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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended MARCH 31, 2005
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the transition period from ________ to _________
Commission File Number 000-29187-87
CARRIZO OIL & GAS, INC.
(Exact name of registrant as specified in its charter)
TEXAS 76-0415919
(State or other jurisdiction of (IRS Employer Identification No.)
incorporation or organization)
1000 LOUISIANA STREET, SUITE 1500, HOUSTON, TX 77002
(Address of principal executive offices) (Zip Code)
(713) 328-1000
(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 [X] NO [ ]
The number of shares outstanding of the registrant's common stock, par value
$0.01 per share, as of April 30, 2005, the latest practicable date, was
22,764,554.
CARRIZO OIL & GAS, INC.
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2005
INDEX
PAGE
----
PART I. FINANCIAL INFORMATION
Item 1. Consolidated Balance Sheets (Unaudited)
- As of December 31, 2004 and March 31, 2005 2
Consolidated Statements of Operations (Unaudited)
- For the three-month periods ended March 31, 2004 and
2005 3
Consolidated Statements of Cash Flows (Unaudited)
- For the three-month periods ended March 31, 2004 and
2005 4
Notes to Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 17
Item 3. Quantitative and Qualitative Disclosure About
Market Risk 32
Item 4. Controls and Procedures 33
PART II. OTHER INFORMATION
Items 1-6. 35
SIGNATURES 37
CARRIZO OIL & GAS, INC.
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
DECEMBER 31, MARCH 31,
2004 2005
------------ ---------
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 5,668 $ 8,264
Accounts receivable, trade (net of allowance for
doubtful accounts of $325 and $325 at December 31,
2004 and March 31, 2005, respectively) 12,738 9,243
Advances to operators 1,614 1,200
Other current assets 1,614 1,230
-------- --------
Total current assets 21,634 19,937
PROPERTY AND EQUIPMENT, net full-cost method of
accounting for oil and natural gas properties
(including unevaluated costs of properties of $45,067
and $51,364 at December 31, 2004 and March 31, 2005,
respectively) 205,482 211,818
Investment in Pinnacle Gas Resources, Inc. 5,229 5,007
Deferred financing costs 1,633 1,586
Other assets 57 49
-------- --------
$234,035 $238,397
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade $ 21,358 $ 13,654
Accrued liabilities 7,516 8,288
Advances for joint operations 1,808 3,136
Current maturities of long-term debt 90 88
-------- --------
Total current liabilities 30,772 25,166
LONG-TERM DEBT 62,884 66,719
ASSET RETIREMENT OBLIGATION 1,407 1,478
DEFERRED INCOME TAXES 18,113 18,719
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS' EQUITY:
Warrants (334,210 and zero outstanding at December
31, 2004 and March 31, 2005, respectively) 80 --
Common stock, par value $.01 (40,000,000 shares
authorized with 22,161,457 and 22,735,554 issued
and outstanding at December 31, 2004 and March 31,
2005, respectively) 221 227
Additional paid in capital 99,766 102,979
Retained earnings 20,733 23,319
Accumulated other comprehensive income (loss) 59 (210)
-------- --------
120,859 126,315
-------- --------
$234,035 $238,397
======== ========
The accompanying notes are an integral part of these
consolidated financial statements.
-2-
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
FOR THE THREE
MONTHS ENDED
MARCH 31,
-------------------------
2004 2005
----------- -----------
(In thousands except
per share amounts)
OIL AND NATURAL GAS REVENUES $ 10,873 $ 15,458
COSTS AND EXPENSES:
Oil and natural gas operating expenses (exclusive of
depletion, depreciation and amortization, shown
separately below) 1,676 2,235
Depreciation, depletion and amortization 3,247 4,678
General and administrative 2,133 2,600
Accretion expense related to asset retirement
obligations 6 18
Stock option compensation 10 976
----------- -----------
Total costs and expenses 7,072 10,507
----------- -----------
OPERATING INCOME 3,801 4,951
OTHER INCOME AND EXPENSES:
Equity in loss of Pinnacle Gas Resources, Inc. (244) (222)
Other income and expenses 9 8
Interest income 13 44
Interest expense (95) (1,596)
Interest expense, related parties (615) --
Capitalized interest 667 988
----------- -----------
INCOME BEFORE INCOME TAXES 3,536 4,173
INCOME TAXES (Note 6) 1,353 1,587
----------- -----------
NET INCOME 2,183 2,586
DIVIDENDS AND ACCRETION ON PREFERRED STOCK 198 --
----------- -----------
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS $ 1,985 $ 2,586
=========== ===========
BASIC EARNINGS PER COMMON SHARE $ 0.12 $ 0.11
=========== ===========
DILUTED EARNINGS PER COMMON SHARE $ 0.10 $ 0.11
=========== ===========
WEIGHTED AVERAGE SHARES OUTSTANDING:
BASIC 16,613,430 22,501,696
=========== ===========
DILUTED 19,284,153 23,402,248
=========== ===========
The accompanying notes are an integral part of these
consolidated financial statements.
