SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2004
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[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ________ to _________
Commission File Number 000-22915.
CARRIZO OIL & GAS, INC.
(Exact name of registrant as specified in its charter)
Texas 76-0415919
----- ----------
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
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 [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act).
YES [ ] NO [X]
The number of shares outstanding of the registrant's common stock, par value
$0.01 per share, as of August 6, 2004, the latest practicable date, was
21,900,927.
CARRIZO OIL & GAS, INC.
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED June 30, 2004
INDEX
PART I. FINANCIAL INFORMATION PAGE
Item 1. Consolidated Balance Sheets
- As of December 31, 2003 and June 30, 2004 2
Consolidated Statements of Income
- For the three and six month periods ended June 30,
2003 and 2004 3
Consolidated Statements of Cash Flows
- For the six-month periods ended June 30, 2003 and
2004 4
Notes to Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 14
Item 3. Quantitative and Qualitative Disclosure About
Market Risk 27
Item 4. Controls and Procedures 28
PART II. OTHER INFORMATION
Items 1-6. 29
SIGNATURES 32
CARRIZO OIL & GAS, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
ASSETS December 31, June 30,
------------ ------------
2003 2004
------------ ------------
(In thousands)
CURRENT ASSETS:
Cash and cash equivalents $ 3,322 $ 2,999
Accounts receivable, trade (net of allowance for doubtful accounts of
none at December 31, 2003 and June 30, 2004, respectively) 8,970 8,270
Advances to operators 1,877 3,776
Deposits 56 156
Other current assets 100 277
------------ ------------
Total current assets 14,325 15,478
PROPERTY AND EQUIPMENT, net (full-cost method of
accounting for oil and natural gas properties) 135,273 168,135
Investment in Pinnacle Gas Resources, Inc. 6,637 6,028
Deferred financing costs 479 963
Other assets 89 64
------------ ------------
$ 156,803 $ 190,668
============ ============
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade $ 19,515 $ 17,103
Accrued liabilities 1,057 4,379
Advances for joint operations 3,430 4,429
Current maturities of long-term debt 1,037 433
Current maturities of seismic obligation payable 1,103 -
------------ ------------
Total current liabilities 26,142 26,344
LONG-TERM DEBT 34,113 36,851
ASSET RETIREMENT OBLIGATION 883 998
DEFERRED INCOME TAXES 12,479 15,131
COMMITMENTS AND CONTINGENCIES (Note 7)
CONVERTIBLE PARTICIPATING PREFERRED STOCK (10,000,000 shares
of preferred stock authorized, of which 150,000 are shares designated as
convertible participating shares, with 71,987 and zero convertible participating
shares issued and outstanding at December 31, 2003 and June 30, 2004,
respectively) (Note 8) 7,114 -
SHAREHOLDERS' EQUITY:
Warrants (3,262,821 and 334,210 outstanding at December 31,
2003 and June 30, 2004, respectively) 780 80
Common stock, par value $.01 (40,000,000 shares authorized with 14,591,348 and
21,897,297 issued and outstanding at December 31, 2003 and
June 30, 2004, respectively) 146 219
Additional paid in capital 65,103 97,359
Retained earnings 10,229 14,200
Accumulated other comprehensive income (186) (514)
------------ ------------
76,072 111,344
------------ ------------
$ 156,803 $ 190,668
============ ============
The accompanying notes are an integral part of these
consolidated financial statements.
2
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
For the Three For the Six
Months Ended Months Ended
June 30, June 30,
----------------------- -----------------------
2003 2004 2003 2004
---------- ---------- ---------- ----------
(In thousands except per share amounts)
OIL AND NATURAL GAS REVENUES $ 8,828 $ 11,959 $ 19,492 $ 22,833
COSTS AND EXPENSES:
Oil and natural gas operating expenses
(exclusive of depreciation shown separately below) 1,763 2,046 3,483 3,723
Depreciation, depletion and amortization 2,605 3,607 5,641 6,853
General and administrative 1,267 1,647 2,650 3,779
Accretion expense related to asset retirement obligations 10 6 18 13
Stock option compensation 33 746 23 756
---------- ---------- ---------- ----------
Total costs and expenses 5,678 8,052 11,815 15,124
---------- ---------- ---------- ----------
OPERATING INCOME 3,150 3,907 7,677 7,709
OTHER INCOME AND EXPENSES:
Other income and expenses (82) (348) 18 (583)
Interest income 22 10 40 23
Interest expense (118) (235) (316) (330)
Interest expense, related parties (591) (464) (1,174) (1,079)
Capitalized interest 704 656 1,479 1,323
---------- ---------- ---------- ----------
INCOME BEFORE INCOME TAXES 3,085 3,526 7,724 7,063
INCOME TAXES (Note 6) 1,125 1,388 2,794 2,742
---------- ---------- ---------- ----------
NET INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE 1,960 2,138 4,930 4321
DIVIDENDS AND ACCRETION ON PREFERRED STOCK 181 153 362 350
---------- ---------- ---------- ----------
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS
BEFORE CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE 1,779 1,985 4,568 3,971
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE - - 128 -
---------- ---------- ---------- ----------
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS $ 1,779 $ 1,985 $ 4,440 $ 3,971
========== ========== ========== ==========
BASIC EARNINGS PER COMMON SHARE BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 0.13 $ 0.10 $ 0.32 $ 0.22
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE NET OF INCOME TAXES - - (0.01) -
---------- ---------- ---------- ----------
BASIC EARNINGS PER COMMON SHARE $ 0.13 $ 0.10 $ 0.31 $ 0.22
========== ========== ========== ==========
DILUTED EARNINGS PER COMMON SHARE BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 0.11 $ 0.10 $ 0.28 $ 0.21
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE NET OF INCOME TAXES - - (0.01) -
---------- ---------- ---------- ----------
DILUTED EARNINGS PER COMMON SHARE $ 0.11 $ 0.10 $ 0.27 $ 0.21
========== ========== ========== ==========
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 Six
Months Ended
June 30,
-----------------------------
2003 2004
------------ ------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income before cumulative effect of change in accounting principle $ 4,930 $ 4,321
Adjustment to reconcile net income to net
cash provided by operating activities-
Depreciation, depletion and amortization 5,641 6,853
Discount accretion 60 134
Ineffective derivative instruments (91) -
Interest payable in kind 704 743
Stock option compensation (benefit) 23 756
Equity in loss of Pinnacle Gas Resources, Inc. - 609
Deferred income taxes 2,704 2,652
Changes in assets and liabilities-
Accounts receivable (350) 700
Other assets 336 (662)
Accounts payable 776 (275)
Other liabilities 324 1,503
------------ ------------
Net cash provided by operating activities 15,057 17,334
------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (13,984) (39,888)
Change in capital expenditure accrual 2,329 (1,611)
Advances to operators (185) (1,899)
Advances for joint operations 123 999
------------ ------------
Net cash used in investing activities (11,717) (42,399)
------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from the sale of common stock 115 24,198
Advances under the Borrowing Base Facility - 9,000
Debt repayments (4,138) (8,456)
------------ ------------
Net cash provided by (used in) financing activities (4,023) 24,742
------------ ------------
NET DECREASE IN CASH AND CASH EQUIVALENTS (683) (323)
CASH AND CASH EQUIVALENTS, beginning of period 4,743 3,322
------------ ------------
CASH AND CASH EQUIVALENTS, end of period $ 4,060 $ 2,999
============ ============
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest (net of amounts capitalized) $ - $ 86
============ ============
Cash paid for income taxes $ - $ -
============ ============
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. 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, 2003.
2. MAJOR CUSTOMERS
The Company sold oil and natural gas production representing more than 10% of
its oil and natural gas revenues as follows:
For the Three Months For the Six Months
Ended June 30, Ended June 30,
-------------------- --------------------
2003 2004 2003 2004
--------- --------- --------- ---------
Cokinos Natural Gas Company 11% 23% 14% 24%
Gulfmark Energy, Inc. 15% - 19% -
WMJ Investments Corp. 12% 12% - 15%
Texon L.P. - 19% - 19%
3. EARNINGS PER COMMON SHARE:
Supplemental earnings per share information is provided below:
For the Three Months Ended June 30,
---------------------------------------------------------------------------
(In thousands except share and per share amounts)
Income Shares Per-Share Amount
----------------------- ----------------------- -----------------------
2003 2004 2003 2004 2003 2004
---------- ---------- ---------- ---------- ---------- ----------
Basic Earnings per Common Share
Net income available to common shareholders $ 1,779 $ 1,985 14,211,173 19,213,010 $ 0.13 $ 0.10
========== ==========
Dilutive effect of Stock Options, Warrants and
Preferred Stock conversions - - 2,384,642 1,080,091
---------- ---------- ---------- ----------
Diluted Earnings per Share
Net income available to common shareholders
plus assumed conversions before cumulative
effect of change in accounting principle $ 1,779 $ 1,985 16,595,815 20,293,101 $ 0.11 $ 0.10
========== ========== ========== ========== ========== ==========
5
For the Six Months Ended June 30,
---------------------------------------------------------------------------
(In thousands except share and per share amounts)
Income Shares Per-Share Amount
----------------------- ----------------------- -----------------------
2003 2004 2003 2004 2003 2004
---------- ---------- ---------- ---------- ---------- ----------
Basic Earnings per Common Share
Net income available to common shareholders
before cumulative effect of change
in accounting principle $ 4,568 $ 3,971 14,204,690 17,913,220 $ 0.32 $ 0.22
========== ==========
Dilutive effect of Stock Options, Warrants and
Preferred Stock conversions - - 2,260,300 1,001,630
---------- ---------- ---------- ----------
Diluted Earnings per Share
Net income available to common shareholders
plus assumed conversions before cumulative
effect of change in accounting principle $ 4,568 $ 3,971 16,464,990 18,914,850 $ 0.28 $ 0.21
========== ========== ========== ========== ========== ==========
For the Three Six Ended June 30,
---------------------------------------------------------------------------
(In thousands except share and per share amounts)
Income Shares Per-Share Amount
----------------------- ----------------------- -----------------------
2003 2004 2003 2004 2003 2004
---------- ---------- ---------- ---------- ---------- ----------
Cumulative effect of change
in accounting principle net of income taxes
Basic Earnings per Common Share
Net loss available to common shareholders $ (128) $ - 14,204,690 17,913,220 $ (0.01) $ -
========== ==========
Dilutive effect of Stock Options, Warrants and
Preferred Stock conversions - - 2,260,300 1,001,630
---------- ---------- ---------- ----------
Diluted Earnings per Share
Net income available to common shareholders
plus assumed conversions $ (128) $ - 16,464,990 18,914,850 $ (0.01) $ -
========== ========== ========== ========== ========== ==========
For the Six Months Ended June 30,
---------------------------------------------------------------------------
(In thousands except share and per share amounts)
Income Shares Per-Share Amount
----------------------- ----------------------- -----------------------
2003 2004 2003 2004 2003 2004
---------- ---------- ---------- ---------- ---------- ----------
Basic Earnings per Common Share
Net income available to common shareholders $ 4,440 $ 3,971 14,204,690 17,913,220 $ 0.31 $ 0.22
========== ==========
Dilutive effect of Stock Options, Warrants and
Preferred Stock conversions - - 2,260,300 1,001,630
---------- ---------- ---------- ----------
Diluted Earnings per Share
Net income available to common shareholders
plus assumed conversions $ 4,440 $ 3,971 16,464,990 18,914,850 $ 0.27 $ 0.21
========== ========== ========== ========== ========== ==========
Basic earnings per common share is based on the weighted average number of
shares of common stock outstanding during the periods. Diluted earnings per
common share is based on the weighted average number of common shares and all
dilutive potential common shares outstanding during the periods. The Company had
outstanding 146,500 and 35,500 stock options and 252,632 and zero warrants,
respectively, during the three months ended June 30, 2003 and 2004,
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 had outstanding 156,500 and
50,500 stock options and 252,632 and zero warrants during the six months ended
June 30, 2003 and 2004, respectively, which were antidilutive because the
exercise price of these instruments exceeded the underlying market value of the
options and warrants. At June 30, 2003 and 2004, the Company also had 1,202,791
and zero shares, respectively, based on the assumed conversion of the Series B
Convertible Participating Preferred Stock, that were antidilutive and were not
included in the calculation.
