SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 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 November 5, 2004, the latest practicable date, was
22,011,623.
CARRIZO OIL & GAS, INC.
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2004
INDEX
PART I. FINANCIAL INFORMATION PAGE
Item 1. Consolidated Balance Sheets (Unaudited)
- As of December 31, 2003 and September 30, 2004 2
Consolidated Statements of Income (Unaudited)
- For the three and nine month periods ended September 30, 2003 and 2004 3
Consolidated Statements of Cash Flows (Unaudited)
- For the nine-month periods ended September 30, 2003 and 2004 4
Notes to Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations 16
Item 3. Quantitative and Qualitative Disclosure About
Market Risk 31
Item 4. Controls and Procedures 32
PART II. OTHER INFORMATION
Items 1-6. 33
SIGNATURES 35
CARRIZO OIL & GAS, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
ASSETS December 31, September 30,
2003 2004
-------------- --------------
(In thousands)
CURRENT ASSETS:
Cash and cash equivalents $ 3,322 $ 3,542
Accounts receivable, trade (net of allowance for doubtful accounts of
none at December 31, 2003 and September 30, 2004, respectively) 8,970 12,118
Advances to operators 1,877 1,453
Deposits 56 156
Other current assets 100 1,637
-------------- --------------
Total current assets 14,325 18,906
PROPERTY AND EQUIPMENT, net (full-cost method of
accounting for oil and natural gas properties) 135,273 184,736
Investment in Pinnacle Gas Resources, Inc. 6,637 5,784
Deferred financing costs 479 1,156
Other assets 89 61
-------------- --------------
$ 156,803 $ 210,643
============== ==============
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade $ 19,515 $ 22,549
Accrued liabilities 1,057 6,039
Advances for joint operations 3,430 1,990
Current maturities of long-term debt 1,037 305
Current maturities of seismic obligation payable 1,103 -
-------------- --------------
Total current liabilities 26,142 30,883
LONG-TERM DEBT 34,113 47,228
ASSET RETIREMENT OBLIGATION 883 1,086
DEFERRED INCOME TAXES 12,479 16,365
COMMITMENTS AND CONTINGENCIES (Note 7)
CONVERTIBLE PARTICIPATING PREFERRED STOCK (10,000,000 shares
of preferred stock authorized, of which 150,000 are shares designated
as convertible participating shares, with 71,987 and zero convertible
participating shares issued and outstanding at December 31, 2003 and
September 30, 2004, respectively) (Note 8) 7,114 -
SHAREHOLDERS' EQUITY:
Warrants (3,262,821 and 334,210 outstanding at December 31,
2003 and September 30, 2004, respectively) 780 80
Common stock, par value $0.01 (40,000,000 shares authorized with
14,591,348 and 21,974,121 issued and outstanding at December 31,
2003 and September 30, 2004, respectively) 146 220
Additional paid in capital 65,103 98,406
Retained earnings 10,229 17,591
Accumulated other comprehensive loss (186) (1,216)
-------------- --------------
76,072 115,081
-------------- --------------
$ 156,803 $ 210,643
============== ==============
The accompanying notes are an integral part
of these consolidated financial statements.
2
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
For the Three For the Nine
Months Ended Months Ended
September 30, September 30,
--------------------------- ---------------------------
2003 2004 2003 2004
------------ ------------ ------------ ------------
(In thousands except per share amounts)
OIL AND NATURAL GAS REVENUES $ 10,123 $ 12,274 $ 29,615 $ 35,107
COSTS AND EXPENSES:
Oil and natural gas operating expenses
(exclusive of depreciation shown separately below) 1,587 2,126 5,071 5,849
Depreciation, depletion and amortization 3,086 3,709 8,727 10,562
General and administrative 1,624 1,296 4,274 5,075
Accretion expense related to asset retirement obligations 11 8 29 21
Stock option compensation (benefit) 296 (139) 319 617
------------ ------------ ------------ ------------
Total costs and expenses 6,604 7,000 18,420 22,124
------------ ------------ ------------ ------------
OPERATING INCOME 3,519 5,274 11,195 12,983
OTHER INCOME AND EXPENSES:
Other income and expenses (185) 269 (163) (315)
Interest income 13 22 50 45
Interest expense (103) (865) (419) (1,195)
Interest expense, related parties (599) - (1,773) (1,079)
Capitalized interest 696 769 2,176 2,092
------------ ------------ ------------ ------------
INCOME BEFORE INCOME TAXES 3,341 5,469 11,066 12,531
INCOME TAXES (Note 6) 1,259 2,079 4,053 4,820
------------ ------------ ------------ ------------
NET INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE 2,082 3,390 7,013 7,711
DIVIDENDS AND ACCRETION ON PREFERRED STOCK 190 - 552 350
------------ ------------ ------------ ------------
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS
BEFORE CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE 1,892 3,390 6,461 7,361
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE,
NET OF INCOME TAXES - - 128 -
------------ ------------ ------------ ------------
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS $ 1,892 $ 3,390 $ 6,333 $ 7,361
============ ============ ============ ============
BASIC EARNINGS PER COMMON SHARE BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 0.13 $ 0.15 $ 0.46 $ 0.38
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, NET OF INCOME TAXES - - (0.01) -
------------ ------------ ------------ ------------
BASIC EARNINGS PER COMMON SHARE $ 0.13 $ 0.15 $ 0.45 $ 0.38
============ ============ ============ ============
DILUTED EARNINGS PER COMMON SHARE BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 0.11 $ 0.15 $ 0.39 $ 0.34
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, NET OF INCOME TAXES - - (0.01) -
------------ ------------ ------------ ------------
DILUTED EARNINGS PER COMMON SHARE $ 0.11 $ 0.15 $ 0.38 $ 0.34
============ ============ ============ ============
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 Nine
Months Ended
September 30,
---------------------------
2003 2004
------------ ------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income before cumulative effect of change in accounting principle $ 7,013 $ 7,711
Adjustment to reconcile net income to net
cash provided by operating activities-
Depreciation, depletion and amortization 8,727 10,562
Discount accretion 93 213
Stock option compensation (benefit) 319 617
Equity in loss of Pinnacle Gas Resources, Inc. 177 853
Deferred income taxes 3,918 4,652
Changes in assets and liabilities-
Accounts receivable (436) (3,148)
Other assets 326 (1,925)
Accounts payable 1,682 (889)
Other liabilities 627 (88)
------------ ------------
Net cash provided by operating activities 22,446 18,558
------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (19,305) (58,954)
Change in capital expenditure accrual 1,864 5,688
Advances to operators (2,196) 424
Advances for joint operations 1,672 (1,440)
------------ ------------
Net cash used in investing activities (17,965) (54,282)
------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from the sale of common stock 599 24,448
Advances under the borrowing base facility - 19,000
Debt repayments (5,397) (7,504)
------------ ------------
Net cash provided by (used in) financing activities (4,798) 35,944
------------ ------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (317) 220
CASH AND CASH EQUIVALENTS, beginning of period 4,743 3,322
------------ ------------
CASH AND CASH EQUIVALENTS, end of period $ 4,426 $ 3,542
============ ============
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest (net of amounts capitalized) $ - $ 182
============ ============
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 u.s. 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 consolidated financial statements and notes thereto
included in the Company's Annual Report on Form 10-K for the year ended December
31, 2003.
2. MAJOR CUSTOMERS:
The Company sold oil and natural gas production representing more than 10% of
its oil and natural gas revenues as follows:
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
----------------------- -----------------------
2003 2004 2003 2004
---------- ---------- ---------- ----------
Cokinos Natural Gas Company 11% 16% 15% 21%
Gulfmark Energy, Inc. 15% - 17% -
WMJ Investments Corp. 12% 11% 14% 13%
Texon L.P. - 10% - 16%
Brigham 19% - - -
Reichmann Petroleum - 10% - -
3. EARNINGS PER COMMON SHARE:
Supplemental earnings per share information is provided below:
For the Three Months Ended September 30,
----------------------------------------------------------------------------------
(In thousands except share and per share amounts)
Income Shares Per-Share Amount
-------------------------- -------------------------- --------------------------
2003 2004 2003 2004 2003 2004
------------ ------------ ------------ ------------ ------------ ------------
Basic Earnings per Common Share
Net income available to common shareholders $ 1,892 $ 3,390 14,264,639 21,909,855 $ 0.13 $ 0.15
============ ============
Dilutive effect of Stock Options, Warrants and
Preferred Stock conversions - - 2,625,991 1,094,227
------------ ------------ ------------ ------------
Diluted Earnings per Common Share
Net income available to common shareholders
plus assumed conversions $ 1,892 $ 3,390 16,890,630 23,004,082 $ 0.11 $ 0.15
============ ============ ============ ============ ============ ============
5
For the Nine Months Ended September 30,
----------------------------------------------------------------------------------
(In thousands except share and per share amounts)
Income Shares Per-Share Amount
-------------------------- -------------------------- --------------------------
2003 2004 2003 2004 2003 2004
------------ ------------ ------------ ------------ ------------ ------------
Basic Earnings per Common Share
Net income available to common shareholders
before cumulative effect of change
in accounting principle $ 6,461 $ 7,361 14,224,893 19,255,156 $ 0.46 $ 0.38
============ ============
Dilutive effect of Stock Options, Warrants and
Preferred Stock conversions - - 2,349,345 2,291,173
------------ ------------ ------------ ------------
Diluted Earnings per Common Share
Net income available to common shareholders
plus assumed conversions before cumulative
effect of change in accounting principle $ 6,461 $ 7,361 16,574,238 21,546,329 $ 0.39 $ 0.34
============ ============ ============ ============ ============ ============
For the Nine Months Ended September 30,
----------------------------------------------------------------------------------
(In thousands except share and per share amounts)
Income Shares Per-Share Amount
-------------------------- -------------------------- --------------------------
2003 2004 2003 2004 2003 2004
------------ ------------ ------------ ------------ ------------ ------------
Cumulative effect of change
in accounting principle, net of income taxes $ (128) $ - 14,224,893 19,255,156 $ (0.01) $ -
============ ============
Basic Earnings per Common Share
Net loss available to common shareholders - - 2,349,345 2,291,173
------------ ------------ ------------ ------------
Dilutive effect of Stock Options, Warrants and
Preferred Stock conversions
Diluted Earnings per Common Share
Net loss available to common shareholders
plus assumed conversions $ (128) $ - 16,574,238 21,546,329 $ (0.01) $ -
============ ============ ============ ============ ============ ============
For the Nine Months Ended September 30,
----------------------------------------------------------------------------------
(In thousands except share and per share amounts)
Income Shares Per-Share Amount
-------------------------- -------------------------- --------------------------
2003 2004 2003 2004 2003 2004
------------ ------------ ------------ ------------ ------------ ------------
Basic Earnings per Common Share
Net income available to common shareholders $ 6,333 $ 7,361 14,224,893 19,255,156 $ 0.45 $ 0.38
============ ============
Dilutive effect of Stock Options, Warrants and
Preferred Stock conversions - - 2,349,345 2,291,173
------------ ------------ ------------ ------------
Diluted Earnings per Common Share
Net income available to common shareholders
plus assumed conversions $ 6,333 $ 7,361 16,574,238 21,546,329 $ 0.38 $ 0.34
============ ============ ============ ============ ============ ============
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 57,000 and 30,000 stock options, during the three months ended
September 30, 2003 and 2004, respectively, which were antidilutive and were not
included in the calculation because the exercise price of these instruments
exceeded the underlying market value of the options and warrants. The Company
had outstanding 129,000 and 30,000 stock options and 252,632 and zero warrants
during the nine months ended September 30, 2003 and 2004, respectively, which
were antidilutive because the exercise price of these instruments exceeded the
underlying market value of the options and warrants. At September 30, 2003 and
2004, the Company also had 1,202,791 and zero shares, respectively, based on the
assumed conversion of the Series B Convertible Participating Preferred Stock,
that were antidilutive and were not included in the calculation. The shares of
Series B Convertible Participating Preferred Stock were antidilutive and were
not included in the calculation for the periods ended September 30, 2003 and
2004.
