SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2004
--------------
[ ] 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 May 4, 2004, the latest practicable date, was 18,414,886.
CARRIZO OIL & GAS, INC.
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2004
INDEX
PART I. FINANCIAL INFORMATION PAGE
Item 1. Consolidated Balance Sheets
- As of December 31, 2003 and March 31, 2004 2
Consolidated Statements of Operations
- For the three-month periods ended March 31, 2004 and
2003 3
Consolidated Statements of Cash Flows
- For the three-month periods ended March 31, 2004 and
2003 4
Notes to Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 13
Item 3. Quantitative and Qualitative Disclosure About
Market Risk 25
Item 4. Controls and Procedures 26
PART II. OTHER INFORMATION
Items 1-6. 27
SIGNATURES 29
CARRIZO OIL & GAS, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
ASSETS December 31, March 31,
------------ ------------
2003 2004
------------ ------------
(In thousands)
CURRENT ASSETS:
Cash and cash equivalents $ 3,322 $ 4,893
Accounts receivable, trade (net of allowance for doubtful accounts of
none at December 31, 2003 and March 31, 2004, respectively) 8,970 8,491
Advances to operators 1,877 1,744
Deposits 56 56
Other current assets 100 437
------------ ------------
Total current assets 14,325 15,621
PROPERTY AND EQUIPMENT, net (full-cost method of
accounting for oil and natural gas properties) 135,273 153,723
Investment in Pinnacle Gas Resources, Inc. 6,637 6,385
Deferred financing costs 479 456
Other assets 89 72
------------ ------------
$ 156,803 $ 176,257
============ ============
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade $ 19,515 $ 17,091
Accrued liabilities 1,057 4,498
Advances for joint operations 3,430 2,761
Current maturities of long-term debt 1,037 858
Current maturities of seismic obligation payable 1,103 500
------------ ------------
Total current liabilities 26,142 25,708
LONG-TERM DEBT 34,113 27,479
ASSET RETIREMENT OBLIGATION 883 906
DEFERRED INCOME TAXES 12,479 13,788
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 convertible participating shares issued
and outstanding at December 31, 2003 and March 31, 2004, respectively) (Note 8)
Issued and outstanding 7,114 7,132
Accrued dividends - 180
SHAREHOLDERS' EQUITY:
Warrants (3,262,821 and 3,025,200 outstanding at December 31,
2003 and March 31, 2004, respectively) 780 780
Common stock, par value $.01 (40,000,000 shares authorized with 14,591,348 and
18,392,386 issued and outstanding at December 31, 2003 and
March 31, 2004, respectively) 146 184
Additional paid in capital 65,103 88,698
Retained earnings 10,229 12,215
Accumulated other comprehensive income (186) (813)
------------ ------------
76,072 101,064
------------ ------------
$ 156,803 $ 176,257
============ ============
The accompanying notes are an integral part of these
consolidated financial statements.
2
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
For the Three
Months Ended
March 31,
-----------------------------
2003 2004
------------ ------------
(In thousands except
per share amounts)
OIL AND NATURAL GAS REVENUES $ 10,663 $ 10,873
COSTS AND EXPENSES:
Oil and natural gas operating expenses
(exclusive of depreciation shown separately below) 1,720 1,676
Depreciation, depletion and amortization 3,036 3,247
General and administrative 1,383 2,133
Accretion expense related to asset retirement obligations 8 6
Stock option compensation (10) 10
------------ ------------
Total costs and expenses 6,137 7,072
------------ ------------
OPERATING INCOME 4,526 3,801
OTHER INCOME AND EXPENSES:
Equity in loss of Pinnacle Gas Resources, Inc. - (244)
Other income and expenses 100 9
Interest income 18 13
Interest expense (198) (95)
Interest expense, related parties (583) (615)
Capitalized interest 776 667
------------ ------------
INCOME BEFORE INCOME TAXES 4,639 3,536
INCOME TAXES (Note 6) 1,669 1,353
------------ ------------
NET INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE 2,970 2,183
DIVIDENDS AND ACCRETION ON PREFERRED STOCK 181 198
------------ ------------
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS
BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 2,789 1,985
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE (128) -
------------ ------------
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS $ 2,661 $ 1,985
============ ============
BASIC EARNINGS PER COMMON SHARE BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 0.20 $ 0.12
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE NET OF INCOME TAXES (0.01) -
------------ ------------
BASIC EARNINGS PER COMMON SHARE $ 0.19 $ 0.12
============ ============
DILUTED EARNINGS PER COMMON SHARE BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 0.17 $ 0.10
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE NET OF INCOME TAXES (0.01) -
------------ ------------
DILUTED EARNINGS PER COMMON SHARE $ 0.16 $ 0.10
============ ============
The accompanying notes are an integral part of these
consolidated financial statements.