6
4. LONG-TERM DEBT:
At December 31, 2003 and June 30, 2004, long-term debt consisted of the
following:
December 31, June 30,
2003 2004
------------ ------------
Hibernia Facility $ 7,000 $ 9,000
Senior subordinated notes - 27,778
Senior subordinated notes, related parties 26,992 -
Capital lease obligations 295 206
Non-recourse note payable to
Rocky Mountain Gas, Inc. 863 300
------------ ------------
35,150 37,284
Less: current maturities (1,037) (433)
------------ ------------
$ 34,113 $ 36,851
============ ============
On May 24, 2002, the Company entered into a credit agreement with Hibernia
National Bank (the "Hibernia Facility") which matures on January 31, 2006, and
repaid its existing facility with Compass Bank (the "Compass Facility"). The
Hibernia Facility provides a revolving line of credit of up to $30.0 million. It
is secured by substantially all of the Company's assets and is guaranteed by the
Company's subsidiary.
The borrowing base will be determined by Hibernia National Bank at least
semi-annually on each October 31 and April 30. The initial borrowing base was
$12.0 million. Each party to the credit agreement can request one unscheduled
borrowing base determination subsequent to each scheduled determination. The
borrowing base will at all times equal the borrowing base most recently
determined by Hibernia National Bank, less quarterly borrowing base reductions
required subsequent to such determination. Hibernia National Bank will reset the
borrowing base amount at each scheduled and each unscheduled borrowing base
determination date. The initial quarterly borrowing base reduction, which
commenced on June 30, 2002, was $1.3 million. The quarterly borrowing base
reduction effective July 31, 2004 was $2.5 million.
On December 12, 2002, the Company entered into an Amended and Restated Credit
Agreement with Hibernia National Bank that provided additional availability
under the Hibernia Facility in the amount of $2.5 million which is structured as
an additional "Facility B" under the Hibernia Facility. The Facility B bore
interest at LIBOR plus 3.375%, was secured by certain leases and working
interests in oil and natural gas wells and matured on April 30, 2003. As such,
the total borrowing base under the Hibernia Facility as of December 31, 2003 and
June 30, 2004 was $19.0 million and $26.0 million, respectively, of which $7.0
and $9.0 million, respectively, was drawn on the Hibernia Facility.
If the principal balance of the Hibernia Facility ever exceeds the borrowing
base as reduced by the quarterly borrowing base reduction (as described above),
the principal balance in excess of such reduced borrowing base will be due as of
the date of such reduction. Otherwise, any unpaid principal or interest will be
due at maturity.
If the principal balance of the Hibernia Facility ever exceeds any re-determined
borrowing base, the Company has the option within thirty days to (individually
or in combination): (i) make a lump sum payment curing the deficiency; (ii)
pledge additional collateral sufficient in Hibernia National Bank's opinion to
increase the borrowing base and cure the deficiency; or (iii) begin making equal
monthly principal payments that will cure the deficiency within the ensuing
six-month period. Such payments are in addition to any payments that may come
due as a result of the quarterly borrowing base reductions.
For each tranche of principal borrowed under the revolving line of credit, the
interest rate will be, at the Company's option: (i) the Eurodollar Rate, plus an
applicable margin equal to 2.375% if the amount borrowed is greater than or
equal to 90% of the borrowing base, 2.0% if the amount borrowed is less than
90%, but greater than or equal to 50% of the borrowing base, or 1.625% if the
amount borrowed is less than 50% of the borrowing base; or (ii) the Base Rate,
plus an applicable margin of 0.375% if the amount borrowed is greater than or
equal to 90% of the borrowing base. Interest on Eurodollar Loans is payable on
either the last day of each Eurodollar option period or monthly, whichever is
earlier. Interest on Base Rate Loans is payable monthly.
The Company is subject to certain covenants under the terms of the Hibernia
Facility, including, but not limited to the maintenance of the following
financial covenants: (i) a minimum current ratio of 1.0 to 1.0 (including
availability under the borrowing base), (ii) a
7
minimum quarterly debt services coverage of 1.25 times, and (iii) a minimum
shareholders equity equal to $56.0 million, plus 100% of all subsequent common
and preferred equity contributed by shareholders, plus 50% of all positive
earnings occurring subsequent to such quarter end, all ratios as more
particularly discussed in the credit facility. The Hibernia Facility also places
restrictions on additional indebtedness, dividends to non-preferred
stockholders, liens, investments, mergers, acquisitions, asset dispositions,
asset pledges and mortgages, change of control, repurchase or redemption for
cash of the Company's common or preferred stock, speculative commodity
transactions, and other matters.
At December 31, 2003 and June 30, 2004, amounts outstanding under the Hibernia
Facility totaled $7.0 million and $9.0 million, respectively, with an additional
$12.0 million and $17.0 million, respectively, available for future borrowings.
At December 31, 2003 and June 30, 2004, one letter of credit was issued and
outstanding under the Hibernia Facility in the amount of $0.2 million.
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 $7.5 million to
RMG as consideration for certain interests in oil and natural gas leases held by
RMG in Wyoming and Montana. The RMG note is payable in 41-monthly principal
payments of $0.1 million 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 natural gas leases in Wyoming and Montana. In
connection with the Company's investment in Pinnacle Gas Resources, Inc., the
Company received a reduction in the principal amount of the RMG note of
approximately $1.5 million and relinquished the right to certain revenues
related to the properties contributed to Pinnacle. During the second quarter of
2004, CCBM, Inc., relinquished a portion of its interests in certain oil and
natural gas leases and reduced the principal due on the note by $0.3 million.
In December 2001, the Company entered into a capital lease agreement secured by
certain production equipment in the amount of $0.2 million. The lease is payable
in one payment of $11,323 and 35 monthly payments of $7,549 including interest
at 8.6% per annum. In October 2002, the Company entered into a capital lease
agreement secured by certain production equipment in the amount of $0.1 million.
The lease is payable in 36 monthly payments of $3,462 including interest at 6.4%
per annum. In May 2003, the Company entered into a capital lease agreement
secured by certain production equipment in the amount of $0.1 million. The lease
is payable in 36 monthly payments of $3,030 including interest at 5.5% per
annum. In August 2003, the Company entered into a capital lease agreement
secured by certain production equipment in the amount of $0.1 million. The lease
is payable in 36 monthly payments of $2,179 including interest at 6.0% per
annum. The Company has the option to acquire the equipment at the conclusion of
the lease for $1 under all of these leases. DD&A on the capital leases for the
three months ended June 30, 2003 and 2004 amounted to $11,000 and $12,000,
respectively. DD&A on the capital leases for the six months ended June 30, 2003
and 2004 amounted to $20,000 and $24,000, respectively, and accumulated DD&A on
the leased equipment at December 31, 2003 and June 30, 2004 amounted to $76,000
and $100,000, respectively.
In December 1999, the Company consummated the sale of $22.0 million principal
amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") and
$8.0 million of common stock and Warrants. The Company sold $17.6 million, $2.2
million, $0.8 million, $0.8 million and $0.8 million principal amount of
Subordinated Notes; 2,909,092, 363,636, 121,212, 121,212 and 121,212 shares of
the Company's common stock and 2,208,152, 276,019, 92,006, 92,006 and 92,006
Warrants to CB Capital Investors, L.P. (now known as JPMorgan Partners (23A
SBIC), L.P.), Mellon Ventures, L.P., Paul B. Loyd, Jr., Steven A. Webster and
Douglas A.P. Hamilton, respectively. The Subordinated Notes were sold at a
discount of $0.7 million, which is being amortized over the life of the notes.
Interest payments are due quarterly commencing on March 31, 2000. The Company
may elect, until December 2004, to increase the amount of the Subordinated Notes
for 60% of the interest which would otherwise be payable in cash. As of December
31, 2003 and June 30, 2004, the outstanding balance of the Subordinated Notes
had been increased by $5.3 million and $6.0 million respectively, for such
interest paid in kind. During the six months ended June 30, 2004, Mellon
Ventures, L.P., JPMorgan Partners (23A SBIC), Steven A. Webster and Douglas A.
P. Hamilton exercised warrants to purchase 276,019, 2,208,152, 92,006 and 92,006
shares of common stock, respectively, on a cashless exercise basis for a total
of 205,692, 1,684,949, 70,205 and 70,205 shares of common stock, respectively,
and Paul B. Loyd, Jr., exercised warrants to purchase 92,006 shares for a total
of 92,006 shares of common stock. As a result, no warrants to purchase shares
remain outstanding from the warrants originally issued in December 1999.
On June 7, 2004, an unaffiliated third party (the "Purchaser") purchased all the
outstanding Subordinated Notes from the original note holders. In exchange for a
$0.4 million amendment fee, certain terms and conditions of the Subordinated
Notes were amended, to provide for, among other things, (1) a one year extension
of the maturity to December 15, 2008, (2) a one year extension, through December
15, 2005, of the paid-in-kind ("PIK") interest option to pay-in-kind 60% of the
interest due each period by increasing the principal balance by a like amount
(the "PIK option"), (3) an additional one year option to extend the PIK option
through December 15, 2006 at an annual interest rate on the deferred amount of
10% and the payment of a one-time fee equal to 0.5% of the principal then
outstanding and (4) additional flexibility to obtain a separate project
financing facility in the future. The amendment fee will be amortized over the
remaining life of the Note.
8
The Company is subject to certain covenants under the terms of 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, (c) a limitation of its capital expenditures to an amount equal to the
Company's EBITDA for the immediately prior fiscal year (unless approved by the
Company's Board of Directors and a JPMorgan Partners, LLC appointed director)
and (d) a limitation on our Total Debt (as defined in the securities purchase
agreement) to 3.5 times EBITDA for any twelve month period.
At June 30, 2004, the Company was in compliance with all of its debt covenants.
5. INVESTMENT IN PINNACLE GAS RESOURCES, INC.
The Pinnacle Transaction
On June 23, 2003, pursuant to a Subscription and Contribution Agreement by and
among the Company and its wholly-owned subsidiary, CCBM, Inc. ("CCBM"), Rocky
Mountain Gas, Inc. ("RMG") and the Credit Suisse First Boston Private Equity
entities, named therein (the "CSFB Parties"), CCBM and RMG contributed their
respective interests, having a estimated fair value of approximately $7.5
million each, in (1) leases in the Clearmont, Kirby, Arvada and Bobcat project
areas and (2) oil and natural gas reserves in the Bobcat project area to a newly
formed entity, Pinnacle Gas Resources, Inc., a Delaware corporation
("Pinnacle"). In exchange for the contribution of these assets, CCBM and RMG
each received 37.5% of the common stock of Pinnacle ("Pinnacle Common Stock") as
of the closing date and options to purchase Pinnacle Common Stock ("Pinnacle
Stock Options"). CCBM no longer has a drilling obligation in connection with the
oil and natural gas leases contributed to Pinnacle.
Simultaneously with the contribution of these assets, the CSFB Parties
contributed approximately $17.6 million of cash to Pinnacle in return for the
Redeemable Preferred Stock of Pinnacle ("Pinnacle Preferred Stock"), 25% of the
Pinnacle Common Stock as of the closing date and warrants to purchase Pinnacle
Common Stock ("Pinnacle Warrants"). The CSFB Parties also agreed to contribute
additional cash, under certain circumstances, of up to approximately $11.8
million to Pinnacle to fund future drilling, development and acquisitions. The
CSFB Parties currently have greater than 50% of the voting power of the Pinnacle
capital stock through their ownership of Pinnacle Common Stock and Pinnacle
Preferred Stock.
