104,161
----------------- -----------------
63,204,104 63,011,545
----------------- -----------------
$117,391,663 $121,244,436
================= =================
The accompanying notes are an integral part
of these consolidated financial statements.
-2-
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
For the Three
Months Ended
March 31,
-------------------------------------------
2001 2002
-------------------- --------------------
OIL AND NATURAL GAS REVENUES $ 8,727,481 $4,026,893
COSTS AND EXPENSES:
Oil and natural gas operating expenses 1,299,571 1,012,656
Depreciation, depletion and amortization 1,629,744 1,969,723
General and administrative 870,482 915,952
Stock option compensation (331,655) (42,035)
------------------ --------------------
Total costs and expenses 3,468,142 3,856,296
------------------ --------------------
OPERATING INCOME 5,259,339 170,597
OTHER INCOME AND EXPENSES:
Other income and expenses, net - 93,774
Interest income 120,501 20,027
Interest expense (749,781) (712,760)
Interest expense, related parties (52,359) (55,244)
Capitalized interest 802,140 768,004
------------------ --------------------
INCOME BEFORE INCOME TAXES 5,379,840 284,398
INCOME TAXES (Note 4) 1,916,031 140,474
------------------ --------------------
NET INCOME $ 3,463,809 $ 143,924
================== ====================
DIVIDENDS AND ACCRETION OF DISCOUNT ON PREFERRED STOCK - (74,259)
================== ====================
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS $ 3,463,809 $ 69,665
================== ====================
BASIC EARNINGS PER COMMON SHARE (Note 2) $ 0.25 $ 0.00
================== ====================
DILUTED EARNINGS PER COMMON SHARE (Note 2) $ 0.21 $ 0.00
================== ====================
DILUTED EARNINGS PER COMMON SHARE (Note 2) $ 0.21 $ 0.00
================== ====================
The accompanying notes are an integral part
of these consolidated financial statements.
-3-
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
For the Three
Months Ended
March 31,
---------------------------
2001 2002
----------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 3,463,809 $ 143,924
Adjustment to reconcile net income to net
cash provided by operating activities-
Depreciation, depletion and amortization 1,629,744 1,969,723
Discount accretion 21,315 21,399
Income from derivative instruments - (232,013)
Interest payable in kind 314,155 331,464
Stock option compensation benefit (331,655) (42,036)
Deferred income taxes 1,882,944 99,539
Changes in assets and liabilities-
Accounts receivable (2,016,731) 2,550,274
Other assets 101,554 (7,234)
Accounts payable, trade 10,203 (2,493,263)
Other current liabilities (266,397) 162,599
----------- -----------
Net cash provided by operating activities 4,808,941 2,504,376
----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures, accrual basis (8,250,779) (5,808,731)
Adjustment to cash basis 1,684,147 (123,302)
Advances to operators 790,003 (527,957)
Advances for joint operations 363,195 1,117,358
----------- -----------
Net cash used in investing activities (5,413,434) (5,342,632)
----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from the sale of common stock 10,800 -
Net proceeds from the sale of preferred stock - 5,784,865
Net proceeds from the sale of warrants - 15,000
Debt repayments (1,600,412) (932,762)
----------- -----------
Net cash provided by (used in) financing activities (1,589,612) 4,867,103
----------- -----------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (2,194,105) 2,028,847
CASH AND CASH EQUIVALENTS, beginning of period 8,217,427 3,235,712
----------- -----------
CASH AND CASH EQUIVALENTS, end of period $ 6,023,322 $ 5,264,559
=========== ===========
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest (net of amounts capitalized) $ - $ -
=========== ===========
Common stock issued for oil and gas property (Note 7) $ - $ 325,006
=========== ===========
The accompanying notes are an integral part
of these consolidated financial statements.
-4-
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 earning per share information is provided below:
For the Three Months Ended March 31,
-------------------------------------------------------------------------------
Income Shares Per-Share Amount
--------------------------- ------------------------ ------------------
2001 2002 2001 2002 2001 2002
----------- --------- ---------- ---------- ------ -------
Net Income $ 3,463,809 $ 143,924
Less: Dividends and Accretion of Discount
on Preferred Shares - (74,259)
----------- ---------
Basic Earnings per Share
Net income available to common shareholders 3,463,809 69,665 14,057,928 14,128,653 $ 0.25 $ 0.00
====== =========
Stock Options and Warrants - - 2,696,906 2,105,154
Diluted Earnings per Share ----------- --------- ---------- -----------
Net income available to common shareholders
plus assumed conversions $ 3,463,809 $ 69,665 16,754,834 16,233,807 $ 0.21 $ 0.00
=========== ========= ========== =========== ====== =========
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 67,000 and 189,833 stock options and zero
and 252,632 warrants during the three months ended March 31, 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. At March 31, 2002, the Company also had
1,052,632 shares based on the assumed conversion of the Series B Convertible
Participating Preferred Stock that were antidilutive and were not included in
the calculation.