3
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
For the Three
Months Ended
March 31,
-----------------------------
2003 2004
------------ ------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income before cumulative effect of change in accounting principle $ 2,970 $ 2,184
Adjustment to reconcile net income to net
cash provided by operating activities-
Depreciation, depletion and amortization 3,036 3,247
Discount accretion 30 67
Interest payable in kind 350 369
Stock option compensation (benefit) (10) 10
Equity in loss of Pinnacle Gas Resources, Inc. - 244
Deferred income taxes 1,624 1,308
Changes in assets and liabilities-
Accounts receivable 456 479
Other assets (203) (10)
Accounts payable (2,307) (2,634)
Other liabilities 307 1,513
------------ ------------
Net cash provided by operating activities 6,253 6,777
------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (4,001) (21,664)
Change in capital expenditure accrual (1,469) 1,165
Advances to operators 442 133
Advances for joint operations 1,572 (668)
------------ ------------
Net cash used in investing activities (3,456) (21,034)
------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from the sale of common stock 47 23,633
Debt repayments (403) (7,805)
------------ ------------
Net cash provided by (used in) financing activities (356) 15,828
------------ ------------
NET INCREASE IN CASH AND CASH EQUIVALENTS 2,441 1,571
CASH AND CASH EQUIVALENTS, beginning of period 4,743 3,322
------------ ------------
CASH AND CASH EQUIVALENTS, end of period $ 7,184 $ 4,893
============ ============
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest (net of amounts capitalized) $ 5 $ 43
============ ============
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 for the three months ended March 31, 2003 to
Gulfmark Energy, Inc. (21%), Cokinos Natural Gas Company (15%) and Discovery
Producers LLC (10%); and for the three months ended March 31, 2004 to Cokinos
Natural Gas Company (24%), Texon L.P. (22%) and WMJ Investments Corp. (18%).
Because alternate purchasers of oil and natural gas are readily available, the
Company believes that the loss of any of its purchasers would not have a
material adverse effect on the financial results of the Company.
3. EARNINGS PER COMMON SHARE:
Supplemental earnings per share information is provided below:
For the Three Months Ended March 31,
---------------------------------------------------------------------------
(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 2,789 1,985 14,198,134 16,613,430 $ 0.20 $ 0.12
========== ==========
Dilutive effect of Stock Options, Warrants and
Preferred Stock conversions 181 198 3,258,632 2,670,723
---------- ---------- ---------- ----------
Diluted Earnings per Share
Net income available to common shareholders
plus assumed conversions before cumulative
effect of change in accounting principle $ 2,970 $ 2,183 17,456,766 19,284,153 $ 0.17 $ 0.10
========== ========== ========== ========== ========== ==========
5
For the Three Months Ended March 31,
---------------------------------------------------------------------------
(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) $ - 14,198,134 16,613,430 $ (0.01) $ -
========== ==========
Dilutive effect of Stock Options, Warrants and
Preferred Stock conversions - - 3,258,632 2,670,723
---------- ---------- ---------- ----------
Diluted Earnings per Share
Net income available to common shareholders
plus assumed conversions $ (128) $ - 17,456,766 19,284,153 $ (0.01) $ -
========== ========== ========== ========== ========== ==========
For the Three Months Ended March 31,
---------------------------------------------------------------------------
(In thousands except share and per share amounts)
Income Shares Per-Share Amount
----------------------- ----------------------- -----------------------
2003 2004 2003 2004 2003 2004
---------- ---------- ---------- ---------- ---------- ----------
Basic Earnings per Share
Net income available to common shareholders $ 2,661 1,985 14,198,134 16,613,430 $ 0.19 $ 0.12
========== ==========
Dilutive effect of Stock Options, Warrants and
Preferred Stock conversions 181 198 3,258,632 2,670,723
---------- ---------- ---------- ----------
Diluted Earnings per Share
Net income available to common shareholders
plus assumed conversions $ 2,842 $ 2,183 17,456,766 19,284,153 $ 0.16 $ 0.10
========== ========== ========== ========== ========== ==========
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 149,833 and 47,000 stock options and 252,632 and zero warrants,
respectively, during the three months ended March 31, 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. At March 31, 2003 and 2004, the Company also
had zero and 1,262,930 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.