Immediately following the contribution and funding, Pinnacle used approximately
$6.2 million of the proceeds from the funding to acquire an approximate 50%
working interest in existing leases and acreage prospective for coalbed methane
development in the Powder River Basin of Wyoming from Gastar Exploration, Ltd.
Pinnacle also agreed to fund up to $14.9 million of future drilling and
development costs on these properties on behalf of Gastar prior to December 31,
2005. The drilling and development work will be done under the terms of an
earn-in joint venture agreement between Pinnacle and Gastar. The majority of
these leases are part of, or adjacent to, the Bobcat project area. All of CCBM
and RMG's interests in the Bobcat project area, the only producing coalbed
methane property owned by CCBM prior to the transaction, were contributed to
Pinnacle.
Prior to and in connection with its contribution of assets to Pinnacle, CCBM
paid RMG approximately $1.8 million in cash as part of its outstanding purchase
obligation on the coalbed methane property interests CCBM previously acquired
from RMG. As of June 30, 2003, approximately $1.1 million remaining balance of
CCBM's obligation to RMG is scheduled to be paid in monthly installments of
approximately $52,805 through November 2004 and a balloon payment on December
31, 2004. As of June 30, 2004, the remaining balance on this obligation was
approximately $0.3 million. The RMG note is secured solely by CCBM's interests
in the remaining oil and natural gas leases in Wyoming and Montana. In
connection with the Company's investment in Pinnacle, the Company received a
reduction in the principal amount of the RMG note of approximately $1.5 million
and relinquished the right to receive certain revenues related to the properties
contributed to Pinnacle.
CCBM continues its coalbed methane business activities and, in addition to its
interest in Pinnacle, owns direct interests in acreage in coalbed methane
properties in the Castle Rock project area in Montana and the Oyster Ridge
project area in Wyoming, which were not contributed to Pinnacle. CCBM and RMG
will continue to conduct exploration and development activities on these
properties as well as pursue other potential acquisitions. Other than indirectly
through Pinnacle, CCBM currently has no proved reserves of, and is no longer
receiving revenue from, coalbed methane gas.
As of December 31, 2003, on a fully diluted basis, assuming that all parties
exercised their Pinnacle Warrants and Pinnacle Stock Options, the CSFB Parties,
CCBM and RMG would have ownership interests of approximately 46.2%, 26.9% and
26.9%, respectively. In March 2004, the CSFB Parties contributed additional
funds of $11.8 million into Pinnacle to continue funding the 2004 development
program which increased the CSFB Parties' ownership to 66.7% on a fully diluted
basis assuming CCBM and RMG each elect not to exercise their Pinnacle Stock
Options. Assuming that CCBM and RMG exercise their Pinnacle Stock Options,
9
the CSFB parties' ownership interest in Pinnacle would be 54.6% and CCBM and RMG
each would own 22.7% on a fully diluted basis.
For accounting purposes, the transaction was treated as a reclassification of a
portion of CCBM's investments in the contributed properties. The property
contribution made by CCBM to Pinnacle was intended to be treated as a
tax-deferred exchange as constituted by property transfers under section 351(a)
of the Internal Revenue Code of 1986, as amended.
The reclassification of investments in contributed properties resulting from the
transaction with Pinnacle are reflected in accordance with the full cost method
of accounting in the Company's balance sheet as of December 31, 2003 and June
30, 2004.
6. INCOME TAXES:
The Company provided deferred income taxes at the rate of 35%, which also
approximates its statutory rate, that amounted to $1.1 million and $1.3 million
for the three months ended June 30, 2003 and 2004, respectively and $2.7 million
and $2.7 million for the six months ended June 30, 2003 and 2004, respectively.
7. 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 of the Company.
The operations and financial position of the Company continue to be affected
from time to time in varying degrees by domestic and foreign political
developments as well as legislation and regulations pertaining to restrictions
on oil and natural gas production, imports and exports, natural gas regulation,
tax increases, environmental regulations and cancellation of contract rights.
Both the likelihood and overall effect of such occurrences on the Company vary
greatly and are not predictable.
8. CONVERTIBLE PARTICIPATING PREFERRED STOCK:
In February 2002, the Company consummated the sale of 60,000 shares of
Convertible Participating Series B Preferred Stock (the "Series B Preferred
Stock") and warrants to purchase 252,632 shares of common stock for an aggregate
purchase price of $6.0 million. The Company sold 40,000 and 20,000 shares of
Series B Preferred Stock and 168,422 and 84,210 warrants to Mellon Ventures,
Inc. and Steven A. Webster, respectively. The Series B Preferred Stock was
convertible into common stock by the investors at a conversion price of $5.70
per share, subject to adjustments, and was initially convertible into 1,052,632
shares of common stock. Dividends on the Series B Preferred Stock were payable
in either cash at a rate of 8% per annum or, at the Company's option, by payment
in kind of additional shares of the same series of preferred stock at a rate of
10% per annum. At December 31, 2003 and through the conversion dates specified
below, the outstanding balance of the Series B Preferred Stock has been
increased by $1.2 million (11,987 shares) and $1.5 million (15,133 shares),
respectively, for dividends paid in kind. The Series B Preferred Stock was
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
also participated in any dividends declared on the common stock. Holders of the
Series B Preferred Stock would have received a liquidation preference upon the
liquidation of, or certain mergers or sales of substantially all assets
involving, the Company. Such holders also had the option of receiving a change
of control repayment price upon certain deemed change of control transactions.
Mellon Ventures, Inc., converted all of its Series B Preferred Stock
(approximately 49,938 shares) into 876,099 shares of common stock on May 25,
2004. Steven A. Webster converted all of his Series B Preferred Stock
(approximately 25,195 shares) into 442,025 shares of common stock on June 30,
2004. As a result, no shares of Series B Preferred Stock remain outstanding. 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. During the six months ended June 30,
2004, Mellon Ventures, Inc. exercised all of its 168,422 warrants on a cashless
exercise basis for a total of 36,570 shares of common stock.
Net proceeds of this financing were approximately $5.8 million and were used
primarily to fund the Company's ongoing exploration and development program and
general corporate purposes.
9. SHAREHOLDER'S EQUITY:
In the first quarter of 2004, the Company completed the public offering of
6,485,000 shares of common stock at $7.00 per share. The offering included
3,655,500 newly issued shares offered by the Company and 2,829,500 shares
offered by certain existing
10
stockholders. The Company did not receive any proceeds from the shares sold by
the selling stockholders. The Company expects to use the net proceeds from this
offering to accelerate its drilling program and to retain larger interests in
portions of its drilling prospects that the Company otherwise would sell down or
for which the Company would seek joint partners and for general corporate
purposes. In the meantime, the Company used a portion of the net proceeds to
repay the $7 million outstanding principal amount under our revolving credit
facility and to complete a $8.2 million Barnett Shale acquisition on February
27, 2004.
The Company issued 55,334 and 7,305,949 shares of common stock during the six
months ended June 30, 2003 and 2004, respectively. The shares issued during the
six months ended June 30, 2003 were the result of the exercise of options
granted under the Company's Incentive Plan. The shares issued during the six
months ended June 30, 2004, consisted of 3,655,500 shares issued through the
secondary offering, 2,159,627 shares issued through the exercise of warrants,
1,318,124 shares issued through the conversion of Series B Preferred Stock and
the balance issued through the exercise of options granted under the Company's
Incentive Plan.
In June of 1997, the Company established the Incentive Plan of Carrizo Oil &
Gas, Inc. (the "Incentive Plan"). In October 1995, the FASB issued SFAS No. 123,
"Accounting for Stock-Based Compensation," which requires the Company to record
stock-based compensation at fair value. In December 2002, the FASB issued SFAS
No. 148, "Accounting for Stock Based Compensation - Transition and Disclosure."
The Company has adopted the disclosure requirements of SFAS No. 148 and has
elected to record employee compensation expense utilizing the intrinsic value
method permitted under Accounting Principles Board (APB) Opinion No. 25,
"Accounting for Stock Issued to Employees." The Company accounts for its
employees' stock-based compensation plan under APB Opinion No. 25 and its
related interpretations. Accordingly, any deferred compensation expense would be
recorded for stock options based on the excess of the market value of the common
stock on the date the options were granted over the aggregate exercise price of
the options. This deferred compensation would be amortized over the vesting
period of each option. Had compensation cost been determined consistent with
SFAS No. 123 "Accounting for Stock Based Compensation" for all options, the
Company's net income (loss) and earnings per share would have been as follows:
For the Three Months Ended
June 30,
--------------------------
2003 2004
----------- ------------
(In thousands except
per share amounts)
Net income available to common
shareholders, as reported $ 1,779 $ 1,985
Less: Total stock-based employee
compensation expense determined under
fair value method for all awards, net of
related tax effects (132) (141)
----------- ------------
Pro forma net income (loss) available
to common shareholders $ 1,647 $ 1,844
=========== ============
Net income per common share, as reported:
Basic $ 0.13 $ 0.10
Diluted 0.11 0.10
Pro Forma net income (loss) per common share, as if
value method had been applied to all awards:
Basic $ 0.12 $ 0.10
Diluted 0.10 0.09
11
For the Six Months Ended
June 30,
--------------------------
2003 2004
----------- ------------
(In thousands except
per share amounts)
Net income available to common
shareholders, as reported $ 4,440 $ 3,971
Less: Total stock-based employee
compensation expense determined under
fair value method for all awards, net of
related tax effects (264) (283)
----------- ------------
Pro forma net income (loss) available
to common shareholders $ 4,176 $ 3,688
=========== ============
Net income per common share, as reported:
Basic $ 0.31 $ 0.22
Diluted 0.27 0.21
Pro Forma net income (loss) per common share, as if
value method had been applied to all awards:
Basic $ 0.29 $ 0.21
Diluted 0.25 0.19
Diluted earnings per share amounts for the three months ended June 30, 2003 and
2004 are based upon 16,595,815 and 20,293,101 shares, respectively, that include
the dilutive effect of assumed stock option and warrant conversions of 2,384,642
and 1,080,091 shares, respectively. Diluted earnings per share amounts for the
six months ended June 30, 2003 and 2004 are based upon 16,464,990 and 18,914,850
shares, respectively, that include the dilutive effect of assumed stock option
and warrant conversion of 2,260,300 and 1,001,630 shares, respectively.
10. CHANGE IN ACCOUNTING PRINCIPLE:
In June 2001, the Financial Accounting Standards Board issued SFAS No. 143,
"Accounting for Asset Retirement Obligations." This Statement is effective for
fiscal years beginning after June 15, 2002, and the Company adopted the
Statement effective January 1, 2003. During the three months ended March 31,
2003, the Company recorded a cumulative effect of change in accounting principle
of $0.1 million, $0.4 million as proved properties and $0.5 million as a
liability for its plugging and abandonment expenses.
11. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY:
The Company's operations involve managing market risks related to changes in
commodity prices. Derivative financial instruments, specifically swaps, futures,
options and other contracts, are used to reduce and manage those risks. The
Company addresses market risk by selecting instruments whose value fluctuations
correlate strongly with the underlying commodity being hedged. The Company
enters into swaps, options, collars and other derivative contracts to hedge the
price risks associated with a portion of anticipated future oil and natural gas
production. While the use of hedging arrangements limits the downside risk of
adverse price movements, it may also limit future gains from favorable
movements. Under these agreements, payments are received or made based on the
differential between a fixed and a variable product price. These agreements are
settled in cash at expiration or exchanged for physical delivery contracts. The
Company enters into the majority of its hedging transactions with two
counterparties and a netting agreement is in place with those counterparties.