-3-
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
FOR THE THREE
MONTHS ENDED
MARCH 31,
-------------------
2004 2005
-------- --------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 2,183 $ 2,586
Adjustment to reconcile net income to net
cash provided by operating activities-
Depreciation, depletion and amortization 3,247 4,678
Accretion of discounts on asset retirement
obligations and debt 67 141
Stock option compensation (benefit) 10 976
Equity in loss of Pinnacle Gas Resources, Inc. 244 222
Deferred income taxes 1,308 1,539
Other -- 126
Changes in assets and liabilities-
Accounts receivable 495 3,495
Other assets (10) 406
Accounts payable (2,634) (6,839)
Other liabilities 1,514 49
-------- --------
Net cash provided by operating activities 6,424 7,379
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (21,295) (19,243)
Proceeds from the sale or properties -- 9,000
Change in capital expenditure accrual 1,165 (1,212)
Advances to operators 133 415
Advances for joint operations (668) 1,327
-------- --------
Net cash used in investing activities (20,665) (9,713)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from the sale of common stock:
Secondary offering, net of offering costs 23,422 --
Warrants exercised -- 1,000
Stock options exercised and other 211 1,010
Advances under borrowing base facility -- 5,024
Debt repayments (7,805) (2,025)
Deferred loan costs (16) (79)
-------- --------
Net cash provided by financing activities 15,812 4,930
-------- --------
NET INCREASE IN CASH AND CASH EQUIVALENTS 1,571 2,596
CASH AND CASH EQUIVALENTS, beginning of period 3,322 5,668
-------- --------
CASH AND CASH EQUIVALENTS, end of period $ 4,893 $ 8,264
======== ========
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest (net of amounts capitalized) $ 43 $ 608
======== ========
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. SUMMARY OF SIGNIFICANT 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 financial statements and notes thereto included in
the Company's Annual Report on Form 10-K for the year ended December 31, 2004.
Reclassifications
Certain reclassifications have been made to prior period's financial statements
to conform to the current presentation.
Critical Accounting Policies and 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 consolidated
financial statements and the reported amounts of revenues and expenses during
the reporting periods. Actual results could differ from these estimates.
Significant estimates include volumes of oil and natural gas reserves used in
calculating depletion of proved oil and natural gas properties, future net
revenues and abandonment obligations, impairment of undeveloped properties,
future income taxes and related assets/liabilities, bad debts, derivatives,
contingencies and litigation. Oil and natural gas reserve estimates, which are
the basis for unit-of-production depletion and the ceiling test, have numerous
inherent uncertainties. The accuracy of any reserve estimate is a function of
the quality of available data and of engineering and geological interpretation
and judgment. Results of drilling, testing and production subsequent to the date
of the estimate may justify revision of such estimate. Accordingly, reserve
estimates are often different from the quantities of oil and natural gas that
are ultimately recovered. In addition, reserve estimates are vulnerable to
changes in wellhead prices of crude oil and natural gas. Such prices have been
volatile in the past and can be expected to be volatile in the future.
The significant estimates are based on current assumptions that may be
materially effected by changes to future economic conditions such as the market
prices received for sales of volumes of oil and natural gas, interest rates, the
market value of the Company's common stock and corresponding volatility and the
Company's ability to generate future taxable income. Future changes to these
assumptions may affect these significant estimates materially in the near term.
Oil and Natural Gas Properties
Investments in oil and natural gas properties are accounted for using the
full-cost method of accounting. All costs directly associated with the
acquisition, exploration and development of oil and natural gas properties are
capitalized. Such costs include lease acquisitions, seismic surveys, and
drilling and completion equipment. The Company proportionally consolidates its
interests in oil and natural gas properties. The Company capitalized
compensation costs for employees working directly on exploration activities of
$0.4 million and $0.5 million for the three months ended March 31, 2004 and
2005, respectively. Maintenance and repairs are expensed as incurred.
Oil and natural gas properties are amortized based on the unit-of-production
method using estimates of proved reserve quantities. Investments in unproved
properties are not amortized until proved reserves associated with the projects
can be determined or until they are impaired. Unevaluated properties are
evaluated periodically for impairment on a property-by-property basis. If the
results of
-5-
an assessment indicate that the properties are impaired, the amount of
impairment is added to the proved oil and natural gas property costs to be
amortized. The amortizable base includes estimated future development costs and,
where significant, dismantlement, restoration and abandonment costs, net of
estimated salvage values. The depletion rate per Mcfe for the three months ended
March 31, 2004 and 2005 was $1.73 and $1.99, respectively.
Dispositions of oil and natural gas properties are accounted for as adjustments
to capitalized costs with no gain or loss recognized, unless such adjustments
would significantly alter the relationship between capitalized costs and proved
reserves.