4. LONG-TERM DEBT:
At December 31, 2003 and March 31, 2004, long-term debt consisted of the
following:
December 31, March 31,
2003 2004
------------ ------------
Hibernia Facility $ 7,000 $ -
Senior subordinated notes, related parties 26,992 27,382
Capital lease obligations 295 250
Non-recourse note payable to
Rocky Mountain Gas, Inc. 863 705
------------ ------------
35,150 28,337
Less: current maturities (1,037) (858)
------------ ------------
$ 34,113 $ 27,479
============ ============
On May 24, 2002, the Company entered into a credit agreement with Hibernia
National Bank (the "Hibernia Facility") which matures on January 31, 2005, and
repaid its existing facility with Compass Bank (the "Compass Facility"). The
Hibernia Facility provides a
6
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. As of May 14, 2004, the April 30, 2004 borrowing base
determination was pending. 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 January 31, 2004 was $3.0 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
March 31, 2004 was $19.0 million and $16.0 million, respectively, of which $7.0
and none, 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 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 March 31, 2004, amounts outstanding under the Hibernia
Facility totaled $7.0 million and none, respectively, with an additional $12.0
million and $16.0 million, respectively, available for future borrowings. At
December 31, 2003 and March 31, 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.
7
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 March 31, 2003 and 2004 amounted to $10,000 and $12,000,
respectively, and accumulated DD&A on the leased equipment at December 31, 2003
and March 31, 2004 amounted to $76,000 and $88,000, 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 March 31, 2004, the outstanding balance of the Subordinated Notes
had been increased by $5.3 million and $5.7 million, respectively, for such
interest paid in kind. During the three months ended March 31, 2004, Mellon
Ventures, L.P. exercised 69,199 of its warrants on a cashless exercise basis for
a total of 49,135 shares of common stock.
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, and (c) a limitation of its capital expenditures to an amount equal to the
Company's EBITDA for the immediately prior fiscal year (unless approved by the
Company's Board of Directors and a JPMorgan Partners, LLC appointed director).
At March 31, 2004, the Company believes it 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
8
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. 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, 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 March
31, 2004.
6. INCOME TAXES:
The Company provided deferred income taxes at the rate of 35%, which also
approximates its statutory rate, that amounted to $1.6 million and $1.3 million
for the three months ended March 31, 2003 and March 31, 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 is
convertible into common stock by the investors at a conversion price of $5.70
per share, subject to adjustments, and is initially convertible into 1,052,632
shares of common stock. Dividends on the Series B Preferred Stock will be
payable in either cash at a rate of 8% per annum or, at the Company's option, by
payment in kind of additional shares of the same series of preferred stock at a
rate of 10% per annum. At December 31, 2003 and
9
March 31, 2004, the outstanding balance of the Series B Preferred Stock has been
increased by $1.2 million (11,987 shares) for dividends paid in kind. The Series
B Preferred Stock is redeemable at varying prices in whole or in part at the
holders' option after three years or at the Company's option at any time. The
Series B Preferred Stock will also participate in any dividends declared on the
common stock. Holders of the Series B Preferred Stock will receive a liquidation
preference upon the liquidation of, or certain mergers or sales of substantially
all assets involving, the Company. Such holders will also have the option of
receiving a change of control repayment price upon certain deemed change of
control transactions. The warrants have a five-year term and entitle the holders
to purchase up to 252,632 shares of Carrizo's common stock at a price of $5.94
per share, subject to adjustments, and are exercisable at any time after
issuance. The warrants may be exercised on a cashless exercise basis. During the
three months ended March 31, 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 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 intends to refinance a large
portion of the Barnett Shale acquisition with a new project financing facility.