The Company does not obtain collateral to support the agreements but monitors
the financial viability of counterparties and believes its credit risk is
minimal on these transactions. In the event of nonperformance, the Company would
be exposed to price risk. The Company has some risk of accounting loss since the
price received for the product at the actual physical delivery point may differ
from the prevailing price at the delivery point required for settlement of the
hedging transaction.
As of December 31, 2003 and June 30, 2004, $0.2 million and $0.5 million, net of
tax of $0.1 million and $0.3 million, respectively, remained in accumulated
other comprehensive income related to the valuation of the Company's hedging
positions.
12
Total oil hedged under swaps and collars during the three months ended June 30,
2003 and 2004 were 63,300 Bbls and 27,300 Bbls, respectively. Total natural gas
hedged under swaps and collars during the three months ended June 30, 2003 and
2004 were 819,000 MMBtu and 1,001,000 MMBtu, respectively. Total oil hedged
under swaps and collars during the six months ended June 30, 2003 and 2004 were
126,300 Bbls and 54,300 Bbls, respectively. Total natural gas hedged under swaps
and collars during the six months ended June 30, 2003 and 2004 were 1,349,000
MMBtu and 1,727,000 MMBtu, respectively. The net losses realized by the Company
under such hedging arrangements were $0.4 and $0.5 million for the three months
ended June 30, 2003 and 2004, respectively, and are included in oil and natural
gas revenues. The net losses realized by the Company under such hedging
arrangements were $1.7 million and $0.4 million for six months ended June 30,
2003 and 2004, respectively, and are included in oil and natural gas revenues.
At June 30, 2003 and 2004 the Company had the following outstanding hedge
positions:
As of June 30, 2003
- --------------------------------------------------------------------------------------------------
Contract Volumes
---------------------------
Average Average Average
Quarter BBls MMbtu Fixed Price Floor Price Ceiling Price
- ---------------------- ------------ ------------ ------------ ------------ -------------
Third Quarter 2003 276,000 $ 4.70
Third Quarter 2003 552,000 $ 3.40 $ 5.25
Fourth Quarter 2003 552,000 3.40 5.25
Second Quarter 2004 273,000 4.00 5.20
Third Quarter 2004 276,000 4.00 5.20
Third Quarter 2004 93,000 4.00 5.20
As of June 30, 2004
- --------------------------------------------------------------------------------------------------
Contract Volumes
---------------------------
Average Average Average
Quarter BBls MMbtu Fixed Price Floor Price Ceiling Price
- ---------------------- ------------ ------------ ------------ ------------ -------------
Third Quarter 2004 27,600 $ 37.42
Third Quarter 2004 1,012,000 $ 4.52 $ 6.24
Fourth Quarter 2004 9,300 38.85
Fourth Quarter 2004 1,197,000 4.71 6.94
First Quarter 2005 810,000 5.09 8.00
13
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. You should read this in conjunction with the
discussion under "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and the audited financial statements included in our
Annual Report on Form 10-K for the year ended December 31, 2003 and the
unaudited financial statements included elsewhere herein.
General Overview
We 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, we began obtaining 3-D seismic data and optioning
to lease substantial acreage in 1995 and began drilling our 3-D based prospects
in 1996. In 2003, we drilled 39 gross wells (10.2 net), 35 gross wells (9.4 net)
of which were successful. During the six months ended June 30, 2004, we
participated in the drilling of 40 gross wells (14.7 net) in the Gulf Coast and
North Texas regions, 36 gross wells (12.1 net) of which were successful. 33 of
these successful wells have been completed and three are in the process of being
completed. We have budgeted to drill up to 44 gross wells (15.3 net) in the Gulf
Coast region in 2004; 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, our cash flow, success of drilling
programs, weather delays and other factors. If we drill the number of wells we
have budgeted for 2004, depreciation, depletion and amortization, oil and
natural gas operating expenses and production are expected to increase over
levels incurred in 2003.
Since our initial public offering, we have primarily grown through the internal
development of properties within our exploration project areas, although we
consider acquisitions from time to time and may in the future complete
acquisitions that we find attractive. In February 2004, we acquired assets in a
Barnett Shale play in North Texas for approximately $8.2 million.
2004 Public Offering
In the first quarter of 2004, we completed the public offering of 6,485,000
shares of our common stock at $7.00 per share. The offering included 3,655,500
newly issued shares offered by us and 2,829,500 shares offered by certain
existing stockholders. We did not receive any proceeds from the shares offered
by the selling stockholders. We expect to use our estimated net proceeds of
approximately $23.4 million from this offering to accelerate our drilling
program and to retain larger interests in portions of our drilling prospects
that we otherwise would sell down or for which we would seek joint partners and
for general corporate purposes. In the meantime, we used a portion of the net
proceeds to repay the $7 million outstanding principal amount under our
revolving credit facility and to purchase the $8.2 million Barnett Shale
acquisition mentioned below.
Barnett Shale Activity
On February 27, 2004, we closed an $8.2 million transaction with a private
company to acquire working interests and acreage in certain oil and natural gas
wells located in the Newark East Field in Denton County, Texas in the Barnett
Shale trend. This acquisition includes non-operated working interests in
properties ranging from 12.5% to 45% over 3,800 gross acres, or an average
working interest of 39%. The Barnett Shale acquisition included 21 existing
gross wells (6.7 net) and interests in approximately 1,500 net acres, which we
expect to provide another 31 gross drill sites: 13 of which will target proved
undeveloped reserves and 18 of which will be exploratory. Current net production
from the acquired properties in July 2004 was approximately 1.5 Mmcfe/d and net
proved reserves are internally estimated at 12.2 Bcfe.
Initially, we financed the Barnett Shale acquisition with our available cash on
hand. We are exploring a number of financing alternatives to refinance a
majority of the acquisition and to fund a majority of our 2004 and 2005 capital
expenditure program for the Barnett Shale play. We may not be able to obtain
such financing on terms that are acceptable to us, or at all.
In mid-2003, we became active in the Barnett Shale play located in Tarrant and
Parker counties in Northeast Texas. Our activity accelerated as a result of the
acquisition described above.
14
In the Barnett Shale play, we drilled six gross wells in 2003 and 19 gross wells
(7.9 net) during the six months ended June 30, 2004, all of which were
successful. We plan to drill between 30 and 45 gross wells in this region in
2004, assuming that we obtain the additional financing mentioned above.
Pinnacle Gas Resources, Inc.
During the second quarter of 2001, we acquired interests in natural gas and oil
leases in Wyoming and Montana in areas prospective for coalbed methane and
subsequently began to drill wells on those leases. During the second quarter of
2003, we contributed our interests in certain of these leases to a newly formed
company, Pinnacle Gas Resources, Inc. ("Pinnacle"). In exchange for this
contribution, we received 37.5% of the common stock of Pinnacle and options to
purchase additional Pinnacle common stock. In February 2004, the CSFB Parties
contributed additional funds of $11.8 million into Pinnacle to continue funding
the 2004 development program which will increase their ownership to 66.7% on a
fully diluted basis should we and RMG each elect not to exercise our available
options.
The business operations and development program of Pinnacle does not require us
to provide any further capital infusion, unless we determine to exercise our
options. We account for our interest in Pinnacle using the equity method. As a
result, our contributed operations and reserves are no longer directly reflected
in our financial statements. Our discussion of future drilling and capital
expenditures does not reflect operations conducted through Pinnacle.
In addition to our interest in Pinnacle, CCBM retained interests in
approximately 145,000 gross acres in the Castle Rock coalbed methane project
area in Montana and the Oyster Ridge project area in Wyoming.
Hedging
Our financial results are largely dependent on a number of factors, including
commodity prices. Commodity prices are outside of our control and historically
have been and are expected to remain volatile. Natural gas prices in particular
have remained volatile during the last few years. Commodity prices are affected
by changes in market demands, overall economic activity, weather, pipeline
capacity constraints, inventory storage levels, basis differentials and other
factors. As a result, we cannot accurately predict future natural gas, natural
gas liquids and crude oil prices, and therefore, cannot accurately predict
revenues.
Because natural gas and oil prices are unstable, we periodically enter into
price-risk-management transactions such as swaps, collars, futures and options
to reduce our exposure to price fluctuations associated with a portion of our
natural gas and oil production and to achieve a more predictable cash flow. The
use of these arrangements limits our ability to benefit from increases in the
prices of natural gas and oil. Our hedging arrangements may apply to only a
portion of our production and provide only partial protection against declines
in natural gas and oil prices.
Results of Operations
Three Months Ended June 30, 2004,
Compared to the Three Months Ended June 30, 2003
Oil and natural gas revenues for the three months ended June 30, 2004 increased
35% to $12.0 million from $8.8 million for the same period in 2003. Production
volumes for natural gas during the three months ended June 30, 2004 increased
from 1.0 Bcf for the three months ended June 30, 2003 to 1.5 Bcf. Average
natural gas prices increased 8% to $6.07 per Mcf in the second quarter of 2004
from $5.64 per Mcf in the same period in 2003. Production volumes for oil in the
second quarter of 2004 decreased 30% to 83 MBbls from 118 MBbls for the same
period in 2003. Average oil prices increased 25% to $35.27 per barrel in the
second quarter of 2004 from $28.23 per barrel in the same period in 2003. The
increase in natural gas production was due to the commencement of production at
the Beach House #1 and #2, Shadyside #1 and the Barnett Shale wells partially
offset by the natural decline in production at the Staubach #1, Burkhart #1R,
Matthes Heubner #1 and other wells. The decrease in oil production was due
primarily to the natural decline of production at the Staubach #1, Burkhart #1R,
Pauline Huebner A-382 #1, Matthes Huebner #1 and other wells partially offset by
the commencement of production from the Beach House #1 and #2 and from other
wells. Oil and natural gas revenues include the impact of hedging activities as
discussed above under "General Overview."
The following table summarizes production volumes, average sales prices and
operating revenues for the Company's oil and natural gas operations for the
three months ended June 30, 2003 and 2004:
15
2004 Period
Compared to 2003 Period
---------------------------
June 30,
--------------------------- Increase % Increase
2003 2004 (Decrease) (Decrease)
------------ ------------ ------------ ------------
Production volumes -
Oil and condensate (MBbls) 118 83 (35) (30)%
Natural gas (MMcf) 973 1,487 514 53%
Average sales prices - (1)
Oil and condensate (per Bbls) $ 28.23 $ 35.27 $ 7.04 25%
Natural gas (per Mcf) 5.64 6.07 0.43 8%
Operating revenues (In thousands)-
Oil and condensate $ 3,344 $ 2,941 $ (403) (12)%
Natural gas 5,484 9,019 3,535 64%
------------ ------------ ------------
Total Operating Revenues $ 8,828 $ 11,960 $ 3,132 35%
============ ============ ============
- ------------------
(1) Includes impact of hedging activities.
Oil and natural gas operating expenses for the three months ended June 30, 2004
increased 16% to $2.0 million from $1.8 million for the same period in 2003.
Operating expenses per equivalent unit decreased slightly to $1.03 per Mcfe in
the second quarter of 2004 compared to $1.05 per Mcfe in the same period in
2003.
Depreciation, depletion and amortization (DD&A) expense for the three months
ended June 30, 2004 increased 38% to $3.6 million ($1.81 per Mcfe) from $2.6
million ($1.55 per Mcfe) for the same period in 2003. DD&A increased primarily
due to increased production and expenses resulting from additional seismic and
drilling costs.
General and administrative expense for the three months ended June 30, 2004
increased by $0.3 million to $1.6 million from $1.3 million for the same period
in 2003 primarily as a result of higher directors' fees ($0.1 million), higher
legal fees ($0.1 million) in connection with a subordinated debt refinancing and
higher professional expenses related to Sarbanes-Oxley Compliance ($0.1
million).