-5-
3. LONG-TERM DEBT:
At December 31, 2001 and March 31, 2002, long-term debt consisted of the
following:
December 31, March 31,
2001 2002
------------- ----------
Borrowing base facility $ 7,166,000 $ 6,626,000
Senior subordinated notes 21,635,252 21,952,830
Senior subordinated notes, related parties 2,403,916 2,439,202
Capital lease obligation 232,919 215,157
Non-recourse note payable to
Rocky Mountain Gas, Inc. 6,750,000 6,375,000
------------- ----------
38,188,087 37,608,189
Less: current maturities (2,107,030) (1,574,980)
------------- ----------
$36,081,057 $36,033,209
=========== ===========
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%. 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
Company may also request borrowing base redeterminations in addition to the
required semiannual reviews at the Company's cost.
At December 31, 2001 and March 31, 2002, amounts outstanding under the Borrowing
Base Facility totaled $7,166,000 and $6,626,000, respectively with an additional
$620,000 and zero, respectively, available for future borrowings. The Borrowing
Base totaled $7,786,000 and $6,850,000 at December 31, 2001 and March 31, 2002,
respectively. The Borrowing Base Facility was also available for letters of
credit, one of which has been issued for $224,000 at December 31, 2001 and March
31, 2002. 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, 2001 and March 31, 2002, the Company had no Guidance Line letters
of credit outstanding.
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.
On June 29, 2001, CCBM, Inc. a wholly owned subsidiary of the Company ("CCBM"),
issued a non-recourse promissory note payable in the amount of $7,500,000 to RMG
as consideration for certain interest in oil and gas leases held by RMG in
Wyoming and Montana. The RMG note is payable in 41-monthly principal payments of
$125,000 plus interest at 8% per annum commencing July 31, 2001 with the balance
due December 31, 2004. The RMG note is secured solely by CCBM's interests in the
oil and gas leases in
-6-
Wyoming and Montana. At December 31, 2001 and March 31, 2002, the principal
balance of this note was $6,750,000 and $6,375,000, 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 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% of the interest which would otherwise be
payable in cash. As of December 31, 2001 and March 31, 2002, the outstanding
balance of the Subordinated Notes had been increased by $2,552,970 and
$2,884,435, 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 JPMorgan Partners appointed director).
4. INCOME TAXES:
The Company provided deferred income taxes at the rate of 35%, which also
approximates its statutory rate, that amounted to $1,882,944 and $99,539 for the
three months ended March 31, 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 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
March 31, 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.
-7-
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 March 31, 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 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. The financial statements at March
31, 2002 reflect an accrual for a dividend of 683.88 shares of Series B
Preferred Stock. 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 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.
The approximately $5,800,000 proceeds of this financing are expected to be used
primarily to fund the Company's ongoing exploration and development program.
7. COMMON STOCK:
The Company issued 76,472 shares of common stock during the three months ended
March 31, 2002 as part of the purchase of an interest in certain oil and gas
properties.
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
-8-
transaction occurs. All of the Company's derivative instruments at January 1,
2001 and December 31, 2001 and March 31, 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 quarter ended
March 31, 2002, $232,000 was reclassified from other comprehensive income into
oil and gas revenues. An allowance for the related asset totalling $759,000, net
of tax of $409,000, was charged to other expense during the fourth quarter of
2001. At December 31, 2001 and March 31, 2002, $706,000, net of tax of $380,000,
and $474,000 net of tax of $255,000, respectively, remained in accumulated other
comprehensive income related to the deferred gains on these derivatives.