The Company issued 23,333 and 3,801,038 shares of common stock during the three
months ended March 31, 2003 and March 31, 2004, respectively. The shares issued
during the three months ended March 31, 2003 were the result of the exercise of
options granted under the Company's Incentive Plan. The shares issued during the
three months ended March 31, 2004 consisted of 3,655,500 shares issued through
the secondary offering, 85,705 shares issued through the exercise of warrants
and the balance 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:
10
For the three months ended
March 31,
--------------------------
2003 2004
----------- ------------
(In thousands except
per share amounts)
Net income available to common
shareholders, as reported $ 2,661 $ 1,985
Less: Total stock-based employee
compensation expense determined under
fair value method for all awards, net of
related tax effects (132) (132)
----------- ------------
Pro forma net income (loss) available
to common shareholders $ 2,529 $ 1,853
=========== ============
Net income per common share, as reported:
Basic $ 0.19 $ 0.12
Diluted 0.16 0.10
Pro Forma net income (loss) per common share, as if
value method had been applied to all awards:
Basic $ 0.18 $ 0.11
Diluted 0.16 0.10
Diluted earnings per share amounts for the three months ended March 31, 2003 and
2004 are based upon 16,311,251 and 19,284,153 shares, respectively, that include
the dilutive effect of assumed stock option and warrant conversions of 2,113,117
and 2,670,723 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 March 31, 2004, $0.2 million and $0.8 million, net
of tax of $0.1 million and $0.4 million, respectively, remained in accumulated
other comprehensive income related to the valuation of the Company's hedging
positions.
11
Total oil hedged under swaps and collars during the three months ended March 31,
2003 and 2004 were 63,000 Bbls and 27,300 Bbls, respectively. Total natural gas
hedged under swaps and collars in the three months ended March 31, 2003 and 2004
were 540,000 MMBtu and 726,000 MMBtu, respectively. The net gains (losses)
realized by the Company under such hedging arrangements were ($1.2) and $0.1
million for the three months ended March 31, 2003 and 2004, respectively, and
are included in oil and natural gas revenues.
At March 31, 2003 and 2004 the Company had the following outstanding hedge
positions:
As of 3/31/2003
- --------------------------------------------------------------------------------------------------
Contract Volumes
---------------------------
Average Average Average
Quarter BBls MMbtu Fixed Price Floor Price Ceiling Price
- ---------------------- ------------ ------------ ------------ ------------ -------------
Second Quarter 2003 27,300 $ 24.85
Second Quarter 2003 36,000 $ 23.50 $ 26.50
Second Quarter 2003 273,000 4.70
Second Quarter 2003 546,000 3.40 5.25
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
As of 3/31/2004
- --------------------------------------------------------------------------------------------------
Contract Volumes
---------------------------
Average Average Average
Quarter BBls MMbtu Fixed Price Floor Price Ceiling Price
- ---------------------- ------------ ------------ ------------ ------------ -------------
Second Quarter 2004 27,300 $ 31.55
Second Quarter 2004 1,001,000 $ 4.40 $ 5.86
Third Quarter 2004 9,300 33.33
Third Quarter 2004 828,000 4.19 6.07
Fourth Quarter 2004 829,000 4.41 6.47
First Quarter 2005 450,000 4.64 8.00
During May 2004, we entered into costless collar arrangements covering 728,000
MMBtu of natural gas for October 2004 through March 2005 production with an
average floor of $5.53 and a ceiling of $8.00.
12
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 three months ended March 31, 2004, we
participated in the drilling of 17 gross wells (8.0 net) in the Gulf Coast and
North Texas regions, 14 gross wells (6.1 net) of which were successful. Nine of
these successful wells have been completed and five are in the process of being
completed. We have budgeted to drill up to 36 gross wells (16.2 net) in the Gulf
Coast region in 2004 and 13 gross wells (9.4 net) in the North Texas 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 March 2004 was approximately 1.4 Mmcfe/d and net
proved reserves are internally estimated at 9.7 Bcfe.
Initially, we financed the Barnett Shale acquisition with our available cash on
hand. We intend to establish a new project financing facility 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.