Stock option compensation expense was $0.7 million for the quarter ended June
30, 2004.
We recorded a $0.4 million after tax charge, or $0.02 per fully diluted share,
on our minority interest in Pinnacle for the three months ended June 30, 2004.
It is likely that Pinnacle will continue to record a valuation allowance on the
deferred federal tax benefit generated from the operating losses incurred during
at least the early development stages of Pinnacle's coalbed methane projects. We
have not recorded a deferred federal income tax benefit generated from these
operating losses due to the uncertainty of future Pinnacle income.
Income taxes increased to $1.4 million for the three months ended June 30, 2004
from $1.1 million for the same period in 2003 as a result of higher taxable
income based on the factors described above.
Capitalized interest was unchanged at $0.7 million in the second quarter of 2004
from $0.7 million for the second quarter of 2003.
Six Months Ended June 30, 2004,
Compared to the Six Months Ended June 30, 2003
Oil and natural gas revenues for the six months ended June 30, 2004 increased
17% to $22.8 million from $19.5 million for the same period in 2003. Production
volumes for natural gas during the six months ended June 30, 2004 increased 36%
to 2.8 Bcf from 2.1 Bcf for the same period in 2003. Average natural gas prices
increased 4% to $6.00 per Mcf in the first six months of 2004 from $5.78 per Mcf
in the same period in 2003. Production volumes for oil in the first six months
of 2004 decreased 34% to 171 MBbls from 258 MBbls for the same period in 2003.
Average oil prices increased 18% to $34.41 per barrel in the first six months of
2004 from $29.04 per barrel in the same period in 2003. The increase in natural
gas production was primarily due to the commencement of production at the Beach
House #1 and #2, Shadyside #1 and the Barnett Shale wells, offset by the natural
decline in production at the Staubach #1, Burkhart #1R, Pauline Huebner A-382
#1, Matthes Huebner #1, Delta Farms #1 and other wells. The decrease in oil
production was
16
due primarily to the natural decline of production at the Staubach #1, Burkhart
#1R, Pauline Huebner A-382 #1, Matthes Huebner #1 and Delta Farms #1 wells,
offset by the commencement of production from the Beach House #1 and #2 and from
other wells. Oil and natural gas revenues include the impact of hedging
activities as discussed above under "General Overview".
The following table summarizes production volumes, average sales prices and
operating revenues for our oil and natural gas operations for the six months
ended June 30, 2003 and 2004:
2004 Period
Compared to 2003 Period
---------------------------
June 30,
--------------------------- Increase % Increase
2003 2004 (Decrease) (Decrease)
------------ ------------ ------------ ------------
Production volumes -
Oil and condensate (MBbls) 258 171 (87) (34)%
Natural gas (MMcf) 2,077 2,826 749 36%
Average sales prices - (1)
Oil and condensate (per Bbls) $ 29.04 $ 34.41 $ 5.37 18%
Natural gas (per Mcf) 5.78 6.00 0.22 4%
Operating revenues (In thousands)-
Oil and condensate $ 7,480 $ 5,867 $ (1,613) (22)%
Natural gas 12,012 16,966 4,954 41%
------------ ------------ ------------
Total Operating Revenues $ 19,492 $ 22,833 $ 3,341 17%
============ ============ ============
- ------------------
(1) Includes impact of hedging activities.
Oil and natural gas operating expenses for the six months ended June 30, 2004
increased to $3.7 million from $3.5 million for the same period in 2003.
Operating expenses per equivalent unit were virtually unchanged at $0.97 per
Mcfe in the first six months of 2004 compared to $0.96 per Mcfe in the same
period in 2003.
Depreciation, depletion and amortization (DD&A) expense for the six months ended
June 30, 2004 increased 21% to $6.9 million ($1.78 per Mcfe) from $5.6 million
($1.56 per Mcfe) for the same period in 2003. DD&A increased primarily due to
increased production and expenses resulting from additional seismic and drilling
costs.
General and administrative expense for the six months ended June 30, 2004
increased by $1.1 million to $3.8 million from $2.7 million for the same period
in 2003 primarily as a result of higher incentive compensation costs ($0.4
million), higher directors' fees ($0.1 million), higher legal fees ($0.1
million) in connection with the subordinated debt refinancing, higher
professional expenses related to Sarbanes-Oxley compliance ($0.1 million) and
higher professional expenses in connection with the 2003 audit ($0.3 million).
Stock option compensation expense was $0.8 million for the six months ended June
30, 2004.
We recorded a $0.6 million after tax charge, or $0.03 per fully diluted share,
on our minority interest in Pinnacle for the six months ended June 30, 2004. It
is likely that Pinnacle will continue to record a valuation allowance on the
deferred federal tax benefit generated from the operating losses incurred during
at least the early development stages of Pinnacle's coalbed methane projects. We
have not recorded a deferred federal income tax benefit generated from these
operating losses due to the uncertainty of future Pinnacle income.
Income taxes decreased to $2.7 million for the six months ended June 30, 2004
from $2.8 million for the same period in 2003 as a result of lower taxable
income based on the factors described above.
Capitalized interest decreased to $1.3 million in the first six months of 2004
from $1.5 million for the first six months of 2003 as a result of lower interest
due to the repayment of a portion of the Rocky Mountain Gas note and the then
outstanding balance under the Hibernia facility.
17
We adopted Financial Accounting Standards Board's Statement of Financial
Standards No. 143 "Accounting for Asset Retirement Obligations" effective
January 1, 2003, and recorded a cumulative effect of change in accounting
principle of $0.1 million in the six months ended June 30, 2003.
Liquidity and Capital Resources
During the six months ended June 30, 2004, we made capital expenditures in
excess of our net cash flows provided by operating activities, using in part the
proceeds generated from our equity offering. For future capital expenditures in
2004, we expect to continue to use such proceeds and cash on hand as well as to
draw on the Hibernia facility to partially fund our planned drilling
expenditures and fund leasehold costs and geological and geophysical costs on
our exploration projects in 2004. We also continue to consider financing
alternatives to fund our Barnett Shale capital program. While we believe that
current cash balances, availability under the Hibernia Facility and anticipated
2004 cash provided by operating activities will provide sufficient capital to
carry out our 2004 exploration plans, there can be no assurance that this will
be the case.
We may not be able to obtain adequate financing on terms that would be
acceptable to us. If we cannot obtain adequate financing, we anticipate that we
may be required to limit or defer our planned natural gas and oil exploration
and development program, thereby adversely affecting the recoverability and
ultimate value of our natural gas and oil properties.
Our liquidity position has been enhanced by our receipt of approximately $23.4
million in net proceeds from the completion of our 2004 public offering as
described above. Our other primary sources of liquidity have included funds
generated by operations, proceeds from the issuance of various securities,
including our common stock, preferred stock and warrants, and borrowings,
primarily under revolving credit facilities and through the issuance of senior
subordinated notes.
Cash flows provided by operating activities were $15.1 million and $17.3 million
for the six months ended June 30, 2003 and 2004, respectively. The increase in
cash flows provided by operating activities in 2004 as compared to 2003 was due
primarily to changes in working capital in 2004, primarily higher accrued
expenses.
We have budgeted capital expenditures in 2004 of approximately $51.3 million, of
which $39.8 million is expected to be used for drilling activities in our
project areas and the balance is expected to be used to fund 3-D seismic
surveys, land acquisitions and capitalized interest and overhead costs. These
capital expenditure amounts do not include the approximately $8.2 million for
the Barnett Shale acquisition. We have budgeted to drill approximately 44 gross
wells (15.3 net) in the Gulf Coast region in 2004. The budget for drilling
additional gross and net wells in the Barnett Shale trend in 2004 is dependent
upon the timing and amount of additional funding. We intend to obtain
alternative financing to fund a majority of our acquisition, exploration and
development program in the Barnett Shale trend in 2004. If we are successful in
obtaining this facility, we expect our capital expenditures in the trend could
increase between $15 and $20 million in 2004. 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.
We have continued to reinvest a substantial portion of our cash flows into
increasing our 3-D prospect portfolio, improving our 3-D seismic interpretation
technology and funding our drilling program. Oil and natural gas capital
expenditures were $14.1 million and $39.1 million (including our $8.2 million
Barnett Shale acquisition) for the six months ended June 30, 2003 and 2004,
respectively. Our drilling efforts resulted in the successful completion of 35
gross wells (9.4 net) in 2003 and 17 gross wells (4.2 net) in the Gulf Coast
region and 11 gross wells (3.9 net) in the Barnett Shale play in the six months
ended June 30, 2004. We have completed 33 of these wells and are in the process
of completing three of these wells as of June 30, 2004.
Since inception, Pinnacle has reported that it drilled 210 gross wells through
June 30, 2004 and estimates that 80% of them were completed by June 30, 2004.
Pinnacle reportedly added approximately 11.4 Bcf of net proved reserves through
development drilling through May 31, 2004. Its gross operated production has
increased by approximately 117% since its inception (to approximately 10.4
MMcf/d at June 30, 2004), and its total well count stands at 449 gross operated
wells.
CCBM has spent $4.6 million for drilling costs, of 50% of which was spent
pursuant to an obligation to fund $2.5 million of drilling costs on behalf of
RMG. As of June 30, 2004, CCBM had satisfied $2.3 million of its drilling
obligations on behalf of RMG.
18
Financing Arrangements
Hibernia Credit Facility
On May 24, 2002, we entered into a credit agreement with Hibernia National Bank
(the "Hibernia Facility") which matures on January 31, 2006, and repaid our
existing facility with Compass Bank (the "Compass Facility"). The Hibernia
Facility provides a revolving line of credit of up to $30.0 million. It is
secured by substantially all of our assets and is guaranteed by our subsidiary.
The borrowing base will be determined by Hibernia National Bank at least
semi-annually on each October 31 and April 30. Each party to the credit
agreement can request one unscheduled borrowing base determination subsequent to
each scheduled determination. The borrowing base will at all times equal the
borrowing base most recently determined by Hibernia National Bank, less
quarterly borrowing base reductions required subsequent to such determination.
Hibernia National Bank will reset the borrowing base amount at each scheduled
and each unscheduled borrowing base determination date.
The terms of our existing and future financial instruments may affect the size
of our borrowing base. See "--Senior Subordinated Notes and Related Securities."
On December 12, 2002, we entered into an Amended and Restated Credit Agreement
with Hibernia National Bank that provided additional availability under the
Hibernia Facility in the amount of $2.5 million which is structured as an
additional "Facility B" under the Hibernia Facility. As such, the total
borrowing base under the Hibernia Facility as of December 31, 2003 and June 30,
2004 was $19.0 million and $26.0 million, respectively, of which $7.0 and $9.0
million, respectively, were drawn as of such dates. The Facility B bore interest
at LIBOR plus 3.375%, was secured by certain leases and working interests in oil
and natural gas wells and matured on April 30, 2003. We used proceeds from our
offering in February 2004 to repay the then outstanding balance under the
Hibernia Facility.
If the principal balance of the Hibernia Facility ever exceeds the borrowing
base as reduced by the quarterly borrowing base reduction (as described above),
the principal balance in excess of such reduced borrowing base will be due as of
the date of such reduction. Otherwise, any unpaid principal or interest will be
due at maturity.
If the outstanding principal balance of the Hibernia Facility exceeds the
borrowing base at any time, we have the option within 30 days to take any of the
following actions, either individually or in combination: make a lump sum
payment curing the deficiency, pledge additional collateral sufficient in
Hibernia National Bank's opinion to increase the borrowing base and cure the
deficiency or begin making equal monthly principal payments that will cure the
deficiency within the ensuing six-month period. Those payments would be in
addition to any payments that may come due as a result of the quarterly
borrowing base reductions. Otherwise, any unpaid principal or interest will be
due at maturity.