6
During the fourth quarter of 2004, the Company discovered an arithmetical error
in the calculation of the dilutive effect of stock options and warrants for the
second quarter of 2004. Net income of $1.985 million and $3.971 million for the
three and six months ended June 30, 2004, respectively, were correct as
previously reported. The following table shows the previously reported share and
per-share amounts, the corrected amounts and the effect of the correction:
For the Three Months Ended June 30, 2004
----------------------------------------------------------------------------------------------
Shares Per-Share Amount
---------------------------------------------- ----------------------------------------------
As Previously As As Previously As
Reported Corrected Change Reported Corrected Change
-------------- -------------- -------------- -------------- -------------- --------------
Basic Earnings per Common Share
Net Income 19,213,010 19,213,010 - $ 0.10 $ 0.10 $ -
Dilutive effect of Stock Options,
Warrants and Preferred
Stock conversion 1,080,091 2,745,637 1,665,546 - (0.01) (0.01)
-------------- -------------- -------------- -------------- -------------- --------------
Diluted Earnings per Common Share
Net Income available to common
shareholders plus
assumed conversions 20,293,101 21,958,647 1,665,546 $ 0.10 $ 0.09 $ (0.01)
============== ============== ============== ============== ============== ==============
For the Six Months Ended June 30, 2004
----------------------------------------------------------------------------------------------
Shares Per-Share Amount
---------------------------------------------- ----------------------------------------------
As Previously As As Previously As
Reported Corrected Change Reported Corrected Change
-------------- -------------- -------------- -------------- -------------- --------------
Basic Earnings per Common Share
Net Income 17,913,220 17,913,220 - $ 0.22 $ 0.22 $ -
Dilutive effect of Stock Options,
Warrants and Preferred
Stock conversion 1,001,630 2,888,989 1,887,359 (0.01) (0.03) (0.02)
-------------- -------------- -------------- -------------- -------------- --------------
Diluted Earnings per Common Share
Net Income available to common
shareholders plus
assumed conversions 18,914,850 20,802,209 1,887,359 $ 0.21 $ 0.19 $ (0.02)
============== ============== ============== ============== ============== ==============
4. LONG-TERM DEBT:
At December 31, 2003 and September 30, 2004, long-term debt consisted of the
following:
December 31, September 30,
2003 2004
------------- -------------
(in thousands)
Credit Facility $ 7,000 $ 19,000
Senior subordinated notes - 28,178
Senior subordinated notes, related parties 26,992 -
Capital lease obligations 295 161
Non-recourse note payable to
Rocky Mountain Gas, Inc. 863 194
------------- -------------
35,150 47,533
Less: current maturities (1,037) (305)
------------- -------------
$ 34,113 $ 47,228
============= =============
Credit Facility
On September 30, 2004, the Company entered into a Second Amended and Restated
Credit Agreement with Hibernia National Bank and Union Bank of California, N.A.
(the "Credit Facility"), which matures on September 30, 2007. The Credit
Facility amended, restated and extended the Company's prior credit facility
(such prior facility herein referred to as the "Prior Credit Facility"). The
Credit Facility provides for (1) a revolving line of credit of up to the lesser
of the Facility A Borrowing Base and $75.0 million and (2) a term loan facility
of up to the lesser of the Facility B Borrowing Base and $25.0 million. It is
secured by substantially all of the Company's assets and is guaranteed by the
Company's subsidiary.
The Facility A Borrowing Bases will be determined by the lenders at least
semi-annually on each November 1 and May 1. The initial Facility A Borrowing
Base is $28.0 million. The initial Facility B Borrowing Base is $0.00 and is
subject to determination by the
7
lenders in their sole discretion. The Company and the lenders may each request
one unscheduled borrowing base determination subsequent to each scheduled
determination. The Facility A Borrowing Base will at all times equal the
Facility A Borrowing Base most recently determined by the lenders, less
quarterly borrowing base reductions required subsequent to such determination.
The lenders will reset the Facility A Borrowing Base amount at each scheduled
and each unscheduled borrowing base determination date.
If the outstanding principal balance of the revolving loans under the Credit
Facility exceeds the Facility A Borrowing Base at any time (including, without
limitation, due to a quarterly borrowing base reduction (as described above)),
the Company has 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 the lenders' opinion to
increase the Facility A 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 revolving loan, the interest rate will be, at the Company's option, (1)
the Eurodollar Rate, plus an applicable margin equal to 2.375% if the amount
borrowed is greater than or equal to 90% of the Facility A Borrowing Base, 2.0%
if the amount borrowed is less than 90%, but greater than or equal to 50% of the
Facility A Borrowing Base, or 1.625% if the amount borrowed is less than 50% of
the Facility A Borrowing Base; or (2) the Base Rate, plus an applicable margin
of 0.375% if the amount borrowed is greater than or equal to 90% of the Facility
A Borrowing Base. The interest rate on each term loan will be, at the Company's
option, (1) the Eurodollar Rate, plus an applicable margin to be determined by
the lenders; or (2) the Base Rate, plus an applicable margin to be determined by
the lenders. 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 Credit
Facility, including, but not limited to the maintenance of the following
financial covenants: (1) a minimum current ratio of 1.0 to 1.0 (including
availability under the borrowing base), (2) a minimum quarterly debt services
coverage of 1.25 times, (3) a minimum shareholders' equity equal to $100.0
million, plus 100% of all subsequent common and preferred equity contributed by
shareholders' subsequent to June 30, 2004, plus 50% of all positive earnings
occurring subsequent to June 30, 2004, plus, 180 days after issuance of any
second-lien subordinated debt with another lender ("the Secured Subordinated
Debt"), an amount equal to the difference, if positive, of (A) 50% of the net
proceeds from the issuance less (B) 100% of all common and preferred equity
contributed by shareholders from September 30, 2004 to the date of the issuance
of any Secured Subordinated Debt, and (4) a maximum total recourse debt to
EBITDA ratio (as defined in the Credit Facility) of not more than 3.0 to 1.0.
The Credit Facility also places restrictions on additional indebtedness,
dividends to shareholders, liens, investments, mergers, acquisitions, asset
dispositions, asset pledges and mortgages, change of control, repurchase or
redemption for cash of the Company's common stock, speculative commodity
transactions and other matters.
At December 31, 2003, amounts outstanding under the Prior Credit Facility
totaled $7.0 million with an additional $12.0 million available for future
borrowings. At September 30, 2004, amounts outstanding under the Credit Facility
totaled $19.0 million, with an additional $9.0 million available for future
borrowings. At December 31, 2003, no letters of credit were issued and
outstanding under the Prior Credit Facility. At September 30, 2004, no letters
of credit were issued and outstanding under the Credit Facility. Subsequently,
the amount outstanding was reduced to $13.0 million on November 2, 2004,
following the Company's new debt financing ("Senior Secured Notes") on October
29, 2004 (see Note 12 and Subsequent Event for further discussion).
Rocky Mountain Gas, Inc. Note
On June 29, 2001, CCBM, Inc., a wholly owned subsidiary of the Company ("CCBM"),
issued a non-recourse promissory note payable in the amount of $7.5 million to
RMG as consideration for certain interests in oil and natural gas leases held by
RMG in Wyoming and Montana. The RMG note is payable in 41-monthly principal
payments of $0.1 million plus interest at 8% per annum commencing July 31, 2001
with the balance due December 31, 2004. The RMG note is secured solely by CCBM's
interests in the oil and natural gas leases in Wyoming and Montana. In
connection with the Company's investment in Pinnacle Gas Resources, Inc., the
Company received a reduction in the principal amount of the RMG note of
approximately $1.5 million and relinquished the right to certain revenues
related to the properties contributed to Pinnacle. During the second quarter of
2004, CCBM, Inc., relinquished a portion of its interests in certain oil and
natural gas leases and reduced the principal due on the note by $0.3 million.
Capital Leases
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
8
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 September 30, 2003 and 2004 amounted
to $14,000 and $11,000, respectively. DD&A on the capital leases for the nine
months ended September 30, 2003 and 2004 amounted to $35,000 and $34,000,
respectively, and accumulated DD&A on the leased equipment at December 31, 2003
and September 30, 2004 amounted to $76,000 and $111,000, respectively.
Senior Subordinated Notes and Related Securities
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 September 30, 2004, the outstanding balance of the Subordinated
Notes had been increased by $5.3 million and $6.4 million respectively, for such
interest paid in kind. During the nine months ended September 30, 2004, Mellon
Ventures, L.P., JPMorgan Partners (23A SBIC), Steven A. Webster and Douglas A.
P. Hamilton exercised warrants to purchase 276,019, 2,208,152, 92,006 and 92,006
shares of common stock, respectively, on a cashless exercise basis for a total
of 205,692, 1,684,949, 70,205 and 70,205 shares of common stock, respectively,
and Paul B. Loyd, Jr., exercised warrants to purchase 92,006 shares for a total
of 92,006 shares of common stock. As a result, no warrants to purchase shares
remain outstanding from the warrants originally issued in December 1999.