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.
13
In the Barnett Shale play, we drilled six gross wells in 2003 and eight gross
wells (4.0 net) during the three months ended March 31, 2004, all of which were
successful. We plan to drill 12 gross wells (8.7 net) in this region in 2004,
assuming that we obtain the project financing facility 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 March 31, 2004,
Compared to the Three Months Ended March 31, 2003
Oil and natural gas revenues for the three months ended March 31, 2004 increased
2% to $10.9 million from $10.7 million for the same period in 2003. Production
volumes for natural gas during the three months ended March 31, 2004 increased
from 1.1 Bcf for the three months ended March 31, 2003 to 1.3 Bcf. Average
natural gas prices increased 1% to $5.95 per Mcf in the first quarter of 2004
from $5.91 per Mcf in the same period in 2003. Production volumes for oil in the
first quarter of 2004 decreased 37% to 87 MBbls from 139 MBbls for the same
period in 2003. Average oil prices increased 12% to $33.33 per barrel in the
first quarter of 2004 from $29.74 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, Delta Farms #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 March 31, 2003 and 2004:
14
2004 Period
Compared to 2003 Period
---------------------------
March 31, Increase % Increase
---------------------------
2003 2004 (Decrease) (Decrease)
------------ ------------ ------------ ------------
Production volumes -
Oil and condensate (MBbls) 139 87 (52) (37)%
Natural gas (MMcf) 1,104 1,339 235 21%
Average sales prices - (1)
Oil and condensate (per Bbls) $ 29.74 $ 33.33 $ 3.59 12%
Natural gas (per Mcf) 5.91 5.95 0.04 1%
Operating revenues (In thousands)-
Oil and condensate $ 4,136 $ 2,904 $ (1,232) (30)%
Natural gas 6,527 7,969 1,442 22%
------------ ------------ ------------
Total $ 10,663 $ 10,873 $ 210 2%
============ ============ ============
- ------------------
(1) Includes impact of hedging activities.
Oil and natural gas operating expenses for the three months ended March 31, 2004
were unchanged at $1.7 million. Operating expenses per equivalent unit were
virtually unchanged at $0.90 per Mcfe in the first quarter of 2004 compared to
$0.89 per Mcfe in the same period in 2003.
Depreciation, depletion and amortization (DD&A) expense for the three months
ended March 31, 2004 increased 7% to $3.2 million from $3.0 million 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 March 31, 2004
increased by $.7 million to $2.1 million from $1.4 million for the same period
in 2003 primarily as a result of higher incentive compensation costs ($0.4
million) and higher professional expenses in connection with the 2003 audit
($0.3 million).
We recorded a $0.2 million after tax charge, or $0.01 per fully diluted share,
on our minority interest in Pinnacle for the three months ended March 31, 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 $1.4 million for the three months ended March 31, 2004
from $1.7 million for the same period in 2003 as a result of lower taxable
income based on the factors described above.
Capitalized interest decreased to $0.7 million in the first quarter of 2004 from
$0.8 million for the first quarter of 2003 as a result of lower interest due to
the repayment of the Rocky Mountain Gas note and the Hibernia facility.
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 three months ended March 31, 2003.
LIQUIDITY AND CAPITAL RESOURCES
During the first quarter ended March 31, 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 seek project facility
financing for 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.
15
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 $6.3 million and $6.8 million
for the three months ended March 31, 2003 and 2004, respectively. The increase
in cash flows provided by operating activities in 2004 as compared to 2003 was
due primarily to higher accrued expenses in 2004.
We have budgeted capital expenditures in 2004 of approximately $45.0 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 36 gross
wells (16.2 net) in the Gulf Coast region and 13 gross wells (9.4 net) in our
North Texas region in 2004. We intend to obtain a project financing facility 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 be between $20 and $30
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 $4.0 million and $21.7 million (including our $8.2 million
Barnett Shale acquisition) for three months ended March 31, 2003 and 2004,
respectively. Our drilling efforts resulted in the successful completion of 35
gross wells (9.4 net) in 2003 and six gross wells (2.1 net) in the Gulf Coast
region and eight gross wells (4.0 net) in the North Texas region in the three
months ended March 31, 2004. We have completed nine of these wells and are in
the process of completing five of these wells as of March 31, 2004.