For each tranche of principal borrowed under the revolving line of credit, the
interest rate will be, at our option: (i) the Eurodollar Rate, plus an
applicable margin equal to 2.375% if the amount borrowed is greater than or
equal to 90% of the borrowing base, 2.0% if the amount borrowed is less than
90%, but greater than or equal to 50% of the borrowing base, or 1.625% if the
amount borrowed is less than 50% of the borrowing base; or (ii) the Base Rate,
plus an applicable margin of 0.375% if the amount borrowed is greater than or
equal to 90% of the borrowing base. Interest on Eurodollar Loans is payable on
either the last day of each Eurodollar option period or monthly, whichever is
earlier. Interest on Base Rate Loans is payable monthly.
We are subject to certain covenants under the terms of the Hibernia Facility,
including, but not limited to the maintenance of the following financial
covenants: (i) a minimum current ratio of 1.0 to 1.0 (including availability
under the borrowing base), (ii) a minimum quarterly debt services coverage of
1.25 times, and (iii) a minimum shareholders equity equal to $56.0 million, plus
100% of all subsequent common and preferred equity contributed by shareholders,
plus 50% of all positive earning occurring subsequent to such quarter end, all
ratios as more particularly discussed in the credit facility. The Hibernia
Facility also places restrictions on additional indebtedness, dividends to
non-preferred stockholders, liens, investments, mergers, acquisitions, asset
dispositions, asset pledges and mortgages, change of control, repurchase or
redemption for cash of our common or preferred stock, speculative commodity
transactions, and other matters.
Rocky Mountain Gas Note
In June 2001, CCBM issued a non-recourse promissory note payable in the amount
of $7.5 million to RMG as consideration for certain interests in oil and natural
gas leases held by RMG in Wyoming and Montana. The RMG note is payable in
41-monthly principal payments of $0.1 million 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 natural gas leases in Wyoming
and Montana. At December 31, 2003 and June 30, 2004, the outstanding principal
balance of this note was $0.9 million and $0.3 million, respectively. In
connection
19
with our investment in Pinnacle, we received a reduction in the principal amount
of the RMG note of approximately $1.5 million and relinquished the right to
certain revenues related to the properties contributed to Pinnacle. During the
second quarter of 2004, CCBM relinquished a portion of its interests in certain
oil and natural gas leases and reduced the principal due on the note by $0.3
million.
Capital Leases
In December 2001, we entered into a capital lease agreement secured by certain
production equipment in the amount of $0.2 million. The lease is payable in one
payment of $11,323 and 35 monthly payments of $7,549 including interest at 8.6%
per annum. In October 2002, we entered into a capital lease agreement secured by
certain production equipment in the amount of $0.1 million. The lease is payable
in 36 monthly payments of $3,462 including interest at 6.4% per annum. In May
2003, we entered into a capital lease agreement secured by certain production
equipment in the amount of $0.1 million. The lease is payable in 36 monthly
payments of $3,030 including interest at 5.5% per annum. In August 2003, we
entered into a capital lease agreement secured by certain production equipment
in the amount of $0.1 million. The lease is payable in 36 monthly payments of
$2,179 including interest at 6.0% per annum. We have the option to acquire the
equipment at the conclusion of the lease for $1 under all of these leases. DD&A
on the capital leases for the three months ended June 30, 2003 and 2004 amounted
to $11,000 and $12,000, respectively. DD&A on the capital leases for the six
months ended June 30, 2003 and 2004 amounted to $20,000 and $24,000,
respectively, and accumulated DD&A on the leased equipment at December 31, 2003
and June 30, 2004 amounted to $76,000 and $100,000, respectively.
Senior Subordinated Notes and Related Securities
In December 1999, we consummated the sale of $22.0 million principal amount of
9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") and $8.0
million of common stock and Warrants. We sold $17.6 million, $2.2 million, $0.8
million, $0.8 million and $0.8 million principal amount of Subordinated Notes;
2,909,092, 363,636, 121,212, 121,212 and 121,212 shares of our common stock and
2,208,152, 276,019, 92,006, 92,006 and 92,006 Warrants to CB Capital Investors,
L.P. (now known as J.P. Morgan Partners (23A SBIC), L.P.), Mellon Ventures,
L.P., Paul B. Loyd, Jr., Steven A. Webster and Douglas A.P. Hamilton,
respectively. The Subordinated Notes were sold at a discount of $0.7 million,
which is being amortized over the life of the notes. Interest payments are due
quarterly commencing on March 31, 2000. We may, until December 2004, elect, and
historically have elected, to increase the amount of the Subordinated Notes for
60% of the interest which would otherwise be payable in cash. As a result, our
cash obligation on the Subordinated Notes will increase significantly after
December 2004. This increase is likely to reduce the amount available to us for
borrowing under the Hibernia Facility. As of December 31, 2003 and June 30,
2004, the outstanding balance of the Subordinated Notes had been increased by
$5.3 million and $6.0 million, respectively, for such interest paid in kind.
Concurrently with the sale of the Subordinated Notes, we sold to the same
purchasers 3,636,364 shares of our common stock at a price of $2.20 per share
and warrants expiring in December 2007 to purchase up to 2,760,189 shares of our
common stock at an exercise price of $2.20 per share. For accounting purposes,
the warrants were valued at $0.25 each. During the six months ended June 30,
2004, Mellon Ventures, L.P., JPMorgan Partners (23A SBIC), Steven A. Webster and
Douglas A. P. Hamilton exercised warrants to purchase 276,019, 2,208,152, 92,006
and 92,006 shares of common stock, respectively, on a cashless exercise basis
for a total of 205,692, 1,684,949, 70,205 and 70,205 shares of common stock,
respectively, and Paul B. Loyd, Jr., exercised warrants to purchase 92,006
shares for a total of 92,006 shares of common stock. As a result, no warrants to
purchase shares remain outstanding from the warrants originally issued in
December 1999.
On June 7, 2004, an unaffiliated third party (the "Purchaser") purchased all the
outstanding Subordinated Notes from the original note holders. In exchange for a
$0.4 million amendment fee, certain terms and conditions of the Subordinated
Notes were amended, to provide for, among other things, (1) a one year extension
of the maturity to December 15, 2008, (2) a one year extension, through December
15, 2005, of the paid-in-kind ("PIK") interest option to pay-in-kind 60% of the
interest due each period by increasing the principal balance by a like amount
(the "PIK option"), (3) an additional one year option to extend the PIK option
through December 15, 2006 at an annual interest rate on the deferred amount of
10% and the payment of a one-time fee equal to 0.5% of the principal then
outstanding, (4) an increase and extension on the prepayment premium on the
Subordinated Notes, (5) a modification of a covenant regarding maximum quarterly
leverage that our Total Debt will not exceed 3.5 times EBITDA (as such terms are
defined in the securities purchase agreement) for the last 12 months at any time
and (6) additional flexibility to obtain a separate project financing facility
in the future. The amendment fee will be amortized over the remaining life of
the Note.
We are 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 our capital expenditures to an amount equal to our EBITDA for the
immediately prior fiscal year (unless approved by our Board of Directors and a
J.P. Morgan Partners (23A SBIC), L.P. appointed director).
20
Series B Preferred Stock
In February 2002, we consummated the sale of 60,000 shares of Series B Preferred
Stock and 2002 Warrants to purchase 252,632 shares of common stock for an
aggregate purchase price of $6.0 million. We sold $4.0 million and $2.0 million
of Series B Preferred Stock and 168,422 and 84,210 warrants to Mellon Ventures,
Inc. and Steven A. Webster, respectively. 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 for transactions including issuance of common
stock or securities convertible into or exercisable for common stock at less
than the conversion price, and is initially convertible into 1,052,632 shares of
common stock. The approximately $5.8 million net proceeds of this financing were
used to fund our ongoing exploration and development program and general
corporate purposes. In the first quarter of 2004, Mellon Ventures exercised all
168,422 of its 2002 warrants on a cashless basis and received 36,570 shares
which it sold in the 2004 public offering.
Dividends on the Series B Preferred Stock were payable in either cash at a rate
of 8% per annum or, at our option, by payment in kind of additional shares of
the Series B Preferred Stock at a rate of 10% per annum. At December 31, 2003
and through the conversion dates, the outstanding balance of the Series B
Preferred Stock had been increased by $1.2 million (11,987 shares) and $1.5
million (15,133 shares), respectively, for dividends paid in kind. In addition
to the foregoing, if we had declared a cash dividend on our common stock, the
holders of shares of Series B Preferred Stock were entitled to receive for each
share of Series B Preferred Stock a cash dividend in the amount of the cash
dividend that would have been received by a holder of the common stock into
which such share of Series B Preferred Stock was convertible on the record date
for such cash dividend. Unless all accrued dividends on the Series B Preferred
Stock were 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.
We must redeem the Series B Preferred Stock at any time after the third
anniversary of our initial issuance upon request from any holder at a price per
share equal to Purchase Price/Dividend Preference (as defined below). On the
other hand, we may opt to redeem the Series B Preferred Stock after the third
anniversary of its issuance 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 Preference. "Purchase Price/Dividend Preference" is
defined to mean, generally, $100 plus all cumulative and accrued dividends.
In the event of any dissolution, liquidation or winding up or specified mergers
or sales or other disposition by us of all or substantially all of our assets,
the holder of each share of Series B Preferred Stock then outstanding will be
entitled to be paid per share of Series B Preferred Stock, prior to the payment
to holders of our common stock and out of our assets available for distribution
to our shareholders, the greater of:
o $100 in cash plus all cumulative and accrued dividends; and
o in specified 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), we are required to make an 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.
Mellon Ventures, Inc., converted all of its Series B Preferred Stock
(approximately 49,938 shares) into 876,099 shares of common stock on May 25,
2004. Steven A. Webster converted all of his Series B Preferred Stock
(approximately 25,195 shares) into 442,025 shares of common stock on June 30,
2004. As a result, no shares of Series B Preferred Stock remain outstanding.
The 2002 Warrants have a five-year term and originally entitled the holders to
purchase up to 252,632 shares of our common stock at a price of $5.94 per share,
subject to adjustment, and are exercisable at any time after issuance. As of
June 30, 2004, 84,210 of the 2002 Warrants remained outstanding. For accounting
purposes, the 2002 Warrants are valued at $0.06 per 2002 Warrant.
Each of our series of warrants may be exercised on a cashless basis at the
option of the holder.
21
Effects of Inflation and Changes in Price
Our results of operations and cash flows are affected by changing oil and
natural gas prices. If the price of oil and natural gas increases (decreases),
there could be a corresponding increase (decrease) in the operating cost that we
are required to bear for operations, as well as an increase (decrease) in
revenues. Inflation has had a minimal effect on us.
Critical Accounting Policies
The following summarizes several of our critical accounting policies:
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. The use of these estimates
significantly affects natural gas and oil properties through depletion and the
full cost ceiling test, as discussed in more detail below.
Oil and Natural Gas Properties
We account for investments in natural gas and oil properties using the full-cost
method of accounting. All costs directly associated with the acquisition,
exploration and development of natural gas and oil properties are capitalized.
These costs include lease acquisitions, seismic surveys, and drilling and
completion equipment. We proportionally consolidate our interests in natural gas
and oil properties. We capitalized compensation costs for employees working
directly on exploration activities of $0.7 million and $0.9 million for the six
months ended June 30, 2003 and 2004, respectively. We expense maintenance and
repairs as they are incurred.
We amortize natural gas and oil properties based on the unit-of-production
method using estimates of proved reserve quantities. We do not amortize
investments in unproved properties until proved reserves associated with the
projects can be determined or until these investments are impaired. We
periodically evaluate, on a property-by-property basis, unevaluated properties
for impairment. If the results of an assessment indicate that the properties are
impaired, we add the amount of impairment to the proved natural gas and oil
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 Mcfe
for the six months ended June 30, 2003 and 2004 was $1.50 and $1.80,
respectively.