On June 7, 2004, an unaffiliated third party (the "Subordinated Notes
Purchaser") purchased all the outstanding Subordinated Notes from the original
note holders. In exchange for a $0.4 million amendment fee, certain terms and
conditions of the Subordinated Notes were amended, to provide for, among other
things, (1) a one year extension of the maturity to December 15, 2008, (2) a one
year extension, through December 15, 2005, of the paid-in-kind ("PIK") interest
option to pay-in-kind 60% of the interest due each period by increasing the
principal balance by a like amount (the "PIK option"), (3) an additional one
year option to extend the PIK option through December 15, 2006 at an annual
interest rate on the deferred amount of 10% and the payment of a one-time fee
equal to 0.5% of the principal then outstanding and (4) additional flexibility
to obtain a separate project financing facility in the future. The amendment fee
will be amortized over the remaining life of the Subordinated Notes.
The Company is subject to certain covenants under the terms of the Subordinated
Notes securities purchase agreement, including but not limited to, (a)
maintenance of a specified tangible net worth, (b) maintenance of a ratio of
EBITDA (earnings before interest, taxes, depreciation and amortization) to
quarterly Debt Service (as defined in the agreement) of not less than 1.00 to
1.00, (c) a limitation of its capital expenditures to an amount equal to the
Company's EBITDA for the immediately prior fiscal year (unless approved by the
Company's Board of Directors and a JPMorgan Partners, LLC appointed director)
and (d) a limitation on our Total Debt (as defined in the securities purchase
agreement) to 3.5 times EBITDA for any twelve month period.
At September 30, 2004, the Company was in compliance with all of its debt
covenants, except for the minimum current ratio covenant in the Credit Facility
which was approximately $0.2 million below the minimum requirement. Shortly
thereafter, this condition was cured on October 29, 2004 by the issuance of the
Senior Secured Notes. On November 10, 2004, the lenders under the Credit
Facility agreed in a letter to the Company to waive the short period of
noncompliance with this covenant.
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
9
exchange for the contribution of these assets, CCBM and RMG each received 37.5%
of the common stock of Pinnacle ("Pinnacle Common Stock") as of the closing date
and options to purchase Pinnacle Common Stock ("Pinnacle Stock Options"). CCBM
no longer has a drilling obligation in connection with the oil and natural gas
leases contributed to Pinnacle.
Simultaneously with the contribution of these assets, the CSFB Parties
contributed approximately $17.6 million of cash to Pinnacle in return for the
Redeemable Preferred Stock of Pinnacle ("Pinnacle Preferred Stock"), 25% of the
Pinnacle Common Stock as of the closing date and warrants to purchase Pinnacle
Common Stock ("Pinnacle Warrants"). The CSFB Parties also agreed to contribute
additional cash, under certain circumstances, of up to approximately $11.8
million to Pinnacle to fund future drilling, development and acquisitions. The
CSFB Parties currently have greater than 50% of the voting power of the Pinnacle
capital stock through their ownership of Pinnacle Common Stock and Pinnacle
Preferred Stock.
Immediately following the contribution and funding, Pinnacle used approximately
$6.2 million of the proceeds from the funding to acquire an approximate 50%
working interest in existing leases and acreage prospective for coalbed methane
development in the Powder River Basin of Wyoming from Gastar Exploration, Ltd.
Pinnacle also agreed to fund up to $14.9 million of future drilling and
development costs on these properties on behalf of Gastar prior to December 31,
2005. The drilling and development work will be done under the terms of an
earn-in joint venture agreement between Pinnacle and Gastar. The majority of
these leases are part of, or adjacent to, the Bobcat project area. All of CCBM
and RMG's interests in the Bobcat project area, the only producing coalbed
methane property owned by CCBM prior to the transaction, were contributed to
Pinnacle.
Prior to and in connection with its contribution of assets to Pinnacle, CCBM
paid RMG approximately $1.8 million in cash as part of its outstanding purchase
obligation on the coalbed methane property interests CCBM previously acquired
from RMG. As of June 30, 2003, approximately $1.1 million of the remaining
balance of CCBM's obligation to RMG is scheduled to be paid in monthly
installments of approximately $52,805 through November 2004 and a balloon
payment on December 31, 2004. As of September 30, 2004, the remaining balance on
this obligation was approximately $0.2 million. The RMG note is secured solely
by CCBM's interests in the remaining oil and natural gas leases in Wyoming and
Montana. In connection with the Company's investment in Pinnacle, the Company
received a reduction in the principal amount of the RMG note of approximately
$1.5 million and relinquished the right to receive certain revenues related to
the properties contributed to Pinnacle.
CCBM continues its coalbed methane business activities and, in addition to its
interest in Pinnacle, owns direct interests in acreage in coalbed methane
properties in the Castle Rock project area in Montana and the Oyster Ridge
project area in Wyoming, which were not contributed to Pinnacle. CCBM and RMG
will continue to conduct exploration and development activities on these
properties as well as pursue other potential acquisitions. Other than indirectly
through Pinnacle, CCBM currently has no proved reserves of, and is no longer
receiving revenue from, coalbed methane gas.
As of December 31, 2003, on a fully diluted basis, assuming that all parties
exercised their Pinnacle Warrants and Pinnacle Stock Options, the CSFB Parties,
CCBM and RMG would have ownership interests of approximately 46.2%, 26.9% and
26.9%, respectively. In February 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
September 30, 2004.
6. INCOME TAXES:
The Company provided deferred income taxes at the rate of 35%, which also
approximates its statutory rate, that amounted to $1.2 million and $2.0 million
for the three months ended September 30, 2003 and 2004, respectively, and $3.9
million and $4.7 million for the nine months ended September 30, 2003 and 2004,
respectively.
10
7. COMMITMENTS AND CONTINGENCIES:
>From time to time, the Company is party to certain legal actions and claims
arising in the ordinary course of business. While the outcome of these events
cannot be predicted with certainty, management does not expect these matters to
have a materially adverse effect on the financial position of the Company.
The operations and financial position of the Company continue to be affected
from time to time in varying degrees by domestic and foreign political
developments as well as legislation and regulations pertaining to restrictions
on oil and natural gas production, imports and exports, natural gas regulation,
tax increases, environmental regulations and cancellation of contract rights.
Both the likelihood and overall effect of such occurrences on the Company vary
greatly and are not predictable.
8. CONVERTIBLE PARTICIPATING PREFERRED STOCK:
In February 2002, the Company consummated the sale of 60,000 shares of
Convertible Participating Series B Preferred Stock (the "Series B Preferred
Stock") and warrants to purchase 252,632 shares of common stock for an aggregate
purchase price of $6.0 million. The Company sold 40,000 and 20,000 shares of
Series B Preferred Stock and 168,422 and 84,210 warrants to Mellon Ventures,
Inc. and Steven A. Webster, respectively. The Series B Preferred Stock was
convertible into common stock by the investors at a conversion price of $5.70
per share, subject to adjustments, and was initially convertible into 1,052,632
shares of common stock. Dividends on the Series B Preferred Stock were payable
in either cash at a rate of 8% per annum or, at the Company's option, by payment
in kind of additional shares of the same series of preferred stock at a rate of
10% per annum. At December 31, 2003 and through the conversion dates specified
below, the outstanding balance of the Series B Preferred Stock has been
increased by $1.2 million (11,987 shares) and $1.5 million (15,133 shares),
respectively, for dividends paid in kind. The Series B Preferred Stock was
redeemable at varying prices in whole or in part at the holders' option after
three years or at the Company's option at any time. The Series B Preferred Stock
also participated in any dividends declared on the common stock. Holders of the
Series B Preferred Stock would have received a liquidation preference upon the
liquidation of, or certain mergers or sales of substantially all assets
involving, the Company. Such holders also had the option of receiving a change
of control repayment price upon certain deemed change of control transactions.
Mellon Ventures, Inc. converted all of its Series B Preferred Stock
(approximately 49,938 shares) into 876,099 shares of common stock on May 25,
2004. Steven A. Webster converted all of his Series B Preferred Stock
(approximately 25,195 shares) into 442,025 shares of common stock on June 30,
2004. As a result, no shares of Series B Preferred Stock remain outstanding. The
warrants have a five-year term and entitle the holders to purchase up to 252,632
shares of Carrizo's common stock at a price of $5.94 per share, subject to
adjustments, and are exercisable at any time after issuance. The warrants may be
exercised on a cashless exercise basis. During the six months ended June 30,
2004, Mellon Ventures, Inc. exercised all of its 168,422 warrants on a cashless
exercise basis for a total of 36,570 shares of common stock.
Net proceeds of the sale of the Series B Preferred Stock were approximately $5.8
million and were used primarily to fund the Company's ongoing exploration and
development program and general corporate purposes.
9. SHAREHOLDERS' 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 shareholders. The Company did not receive any
proceeds from the shares sold by the selling shareholders. 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 an $8.2 million Barnett
Shale acquisition on February 27, 2004.
The Company issued 208,168 and 7,382,773 shares of common stock during the nine
months ended September 30, 2003 and 2004, respectively. The shares issued during
the nine months ended September 30, 2003 were the result of the exercise of
options granted under the Company's Incentive Plan. The shares issued during the
nine months ended September 30, 2004 consisted of 3,655,500 shares issued
through the public offering, 2,159,627 shares issued through the exercise of
warrants, 1,318,124 shares issued through the conversion of Series B Preferred
Stock and the balance issued through the exercise of options granted under the
Company's Incentive Plan.
In June of 1997, the Company established the Incentive Plan of Carrizo Oil &
Gas, Inc. (the "Incentive Plan"). In October 1995, the FASB issued SFAS No. 123,
"Accounting for Stock-Based Compensation," which requires the Company to record
stock-based compensation at fair value. In December 2002, the FASB issued SFAS
No. 148, "Accounting for Stock Based Compensation -
11
Transition and Disclosure." The Company has adopted the disclosure requirements
of SFAS No. 148 and has elected to record employee compensation expense
utilizing the intrinsic value method permitted under Accounting Principles Board
(APB) Opinion No. 25, "Accounting for Stock Issued to Employees." The Company
accounts for its employees' stock-based compensation plan under APB Opinion No.