Since inception through March 2004, Pinnacle has reported that it drilled 132
gross wells through March 31, 2004 and estimates that 80% of them were completed
by March 31, 2004. Pinnacle reportedly added approximately 10.0 Bcf of net
proved reserves through development drilling through December 31, 2003. Its
gross operated production has increased by approximately 75% since its inception
(to approximately 8.8 MMcf/d at March 31, 2004), and its total well count stands
at 378 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 March 31, 2004, CCBM had satisfied $2.3 million of its drilling
obligations on behalf of RMG.
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, 2005, 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. The initial borrowing base was
$12.0 million, and the borrowing base as of January 31, 2004 was $16.0 million.
The April 30, 2004 borrowing base determination is pending as of May 14, 2004.
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
16
additional "Facility B" under the Hibernia Facility. As such, the total
borrowing base under the Hibernia Facility as of December 31, 2003 and March 31,
2004 was $19.0 million and $16.0 million, respectively, of which $7.0 and zero,
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 outstanding balance under the Hibernia
Facility. As of March 31, 2004, no amounts were drawn 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.
At December 31, 2003 and March 31, 2004, amounts outstanding under the Hibernia
Facility totaled $7.0 million and zero, respectively, with an additional $12.0
million and $16.0 million, respectively, available for future borrowings. At
December 31, 2003 and March 31, 2004, one letter of credit was issued and
outstanding under the Hibernia Facility in the amount of $0.2 million.
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 March 31, 2004, the outstanding principal
balance of this note was $0.9 million and $0.7 million, respectively. In
connection 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.
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
17
capital leases for the three months ended March 31, 2003 and 2004 amounted to
$10,000 and $12,000, respectively, and accumulated DD&A on the leased equipment
at December 31, 2003 and March 31, 2004 amounted to $76,000 and $88,000,
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 March 31,
2004, the outstanding balance of the Subordinated Notes had been increased by
$5.3 million and $5.7 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. In the first quarter of 2004, Mellon
Ventures exercised 69,199 of its 1999 warrants on a cashless basis and received
49,135 shares which it sold in the 2004 public offering.
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).
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 will be 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 March 31, 2004, the outstanding balance of the Series B Preferred Stock had
been increased by $1.2 million (11,987 shares), respectively, for dividends paid
in kind. In addition to the foregoing, if we declare a cash dividend on our
common stock, the holders of shares of Series B Preferred Stock are entitled to
receive for each share of Series B Preferred Stock a cash dividend in the amount
of the cash dividend that would be received by a holder of the common stock into
which such share of Series B Preferred Stock is convertible on the record date
for such cash dividend. Unless all accrued dividends on the Series B Preferred
Stock shall have been paid and a sum sufficient for the payment thereof set
apart, no distributions may be paid on any Junior Stock (which includes the
common stock) (as defined in the Statement of Resolutions for the Series B
Preferred Stock) and no redemption of any Junior Stock shall occur other than
subject to certain exceptions.
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.
18
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.
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
March 31, 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.
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 $0.3 million and $0.4 million for the
three months ended March 31, 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 three months ended March 31, 2003 and 2004 was $1.57 and $1.73,
respectively.
19
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 three months ended March 31, 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 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 March 31, 2004 ceiling test computation, a price
sensitivity study also indicated that a 20% increase in commodity prices at
March 31, 2004 would have increased the pre-tax present value of future net
revenues ("NPV") by approximately $36.3 million. Conversely, a 20% decrease in
commodity prices at March 31, 2004 would have reduced our NPV by approximately
$34.6 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 March 31, 2004 and, accordingly, does not include
any potential changes in reserves due to second 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, 52.3 Bcfe of
proved undeveloped reserves, representing 64% and 54% of our total proved
reserves at December 31, 2003 and March 31, 2004, respectively. As of December
31, 2003 and March 31, 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 low historical depletion rate to continue until the high level of
nonproducing reserves to total proved reserves is reduced and the life of our
proved developed reserves is extended through development drilling and/or the
significant addition of new
20
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.
SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and
Intangible Assets," were issued by the FASB in June 2001 and became effective
for us on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141 requires
all business combinations initiated after June 30, 2001 to be accounted for
using the purchase method. Additionally, SFAS No. 141 requires companies to
disaggregate and report separately from goodwill certain intangible assets. SFAS
No. 142 establishes new guidelines for accounting for goodwill and other
intangible assets. Under SFAS No. 142, goodwill and certain other intangible
assets are not amortized but rather are reviewed annually for impairment.
Natural gas and oil mineral rights held under lease and other contractual
arrangements representing the right to extract such reserves for both
undeveloped and developed leaseholds may have to be classified separately from
natural gas and oil properties as intangible assets on our consolidated balance
sheets. In addition, the disclosures required by SFAS No. 141 and 142 relative
to intangibles would be included in the notes to the consolidated financial
statements. Historically, we, like many other natural gas and oil companies,
have included these rights as part of natural gas and oil properties, even after
SFAS No. 141 and 142 became effective.
As it applies to companies like us that have adopted full cost accounting for
natural gas and oil activities, we understand that this interpretation of SFAS
No. 141 and 142 would only affect our balance sheet classification of proved
natural gas and oil leaseholds acquired after June 30, 2001 and all of our
unproved natural gas and oil leaseholds. We would not be required to reclassify
proved reserve leasehold acquisitions prior to June 30, 2001 because we did not
separately value or account for these costs prior to the adoption date of SFAS
No. 141. Our results of operations and cash flows would not be affected, since
these natural gas and oil mineral rights held under lease and other contractual
arrangements representing the right to extract natural gas and oil reserves
would continue to be amortized in accordance with full cost accounting rules.
As of March 31, 2004 and December 31, 2003 we had leasehold costs incurred of
approximately $7.2 million and $5.5 million, respectively, that would be
classified on our consolidated balance sheet as "intangible leasehold costs" if
we applied the interpretation discussed above.
We will continue to classify our natural gas and oil mineral rights held under
lease and other contractual rights representing the right to extract such
reserves as tangible oil and natural gas properties until further guidance is
provided.
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.
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.
21
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 March 31, 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
yearend 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 Natural Gas Collars 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 March 31,
2003 and 2004 were 63,000 Bbls and 27,300 Bbls, respectively. Total natural gas
hedged under swaps and collars in the three months ended March 31, 2003 and 2004
were 540,000 MMBtu and 726,000 MMBtu respectively. The net gains and (losses)
realized by us under such hedging arrangements were $(1.2) million and $0.1
million for the three months ended March 31, 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
22
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 March 31, 2004, $0.2 million and $0.8 million, net
of tax of $0.1 million and $0.4, 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 March
2004, a $0.10 change in the price per Mcf of gas sold would have changed revenue
by $134,000. A $0.70 change in the price per barrel of oil would have changed
revenue by $61,000.
The table below summarizes our total natural gas production volumes subject to
derivative transactions during the three months ended March 31, 2004 and the
weighted average NYMEX reference price for those volumes.
Natural Gas Swaps Natural Gas Collars
- ------------------------ --------------------------
Volumes (MMBtu) 180,000 Volumes (MMBtu) 546,000
Average price ($/MMBtu) $ 6.50 Average price ($/MMBtu)
Floor $ 4.10
Ceiling $ 7.00
The table below summarizes our total crude oil production volumes subject to
derivative transactions for the three months ended March 31, 2004 and the
weighted average NYMEX reference price for those volumes.
Crude Oil Swaps Crude Oil Collars
- ---------------------- ----------------------
Volumes (Bbls) 27,000 Volumes (Bbls) -
Average price ($/Bbls) $ 30.36 Average price ($/Bbls)
Floor $ -
Ceiling $ -
At March 31, 2003 and 2004 we had the following outstanding hedge positions:
As of 3/31/2003
- --------------------------------------------------------------------------------------------------
Contract Volumes
---------------------------
Average Average Average
Quarter BBls MMbtu Fixed Price Floor Price Ceiling Price
- ---------------------- ------------ ------------ ------------ ------------ -------------
Second Quarter 2003 27,300 $ 24.85
Second Quarter 2003 36,000 $ 23.50 $ 26.50
Second Quarter 2003 273,000 4.70
Second Quarter 2003 546,000 3.40 5.25
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
23
As of 3/31/2004
- --------------------------------------------------------------------------------------------------
Contract Volumes
---------------------------
Average Average Average
Quarter BBls MMbtu Fixed Price Floor Price Ceiling Price
- ---------------------- ------------ ------------ ------------ ------------ -------------
Second Quarter 2004 27,300 $ 31.55
Second Quarter 2004 1,001,000 $ 4.40 $ 5.86
Third Quarter 2004 9,300 33.33
Third Quarter 2004 828,000 4.19 6.07
Fourth Quarter 2004 829,000 4.41 6.47
First Quarter 2005 450,000 4.64 8.00
During May 2004, we entered into costless collar arrangements covering 728,000
MMBtu of natural gas for October 2004 through March 2005 production with an
average floor of $5.53 and a ceiling of $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, a project facility to finance a majority 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.