Effective February 1, 2005, the Company sold to a private company its interest
in the Patterson Prospect Area in St. Mary Parish, Louisiana, including the
Shadyside #1 well and any anticipated follow-up wells, for approximately $9.0
million. The Company's average daily production from the Shadyside #1 during the
fourth quarter 2004 was approximately 970 Mcfe per day. Proceeds from the sale
were used in the 2005 Barnett Shale and Gulf Coast drilling program and for
general corporate purposes.
The net capitalized costs of proved oil and natural gas properties are subject
to a "ceiling test" which limits such costs to the estimated present value,
discounted at a 10% interest rate, of future net revenues from proved reserves,
based on current economic and operating conditions. If net capitalized costs
exceed this limit, the excess is charged to operations through depreciation,
depletion and amortization. During the year-end close of 2003, a computational
error was identified in the ceiling test calculation which overstated the tax
basis used in the computation to derive the after-tax present value (discounted
at 10%) of future net revenues from proved reserves. This tax basis error was
also present in each of the previous ceiling test computations dating back to
1997. This error only affected the after-tax computation, used in the ceiling
test calculation and the unaudited supplemental oil and natural gas disclosure
and did not impact: (1) the pre-tax valuation of the present value (discounted
at 10%) of future net revenues from proved reserves, (2) the proved reserve
volumes, (3) the Company's EBITDA or future cash flows from operations, (4) the
net deferred tax liability, (5) the estimated tax basis in oil and natural gas
properties, or (6) the 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 oil and
natural gas assets was necessary in any of the years from 1997 to 2003. However,
based upon the oil and natural gas prices in effect on 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 the 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 on March 31, 2003 and
September 30, 2003, the after-tax write-down would have been approximately $1.0
million and $6.3 million, respectively, had we not taken into account the
subsequent improvements. These improvements at September 30, 2003 included
estimated proved reserves attributable to the Company's Shady Side # 1 well
(which the Company subsequently sold in February 2005). 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.
Depreciation of other property and equipment is provided using the straight-line
method based on estimated useful lives ranging from five to 10 years.
Supplemental Cash Flow Information
The Statement of Cash Flows for the three months ended March 31, 2004 does not
include interest paid-in-kind of $0.4 million. The Statement of Cash Flows for
the three months ended March 31, 2005 does not include interest paid-in-kind of
$0.7 million and the net exercise of $80,000 of warrants.
Stock-Based Compensation
In June of 1997, the Company established the Incentive Plan of Carrizo Oil &
Gas, Inc. (the "Incentive Plan"). In October 1995, the FASB issued SFAS No. 123,
"Accounting for Stock-Based Compensation," which requires the Company to record
stock-based compensation at fair value. In December 2002, the FASB issued SFAS
No. 148, "Accounting for Stock Based Compensation - Transition and Disclosure."
The Company has adopted the disclosure requirements of SFAS No. 148 and has
elected to record employee compensation expense utilizing the intrinsic value
method permitted under Accounting Principles Board (APB) Opinion No. 25,
"Accounting for Stock Issued to Employees." The Company accounts for its
employees' stock-based compensation plan under APB Opinion No. 25 and its
related interpretations. Accordingly, any deferred compensation expense would be
recorded for stock options based on the excess of the market value of the common
stock on the date the options were granted over the aggregate exercise price of
the options. This deferred compensation would be amortized over the vesting
period of each option. Had compensation cost been determined consistent with
SFAS No. 123 "Accounting for Stock Based Compensation" for all options, the
Company's net income (loss) and earnings per share would have been as follows:
-6-
FOR THE THREE MONTHS ENDED
MARCH 31,
--------------------------
2004 2005
------ ------
(In thousands except
per share amounts)
Net income available to common
shareholders, as reported $1,985 $2,586
Add: Stock-based employee compensation
expense recognized, net of tax -- 634
Less: Total stock-based employee
compensation expense determined under
fair value method for all awards, net of
related tax effects (132) (122)
------ ------
Pro forma net income available
to common shareholders $1,853 $3,098
====== ======
Net income per common share, as reported:
Basic $ 0.12 $ 0.11
Diluted 0.10 0.11
Pro Forma net income per common share, as if value
method had been applied to all awards:
Basic $ 0.11 $ 0.14
Diluted 0.10 0.13
Diluted earnings per share amounts for the three months ended March 31, 2004 and
2005 are based upon 19,284,153 and 23,402,248 shares, respectively, that include
the dilutive effect of assumed stock option and warrant conversions of 2,670,723
and 900,552 shares, respectively.
Repriced options are accounted for as compensatory options using variable
accounting treatment in accordance with FASB Interpretation No. 44, "Accounting
for Certain Transactions involving Stock Based Compensation - on Interpretation
of APB No. 25" (FIN 44). Under variable plan accounting, compensation expense is
adjusted for increases or decreases in the fair market value of the Company's
common stock to the extent that the market value exceeds the exercise price of
the option. Variable plan accounting is applied to the repriced options until
the options are exercised, forfeited, or expire unexercised.