25 and its related interpretations. Accordingly, any deferred compensation
expense would be recorded for stock options based on the excess of the market
value of the common stock on the date the options were granted over the
aggregate exercise price of the options. This deferred compensation would be
amortized over the vesting period of each option. Had compensation cost been
determined consistent with SFAS No. 123 "Accounting for Stock Based
Compensation" for all options, the Company's net income (loss) and earnings per
share would have been as follows:
For the Three Months Ended
September 30,
---------------------------
2003 2004
------------ ------------
(In thousands except
per share amounts)
Net income available to common
shareholders, as reported $ 1,892 $ 3,390
Less: Total stock-based employee
compensation expense determined under
fair value method for all awards, net of
related tax effects (132) (145)
------------ ------------
Pro forma net income available
to common shareholders $ 1,760 $ 3,245
============ ============
Net income per common share, as reported:
Basic $ 0.13 $ 0.15
Diluted 0.11 0.15
Pro Forma net income per common share, as if the fair
value method had been applied to all awards:
Basic $ 0.12 $ 0.15
Diluted 0.10 0.14
12
For the Nine Months Ended
September 30,
---------------------------
2003 2004
------------ ------------
(In thousands except
per share amounts)
Net income available to common
shareholders, as reported $ 6,333 $ 7,361
Less: Total stock-based employee
compensation expense determined under
fair value method for all awards, net of
related tax effects (397) (658)
------------ ------------
Pro forma net income available
to common shareholders $ 5,936 $ 6,703
============ ============
Net income per common share, as reported:
Basic $ 0.45 $ 0.38
Diluted 0.38 0.34
Pro Forma net income per common share, as if the fair
value method had been applied to all awards:
Basic $ 0.42 $ 0.35
Diluted 0.36 0.31
Diluted earnings per share amounts for the three months ended September 30, 2003
and 2004 are based upon 16,890,630 and 23,004,082 shares, respectively, that
include the dilutive effect of assumed stock option and warrant conversions of
2,625,991 and 1,094,227 shares, respectively. Diluted earnings per share amounts
for the nine months ended September 30, 2003 and 2004 are based upon 16,574,238
and 21,546,329 shares, respectively, that include the dilutive effect of assumed
stock option and warrant conversions of 2,349,345 and 2,291,173 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 September 30, 2004, $0.2 million and $1.2 million,
net of tax of $0.1 million and $0.7 million, respectively, remained in
accumulated other comprehensive income related to the valuation of the Company's
hedging positions.
13
Total oil hedged under swaps and collars during the three months ended September
30, 2003 and 2004 were 24,400 Bbls and 30,600 Bbls, respectively. Total natural
gas hedged under swaps and collars during the three months ended September 30,
2003 and 2004 were 828,000 MMBtu and 1,012,000 MMBtu, respectively. Total oil
hedged under swaps and collars during the nine months ended September 30, 2003
and 2004 were 150,700 Bbls and 84,900 Bbls, respectively. Total natural gas
hedged under swaps and collars during the nine months ended September 30, 2003
and 2004 were 2,187,000 MMBtu and 2,739,000 MMBtu, respectively. The net losses
realized by the Company under such hedging arrangements were $0.1 million and
$0.3 million for the three months ended September 30, 2003 and 2004,
respectively, and are included in oil and natural gas revenues. The net losses
realized by the Company under such hedging arrangements were $1.8 million and
$0.7 million for nine months ended September 30, 2003 and 2004, respectively,
and are included in oil and natural gas revenues.
At September 30, 2003 and 2004 the Company had the following outstanding hedge
positions:
As of September 30, 2003
- --------------------------------------------------------------------------------------------------
Contract Volumes
---------------------------
Average Average Average
Quarter BBls MMbtu Fixed Price Floor Price Ceiling Price
- ----------------------- ------------ ------------ ------------ ------------ -------------
Fourth Quarter 2003 30,700 $ 30.22
Fourth Quarter 2003 552,000 $ 3.40 $ 5.25
First Quarter 2004 546,000 4.10 7.00
Second Quarter 2004 273,000 4.00 5.20
Third Quarter 2004 276,000 4.00 5.20
Fourth Quarter 2004 93,000 4.00 5.20
As of September 30, 2004
- --------------------------------------------------------------------------------------------------
Contract Volumes
---------------------------
Average Average Average
Quarter BBls MMbtu Fixed Price Floor Price Ceiling Price
- ----------------------- ------------ ------------ ------------ ------------ -------------
Fourth Quarter 2004 9,300 $ 38.85
Fourth Quarter 2004 15,300 $ 41.21 $ 50.00
Fourth Quarter 2004 1,197,000 4.71 6.94
First Quarter 2005 18,000 40.00 50.00
First Quarter 2005 810,000 5.09 8.00
Second Quarter 2005 364,000 5.25 7.15
Second Quarter 2005 91,000 6.03
Third Quarter 2005 368,000 5.25 7.40
Third Quarter 2005 92,000 6.03
Fourth Quarter 2005 276,000 5.25 7.92
Fourth Quarter 2005 92,000 6.03
In November 2001, the Company had no-cost collars with an affiliate of Enron
Corp. which, because of Enron's financial condition, were no longer considered
effective. An allowance was recorded at that time for the full value of the
collars (the "Enron Claim") that was classified as other expense. The Company
sold its Enron Claim to a financial institution for $0.5 million that was
recorded in the third quarter of 2004 as other income.
12. SUBSEQUENT EVENT
On October 29, 2004 the Company entered into a debt agreement, issuing $18
million of 10% senior secured subordinated notes due in December 2008 (the
"Senior Secured Notes"). The Senior Secured Notes and the Subordinated Notes are
held by affiliates of HBK Investments L.P. (the "Purchaser"). The Company's
obligations under the Senior Secured Notes are (1) secured by a second lien on
the Company's assets and (2) subordinated to the Company's obligations under the
Credit Facility. The debt agreement also provides the Company the option to
issue up to $10 million of additional Senior Secured Notes to the Purchaser over
the next two years under the same terms. Certain terms and conditions of the
Senior Secured Notes and other options of the Company include: (1) no mandatory
amortization before maturity in 2008, (2) the option, subject to certain
conditions, to make interest payments, principal
14
prepayments and payments at maturity with the Company's common stock (issuable
at 90% of an average market price as determined prior to issuance), (3) the
option at any time to redeem all or any portion of the outstanding Senior
Secured Notes with no prepayment penalty and (4) a "PIK" interest option, during
the period ended June 5, 2007, to pay-in-kind 50% of the interest due each
period by increasing the principal balance by a like amount.
Net of a 10% discount on the face amount of the Senior Secured Notes (before
debt issuance costs), the Company received proceeds of approximately $16.2
million; $6 million was used to reduce the debt outstanding under the Credit
Facility and the remainder will primarily be used in its Barnett Shale
development.
15
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 nine months ended September 30, 2004, we
participated in the drilling of 56 gross wells (22.2 net) in the Gulf Coast and
North Texas regions, 50 gross wells (18.4 net) of which were successful. 43 of
these successful wells have been completed and seven are in the process of being
completed. We have planned to drill up to 42 gross wells (14.5 net) in the Gulf
Coast region and 40 gross wells (16.4 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 shareholders. We did not receive any proceeds from the shares offered
by the selling shareholders. We expect to use our estimated net proceeds of
approximately $23.3 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 October 2004 was approximately 1.4 MMcfe/d and
net proved reserves are internally estimated at 4.0 Bcfe.
Initially, we financed the Barnett Shale acquisition with our available cash on
hand. Subsequently, we are financing a portion of our 2004 capital expenditure
program for the Barnett Shale play with funds from the issuance of the Senior
Secured Notes. We are exploring a number of financing alternatives which may be
used to partially fund our 2005 capital expenditure program for the Barnett
Shale play. We may not be able to obtain such financing on terms that are
acceptable to us, or at all.
In mid-2003, we became active in the Barnett Shale play located in Tarrant and
Parker counties in Northeast Texas. Our activity accelerated as a result of the
acquisition described above.
16
In the Barnett Shale play (our North Texas region), we drilled six gross wells
in 2003 and 27 gross wells (11.0 net) during the nine months ended September 30,
2004, all of which were successful. We plan to drill up to 40 gross wells in
this region in 2004.
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 and more recently oil prices
have become volatile. 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 September 30, 2004,
Compared to the Three Months Ended September 30, 2003
Oil and natural gas revenues for the three months ended September 30, 2004
increased 21% to $12.3 million from $10.1 million for the same period in 2003.
Production volumes for natural gas during the three months ended September 30,
2004 increased from 1.4 Bcf for the three months ended September 30, 2003 to 1.6
Bcf. Average natural gas prices increased 9% to $5.69 per Mcf in the third
quarter of 2004 from $5.21 per Mcf in the same period in 2003. Production
volumes for oil in the third quarter of 2004 decreased 31% to 73 MBbls from 105
MBbls for the same period in 2003. Average oil prices increased 49% to $43.57
per barrel in the third quarter of 2004 from $29.15 per barrel in the same
period in 2003. The increase in natural gas production was due to the
commencement of production at the Lopez #13, the Peal Ranch wells, B.P. America
#1, the increase in production at the Shadyside #1 and the Barnett Shale wells
partially offset by the natural decline in production at the Espree #1, Hankamer
#1 and other wells. The decrease in oil production was due primarily to the
natural decline of production at the Staubach #1, Burkhart #1R, Hankamer #1,
Pauline Huebner A-382 #1, Matthes Huebner #1, Espree #1 and other wells
partially offset by the commencement of production from the LL&E #1, the Delta
Farms #1 workover 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 September 30, 2003 and 2004:
17
2004 Period
Compared to 2003 Period
September 30, ---------------------------
--------------------------- Increase % Increase
2003 2004 (Decrease) (Decrease)
------------ ------------ ------------ ------------
Production volumes -
Oil and condensate (MBbls) 105 73 (32) (31)%
Natural gas (MMcf) 1,355 1,602 247 18%
Average sales prices - (1)
Oil and condensate (per Bbls) $ 29.15 $ 43.57 $ 14.42 49%
Natural gas (per Mcf) 5.21 5.69 0.48 9%
Operating revenues (In thousands)-
Oil and condensate $ 3,064 $ 3,164 $ 100 3%
Natural gas 7,059 9,110 2,051 29%
------------ ------------ ------------
Total Operating Revenues $ 10,123 $ 12,274 $ 2,151 21%
============ ============ ============
- ------------------
(1) Includes impact of hedging activities.
Oil and natural gas operating expenses for the three months ended September 30,
2004 increased 34% to $2.1 million from $1.6 million for the same period in
2003. Operating expenses per equivalent unit increased to $1.04 per Mcfe in the
third quarter of 2004 compared to $0.80 per Mcfe in the same period in 2003 as a
result of higher severance taxes resulting from higher gas sales and the
addition of wells with relatively higher operating costs.
Depreciation, depletion and amortization (DD&A) expense for the three months
ended September 30, 2004 increased 20% to $3.7 million ($1.82 per Mcfe) from
$3.1 million ($1.55 per Mcfe) for the same period in 2003. DD&A increased
primarily due to increased production and expenses resulting from additional
seismic and drilling costs.
General and administrative expense for the three months ended September 30, 2004
decreased by $0.3 million to $1.3 million from $1.6 million for the same period
in 2003 primarily as a result of executive termination costs ($0.3 million) in
the 2003 period and insurance expenses ($0.2 million) partially offset by higher
professional expenses related to Sarbanes-Oxley compliance ($0.1 million).