We account for dispositions of natural gas and oil properties 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. We have not had any transactions that significantly alter that
relationship.
The net capitalized costs of proved oil and natural 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.
In mid-March 2004, during the year-end close of our 2003 financial statements,
it was determined that there was a computational error in the ceiling test
calculation which overstated the tax basis used in the computation to derive our
after-tax present value (discounted at 10%) of future net revenues from proved
reserves. We further determined that this tax basis error was also present in
each of our previous ceiling test computations dating back to 1997. This error
only affected our after-tax computation, used in the ceiling test calculation
and the unaudited supplemental oil and natural gas disclosure, and did not
impact our: (1) pre-tax valuation of the present value (discounted at 10%) of
future net revenues from proved reserves, (2) our proved reserve volumes, (3)
our EBITDA or our future cash flows from operations, (4) our net deferred tax
liability, (5) our estimated tax basis in oil and natural gas properties, or (6)
our estimated tax net operating losses.
After discovering this computational error, the ceiling tests for all quarters
since 1997 were recomputed and it was determined that no write-down of our oil
and natural gas assets was necessary in any of the years from 1997 to 2003.
Additionally, no write-down of our oil and natural gas assets was necessary for
the six months ended June 30, 2004. However, based upon the oil and natural gas
prices in effect on December 31, 2001, March 31, 2003 and September 30, 2003,
the unamortized cost of oil and natural gas properties exceeded the cost center
ceiling. As permitted by full cost accounting rules, improvements in pricing
and/or the addition of proved
22
reserves subsequent to those dates sufficiently increased the present value of
our oil and natural gas assets and removed the necessity to record a write-down
in these periods. Using the prices in effect and estimated proved reserves
existing on December 31, 2001, March 31, 2003 and September 30, 2003, the
after-tax write-down would have been approximately $6.3 million, $1.0 million,
and $6.3 million, respectively, had we not taken into account these subsequent
improvements. These improvements at September 30, 2003 included estimated proved
reserves attributable to our Shady Side #1 well. Because of the volatility of
oil and natural gas prices, no assurance can be given that we will not
experience a write-down in future periods.
In connection with our June 30, 2004 ceiling test computation, a price
sensitivity study also indicated that a 20% increase in commodity prices at June
30, 2004 would have increased the pre-tax present value of future net revenues
("NPV") by approximately $36.4 million. Conversely, a 20% decrease in commodity
prices at June 30, 2004 would have reduced our NPV by approximately $36.3
million. This would have caused our unamortized cost of proved oil and natural
gas properties to exceed the cost pool ceiling, resulting in an after-tax
write-down of approximately $6.8 million. The aforementioned price sensitivity
and NPV is as of June 30, 2004 and, accordingly, does not include any potential
changes in reserves due to third quarter 2004 performance, such as commodity
prices, reserve revisions and drilling results.
Under the full cost method of accounting, the depletion rate is the current
period production as a percentage of the total proved reserves. Total proved
reserves include both proved developed and proved undeveloped reserves. The
depletion rate is applied to the net book value and estimated future development
costs to calculate the depletion expense.
We have a significant amount of proved undeveloped reserves, which are primarily
oil reserves. We had 44.9 Bcfe and, based on internal estimates, 55.1 Bcfe of
proved undeveloped reserves, representing 64% and 64% of our total proved
reserves at December 31, 2003 and June 30, 2004, respectively. As of December
31, 2003 and June 30, 2004, a large portion of these proved undeveloped
reserves, or approximately 43.9 Bcfe, are attributable to our Camp Hill
properties that we acquired in 1994. The estimated future development costs to
develop our proved undeveloped reserves on our Camp Hill properties are
relatively low, on a per Mcfe basis, when compared to the estimated future
development costs to develop our proved undeveloped reserves on our other oil
and natural gas properties. Furthermore, the average depletable life of our Camp
Hill properties is considerably higher, or approximately 15 years, when compared
to the depletable life of our remaining oil and natural gas properties of
approximately 2.25 years. Accordingly, the combination of a relatively low ratio
of future development costs and a relatively long depletable life on our Camp
Hill properties has resulted in a relatively low overall historical depletion
rate and DD&A expense. This has resulted in a capitalized cost basis associated
with producing properties being depleted over a longer period than the
associated production and revenue stream. It has also resulted in the build-up
of nondepleted capitalized costs associated with properties that have been
completely produced out.
We expect our relatively low historical depletion rate condition to continue
until the high level of nonproducing reserves to total proved reserves is
reduced and the average life of our proved developed reserves is extended
through development drilling and/or the significant addition of new proved
producing reserves through acquisition or exploration. If our level of total
proved reserves and current prices were both to remain constant, this continued
build-up of capitalized costs increases the probability of a ceiling test
write-down.
We depreciate other property and equipment using the straight-line method based
on estimated useful lives ranging from five to 10 years.
Oil and Natural Gas Reserve Estimates
The reserve data included in this document are estimates prepared by Ryder Scott
Company and Fairchild & Wells, Inc., Independent Petroleum Engineers. Reserve
engineering is a subjective process of estimating underground accumulations of
hydrocarbons that cannot be measured in an exact manner. The process relies on
interpretation of available geologic, geophysical, engineering and production
data. The extent, quality and reliability of this data can vary. The process
also requires certain economic assumptions regarding drilling and operating
expense, capital expenditures, taxes and availability of funds. The SEC mandates
some of these assumptions such as oil and natural gas prices and the present
value discount rate.
Proved reserve estimates prepared by others may be substantially higher or lower
than these estimates. Because these estimates depend on many assumptions, all of
which may differ from actual results, reserve quantities actually recovered may
be significantly different than estimated. Material revisions to reserve
estimates may be made depending on the results of drilling, testing, and rates
of production.
23
You should not assume that the present value of future net cash flows is the
current market value of our estimated proved reserves. In accordance with SEC
requirements, we based the estimated discounted future net cash flows from
proved reserves on prices and costs on the date of the estimate.
Our rate of recording depreciation, depletion and amortization expense for
proved properties depends on our estimate of proved reserves. If these reserve
estimates decline, the rate at which we record these expenses will increase.
Derivative Instruments and Hedging Activities
Upon entering into a derivative contract, we designate 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
natural gas revenues when the forecasted transaction occurs. All of our
derivative instruments at December 31, 2003 and June 30, 2004 were designated
and effective as cash flow hedges.
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.
We typically use fixed rate swaps and costless collars to hedge our exposure to
material changes in the price of natural gas and oil. We formally document all
relationships between hedging instruments and hedged items, as well as our 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. We also formally assess, 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.
Our Board of Directors sets all of our 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 representatives authorized to execute trades. The
Board of Directors also reviews the status and results of hedging activities
quarterly.
Income Taxes
Under Statement of Financial Accounting Standards No. 109 ("SFAS No. 109"),
"Accounting for Income Taxes," deferred income taxes are recognized at each year
end for the future tax consequences of differences between the tax bases of
assets and liabilities and their financial reporting amounts based on tax laws
and statutory tax rates applicable to the periods in which the differences are
expected to affect taxable income. Valuation allowances are established when
necessary to reduce the deferred tax asset to the amount expected to be
realized.
Contingencies
Liabilities and other contingencies are recognized upon determination of an
exposure, which when analyzed indicates that it is both probable that an asset
has been impaired or that a liability has been incurred and that the amount of
such loss is reasonably estimable.
Volatility of Oil and Natural Gas Prices
Our revenues, future rate of growth, results of operations, financial condition
and ability to borrow funds or obtain additional capital, as well as the
carrying value of our properties, are substantially dependent upon prevailing
prices of oil and natural gas.
We periodically review the carrying value of our oil and natural gas properties
under the full cost accounting rules of the Commission. See "--Critical
Accounting Policies and Estimates--Oil and Natural Gas Properties."
Total oil hedged under swaps and collars during the three months ended June 30,
2003 and 2004 were 63,300 Bbls and 27,300 Bbls, respectively. Total natural gas
hedged under swaps and collars during the three months ended June 30, 2003 and
2004 were 819,000
24
MMBtu and 1,001,000 MMBtu, respectively. Total oil hedged under swaps and
collars during the six months ended June 30, 2003 and 2004 were 126,300 Bbls and
54,300 Bbls, respectively. Total natural gas hedged under swaps and collars
during the six months ended June 30, 2003 and 2004 were 1,349,000 MMBtu and
1,727,000 MMBtu, respectively. The net losses realized by the Company under such
hedging arrangements were $0.4 and $0.5 million for the three months ended June
30, 2003 and 2004, respectively, and are included in oil and natural gas
revenues. The net losses realized by the Company under such hedging arrangements
were $1.7 million and $0.4 million for six months ended June 30, 2003 and 2004,
respectively, and are included in oil and natural gas revenues.
To mitigate some of our commodity price risk, we engage periodically in certain
other limited hedging activities. For instance, during the second quarter of
2003, we acquired options to sell 6,000 MMBtu of natural gas per day for the
period July 2003 through September 2003 (552,000 MMBtu) at $8.00 per MMBtu for
approximately $119,000. We acquired these options to protect its cash position
against potential margin calls on certain natural gas derivative due to large
increases in the price of natural gas. These options were classified as
derivatives. The costs were recorded as a reduction of natural gas revenues as
the options expired.
As of December 31, 2003 and June 30, 2004, $0.2 million and $0.5 million, net of
tax of $0.1 million and $0.3 million, respectively, remained in accumulated
other comprehensive income related to the valuation of our hedging positions.
While the use of hedging arrangements limits the downside risk of adverse price
movements, it may also limit our ability to benefit from increases in the prices
of natural gas and oil. We enter into the majority of our hedging transactions
with two counterparties and have a netting agreement in place with those
counterparties. We do not obtain collateral to support the agreements but
monitor the financial viability of counterparties and believe our credit risk is
minimal on these transactions. Under these arrangements, payments are received
or made based on the differential between a fixed and a variable product price.
These agreements are settled in cash at expiration or exchanged for physical
delivery contracts. In the event of nonperformance, we would be exposed again to
price risk. We have some risk of financial loss because the price received for
the product at the actual physical delivery point may differ from the prevailing
price at the delivery point required for settlement of the hedging transaction.
Moreover, our hedging arrangements generally do not apply to all of our
production and thus provide only partial price protection against declines in
commodity prices. We expect that the amount of our hedges will vary from time to
time.
Our natural gas derivative transactions are generally settled based upon the
average of the reporting settlement prices on the NYMEX for the last three
trading days of a particular contract month. Our oil derivative transactions are
generally settled based on the average reporting settlement prices on the NYMEX
for each trading day of a particular calendar month. For the month of June 2004,
a $0.10 change in the price per Mcf of gas sold would have changed revenue by
$49,000. A $0.70 change in the price per barrel of oil would have changed
revenue by $18,000.
The table below summarizes our total natural gas production volumes subject to
derivative transactions during the six months ended June 30, 2004 and the
weighted average NYMEX reference price for those volumes.
Natural Gas Swaps Natural Gas Collars
- ----------------------------- -----------------------------
Volumes (MMBtu) Volumes (MMBtu) 1,727,000
Average price ($/MMBtu) $ - Average price ($/MMBtu)
Floor $ 4.33
Ceiling $ 6.26
The table below summarizes our total crude oil production volumes subject to
derivative transactions for the six months ended June 30, 2004 and the weighted
average NYMEX reference price for those volumes.