24
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.
25
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 March 31, 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 March 31,
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.
26
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 February 2004, in connection with our public offering, Mellon Ventures,
L.P. exercised all of its warrants to purchase 168,422 shares of our common
stock issued in 2002 and 61,199 of its warrants to purchase shares issued in
1999 on a cashless "net exercise" basis. Mellon Ventures received 36,570 shares
and 49,135 shares of common stock respectively from the exercise of these
warrants. In May 2004, Mellon Ventures exercised all 206,820 of its remaining
warrants to purchase shares issued in 1999 on a cashless "net exercise" basis
and received 156,557 shares of common stock. 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 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
None
Item 5 - Other Information
None.
Item 6 - Exhibits and Reports on Form 8-K
Exhibits
Exhibit
Number Description
+2.1 -- Combination Agreement by and among the Company, Carrizo
Production, Inc., Encinitas Partners Ltd., La Rosa Partners
Ltd., Carrizo Partners Ltd., Paul B. Loyd, Jr., Steven A.
Webster, S.P. Johnson IV, Douglas A.P. Hamilton and Frank A.
Wojtek dated as of September 6, 1997 (incorporated herein by
reference to Exhibit 2.1 to the Company's Registration
Statement on Form S-1 (Registration No. 333-29187)).
+3.1 -- Amended and Restated Articles of Incorporation of the
Company (incorporated herein by reference to Exhibit 3.1 to
the Company's Annual Report on Form 10-K for the year ended
December 31, 1997).
+3.2 -- Amended and Restated Bylaws of the Company, as amended by
Amendment No. 1 (incorporated herein by reference to Exhibit
3.2 to the Company's Registration Statement on Form 8-A
(Registration No. 000-22915) Amendment No. 2 (incorporated
herein by reference to Exhibit 3.2 to the Company's Current
Report on Form 8-K dated December 15, 1999) and Amendment No.
3 (Incorporated herein by reference to Exhibit 3.1 to the
Company's Current Report on Form 8-K dated February 20, 2002).
+3.3 -- Statement of Resolution dated February 20, 2002 establishing
the Series B Convertible Participating Preferred Stock
providing for the designations, preferences, limitations and
relative rights, voting, redemption and other rights thereof
(Incorporated herein by reference to Exhibit 99.2 to the
Company's Current Report on Form 8-K dated February 20, 2002).
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.
27
32.2 -- CFO Certification Pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002.
+ Incorporated herein by reference as indicated.
Reports on Form 8-K
The Company filed a Current Report on Form 8-K on January 23, 2004
announcing operating results for the quarter and year ended December 31, 2003
(information furnished not filed); a Current Report on Form 8-K on March 9, 2004
announcing the Barnett Shale Acquisition (information furnished not filed) and
the closing of the over-allotment option in the Company's public offering; and a
Current Report on Form 8-K on March 25, 2004 announcing financial results for
the quarter and year ended December 31, 2003 (information furnished not filed).
28
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this Report to be signed on its
behalf by the undersigned, thereunto duly authorized.
Carrizo Oil & Gas, Inc.
(Registrant)
Date: May 17, 2004 By: /s/S. P. Johnson, IV
-------------------------
President and Chief Executive Officer
(Principal Executive Officer)
Date: May 17, 2004 By: /s/Paul F. Boling
----------------------
Chief Financial Officer
(Principal Financial and
Accounting Officer)