Derivative Instruments and Hedging Activities
Upon entering into a derivative contract, the Company designates the derivative
instruments as a hedge of the variability of cash flow to be received (cash flow
hedge). Changes in the fair value of a cash flow hedge are recorded in other
comprehensive income to the extent that the derivative is effective in
offsetting changes in the fair value of the hedged item. Any ineffectiveness in
the relationship between the cash flow hedge and the hedged item is recognized
currently in income. Gains and losses accumulated in other comprehensive income
associated with the cash flow hedge are recognized in earnings as oil and
natural gas revenues when the forecasted transaction occurs. All of the
Company's derivative instruments at December 31, 2004 and March 31, 2005 were
designated 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.
-7-
The Company typically uses fixed rate swaps and costless collars to hedge its
exposure to material changes in the price of oil and natural gas. The Company
formally documents all relationships between hedging instruments and hedged
items, as well as its risk management objectives and strategy for undertaking
various hedge transactions. This process includes linking all derivatives that
are designated cash flow hedges to forecasted transactions. The Company also
formally assesses, both at the hedge's inception and on an ongoing basis,
whether the derivatives that are used in hedging transactions are highly
effective in offsetting changes in cash flows of hedged transactions.
The Company's Board of Directors sets all of the Company's hedging policy,
including volumes, types of instruments and counterparties, on a quarterly
basis. These policies are implemented by management through the execution of
trades by either the President or Chief Financial Officer after consultation and
concurrence by the President, Chief Financial Officer and Chairman of the Board.
The master contracts with the authorized counterparties identify the President
and Chief Financial Officer as the only Company representatives authorized to
execute trades. The Board of Directors also reviews the status and results of
hedging activities quarterly.
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
ENDED MARCH 31,
--------------------
2004 2005
---- ----
Cokinos Natural Gas Company 24% 11%
Chevron/Texaco -- 16%
WMJ Investments Corp. 18% 12%
Texon L.P. 22% --
Sequent Energy Management L.P. -- 11%
Earnings Per Share
Supplemental earnings per share information is provided below:
FOR THE THREE MONTHS ENDED MARCH 31,
------------------------------------------------------------
INCOME SHARES PER-SHARE AMOUNT
--------------- ----------------------- ----------------
2004 2005 2004 2005 2004 2005
------ ------ ---------- ---------- ----- -----
(In thousands except share and per share amounts)
Basic Earnings per Common Share
Net income available to common shareholders $1,985 $2,586 16,613,430 22,501,696 $0.12 $0.11
===== =====
Dilutive effect of Stock Options, Warrants and
Preferred Stock conversions 198 -- 2,670,723 900,552
------ ------ ---------- ----------
Diluted Earnings per Common Share
Net income available to common shareholders
plus assumed conversions $2,183 $2,586 19,284,153 23,402,248 $0.10 $0.11
====== ====== ========== ========== ===== =====
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 47,000 and 53,334 stock options, during the three months ended March
31, 2004 and 2005, 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. At March 31, 2004 and 2005, the Company
also had 1,262,930 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.
Recently Issued Accounting Pronouncements
On December 16, 2004, the FASB issued SFAS No. 123 (revised 2004), "Share-Based
Payment" (SFAS No. 123(R)"). SFAS No. 123(R) will require companies to measure
all employee stock-based compensation awards using a fair value method and
record such
-8-
expense in their consolidated financial statements. In addition, the adoption of
SFAS No. 123(R) requires additional accounting and disclosure related to the
income tax and cash flow effects resulting from share-based payment
arrangements. SFAS No. 123(R) was effective beginning as of the first interim or
annual reporting period beginning after June 15, 2005. On April 14, 2005, the
SEC adopted a new rule that defers the effective date of SFAS No. 123(R) and
allows companies to implement the provisions of SFAS No. 123 (R) at the
beginning of their next fiscal year. The Company will adopt the provisions of
SFAS No. 123 (R) during the first quarter of 2006 using the modified prospective
method for transition. The Company believes it is likely that the impact of the
requirements of SFAS No. 123(R) will significantly impact the Company's future
results of operations and continues to evaluate it to determine the degree of
significance.
2. LONG-TERM DEBT:
At December 31, 2004 and March 31, 2005, long-term debt consisted of the
following:
DECEMBER 31, MARCH 31,
2004 2005
------------ ---------
(IN THOUSANDS)
Credit Facility $18,000 $21,000
Senior Secured Notes(1) 16,268 16,692
Senior Subordinated Notes(1) 28,584 28,995
Capital lease obligations 122 97
Other -- 23
------- -------
62,974 66,807
Less: current maturities (90) (88)
------- -------
$62,884 $66,719
======= =======
- ----------
(1) Amounts are presented net of discount of $2.0 million and $1.9 million as
of December 31, 2004 and March 31, 2005, respectively.
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 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
wholly-owned subsidiary.