Stock option compensation expense was a $0.1 million benefit for the quarter
ended September 30, 2004 compared to an expense of $0.3 million for the same
period in 2003. The expense is derived from options to purchase our common stock
that were repriced in 2000, which fluctuate in value with the market value of
our common stock.
We recorded a $0.4 million after tax charge, or $0.02 per fully diluted share,
on our minority interest in Pinnacle for the three months ended September 30,
2004. It is likely that Pinnacle will continue to record a valuation allowance
on the deferred federal tax benefit generated from the operating losses incurred
during at least the early development stages of Pinnacle's coalbed methane
projects. We have not recorded a deferred federal income tax benefit generated
from these operating losses due to the uncertainty of future Pinnacle taxable
income.
Other income for the three months ended September 30, 2004 includes $0.5 million
from the sale of certain hedge contracts with affiliates of Enron for which the
Company had previously recorded an allowance for their full value.
Income taxes increased to $2.1 million for the three months ended September 30,
2004 from $1.3 million for the same period in 2003 as a result of higher taxable
income based on the factors described above.
Capitalized interest increased $0.1 million to $0.8 million in the third quarter
of 2004 from $0.7 million for the third quarter of 2003.
Nine Months Ended September 30, 2004,
Compared to the Nine Months Ended September 30, 2003
Oil and natural gas revenues for the nine months ended September 30, 2004
increased 19% to $35.1 million from $29.6 million for the same period in 2003.
Production volumes for natural gas during the nine months ended September 30,
2004 increased 29% to 4.4 Bcf
18
from 3.4 Bcf for the same period in 2003. Average natural gas prices increased
6% to $5.89 per Mcf in the first nine months of 2004 from $5.56 per Mcf in the
same period in 2003. Production volumes for oil in the first nine months of 2004
decreased 33% to 243 MBbls from 363 MBbls for the same period in 2003. Average
oil prices increased 28% to $37.14 per barrel in the first nine months of 2004
from $29.08 per barrel in the same period in 2003. The increase in natural gas
production was primarily due to the commencement of production at the Beach
House #1 and #2, the Shadyside #1, the Peal Ranch wells and the Barnett Shale
wells, offset by the natural decline in production at the Staubach #1, Burkhart
#1R, Pauline Huebner A-382 #1, Matthes Huebner #1, Pitchfork Ranch #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, Hankamer #1 and Espree #1 wells, offset by the commencement
of production from the Beach House #1 and #2, Delta Farms #1 workover and from
other wells. Oil and natural gas revenues include the impact of hedging
activities as discussed above under "General Overview".
The following table summarizes production volumes, average sales prices and
operating revenues for our oil and natural gas operations for the nine months
ended September 30, 2003 and 2004:
2004 Period
Compared to 2003 Period
September 30, ---------------------------
--------------------------- Increase % Increase
2003 2004 (Decrease) (Decrease)
------------ ------------ ------------ ------------
Production volumes -
Oil and condensate (MBbls) 363 243 (120) (33)%
Natural gas (MMcf) 3,432 4,427 995 29%
Average sales prices - (1)
Oil and condensate (per Bbls) $ 29.08 $ 37.14 $ 8.06 28%
Natural gas (per Mcf) 5.56 5.89 0.33 6%
Operating revenues (In thousands)-
Oil and condensate $ 10,544 $ 9,031 $ (1,513) (14)%
Natural gas 19,071 26,076 7,005 37%
------------ ------------ ------------
Total Operating Revenues $ 29,615 $ 35,107 $ 5,492 19%
============ ============ ============
- ------------------
(1) Includes impact of hedging activities.
Oil and natural gas operating expenses for the nine months ended September 30,
2004 increased to $5.8 million from $5.1 million for the same period in 2003.
Operating expenses per equivalent unit increased to $0.99 per Mcfe in the first
nine months of 2004 compared to $0.90 per Mcfe in the same period in 2003
primarily due to higher severance taxes resulting from higher gas sales.
Depreciation, depletion and amortization (DD&A) expense for the nine months
ended September 30, 2004 increased 21% to $10.6 million ($1.79 per Mcfe) from
$8.7 million ($1.56 per Mcfe) for the same period in 2003. DD&A increased
primarily due to increased production and expenses resulting from additional
seismic and drilling costs.
General and administrative expense for the nine months ended September 30, 2004
increased by $0.8 million to $5.1 million from $4.3 million for the same period
in 2003 primarily as a result of higher incentive compensation costs ($0.4
million), higher directors' fees ($0.1 million), higher legal fees ($0.1
million) in connection with the subordinated debt refinancing, higher
professional expenses related to Sarbanes-Oxley compliance ($0.1 million) and
higher professional expenses in connection with the 2003 audit ($0.2 million)
partially offset by lower insurance costs ($0.1 million).
Stock option compensation expense increased to $0.6 million for the nine months
ended September 30, 2004 from $0.3 million for the same period in 2003. Compared
to an expense of $0.3 million for the same period in 2003. The expense is
derived from the options to purchase our common stock that were repriced in
2000, which fluctuates in value with the market value of our common stock.
We recorded a $1.0 million after tax charge, or $0.05 per fully diluted share,
on our minority interest in Pinnacle for the nine months ended September 30,
2004. It is likely that Pinnacle will continue to record a valuation allowance
on the deferred federal tax benefit generated from the operating losses incurred
during at least the early development stages of Pinnacle's coalbed methane
projects. We have not recorded a deferred federal income tax benefit generated
from these operating losses due to the uncertainty of future Pinnacle taxable
income.
19
Income taxes increased to $4.8 million for the nine months ended September 30,
2004 from $4.1 million for the same period in 2003 as a result of higher taxable
income based on the factors described above.
Capitalized interest decreased to $2.1 million in the first nine months of 2004
from $2.2 million for the first nine months of 2003 as a result of lower
interest due to the then outstanding balance under the Prior Credit 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 nine months ended September 30, 2003.
Liquidity and Capital Resources
During the nine months ended September 30, 2004, we made capital expenditures in
excess of our net cash flows provided by operating activities, using in part the
proceeds generated from our equity offering. For future capital expenditures in
2004, we expect to continue to use such proceeds and cash on hand as well as to
draw on the Credit Facility and use the proceeds of our recently completed sale
of the Senior Secured Notes to partially fund our planned drilling expenditures
and fund leasehold costs and geological and geophysical costs on our exploration
projects in 2004. We also continue to consider financing alternatives to fund
our Barnett Shale capital program. Although we believe that current cash
balances, availability under the Credit Facility, proceeds from the sale of the
Senior Secured Notes, including possible sales of additional Senior Secured
Notes, and anticipated 2004 cash provided by operating activities will provide
sufficient capital to carry out our 2004 exploration plans, there can be no
assurance that this will be the case.
We may not be able to obtain adequate financing on terms that would be
acceptable to us. If we cannot obtain adequate financing, we anticipate that we
may be required to limit or defer our planned natural gas and oil exploration
and development program, thereby adversely affecting the recoverability and
ultimate value of our natural gas and oil properties.
Our liquidity position has been enhanced by our receipt of approximately $23.3
million in net proceeds from the completion of our 2004 public offering, the
increase in availability of funds under the Credit Facility and the proceeds
from the sale of the Senior Secured Notes. 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 $22.4 million and $18.6 million
for the nine months ended September 30, 2003 and 2004, respectively. The
decrease in cash flows provided by operating activities in 2004 as compared to
2003 was due primarily to changes in working capital in 2004, primarily higher
accrued expenses.
We have budgeted capital expenditures in 2004 of approximately $73.4 million, of
which $51.8 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 82 gross
wells (30.9 net) in the Gulf Coast and North Texas regions 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
funding our drilling program leasehold coverages acquiring our 3-D prospect
portfolio and improving our 3-D seismic interpretation technology. Oil and
natural gas capital expenditures were $19.3 million and $59.0 million (including
our $8.2 million Barnett Shale acquisition) for the nine months ended September
30, 2003 and 2004, respectively. Our drilling efforts resulted in the successful
completion of 35 gross wells (9.4 net) in 2003 and 23 gross wells (6.9 net) in
the Gulf Coast region and 27 gross wells (11.0 net) in the Barnett Shale play in
the nine months ended September 30, 2004. We have completed 43 of these wells
and are in the process of completing seven of these wells as of September 30,
2004.
Since inception, Pinnacle has reported that it drilled 230 gross wells through
September 30, 2004 and estimates that 95% of them were completed by September
30, 2004. Pinnacle reportedly added approximately 21.2 Bcf of net proved
reserves through development drilling through September 30, 2004 excluding the
10.6 Bcfe contributed or acquired at inception. Its gross operated production
has increased by approximately 275% since its inception (to approximately 13.3
MMcf/d at September 30, 2004), and its total well count stands at 485 gross
operated wells.
20
CCBM has spent $5.0 million for drilling costs, 50% of which was spent pursuant
to an obligation to fund $2.5 million of drilling costs on behalf of RMG. As of
September 30, 2004, CCBM had satisfied all $2.5 million of its drilling
obligations on behalf of RMG.
Financing Arrangements
Credit Facility
On September 30, 2004, we entered into a Second Amended and Restated Credit
Agreement with Hibernia National Bank and Union Bank of California, N.A. (the
"Credit Facility"), which matures on September 30, 2007. The Credit Facility
amended, restated and extended our prior credit facility (such prior facility
herein referred to as the "Prior Credit Facility"). The Credit Facility provides
for (1) a revolving line of credit of up to the lesser of the Facility A
Borrowing Base and $75.0 million and (2) a term loan facility of up to the
lesser of the Facility B Borrowing Base and $25.0 million. It is secured by
substantially all of our assets and is guaranteed by our subsidiary.
The Facility A Borrowing Bases will be determined by the lenders at least
semi-annually on each November 1 and May 1. The initial Facility A Borrowing
Base is $28.0 million. The initial Facility B Borrowing Base is $0.00 and is
subject to determination by the lenders in their sole discretion. We and the
lenders may each request one unscheduled borrowing base determination subsequent
to each scheduled determination. The Facility A Borrowing Base will at all times
equal the Facility A Borrowing Base most recently determined by the lenders,
less quarterly borrowing base reductions required subsequent to such
determination. The lenders will reset the Facility A Borrowing Base amount at
each scheduled and each unscheduled borrowing base determination date.