At March 31, 2002, the Company had recorded $370,000 of hedging losses in other
comprehensive income, 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 swap arrangements during the three months ended March 31, 2001
and 2002 were 18,000 Bbls and zero Bbls, respectively, and 993,000 MMBtu and
zero MMBtu, respectively. Losses realized by the Company under such swap
arrangements were $1,013,000 and zero for the three months ended March 31, 2001
and 2002, respectively. At March 31, 2001, the Company had outstanding hedge
positions covering 2,004,000 MMBtu and zero Bbls. The 2,004,000 MMBtu of natural
gas hedges had an average floor of $4.73 and an average ceiling of $5.72 for
April through December 2001 production. At March 31, 2002, the Company had
outstanding hedge positions covering 1,705,000 MMBtu and 73,100 Bbls. The
1,705,000 of natural gas hedges had an average fixed price of $3.19 for April
2002 through December 2002 production. The oil hedges consisted of 18,200 Bbls
at a fixed price of $24.65 for April 2002 through June 2002 production and
54,900 Bbls with a floor of $22.00 and a ceiling of $25.00 for April 2002
through September 2002 production.
-9-
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 4 gross wells through the three months ended March 31, 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 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, 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 plans 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 eight
gross wells (four net) and incurred total drilling costs of $306,000 through the
three months ended March 31, 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.
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 March 31, 2002, the Company had recorded $370,000 of
hedge losses in other comprehensive income, all of which is expected to be
reclassified to current earnings within the next twelve months. The amount
ultimately reclassified to earnings will vary due to changes in the fair value
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 March 31, 2001 and 2002 were 18,000 Bbls and zero Bbls,
respectively, and 993,000 MMBtu and zero MMBtu, respectively. Losses realized by
the Company under such swap arrangements were $1,013,000 and zero for the three
months ended March 31, 2001 and 2002, respectively. At March 31, 2001, the
Company had outstanding hedge positions covering 2,004,000 MMBtu and zero Bbls.
The 2,004,000 MMBtu of natural gas hedges had an average floor of $4.73 and an
average ceiling of $5.72 for April through December 2001 production. At March
31, 2002, the Company had outstanding hedge positions covering 1,705,000 MMBtu
and 73,100 Bbls. The 1,705,000 of natural gas hedges had an
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average fixed price of $3.19 for April 2002 through December 2002 production.
The oil hedges consisted of 18,200 Bbls at a fixed price of $24.65 for April
2002 through June 2002 production and 54,900 Bbls with a floor of $22.00 and a
ceiling of $25.00 for April 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 quarter ended
March 31, 2002, $232,000 was reclassified from other comprehensive income into
oil and gas revenues. An allowance for the related asset totalling $759,000, net
of tax of $409,000, was charged to other expense during the fourth quarter of
2001. At December 31, 2001 and March 31, 2002, $706,000, net of tax of $380,000,
and $474,000 net of tax of $255,000, respectively, remained in accumulated other
comprehensive income related to the deferred gains on these derivatives.
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. 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 ended March 31, 2002 and 2001.
Once incurred, a write-down of oil and gas properties is not reversible at a
later date.
RESULTS OF OPERATIONS
Three Months Ended March 31, 2002,
Compared to the Three Months Ended March 31, 2001
Oil and natural gas revenues for the three months ended March 31, 2002 decreased
54% to $4,027,000 from $8,727,000 for the same period in 2001. Production
volumes for natural gas during the three months ended March 31, 2002 decreased
5% to 1,098,616 from 1,161,050 for the same period in 2001. Average natural gas
prices decreased 60% to $2.67 per Mcf in the first quarter of 2002 from $6.66
per Mcf in the same period in 2001. Production volumes for oil in the first
quarter of 2002 increased 42% to 53,209 Bbls from 37,460 Bbls for the same
period in 2001. Average oil prices decreased 23% to $20.50 per barrel in the
first quarter of 2002 from $26.69 per barrel in the same period in 2001. The
increase in oil production was due primarily to the commencement of production
at the Staubach #1 and Riverdale #2 wells offset by the natural decline in
production from other wells. The decrease in natural gas production was due
primarily to the loss of production from the N. La Copita wells and the natural
decline in production primarily at the initial Matagorda Project wells and Jones
Branch wells offset by the commencement of production at the Staubach #1 and
Riverdale #2 wells. Oil and natural gas revenues include the impact of hedging
activities as discussed above under "General Overview".