Crude Oil Swaps Crude Oil Collars
- ----------------------------- -----------------------------
Volumes (Bbls) 54,300 Volumes (Bbls) -
Average price ($/Bbls) $ 30.96 Average price ($/Bbls)
Floor $ -
Ceiling $ -
25
At June 30, 2003 and 2004 we had the following outstanding hedge positions:
As of June 30, 2003
- --------------------------------------------------------------------------------------------------
Contract Volumes
---------------------------
Average Average Average
Quarter BBls MMbtu Fixed Price Floor Price Ceiling Price
- ---------------------- ------------ ------------ ------------ ------------ -------------
Third Quarter 2003 276,000 $ 4.70
Third Quarter 2003 552,000 $ 3.40 $ 5.25
Fourth Quarter 2003 552,000 3.40 5.25
Second Quarter 2004 273,000 4.00 5.20
Third Quarter 2004 276,000 4.00 5.20
Third Quarter 2004 93,000 4.00 5.20
As of June 30, 2004
- --------------------------------------------------------------------------------------------------
Contract Volumes
---------------------------
Average Average Average
Quarter BBls MMbtu Fixed Price Floor Price Ceiling Price
- ---------------------- ------------ ------------ ------------ ------------ -------------
Third Quarter 2004 27,600 $ 37.42
Third Quarter 2004 1,012,000 $ 4.52 $ 6.24
Fourth Quarter 2004 9,300 38.85
Fourth Quarter 2004 1,197,000 4.71 6.94
First Quarter 2005 810,000 5.09 8.00
Forward Looking Statements
The statements contained in all parts of this document, including, but not
limited to, those relating to our schedule, targets, estimates or results of
future drilling, including the number, timing and results of wells, budgeted
wells, increases in wells, the timing and risk involved in drilling follow-up
wells, expected working or net revenue interests, planned expenditures,
prospects budgeted and other future capital expenditures, risk profile of oil
and natural gas exploration, acquisition of 3-D seismic data (including number,
timing and size of projects), planned evaluation of prospects, probability of
prospects having oil and natural gas, expected production or reserves, increases
in reserves, acreage, working capital requirements, hedging activities, the
ability of expected sources of liquidity to implement our business strategy,
future hiring, future exploration activity, production rates, potential drilling
locations targeting coal seams, the outcome of legal challenges to new coalbed
methane drilling permits in Montana, financing of the February 2004 acquisition
costs in the Barnett Shale trend and the exploration and development
expenditures in that trend, all 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, availability of financing
and other factors detailed in the Company's Annual Report on Form 10-K for the
year ended December 31, 2003 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. All subsequent written and oral forward-looking
statements attributable to us or persons acting on our behalf are expressly
qualified in their entirety by reference to these risks and uncertainties. You
should not place undue reliance on forward-looking statements. Each
forward-looking statement speaks only as of the date of the particular statement
and the Company undertakes no obligation to update or revise any forward looking
statement.
26
ITEM 3 - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
For information regarding our exposure to certain market risks, see
"Quantitative and Qualitative Disclosures about Market Risk" in Item 7A of our
Annual Report on Form 10-K for the year ended December 31, 2003 except for the
Company's hedging activity subsequent to December 31, 2003 as described above in
"Volatility of Oil and Natural Gas Prices." There have been no material changes
to the disclosure regarding our exposure to certain market risks made in the
Annual Report. For additional information regarding our long-term debt, see Note
4 of the Notes to Unaudited Consolidated Financial Statements in Item 1 of Part
I of this Quarterly Report on Form 10-Q.
27
ITEM 4 - CONTROLS AND PROCEDURES
In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an
evaluation, under the supervision and with the participation of management,
including our Chief Executive Officer and Chief Financial Officer, of the
effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report. Based on that evaluation, our Chief Executive
Officer and Chief Financial Officer concluded that our disclosure controls and
procedures were effective as of June 30, 2004 to provide reasonable assurance
that information required to be disclosed in our reports filed or submitted
under the Exchange Act is recorded, processed, summarized and reported within
the time periods specified in the Securities and Exchange Commission's rules and
forms.
Except as set forth below, there has been no change in our internal controls
over financial reporting that occurred during the three months ended June 30,
2004 that has materially affected, or is reasonably likely to materially affect,
our internal controls over financial reporting. Management has and is
implementing procedures and controls to address the following deficiencies and
enhance the reliability of our internal control procedures: (1) the presence of
underlying errors in the tax basis utilized in our full cost ceiling test
computations and certain disclosures and the lack of underlying detailed tax
basis documentation which adversely impacted our ability to evaluate the
appropriateness of the tax basis (see "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Critical Accounting Policies --
Oil and Natural Gas Properties") and (2) the sufficiency of review applied to
the financial statement close process and account reconciliation.
28
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.
Item 2 - Changes in Securities, Use of Proceeds and Issuer Purchases of Equity
Securities
In May 2004, Mellon Ventures converted all of its approximately 49,938
shares of Series B Preferred Stock into 876,099 shares of common stock. In June
2004, each of Messrs. Webster and Hamilton exercised all of his warrants to
purchase 92,006 shares of common stock issued in 1999 on a cashless "net
exercise" basis and received 70,205 shares of common stock. In June 2004, Mr.
Loyd exercised all of his warrants to purchase 92,006 shares of common stock
issued in 1999 and received 92,006 shares of common stock. In June 2004, Mr.
Webster converted all of his approximately 25,195 shares of Series B Preferred
Stock into 442,025 shares of common stock. All of these transactions were exempt
from the registration requirements of the Securities Act of 1933, as amended, by
virtue of Section 4(2) as a transaction not involving any public offering and
the exercises of warrants on a cashless "net exercise" basis were also exempt by
virtue of Section 3(a)(9).
Item 3 - Defaults Upon Senior Securities
None
Item 4 - Submission of Matters to a Vote of Security Holders
At the Annual Meeting of Carrizo Oil & Gas, Inc., held on May 21, 2004,
there were represented by person or by proxy 17,441, 554 shares out of
18,392,386 entitled to vote as of the record date, constituting a quorum.
The matters submitted to a vote of shareholders were (1) the reelection of
Steven A. Webster, Christopher C. Behrens, Bryan R. Martin, Douglas A. P.
Hamilton, Paul B. Loyd, Jr., F. Gardner Parker, S. P. Johnson IV and Frank A.
Wojtek and the election of Mr. Roger A. Ramsey as directors, (2) the approval of
an amendment to the incentive plan to increase by 500,000 the number of shares
of common stock available for issuance under the plan, replace automatic annual
grants of options to nonemployee directors with discretionary awards of options
or restricted stock, provide for additional stock option grants to the chairman
and certain members of the nominating committee of the Board of Directors and
make certain clarifications to other provisions of the plan and (3) the approval
of the appointment of Ernst & Young LLP as Independent Public Accountants for
the fiscal year ended December 31, 2004. With respect to the election of
directors, the following number of votes were cast for the nominees: 15,691,839
for Mr. Webster and 1,749,715 withheld; 17,388,434 for Mr. Behrens and 53,120
withheld; 17,388,334 for Mr. Martin and 53,220 withheld; 17,433,034 for Mr.
Hamilton and 8,520 withheld; 15,692,839 for Mr. Loyd and 1,748,715 withheld;
17,428,234 for Mr. Parker and 13,320 withheld; 17,387,334 for Mr. Johnson and
54,220 withheld; 17,310,473 for Mr. Wojtek and 131,081 withheld; and 17,377,634
for Mr. Ramsey and 63,920 withheld. There were no abstentions in the election of
directors. With respect to the amendment to the incentive plan, 10,943,924 votes
were cast for the amendment, 1,661,934 votes were against and 23,200 votes
abstained. With respect to the appointment for Ernst & Young LLP as Independent
Public Accountants, 16,566,220 votes were cast for the appointment and 6,720
votes were against, and 746,579 votes abstained.
Item 5 - Other Information
Mr. Hamilton resigned as a director on July 6, 2004.
Mr. Behrens resigned as a director on July 15, 2004.
Item 6 - Exhibits and Reports on Form 8-K
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.
29
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).
+10.1 -- Amendment No. 4 to the Amended and Restated Incentive Plan
of the Company (incorporated herein by reference to Appendix B
to the Company's Proxy Statement dated April 26, 2004).
+10.2 -- First Amendment to Securities Purchase Agreement dated
as of June 7, 2004 among Carrizo Oil & Gas, Inc., Steelhead
Investments Ltd., Douglas A.P. Hamilton, Paul B. Loyd, Jr.,
Steven A. Webster and Mellon Ventures, L.P. (incorporated
herein by reference to Exhibit 99.1 to the Company's Current
Report on Form 8-K filed on July 10, 2004).
+10.3 -- Form of Amended and Restated 9% Senior Subordinated Note due
2008 (incorporated herein by reference to Exhibit 99.2 to the
Company's Current Report on Form 8-K filed on July 10, 2004).
+10.4 -- Consent dated as of June 7, 2004 among Carrizo Oil & Gas,
Inc., CCBM, Inc. and Hibernia National Bank (incorporated
herein by reference to Exhibit 99.3 to the Company's Current
Report on Form 8-K filed on July 10, 2004).
+10.5 -- First Amendment to Shareholders Agreement dated as of April
21, 2004 among Carrizo Oil & Gas, Inc., J.P. Morgan Partners
(23A SBIC), LLC, Mellon Ventures, L.P., S.P. Johnson IV,
Frank A. Wojtek and Steven A. Webster (incorporated herein
by reference to Exhibit 29 to the Schedule 13D/A filed by
Paul B. Loyd, Jr. on May 28, 2004).
+10.6 -- First Amendment to Shareholders Agreement dated as of
April 21, 2004 among Carrizo Oil & Gas, Inc., Mellon
Ventures, L.P., S.P. Johnson IV, Frank A. Wojtek, Steven A.
Webster, Douglas A.P. Hamilton, Paul B. Loyd, Jr. and DAPHAM
Partnership, L.P. (incorporated herein by reference to
Exhibit 30 to the Schedule 13D/A filed by Paul B. Loyd, Jr.
on May 28, 2004).
+10.7 -- Second Amendment to Shareholders Agreement dated as of June
7, 2004 among Carrizo Oil & Gas, Inc., J.P. Morgan Partners
(23A SBIC), LLC, Mellon Ventures, L.P., S.P. Johnson IV,
Frank A. Wojtek and Steven A. Webster (incorporated herein
by reference to Exhibit 99.4 to the Company's Current Report
on Form 8-K filed on July 10, 2004).
+10.8 -- Termination Agreement dated as of June 7, 2004 among Carrizo
Oil & Gas, Inc., Mellon Ventures, L.P., S.P. Johnson IV,
Frank A. Wojtek and Steven A. Webster (incorporated herein
by reference to Exhibit 99.5 to the Company's Current Report
on Form 8-K filed on July 10, 2004).
31.1 -- CEO Certification Pursuant to Section 302 of the Sarbanes-
Oxley Act of 2002.
31.2 -- CFO Certification Pursuant to Section 302 of the Sarbanes-
Oxley Act of 2002.
32.1 -- CEO Certification Pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002.
32.2 -- CFO Certification Pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002.
+ Incorporated herein by reference as indicated.
30
Reports on Form 8-K
The Company filed a Current Report on Form 8-K on April 30, 2004 announcing
operating results for the quarter ended March 31, 2004 (information furnished
not filed) and disclosing information regarding the Company's 2004 drilling
schedule and 2004 budgeted capital expenditures, a Current Report on Form 8-K on
May 20, 2004 announcing financial results for the quarter ended March 31, 2004
(information furnished not filed), and a Current Report on Form 8-K on June 10,
2004 announcing the purchase of the Company's outstanding 9% senior subordinated
notes from the original holder by an unaffiliated third party, and related
transactions.
31
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this Report to be signed on its
behalf by the undersigned, thereunto duly authorized.
Carrizo Oil & Gas, Inc.
(Registrant)
Date: August 16, 2004 By: /s/S. P. Johnson, IV
-------------------------
President and Chief Executive Officer
(Principal Executive Officer)
Date: August 16, 2004 By: /s/Paul F. Boling
----------------------
Chief Financial Officer
(Principal Financial and
Accounting Officer)