If the outstanding principal balance of the revolving loans under the Credit
Facility exceeds the Facility A Borrowing Base at any time (including, without
limitation, due to a quarterly borrowing base reduction (as described above)),
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 the lenders' opinion to increase the
Facility A 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 revolving loan, the interest rate will be, at our option, (1) the
Eurodollar Rate, plus an applicable margin equal to 2.375% if the amount
borrowed is greater than or equal to 90% of the Facility A Borrowing Base, 2.0%
if the amount borrowed is less than 90%, but greater than or equal to 50% of the
Facility A Borrowing Base, or 1.625% if the amount borrowed is less than 50% of
the Facility A Borrowing Base; or (2) the Base Rate, plus an applicable margin
of 0.375% if the amount borrowed is greater than or equal to 90% of the Facility
A Borrowing Base. The interest rate on each term loan will be, at our option,
(1) the Eurodollar Rate, plus an applicable margin to be determined by the
lenders; or (2) the Base Rate, plus an applicable margin to be determined by the
lenders. 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 Credit Facility,
which were amended at the time of the issuance of the Senior Secured Notes.
These covenants, as amended, include, but are not limited to the maintenance of
the following financial covenants: (1) a minimum current ratio of 1.0 to 1.0
(including availability under the borrowing base), (2) a minimum quarterly debt
services coverage of 1.25 times, (3) a minimum shareholders' equity equal to
$100.0 million, plus 100% of all subsequent common and preferred equity
contributed by shareholders subsequent to June 30, 2004, plus 50% of all
positive earnings occurring subsequent to June 30, 2004, plus, 180 days after
issuance of any second-lien subordinated debt with another lender (the "Secured
Subordinated Debt"), an amount equal to the difference, if positive, of (A) 50%
of the net proceeds from the issuance less (B) 100% of all common and preferred
equity contributed by shareholders from September 30, 2004 to the date of the
issuance of any Secured Subordinated Debt, and (4) a maximum total recourse debt
to EBITDA ratio (as defined in the Credit Facility) of not more than 2.6 to 1.0.
The Credit Facility also places restrictions on additional indebtedness,
dividends to shareholders, liens, investments, mergers, acquisitions, asset
dispositions, asset pledges and mortgages, change of control, repurchase or
redemption for cash of our common stock, speculative commodity transactions and
other matters.
In connection with the Senior Secured Notes Purchase Agreement, we amended the
Credit Facility including without limitation, to: (1) amend the covenant
regarding maintenance of a minimum shareholders' equity, (2) add a new covenant
requiring maintenance of a minimum EBITDA to interest expense ratio and (3) add
other provisions and a consent which allow for the indebtedness incurred under
the Senior Secured Notes.
21
On November 7, 2004, we determined that, as of September 30, 2004, we were not
in compliance with the minimum current ratio covenant in the Credit Facility. We
cured the noncompliance on October 29, 2004 with the issuance of the Senior
Secured Notes. On November 10, 2004, the lenders under the Credit Facility
agreed in a letter to the Company to waive the noncompliance period from
September 30, 2004 through October 29, 2004.
At December 31, 2003, amounts outstanding under the Prior Credit Facility
totaled $7.0 million, with an additional $12.0 million available for future
borrowings. At September 30, 2004, amounts outstanding under the Credit Facility
totaled $19.0 million, with an additional $9.0 million available for future
borrowings. At December 31, 2003, no letters of credit were issued and
outstanding under the Prior Credit Facility. At September 30, 2004, no letters
of credit were issued and outstanding under the Credit Facility.
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 September 30, 2004, the outstanding
principal balance of this note was $0.9 million and $0.2 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.
During the second quarter of 2004, CCBM relinquished a portion of its interests
in certain oil and natural gas leases and reduced the principal due on the note
by $0.3 million.
Capital Leases
In December 2001, we entered into a capital lease agreement secured by certain
production equipment in the amount of $0.2 million. The lease is payable in one
payment of $11,323 and 35 monthly payments of $7,549 including interest at 8.6%
per annum. In October 2002, we entered into a capital lease agreement secured by
certain production equipment in the amount of $0.1 million. The lease is payable
in 36 monthly payments of $3,462 including interest at 6.4% per annum. In May
2003, we entered into a capital lease agreement secured by certain production
equipment in the amount of $0.1 million. The lease is payable in 36 monthly
payments of $3,030 including interest at 5.5% per annum. In August 2003, we
entered into a capital lease agreement secured by certain production equipment
in the amount of $0.1 million. The lease is payable in 36 monthly payments of
$2,179 including interest at 6.0% per annum. We have the option to acquire the
equipment at the conclusion of the lease for $1 under all of these leases. DD&A
on the capital leases for the three months ended September 30, 2003 and 2004
amounted to $14,000 and $11,000, respectively. DD&A on the capital leases for
the nine months ended September 30, 2003 and 2004 amounted to $35,000 and
$34,000, respectively, and accumulated DD&A on the leased equipment at December
31, 2003 and September 30, 2004 amounted to $76,000 and $111,000, 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
(subsequently extended to December 2005 as described below), 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 of December 31,
2003 and September 30, 2004, the outstanding balance of the Subordinated Notes
had been increased by $5.3 million and $6.4 million, respectively, for such
interest paid in kind. Concurrently with the sale of the Subordinated Notes, we
sold to the same purchasers 3,636,364 shares of our common stock at a price of
$2.20 per share and warrants expiring in December 2007 to purchase up to
2,760,189 shares of our common stock at an exercise price of $2.20 per share.
For accounting purposes, the warrants were valued at $0.25 each. During the nine
months ended September 30, 2004, Mellon Ventures, L.P., JPMorgan Partners (23A
SBIC), Steven A. Webster and Douglas A. P. Hamilton exercised warrants to
purchase 276,019, 2,208,152, 92,006 and 92,006 shares of common stock,
respectively, on a cashless exercise basis for a total of 205,692, 1,684,949,
70,205 and 70,205 shares of common stock, respectively, and Paul B. Loyd, Jr.,
exercised warrants to purchase 92,006 shares for a total of 92,006 shares of
common stock. As a result, no warrants to purchase shares remain outstanding
from the warrants originally issued in December 1999.
22
On June 7, 2004, an unaffiliated third party (the "Subordinated Notes
Purchaser") purchased all the outstanding Subordinated Notes from the original
note holders. In exchange for a $0.4 million amendment fee, certain terms and
conditions of the Subordinated Notes were amended, to provide for, among other
things, (1) a one year extension of the maturity to December 15, 2008, (2) a one
year extension, through December 15, 2005, of the paid-in-kind ("PIK") interest
option to pay-in-kind 60% of the interest due each period by increasing the
principal balance by a like amount (the "PIK option"), (3) an additional one
year option to extend the PIK option through December 15, 2006 at an annual
interest rate on the deferred amount of 10% and the payment of a one-time fee
equal to 0.5% of the principal then outstanding, (4) an increase and extension
on the prepayment premium on the Subordinated Notes, (5) a modification of a
covenant regarding maximum quarterly leverage that our Total Debt will not
exceed 3.5 times EBITDA (as such terms are defined in the securities purchase
agreement related to the Subordinated Notes) for the last 12 months at any time
and (6) additional flexibility to obtain a separate project financing facility
in the future. The amendment fee will be amortized over the remaining life of
the Subordinated Notes.
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). Also in connection
with the issuance of the Senior Secured Notes, we amended the Subordinated Notes
to, among other things: (1) adjust the prepayment premium, (2) add a provision
that permits repurchase of our common stock as required by the Registration
Rights Agreement (as defined below), and (3) add a provision which allows for
the indebtedness incurred under the Senior Secured Notes.
Senior Subordinated Secured Notes
On October 29, 2004, we entered into a Note Purchase Agreement (the "Senior
Secured Notes Purchase Agreement") with PCRL Investments L.P. (the "Senior
Secured Notes Purchaser"). Pursuant to the Senior Secured Notes Purchase
Agreement, we may issue up to $28 million aggregate principal amount of our 10%
Senior Subordinated Secured Notes due 2008 (the "Senior Secured Notes") for a
purchase price equal to 90% of the principal amount of the Senior Secured Notes
then issued. On October 29, 2004, the Senior Secured Notes Purchaser purchased
$18 million aggregate principal amount of the Senior Secured Notes for a
purchase price of $16.2 million. Subject to the satisfaction of certain
conditions, we have an option to issue up to an additional $10 million aggregate
principal amount of the Senior Secured Notes to the Senior Secured Notes
Purchaser before October 29, 2006.
The Senior Secured Notes are secured by a second lien on substantially all of
our current proved producing reserves and non-reserve assets, guaranteed by our
subsidiary, and subordinated to our obligations under the Credit Facility. The
Senior Secured Notes bear interest at 10% per annum, payable quarterly on the
5th day of March, June, September and December of each year beginning March 5,
2005. The principal on the Senior Secured Notes is due December 15, 2008, and we
have the option to prepay the Senior Secured Notes at any time. The Senior
Secured Notes include an option that allows us to pay-in-kind 50% of the
interest due until June 5, 2007 by increasing the principal due by a like
amount. Subject to certain conditions, we have the option to pay the interest on
and principal of (at maturity or upon prepayment) the Senior Secured Notes with
our common stock, as long as the Secured Note Purchaser would not hold more than
9.99% of the number of shares of our common stock outstanding immediately after
giving effect to such payment. The value of such shares issued as payment on the
Senior Secured Notes is determined based on 90% of the volume weighted average
trading price during a specified period of days beginning with the date of the
payment notice and ending before the payment date. Our issuance costs related to
the transaction were estimated to be $0.6 million.
As contemplated by the Purchase Agreement, we also entered into a registration
rights agreement with the Secured Note Purchaser (the "Registration Rights
Agreement"). In the event that we choose to issue shares of our common stock as
payment of interest on the principal of the Senior Secured Notes, the
Registration Rights Agreement provides registration rights with respect to such
shares. We are generally required to file a resale shelf registration statement
to register the resale of such shares under the Securities Act of 1933 (the
"Securities Act") if such shares are not freely tradable under Rule 144(k) under
the Securities Act. We are subject to certain covenants under the terms of the
Registration Rights Agreement, including the requirement that the registration
statement be kept effective for resale of shares subject to certain "blackout
periods," when sales may not be made. In certain circumstances, including those
relating to (1) delisting of our common stock, (2) blackout periods in excess of
a maximum length of time, (3) certain failures to make timely periodic filings
with the Securities and Exchange Commission, or (4) certain delays or failures
to deliver stock certificates, we may be required to repurchase common stock
issued as payment on the Senior Secured Notes and, in certain of these
circumstances, to pay damages based on the market value of our common stock. In
certain situations, we are required to indemnify the holders of registration
rights under the Registration Rights Agreement, including, without limitation,
for liabilities under the Securities Act.