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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 March 31, 2001 and 2002:
2002 Period
Compared to 2001 Period
March 31, ---------------------------
-------------------------------- Increase % Increase
2001 2002 (Decrease) (Decrease)
-------------------------------- ------------- -------------
Production volumes -
Oil and condensate (Bbls) 37,460 53,209 15,749 42%
Natural gas (Mcf) 1,161,050 1,098,616 (62,434) (5%)
Average sales prices - (1)
Oil and condensate (per Bbls) $ $26.69 $ 20.50 (6.19) (23%)
Natural gas (per Mcf) 6.66 2.67 (3.99) (60%)
Operating revenues -
Oil and condensate $ 999,832 $1,090,726 $ 90,894 9%
Natural gas 7,727,649 2,936,167 (4,791,482) (62%)
------------- ---------- -----------
Total $ 8,727,481 $4,026,893 $(4,700,588) (54%)
============= ========== ===========
- ------------------
(1) Includes impact of hedging activities.
Oil and natural gas operating expenses for the three months ended March 31, 2002
decreased 22% to $1,013,000 from $1,300,000 for the same period in 2001
primarily due to lower severance taxes offset by higher ad valorem taxes and the
addition of new production. Operating expenses per equivalent unit decreased 23%
to $.71 per Mcfe in the first quarter of 2002 from $.94 per Mcfe in the same
period in 2001 primarily as a result of lower severance taxes offset by higher
ad valorem taxes.
Depreciation, depletion and amortization (DD&A) expense for the three months
ended March 31, 2002 increased 21% to $1,970,000 from $1,630,000 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 three
months ended March 31, 2002 increased 5% to $916,000 from $870,000 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 $140,000 for the three months ended March 31, 2002
from $1,916,000 for the same period in 2001.
Interest income for the three months ended March 31, 2002 decreased to $20,000
from $121,000 in the first quarter of 2001 primarily as a result of lower
interest rates during the first quarter of 2002. Capitalized interest decreased
to $768,000 in the first quarter of 2002 from $802,000 in the first quarter of
2001 primarily due to lower interest during the first quarter of 2002.
Income before income taxes for the three months ended March 31, 2002 decreased
to $285,000 from $5,380,000 in the same period in 2001. Net income for the three
months ended March 31, 2002 decreased to $144,000 from $3,464,000 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
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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 2002 sale of shares of Series B Convertible
Participating Preferred Stock and Warrants, the 1998 sale of shares of Series A
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, 2001 and 2002 drilling program in return for participation in certain
wells.
Cash flows provided by operations (after changes in working capital) were
$4,809,000 and $2,504,000 for the three months ended March 31, 2001 and 2002,
respectively. The decrease in cash flows provided by operations in 2002 as
compared to 2001 was due primarily to additional revenue as a result of higher
oil and natural gas prices during the first quarter 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 $5.8 million for the three months ended March 31,
2002, which included $926,000 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 4 gross wells (1.9 net) during the three months
ended March 31, 2002. All of the 39 gross wells (16 net) drilled by CCBM are
awaiting evaluation before a determination can be made as to their success.
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%. 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.
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
Company may also request borrowing base redeterminations in addition to the
required semiannual reviews at the Company's cost.
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, 2001 and March 31, 2002,
outstanding revolving credit loans totaled $7,166,000 and $6,626,000,
respectively, with an additional $620,000 and zero, 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,
2001 and March 31, 2002. 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, 2001 and March 31, 2002, the
Company had no Guidance Line letters of credit outstanding.
The Company is seeking to refinance the Company Credit Facility and has entered
into a commitment letter with a bank for a replacement facility. The
commitment letter contemplates a new credit facility with an increased
borrowing base and extended maturity as compared to the current Company Credit
Facility. The commitment letter is subject to several conditions and in any
event there can be no assurance as to the final terms of, or whether the
Company will enter into, any new credit facility.
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On June 29, 2001, CCBM, Inc. a wholly owned subsidiary of the Company ("CCBM"),
issued a non-recourse promissory note payable in the amount of $7,500,000 to RMG
as consideration for certain interest in oil and gas leases held by RMG in
Wyoming and Montana. The RMG note is payable in 41-monthly principal payments of
$125,000 plus interest at 8% per annum commencing July 31, 2001 with the balance
due December 31, 2004. The RMG note is secured solely by CCBM's interests in the
oil and gas leases in Wyoming and Montana.
In December 2001, the Company entered into a capital lease agreement secured by
certain production equipment in the amount of $243,369. The lease is payable in
one payment of $11,323 and 35 monthly payments of $7,549 including interest at
8.6% per annum. The Company has the option to acquire the equipment at the
conclusion of the lease for $1.