The Facility A Borrowing Bases are scheduled to be redetermined by the lenders
at least semi-annually on each November 1 and May 1. The May 1, 2005
redetermination has not yet been completed. The Facility A Borrowing Base, under
the Credit Facility, as of December 31, 2004 was $30.0 million and was $37.0
million as of March 31, 2005. The Company and the lenders may each request one
unscheduled borrowing base redetermination subsequent to each scheduled
redetermination. The Facility A Borrowing Base will at all times equal the
Facility A Borrowing Base most recently redetermined by the lenders, less
quarterly borrowing base reductions required subsequent to such redetermination.
The borrowing base reductions are $3.0 million per quarter currently increasing
to $4.0 million per quarter effective May 1, 2005. The lenders will reset the
Facility A Borrowing Base amount at each scheduled and each unscheduled
borrowing base redetermination 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
-9-
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. These covenants, as amended, include 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 $108.8 million, plus 100%
of all subsequent common and preferred equity contributed by shareholders'
subsequent to December 31, 2004, plus 50% of all positive earnings occurring
subsequent to December 31, 2004, 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.
On April 27, 2005 the Company amended the Credit Facility to, among other
things, add a provision restricting loans from the Company to its subsidiaries
or guarantors of the Credit Facility if the proceeds of such loans will be
invested in an entity in which the Company holds an equity interest.
At December 31, 2004, amounts outstanding under the Credit Facility totaled
$18.0 million with an additional $12.0 million available for future borrowings.
At March 31, 2005, amounts outstanding under the Credit Facility totaled $21.0
million, with an additional $16.0 million available for future borrowings. At
December 31, 2004 and at March 31, 2005, no letters of credit were issued and
outstanding under the Credit Facility.
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
Rocky Mountain Gas, Inc. ("RMG") as consideration for certain interests in oil
and natural gas leases held by RMG in Wyoming and Montana. The RMG note was
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. All of
these amounts have been paid. The RMG note was 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.
("Pinnacle"), 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 relinquished a portion of its interests in certain oil and
natural gas leases to RMG and reduced the principal due on the RMG 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 was
payable in one payment of $11,323 and 35 monthly payments of $7,549 including
interest at 8.6% per annum. In October 2002, the Company entered into a capital
lease agreement secured by certain production equipment in the amount of $0.1
million. The lease is payable in 36 monthly payments of $3,462 including
interest at 6.4% per annum. In May 2003, the Company entered into a capital
lease agreement secured by certain production equipment in the amount of $0.1
million. The lease is payable in 36 monthly payments of $3,030 including
interest at 5.5% per annum. In August 2003, the Company entered into a capital
lease agreement secured by certain production equipment in the amount of $0.1
million. The lease is payable in 36 monthly payments of $2,179 including
interest at 6.0% per annum. The Company has the option to acquire the equipment
at the conclusion of the lease for $1 under all of these leases. Depreciation on
the capital leases for the three months ended March 31, 2004 and 2005 amounted
to $12,000 and $11,000, respectively, and accumulated depreciation on the leased
equipment at December 31, 2004 and March 31, 2005 amounted to $124,000 and
$135,000, respectively.
-10-
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. As amended as
described below, the Subordinated Notes allow the Company, until December 2005,
to increase the amount of the Subordinated Notes for 60% of the interest which
would otherwise be payable in cash. As of December 31, 2004 and March 31, 2005,
the outstanding balance of the Subordinated Notes had been increased by $6.8
million and $7.2 million respectively, for such interest paid in kind. During
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 for cash to purchase
92,006 shares for a total of 92,006 shares of common stock. As a result, no
warrants to purchase shares of common stock 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
amendment 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 is being amortized over the remaining life of the Subordinated
Notes using the effective interest method.
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 (d) a limitation on our Total Debt (as defined
in the securities purchase agreement) to 3.5 times EBITDA for any twelve month
period.
Senior Subordinated Secured Notes
On October 29, 2004, the Company 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, the Company may issue up to $28 million aggregate principal amount of
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 $18.0 million aggregate principal amount of the Senior Secured Notes
for a purchase price of $16.2 million. The debt discount is being amortized to
interest expense using the effective interest method over the life of the note.
Subject to the satisfaction of certain conditions, the Company has 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
the Company's current proved producing reserves and non-reserve assets,
guaranteed by the Company's subsidiary, and subordinated to the Company's
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 the Company has the option to prepay
the Senior Secured Notes at any time. The Senior Secured Notes include an option
that allows the Company to pay-in-kind 50% of the interest due until June 5,
2007 by increasing the principal due by a like amount. As of March 31, 2005, the
outstanding balance of the Senior Subordinated Secured Note had been increased
by $0.3 million for such interest paid-in-kind. Subject to certain conditions,
the Company has the option to pay the interest on and principal of (at maturity
or upon prepayment) the Senior Secured Notes with the Company's common stock, as
long as the Secured Note Purchaser does not hold more than 9.99% of the number
of shares of the Company's 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. Issuance costs
-11-
related to the transaction were $0.5 million and are being amortized over the
life of the Senior Secured Notes using the effective interest method.