23
The Senior Secured Notes Purchase Agreement includes certain representations,
warranties and covenants by the parties thereto. We are subject to certain
covenants under the terms of the Senior Secured Notes Purchase Agreement,
including, without limitation, the maintenance of the following financial
covenants: (1) a maximum total recourse debt to EBITDA ratio of not more than
3.50 to 1.0, (2) a minimum EBITDA to interest expense ratio of 2.50 to 1.0, and
(3) as of April 30, 2005, a minimum tangible net worth of $12.5 million in
excess of our tangible net worth as of September 30, 2004. Upon a change of
control, any holders of the Senior Secured Notes may require us to repurchase
such holders' Senior Secured Notes at a price equal to then outstanding
principal amount of such Senior Secured Notes, together with all interest
accrued on such Senior Secured Notes through the date of repurchase. The Senior
Secured Notes Purchase Agreement also places restrictions on additional
indebtedness, dividends to shareholders, liens, investments, mergers,
acquisitions, asset dispositions, asset pledges and mortgages, repurchase or
redemption for cash of our common stock, speculative commodity transactions and
other matters. The Senior Secured Notes Purchaser is an affiliate of the
Subordinated Notes Purchaser.
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 was
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.
Mellon Ventures, Inc. converted all of its Series B Preferred Stock
(approximately 49,938 shares) into 876,099 shares of common stock on May 25,
2004. Steven A. Webster converted all of his Series B Preferred Stock
(approximately 25,195 shares) into 442,025 shares of common stock on June 30,
2004. As a result, no shares of Series B Preferred Stock remain outstanding.
The 2002 Warrants have a five-year term and originally entitled the holders to
purchase up to 252,632 shares of our common stock at a price of $5.94 per share,
subject to adjustment, and are exercisable at any time after issuance. As of
September 30, 2004, 84,210 of the 2002 Warrants remained outstanding. For
accounting purposes, the 2002 Warrants are valued at $0.06 per 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 U.S. 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 oil and natural gas 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 $1.1 million and $1.3
24
million for the nine months ended September 30, 2003 and 2004, respectively. We
expense maintenance and repairs as they are incurred.
We amortize natural gas and oil properties based on the unit-of-production
method using estimates of proved reserve quantities. We do not amortize
investments in unproved properties until proved reserves associated with the
projects can be determined or until these investments are impaired. We
periodically evaluate, on a property-by-property basis, unevaluated properties
for impairment. If the results of an assessment indicate that the properties are
impaired, we add the amount of impairment to the proved natural gas and oil
property costs to be amortized. The amortizable base includes estimated future
development costs and, where significant, dismantlement, restoration and
abandonment costs, net of estimated salvage values. The depletion rate per Mcfe
for the nine months ended September 30, 2003 and 2004 was $1.56 and $1.79,
respectively.
We account for dispositions of natural gas and oil properties as adjustments to
capitalized costs with no gain or loss recognized, unless such adjustments would
significantly alter the relationship between capitalized costs and proved
reserves. We have not had any transactions that significantly alter that
relationship.
The net capitalized costs of proved oil and natural gas properties are subject
to a "ceiling test" which limits such costs to the estimated present value,
discounted at a 10% interest rate, of future net revenues from proved reserves,
based on current economic and operating conditions (the "Full Cost Ceiling"). 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 nine months ended September 30, 2004. However, based upon the oil and
natural gas prices in effect on December 31, 2001, March 31, 2003 and September
30, 2003, the unamortized cost of oil and natural gas properties exceeded the
cost center ceiling. As permitted by full cost accounting rules, improvements in
pricing and/or the addition of proved 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 September 30, 2004 ceiling test computation, a price
sensitivity study also indicated that a 20% increase in commodity prices at
September 30, 2004 would have increased the pre-tax present value of future net
revenues ("NPV") by approximately $58.9 million. Conversely, a 20% decrease in
commodity prices at September 30, 2004 would have reduced our NPV by
approximately $52.2 million. This would have reduced our Full Cost Ceiling
cushion to approximately $27.6 million. The aforementioned price sensitivity and
NPV is as of September 30, 2004 and, accordingly, does not include any potential
changes in reserves due to fourth quarter 2004 performance, such as commodity
prices, reserve revisions and drilling results.
The Full Cost Ceiling cushion at September 30, 2004 of approximately $61.5
million was based upon average realized oil and natural gas prices of $47.33 per
Bbl and $5.64 per Mcf, respectively, or a volume weighted average price of
$41.19 per BOE. This cushion, however, would have been zero on such date at an
estimated volume weighted average price of $26.50 per BOE. A BOE means one
barrel of oil equivalent, determined using the ratio of six Mcf of natural gas
to one Bbl of oil, condensate or natural gas liquids, which approximates the
relative energy content of oil, condensate and natural gas liquids as compared
to natural gas. Prices have historically often been higher or substantially
higher for oil than natural gas on an energy equivalent basis, although there
have been periods in which they have been lower or substantially lower.
25
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, 67.9 Bcfe of
proved undeveloped reserves, representing 64% and 69% of our total proved
reserves at December 31, 2003 and September 30, 2004, respectively. As of
December 31, 2003 and September 30, 2004, a 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 longer, or approximately 15 years, when compared
to the depletable life of our remaining oil and natural gas properties of
approximately 2.25 years. Accordingly, the combination of a relatively low ratio
of future development costs and a relatively long depletable life on our Camp
Hill properties has resulted in a relatively low overall historical depletion
rate and DD&A expense. This has resulted in a capitalized cost basis associated
with producing properties being depleted over a longer period than the
associated production and revenue stream. It has also resulted in the build-up
of nondepleted capitalized costs associated with properties that have been
completely produced out.
We expect our relatively low historical depletion rate condition to continue
until the high level of nonproducing reserves to total proved reserves is
reduced and the average life of our proved developed reserves is extended
through development drilling and/or the significant addition of new proved
producing reserves through acquisition or exploration. If our level of total
proved reserves, finding costs and current prices were to remain constant, this
continued build-up of capitalized costs increases the probability of a ceiling
test write-down.
We depreciate other property and equipment using the straight-line method based
on estimated useful lives ranging from five to 10 years.
Oil and Natural Gas Reserve Estimates
The reserve data as of December 31, 2003 included in this document are estimates
prepared by Ryder Scott Company and Fairchild & Wells, Inc., Independent
Petroleum Engineers. We estimated the reserve data for all other dates. 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.
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
26
forecasted transaction occurs. All of our derivative instruments at December 31,
2003 and September 30, 2004 were designated and effective as cash flow hedges.
When hedge accounting is discontinued because it is probable that a forecasted
transaction will not occur, the derivative will continue to be carried on the
balance sheet at its fair value and gains and losses that were accumulated in
other comprehensive income will be recognized in earnings immediately. In all
other situations in which hedge accounting is discontinued, the derivative will
be carried at fair value on the balance sheet with future changes in its fair
value recognized in future earnings.
We typically use fixed rate swaps and costless collars to hedge our exposure to
material changes in the price of natural gas and oil. We formally document all
relationships between hedging instruments and hedged items, as well as our risk
management objectives and strategy for undertaking various hedge transactions.
This process includes linking all derivatives that are designated cash flow
hedges to forecasted transactions. We also formally assess, both at the hedge's
inception and on an ongoing basis, whether the derivatives that are used in
hedging transactions are highly effective in offsetting changes in cash flows of
hedged transactions.
Our Board of Directors sets all of our hedging policy, including volumes, types
of instruments and counterparties, on a quarterly basis. These policies are
implemented by management through the execution of trades by either the
President or Chief Financial Officer after consultation and concurrence by the
President, Chief Financial Officer and Chairman of the Board. The master
contracts with the authorized counterparties identify the President and Chief
Financial Officer as the only representatives authorized to execute trades. The
Board of Directors also reviews the status and results of hedging activities
quarterly.
Income Taxes
Under Statement of Financial Accounting Standards No. 109 ("SFAS No. 109"),
"Accounting for Income Taxes," deferred income taxes are recognized at each year
end for the future tax consequences of differences between the tax bases of
assets and liabilities and their financial reporting amounts based on tax laws
and statutory tax rates applicable to the periods in which the differences are
expected to affect taxable income. Valuation allowances are established when
necessary to reduce the deferred tax asset to the amount expected to be
realized.
Contingencies
Liabilities and other contingencies are recognized upon determination of an
exposure, which when analyzed indicates that it is both probable that an asset
has been impaired or that a liability has been incurred and that the amount of
such loss is reasonably estimable.
Volatility of Oil and Natural Gas Prices
Our revenues, future rate of growth, results of operations, financial condition
and ability to borrow funds or obtain additional capital, as well as the
carrying value of our properties, are substantially dependent upon prevailing
prices of oil and natural gas.
We periodically review the carrying value of our oil and natural gas properties
under the full cost accounting rules of the Commission. See "--Critical
Accounting Policies and Estimates--Oil and Natural Gas Properties."
Total oil hedged under swaps and collars during the three months ended September
30, 2003 and 2004 were 24,400 Bbls and 30,600 Bbls, respectively. Total natural
gas hedged under swaps and collars during the three months ended September 30,
2003 and 2004 were 828,000 MMBtu and 1,012,000 MMBtu, respectively. Total oil
hedged under swaps and collars during the nine months ended September 30, 2003
and 2004 were 150,700 Bbls and 84,900 Bbls, respectively. Total natural gas
hedged under swaps and collars during the nine months ended September 30, 2003
and 2004 were 2,187,000 MMBtu and 2,739,000 MMBtu, respectively. The net losses
realized by the Company under such hedging arrangements were $0.1 and $0.3
million for the three months ended September 30, 2003 and 2004, respectively,
and are included in oil and natural gas revenues. The net losses realized by the
Company under such hedging arrangements were $1.8 million and $0.7 million for
nine months ended September 30, 2003 and 2004, respectively, and are included in
oil and natural gas revenues.
To mitigate some of our commodity price risk, we engage periodically in certain
other limited hedging activities. For instance, during the second quarter of
2003, we acquired options to sell 6,000 MMBtu of natural gas per day for the
period July 2003 through September 2003 (552,000 MMBtu) at $8.00 per MMBtu for
approximately $119,000. We acquired these options to protect its cash position
against potential margin calls on certain natural gas derivative due to large
increases in the price of natural gas. These options were classified as
derivatives. The costs were recorded as a reduction of natural gas revenues as
the options expired.
27
As of December 31, 2003 and September 30, 2004, $0.2 million and $1.2 million,
net of tax of $0.1 million and $0.7 million, respectively, remained in
accumulated other comprehensive income related to the valuation of our hedging
positions.