In December 1999, the Company consummated the sale of $22 million principal
amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") to an
investor group led by CB Capital Investors, L.P. (now JPMorgan Partners) 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 $2,884,435 for such
interest as of December 31, 2001 and March 31, 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 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
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 Corporation 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 Company expects 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 approximately $5,800,000 net proceeds of this financing are expected to be
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.
The financial statements at March 31, 2002 reflect an accrual for a dividend of
683.88 shares of Series B Preferred Stock. 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.
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The Series B Preferred Stock is required to be redeemed by the Company at any
time after the third anniversary of the initial issuance of the Series B
Preferred Stock (the "Issue Date") upon request from any holder at a price per
share equal to Purchase Price/Dividend Preference (as defined below). The
Company may redeem the Series B Preferred Stock after the third anniversary of
the Issue Date, at a price per share equal to the Purchase Price/Dividend
Preference and, prior to that time, at varying preferences to the Purchase
Price/Dividend Purchase. "Purchase Price/Dividend Preference" is defined to
mean, generally, $100 plus all cumulative and accrued dividends on such share of
Series B Preferred Stock.
In the event of any dissolution, liquidation or winding up or certain mergers or
sales or other disposition by the Company of all or substantially all of its
assets (a "Liquidation"), the holder of each share of Series B Preferred Stock
then outstanding will be entitled to be paid out of the assets of the Company
available for distribution to its shareholders, the greater of the following
amounts per share of Series B Preferred Stock: (i) $100 in cash plus all
cumulative and accrued dividends and (ii) in certain circumstances, the
"as-converted" liquidation distribution, if any, payable in such Liquidation
with respect to each share of Common Stock.
Upon the occurrence of certain events constituting a "Change of Control" (as
defined in the Statement of Resolutions), the Company is required to make a
offer to each holder of Series B Preferred Stock to repurchase all of such
holder's Series B Preferred Stock at an offer price per share of Series B
Preferred Stock in cash equal to 105% of the Change of Control Purchase Price,
which is generally defined to mean $100 plus all cumulative and accrued
dividends.
The 2002 Warrants have a five-year term and entitle the holders to purchase up
to 252,632 shares of Carrizo's Common Stock at a price of $5.94 per share,
subject to adjustment, and are exercisable at any time after issuance. For
accounting purposes, the 2002 Warrants are valued at $0.06 per 2002 Warrant.
EFFECTS OF INFLATION AND CHANGES IN PRICE
The Company's results of operations and cash flows are affected by changing oil
and gas prices. If the price of oil and gas increases (decreases), there could
be a corresponding increase (decrease) in the operating cost that the Company is
required to bear for operations, as well as an increase (decrease) in revenues.
Inflation has had a minimal effect on the Company.
CRITICAL ACCOUNTING POLICIES
Oil and Natural Gas Properties
Investments in oil and natural gas properties are accounted for using the
full-cost method of accounting. All costs directly associated with the
acquisition, exploration and development of oil and natural gas properties are
capitalized. Such costs include lease acquisitions, seismic surveys, and
drilling and completion equipment. The Company proportionally consolidates its
interests in oil and gas properties. Additionally, the Company capitalized
compensation costs for employees working directly on exploration activities of
$276,000 and $214,000 for the three months ended March 31, 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 three months ended March 31, 2001 and 2002, was $1.10 and $1.35,
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 ended March 31, 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
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approximately $700,000. Because of the volatility of oil and gas prices, no
assurance can be given that the Company will not experience a ceiling test
writedown in future periods.
Depreciation of other property and equipment is provided using the straight-line
method based on estimated useful lives ranging from five to 10 years.
Stock-Based Compensation
The Company accounts for employee stock-based compensation using the intrinsic
value method prescribed by Accounting Principles Board (APB) Opinion No. 25,
"Accounting for Stock Issued to Employees" and related interpretations. Under
this method, the Company records no compensation expense for stock options
granted when the exercise price of those options is equal to or greater than the
market price of the Company's common stock on the date of grant. Repriced
options are accounted for as compensatory options using variable accounting
treatment. Under variable plan accounting, compensation expense is adjusted for
increases or decreases in the fair market value of the Company's common stock.
Variable plan accounting is applied to the repriced options until the options
are exercised, forfeited, or expired unexercised.