As contemplated by the Secured Senior Notes Purchase Agreement, the Company also
entered into a registration rights agreement with the Secured Note Purchaser
(the "Registration Rights Agreement"). In the event the Company chooses to issue
shares of its 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. The Company is 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. The Company is 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 the
Company's 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, the Company 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 its common stock. In certain
situations, the Company is required to indemnify the holders of registration
rights under the Registration Rights Agreement, including, without limitation,
for liabilities under the Securities Act.
The Senior Secured Notes Purchase Agreement includes certain representations,
warranties and covenants by the parties thereto. The Company is 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 the Company's tangible net worth as of September 30, 2004. Upon a
change of control, any holders of the Senior Secured Notes may require the
Company 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 stockholders, liens, investments,
mergers, acquisitions, asset dispositions, asset pledges and mortgages,
repurchase or redemption for cash of the Company's common stock, speculative
commodity transactions and other matters. The Senior Secured Notes Purchaser is
an affiliate of the Subordinated Notes Purchaser.
3. INVESTMENT IN PINNACLE GAS RESOURCES, INC.:
THE PINNACLE TRANSACTION
On June 23, 2003, pursuant to a Subscription and Contribution Agreement by and
among the Company and its wholly-owned subsidiary, CCBM, Inc. ("CCBM"), Rocky
Mountain Gas, Inc. ("RMG") and the Credit Suisse First Boston Private Equity
entities, named therein (the "CSFB Parties"), CCBM and RMG contributed their
respective interests, having a estimated fair value of approximately $7.5
million each, in (1) leases in the Clearmont, Kirby, Arvada and Bobcat project
areas and (2) oil and natural gas reserves in the Bobcat project area to a newly
formed entity, Pinnacle Gas Resources, Inc., a Delaware corporation
("Pinnacle"). In exchange for the contribution of these assets, CCBM and RMG
each received 37.5% of the common stock of Pinnacle ("Pinnacle Common Stock") as
of the closing date and options to purchase Pinnacle Common Stock ("Pinnacle
Stock Options"). The Company accounts for its interest in Pinnacle using the
Equity method. 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.
-12-
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, the approximately $1.1 million of the remaining
balance of CCBM's obligation to RMG was scheduled to be paid in monthly
installments of approximately $52,805 through November 2004 and a balloon
payment on December 31, 2004. All of these amounts have been paid. The RMG note
was 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 March 31, 2005, 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 54.6%, 22.7% and
22.7%, respectively. In March 2004, the CSFB Parties contributed additional
funds of $11.8 million into Pinnacle to continue funding the 2004 development
program which increased the CSFB Parties' ownership to 66.7% on a fully diluted
basis assuming CCBM and RMG each elect not to exercise their Pinnacle Stock
Options.
Historically, the business operations and development program of Pinnacle has
not required the Company to provide any further capital infusion. In March 2005,
Pinnacle acquired additional undeveloped acreage with an undisclosed company
which could significantly increase Pinnacle's development program budget in
2005. On or before May 12, 2005, CCBM and the other Pinnacle shareholders have
the option to participate in the equity contribution into Pinnacle needed to
finance the acquisition and the related development program in 2005. Should the
Company elect to maintain its proportionate ownership interest in Pinnacle, the
Company estimates that it would be required to contribute $3.2 million. If CCBM
opts not to contribute any or all of its share of the equity contribution, its
fully diluted ownership in Pinnacle would be reduced. CCBM plans to contribute
$3.0 million in May 2005, its approximate share of the equity capital needed to
close the acquisition and fund part of the additional development program.
Subject to approval from the Company's board of directors and lenders, CCBM may
elect to increase its contribution in May 2005 from $3.0 million to $4.0
million, if additional equity participation becomes available. There can be no
assurance regarding CCBM's level of participation in future equity contributions
needed, if any.
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 is 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 sheets as of December 31, 2004 and March
31, 2005.
4. INCOME TAXES:
The Company provides deferred income taxes at the rate of 35%, which also
approximates its statutory rate, that amounted to $1.3 million and $1.5 million
for the three months ended March 31, 2004 and March 31, 2005, respectively.
5. COMMITMENTS AND CONTINGENCIES:
From time to time, the Company is party to certain legal actions and claims
arising in the ordinary course of business. While the outcome of these events
cannot be predicted with certainty, management does not expect these matters to
have a materially adverse effect on the financial position 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.
-13-
6. 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 was 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 442,026
shares of common stock on June 30, 2004. As a result, no shares of Series B
Preferred Stock remain outstanding. The total value of the Series B Preferred
Stock upon conversion was $7.5 million and was reclassified to stockholders'
equity following the conversion.
The warrants had a five-year term and entitled 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
were exercisable on a cashless exercise basis. During 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 and, during the first quarter of 2005, Mr.
Webster exercised all of his 84,210 warrants on a cashless basis, receiving a
total of 54,669 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.