While the use of hedging arrangements limits the downside risk of adverse price
movements, it may also limit our ability to benefit from increases in the prices
of natural gas and oil. We enter into the majority of our hedging transactions
with two counterparties and have a netting agreement in place with those
counterparties. We do not obtain collateral to support the agreements but
monitor the financial viability of counterparties and believe our credit risk is
minimal on these transactions. Under these arrangements, payments are received
or made based on the differential between a fixed and a variable product price.
These agreements are settled in cash at expiration or exchanged for physical
delivery contracts. In the event of nonperformance, we would be exposed again to
price risk. We have some risk of financial loss because the price received for
the product at the actual physical delivery point may differ from the prevailing
price at the delivery point required for settlement of the hedging transaction.
Moreover, our hedging arrangements generally do not apply to all of our
production and thus provide only partial price protection against declines in
oil and natural gas 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 September
2004, a $0.10 change in the price per Mcf of gas sold would have changed revenue
by $66,000. A $0.70 change in the price per barrel of oil would have changed
revenue by $17,000.
The table below summarizes our total natural gas production volumes subject to
derivative transactions during the nine months ended September 30, 2004 and the
weighted average NYMEX reference price for those volumes.
Natural Gas Swaps Natural Gas Collars
- ----------------------------- -----------------------------
Volumes (MMBtu) 180,000 Volumes (MMBtu) 2,559,000
Average price ($/MMBtu) $ 6.60 Average price ($/MMBtu)
Floor $ 4.40
Ceiling $ 6.25
The table below summarizes our total crude oil production volumes subject to
derivative transactions for the nine months ended September 30, 2004 and the
weighted average NYMEX reference price for those volumes.
Crude Oil Swaps Crude Oil Collars
- ----------------------------- ------------------------------
Volumes (Bbls) 81,900 Volumes (Bbls) 3,000
Average price ($/Bbls) $ 33.13 Average price ($/Bbls)
Floor $ 42.25
Ceiling $ 50.00
28
At September 30, 2003 and 2004 the Company had the following outstanding hedge
positions:
As of September 30, 2003
- --------------------------------------------------------------------------------------------------
Contract Volumes
---------------------------
Average Average Average
Quarter BBls MMbtu Fixed Price Floor Price Ceiling Price
- ----------------------- ------------ ------------ ------------ ------------ -------------
Fourth Quarter 2003 30,700 $ 30.22
Fourth Quarter 2003 552,000 $ 3.40 $ 5.25
First Quarter 2004 546,000 4.10 7.00
Second Quarter 2004 273,000 4.00 5.20
Third Quarter 2004 276,000 4.00 5.20
Fourth Quarter 2004 93,000 4.00 5.20
As of September 30, 2004
- --------------------------------------------------------------------------------------------------
Contract Volumes
---------------------------
Average Average Average
Quarter BBls MMbtu Fixed Price Floor Price Ceiling Price
- ----------------------- ------------ ------------ ------------ ------------ -------------
Fourth Quarter 2004 9,300 $ 38.85
Fourth Quarter 2004 15,300 $ 41.21 $ 50.00
Fourth Quarter 2004 1,197,000 4.71 6.94
First Quarter 2005 18,000 40.00 50.00
First Quarter 2005 810,000 5.09 8.00
Second Quarter 2005 364,000 5.25 7.15
Second Quarter 2005 91,000 6.03
Third Quarter 2005 368,000 5.25 7.40
Third Quarter 2005 92,000 6.03
Fourth Quarter 2005 276,000 5.25 7.92
Fourth Quarter 2005 92,000 6.03
In November 2001, the Company had no-cost collars with an affiliate of Enron
Corp. which, because of Enron's financial condition, were no longer considered
effective. An allowance was recorded at that time for the full value of the
collars (the "Enron Claim") that was classified as other expense. The Company
sold its Enron Claim to a financial institution for $0.5 million that was
recorded in the third quarter of 2004 as other income.
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, financing of the February 2004 acquisition costs
in the Barnett Shale trend and the exploration and development expenditures in
that trend, all and any other statements regarding future operations, financial
results, business plans and cash needs and other statements that are not
historical facts are forward looking statements. When used in this document, the
words "anticipate," "estimate," "expect," "may," "project," "believe" and
similar expression are intended to be among the statements that identify forward
looking statements. Such statements involve risks and uncertainties, including,
but not limited to, those relating to the Company's dependence on its
exploratory drilling activities, the volatility of oil and natural gas prices,
the need to replace reserves depleted by production, operating risks of oil and
natural gas operations, the Company's dependence on its key personnel, factors
that affect the Company's ability to manage its growth and achieve its business
strategy, risks relating to, limited operating history, technological changes,
significant capital requirements of the Company, the potential impact of
government regulations, litigation, competition, the uncertainty of reserve
information and future net revenue estimates, property acquisition risks,
availability of equipment, weather,
29
availability of financing and other factors detailed in the Company's Annual
Report on Form 10-K for the year ended December 31, 2003 and other filings with
the Securities and Exchange Commission. Should one or more of these risks or
uncertainties materialize, or should underlying assumptions prove incorrect,
actual outcomes may vary materially from those indicated. All subsequent written
and oral forward-looking statements attributable to us or persons acting on our
behalf are expressly qualified in their entirety by reference to these risks and
uncertainties. You should not place undue reliance on forward-looking
statements. Each forward-looking statement speaks only as of the date of the
particular statement and the Company undertakes no obligation to update or
revise any forward looking statement.
30
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.
31
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 September 30, 2004 to provide reasonable
assurance that information required to be disclosed in our reports filed or
submitted under the Exchange Act is recorded, processed, summarized and reported
within the time periods specified in the Securities and Exchange Commission's
rules and forms.
Except as set forth below, there has been no change in our internal controls
over financial reporting that occurred during the three months ended September
30, 2004 that has materially affected, or is reasonably likely to materially
affect, our internal controls over financial reporting. During management's
review of the third quarter results, an arithmetical error was discovered in the
calculation of diluted earnings per common share. 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 and (3) the
calculation of diluted earnings per share.
32
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 - Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3 - Defaults Upon Senior Securities
None.
Item 4 - Submission of Matters to a Vote of Security Holders
None.
Item 5 - Other Information
On November 15, 2004, the Company issued a press release concerning second
and third quarter 2004 financial results. In the press release, the Company
reported corrections to its financial statements for the second and third
quarters of 2004 due to a computational error in its diluted shares outstanding.
To the extent permitted by applicable rules, none of the information
provided in this Item 5 of Part II of this Form 10-Q and the accompanying
Exhibit 99.1 will be deemed "filed" for purposes of Section 18 of the Securities
Exchange Act of 1934, as amended, nor will it be incorporated by reference into
any registration statement filed by the Company under the Securities Act of
1933, as amended, unless specifically identified therein as being incorporated
therein by reference. The furnishing of the information in this Item 5 is not
intended to, and does not, constitute a determination or admission by the
Company, that the information in this report is material or complete, or that
investors should consider this information before making an investment decision
with respect to any security of the Company.
Item 6 - Exhibits
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).
33
+10.1 -- Second Amended and Restated Credit Agreement dated as of September
30, 2004 by and among Carrizo Oil & Gas, Inc., CCBM, Inc., Hibernia
National Bank, as Agent, Union Bank of California, N.A., as co-agent
and Hibernia National Bank and Union Bank of California, N.A., as
lenders (incorporated herein by reference to Exhibit 10.1 to the
Company's Current Report on Form 8-K filed on October 6, 2004).
+10.2 -- Commercial Guaranty made and entered into as of September 30, 2004
by CCBM, Inc. in favor of Hibernia National Bank, as agent
(incorporated herein by reference to Exhibit 10.2 to the Company's
Current Report on Form 8-K filed on October 6, 2004).
+10.3 -- Amended and Restated Stock Pledge and Security Agreement dated and
effective as of September 30, 2004 by Carrizo Oil & Gas, Inc. in favor
of Hibernia National Bank, as agent (incorporated herein by
reference to Exhibit 10.3 to the Company's Current Report on Form 8-K
filed on October 6, 2004).
+10.4 -- Note Purchase Agreement dated as of October 29, 2004 among Carrizo
Oil & Gas, Inc., the Purchasers named therein and PCRL Investments
L.P., as collateral agent (incorporated herein by reference to Exhibit
10.1 to the Company's Current Report on Form 8-K filed on November 3,
2004).
+10.5 -- Form of 10% Senior Subordinated Secured Note due 2008
(incorporated herein by reference to Exhibit 10.2 to the Company's
Current Report on Form 8-K filed on November 3, 2004).
+10.6 -- Stock Pledge and Security Agreement dated as of October 29, 2004
by Carrizo Oil & Gas, Inc. in favor of PCRL Investments L.P., as
collateral agent (incorporated herein by reference to Exhibit 10.3 to
the Company's Current Report on Form 8-K filed on November 3, 2004).
+10.7 -- Commercial Guaranty dated as of October 29, 2004 by CCBM, Inc. in
favor of PCRL Investments L.P., guarantying the indebtedness of
Carrizo Oil & Gas, Inc. (incorporated herein by reference to Exhibit
10.4 to the Company's Current Report on Form 8-K filed on November 3,
2004).
+10.8 -- Registration Rights Agreement dated as of October 29, 2004 among
Carrizo Oil & Gas, Inc. and the Investors named therein (incorporated
herein by reference to Exhibit 10.5 to the Company's Current Report on
Form 8-K filed on November 3, 2004).
+10.9 -- First Amendment to Second Amended and Restated Credit Agreement
dated as of October 29, 2004 among Carrizo Oil & Gas, Inc., CCBM,
Inc., Hibernia National Bank and Union Bank of California, N.A.
(incorporated herein by reference to Exhibit 10.6 to the Company's
Current Report on Form 8-K filed on November 3, 2004).
+10.10 -- Second Amendment to Securities Purchase Agreement dated as of
October 29, 2004 among Carrizo Oil & Gas, Inc. and the Investors named
therein (incorporated herein by reference to Exhibit 10.7 to the
Company's Current Report on Form 8-K filed on November 3, 2004).
31.1 -- CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.
31.2 -- CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.
32.1 -- CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.
32.2 -- CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.
99.1 -- Press Release dated November 15, 2004 Announcing Corrected Diluted
Share Computations for the Second and Third Quarters 2004 (furnished,
not filed, to the extent permitted by applicable rules).
+ Incorporated herein by reference as indicated.
34
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this Report to be signed on its
behalf by the undersigned, thereunto duly authorized.
Carrizo Oil & Gas, Inc.
(Registrant)
Date: November 15, 2004 By: /s/S. P. Johnson, IV
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President and Chief Executive Officer
(Principal Executive Officer)
Date: November 15, 2004 By: /s/Paul F. Boling
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Chief Financial Officer
(Principal Financial and Accounting Officer)