Derivative Instruments and Hedging Activities
In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative
Instruments and Hedging Activities". This statement, as amended by SFAS No. 137
and SFAS No. 138, establishes standards of accounting for and disclosures of
derivative instruments and hedging activities. This statement requires all
derivative instruments to be carried on the balance sheet at fair value with
changes in a derivative instrument's fair value recognized currently in earnings
unless specific hedge accounting criteria are met. SFAS No. 133 was effective
for the Company beginning January 1, 2001 and was adopted by the Company on that
date. In accordance with the current transition provisions of SFAS No. 133, the
Company recorded a cumulative effect transition adjustment of $2.0 million (net
of related tax expense of $1.1 million) in accumulated other comprehensive
income to recognize the fair value of its derivatives designated as cash-flow
hedging instruments at the date of adoption.
Upon entering into a derivative contract, the Company designates the derivative
instruments as a hedge of the variability of cash flow to be received (cash flow
hedge). Changes in the fair value of a cash flow hedge are recorded in other
comprehensive income to the extent that the derivative is effective in
offsetting changes in the fair value of the hedged item. Any ineffectiveness in
the relationship between the cash flow hedge and the hedged item is recognized
currently in income. Gains and losses accumulated in other comprehensive income
associated with the cash flow hedge are recognized in earnings as oil and gas
revenues when the forecasted transaction occurs. All of the Company's derivative
instruments at January 1, 2001 and December 31, 2001 were designated and
effective as cash flow hedges except for its positions with an affiliate of
Enron Corp. discussed in Note 12 to the Consolidated Financial Statements.
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.
-16-
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.
-17
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
March 31, 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 February 2002 the Company consummated the sale of Series B Preferred
Stock and the 2002 Warrants. See Part II, Item 7 of the Company's annual report
on Form 10-K for the year ended December 31, 2001, "Management's Discussion and
Analysis of Financial Conditions and Results of Operations - Financing
Arrangements" in this report and "Certain Transactions" in the Company's proxy
statement for the 2002 annual meeting.
In December 2001, the Company issued 2,750 shares of Common Stock to
Heartland Resources, Inc. for previous assignments of mineral leases. In
January, 2002, the Company issued 76,472 shares of Common Stock to several
individuals as part of the purchase of an interest in certain oil and gas
properties. Each of the sales 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 offering.
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, use of offering proceeds, outcome and effects
of litigation, recovery of well costs in litigation, expected production or
-18-
reserves, increases in reserves, acreage working capital requirements, hedging
activities, the ability of expected sources of liquidity to implement its
business strategy, and any other statements regarding future operations,
financial results, business plans and cash needs and other statements that are
not historical facts are forward looking statements. When used in this document,
the words "anticipate," "estimate," "expect," "may," "project," "believe" and
similar expression are intended to be among the statements that identify forward
looking statements. Such statements involve risks and uncertainties, including,
but not limited to, those relating to the Company's dependence on its
exploratory drilling activities, the volatility of oil and natural gas prices,
the need to replace reserves depleted by production, operating risks of oil and
natural gas operations, the Company's dependence on its key personnel, factors
that affect the Company's ability to manage its growth and achieve its business
strategy, risks relating to, limited operating history, technological changes,
significant capital requirements of the Company, the potential impact of
government regulations, litigation, competition, the uncertainty of reserve
information and future net revenue estimates, property acquisition risks,
availability of equipment, weather and other factors detailed in the Company's
Annual Report on Form 10-K for the year ended December 31, 2001 and other
filings with the Securities and Exchange Commission. Should one or more of these
risks or uncertainties materialize, or should underlying assumptions prove
incorrect, actual outcomes may vary materially from those indicated.
Item 6 - Exhibits and Reports on Form 8-K
Exhibits
<Table>
<Caption>
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).
</Table>
+ Incorporated herein by reference as indicated.
Reports on Form 8-K
On February 27, 2002, the Company filed a Current Report on Form
8-K to disclose the closing of the sale of convertible participating
Series B Preferred Stock and 2002 Warrants.
On April 12, 2002, the Company filed a Current Report on Form 8-K
to disclose the change in the Company's independent public accountants.
-19-
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: May 10, 2002 By: /s/S. P. Johnson, IV
--------------------------------------------
President and Chief Executive Officer
(Principal Executive Officer)
Date: May 10, 2002 By: /s/Frank A. Wojtek
--------------------------------------------
Chief Financial Officer
(Principal Financial and Accounting Officer)
-20-