7. SHAREHOLDER'S EQUITY:
In the first quarter of 2004, the Company completed the public offering of
6,485,000 shares of common stock at $7.00 per share generating net proceeds of
approximately $23.3 million. The offering included 3,655,500 newly issued shares
offered by the Company and 2,829,500 shares offered by certain selling
shareholders. The Company did not receive any proceeds from the shares sold by
the selling shareholders. The Company used part of 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. Initially, the Company used a portion of the net proceeds to repay the
$7 million outstanding principal amount under its revolving credit facility and
to complete an $8.2 million Barnett Shale acquisition on February 27, 2004.
The Company issued 3,801,038 and 574,097 shares of common stock during the three
months ended March 31, 2004 and March 31, 2005, respectively. The shares issued
during the three months ended March 31, 2004 consisted of 3,655,500 shares
issued through the secondary offering, 85,705 shares issued through the exercise
of warrants and the balance through the exercise of options granted under the
Company's Incentive Plan. The shares issued during the three months ended March
31, 2005 consisted of 304,669 shares issued through the exercise of warrants and
the balance through the exercise of options granted under the Company's
Incentive Plan.
In January 2005, all of the remaining 250,000 warrants that were originally
issued to affiliates of Enron were exercised for 250,000 shares of the Company's
common stock. The net cash proceeds from the exercise of the warrants amounted
to $1.0 million.
8. 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
-14-
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 termination or 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, 2004 and March 31, 2005, the unrealized gain/(loss) was
$59,000 and ($0.2 million), net of tax of $34,000 and ($0.1 million),
respectively, remained in accumulated other comprehensive income (loss) related
to the valuation of the Company's hedging positions.
Total oil hedged under swaps and collars during the three months ended March 31,
2004 and 2005 were 27,300 Bbls and 32,900 Bbls, respectively. Total natural gas
hedged under swaps and collars during the three months ended March 31, 2004 and
2005 were 726,000 MMBtu and 928,000 MMBtu, respectively. The net gains (losses)
realized by the Company under such hedging arrangements were $0.1 million and
$0.2 million for the three months ended March 31, 2004 and 2005, respectively,
and are included in oil and natural gas revenues.
At March 31, 2004 and 2005 the Company had the following outstanding hedge
positions:
AS OF 3/31/2004
--------------------------------------------------------------
CONTRACT VOLUMES
------------------ AVERAGE AVERAGE AVERAGE
QUARTER BBLS MMBTU FIXED PRICE FLOOR PRICE CEILING PRICE
------- ------ --------- ----------- ----------- -------------
Second Quarter 2004 27,300 $31.55
Second Quarter 2004 1,001,000 $4.40 $5.86
Third Quarter 2004 9,300 33.33
Third Quarter 2004 828,000 4.19 6.07
Fourth Quarter 2004 829,000 4.41 6.47
First Quarter 2005 450,000 4.64 8.00
AS OF 3/31/2005
--------------------------------------------------------------
CONTRACT VOLUMES
------------------ AVERAGE AVERAGE AVERAGE
QUARTER BBLS MMBTU FIXED PRICE FLOOR PRICE CEILING PRICE
------- ------ --------- ----------- ----------- -------------
Second Quarter 2005 21,200 $50.64
Second Quarter 2005 819,000 $5.79 $7.31
Second Quarter 2005 91,000 6.03
Third Quarter 2005 736,000 5.70 7.54
Third Quarter 2005 92,000 6.03
Fourth Quarter 2005 552,000 5.25 7.92
Fourth Quarter 2005 92,000 6.03
During April 2005, the Company entered into costless collar arrangements
covering 668,000 MMBtu of natural gas for May 2005 through March 2006 production
with an average floor of $7.39 and an average ceiling of $8.70, and 36,000 Bbls
of oil for April 2005 through September 2005 production with a floor of $50.00
and an average ceiling of $67.14.
-15-
9. SUBSEQUENT EVENT:
During April 2005, the Company acquired working interests in certain producing
oil and natural gas properties and certain leaseholds for total consideration of
approximately $4.1 million, comprised of approximately $2.3 million in cash and
112,697 shares of the Company's common stock. The properties are located in the
Company's Barnett Shale project area in North Texas.
-16-
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, 2004 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 2004, we drilled 71 wells (27.3 net), including 38 wells in the
onshore Gulf Coast area and 33 wells in the Barnett Shale play, with a success
rate of 92%. During the three months ended March 31, 2005, we participated in
the drilling of 16 gross wells (9.2 net) in the onshore Gulf Coast, Barnett
Shale and East Texas areas, all of which were successful. Twelve of these
successful wells have been completed and four are in the process of being
completed. In 2005, we plan to drill 34 gross wells (14.4 net) in the onshore
Gulf Coast area, 37 gross wells (24.0 net) in our Barnett Shale area and nine
gross wells (7.7 net) in our East Texas area. 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 2005, depreciation, depletion and amortization, oil
and natural gas operating expenses and production are expected to increase over
levels incurred in 2004.
Since our initial public offering, we have grown primarily through the
exploration of properties within our project areas, although we consider
acquisitions from time to time and may in the future complete acquisitions that
we find attractive. In 2004 and 2005 we completed asset acquisitions in our
Barnett Shale project area described below in "--Barnett Shale Activity."
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
selling stockholders. Our net proceeds of approximately $23.3 million from this
offering were used: (1) to accelerate our drilling program, (2) to retain larger
interests in portions of our drilling prospects that we otherwise would sell
down (or for which we would seek joint partners), (3) to fund a portion of our
activities in the Barnett Shale area and (4) for general corporate purposes. We
did not receive any proceeds from the shares sold by the selling stockholders.
Barnett Shale Activity
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 on February 27, 2004 of working interests and acreage in certain oil
and gas wells located in the Newark East Field in Denton County, Texas in the
Barnett Shale trend for $8.2 million. This acquisition included 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 acquisition included 21
existing gross wells (6.7 net) and interests in approximately 1,500 net acres,
which we expect will provide another 31 gross drill sites: five of which were
drilled in 2004, 21 of which will target proved undeveloped reserves and five of
which will be exploratory.
In April 2005, we acquired assets in the Barnett Shale for approximately $4.1
million. This acquisition consisted of approximately 600 net acres and working
interests in 14 existing gross wells (7.3 net) with an estimated 5.4 MMcfe of
proved reserves, based upon our internal estimates. All of the interests in the
wells acquired related to wells in which we already had an interest. The
consideration paid for this acquisition was $2.3 million in cash and 112,697
shares of the Company's common stock.
Initially, we financed our Barnett Shale activities with our available cash on
hand. We financed a portion of our 2004 capital expenditure program for the
Barnett Shale area with funds from the October 2004 issuance of the 10% Senior
Subordinated 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 area. We may not be able to obtain such financing on terms that
are acceptable to us, or at all.
-17-
In the Barnett Shale area, we drilled 33 gross wells (13.7 net) in 2004 and nine
gross wells (4.8 net) during the three months ended March 31, 2005, all of which
were successful. We plan to drill 37 gross wells (24.0 net) in this area in
2005, subject to obtaining additional financing to supplement our Credit
Facility, additional Senior Secured Note financing available and achieving
expected operating cash flows. For the quarter ended March 31, 2005 our average
daily production was approximately 3.1 MMcfe/d, with 43 gross wells on line and
another 25 gross wells in various stages of testing, completion and awaiting
pipeline hookup. Currently we estimate our production rate to be approximately
5.0 MMcfe/d.
In addition to our drilling activity, we have continued to expand our Barnett
Shale acreage position, growing our net leasehold acreage from approximately
4,100 to 30,700 to 50,000 acres, at the end of 2003, 2004 and April 2005,
respectively. Similarly, we have increased our estimated number of developmental
locations from four to 40 to 41 horizontal locations, at the end of 2003, 2004
and April 2005, respectively and we have increased our estimated number of
exploratory drilling locations (horizontal) in the Barnett Shale area from 21 to
152 to 300 locations, at the end of 2003, 2004 and April 2005, respectively.
Recent Developments
Effective February 1, 2005, we sold to a private company our interest in the
Patterson Prospect Area in St. Mary Parish, Louisiana, including the Shadyside
#1 well and any anticipated follow-up wells, for approximately $9.0 million. Our
average daily production from the Shadyside #1 during the fourth quarter 2004
was approximately 970 Mcfe per day. Proceeds from the sale were used in the 2005
Barnett Shale and Gulf Coast drilling program and for general corporate
purposes.
On or about April 30, 2005, two of our top producing wells - the Delta Farms #1
and the Beach House #1, were shut in for workovers. The Beach House #1, which
averages approximately 2.0 MMcfe/d net to us, is expected to be shut in for two
weeks while we complete a workover and gravel pack. The Delta Farms #1, which
averages approximately 2.0 MMcfe/d net to us, will probably remain shut in for
four to five weeks while we perform a squeeze cement job to eliminate water
channeling behind the casing. While there can be no assurance at this time, we
believe wellbore problems to be the cause for the production disruptions on both
wells, and, accordingly, expect that we will successfully re-establish
production at the pre-shut-in levels. Based upon the period of time these wells
are projected to be shut in, we estimate that our second quarter average daily
production will be reduced by approximately 1.5 MMcfe/d. There's always a risk
that these workovers may be unsuccessful. In that event, we could lose up to an
estimated 1.4 Bcfe and 0.1 Bcfe of reserves currently booked on the Delta Farms
#1 (current pay zone) and the Beach House #1, respectively. The Delta Farms #1
has another proven zone up the hole; accordingly, we would recomplete the well
in the second zone should the aforementioned workover be unsuccessful.
In connection with our revolving credit facility (the "Credit Facility"), we are
presently completing a scheduled May 2005 borrowing base redetermination with
our lenders. In light of the aforementioned workovers planned for the Delta
Farms #1 and the Beach House #1, our lenders have granted a five week extension
to complete this redetermination of our borrowing base. Until the
redetermination is completed in mid June 2005, our borrowing base, which is
subject to scheduled quarterly reductions of $4.0 million, will be reduced from
$37.0 million to $33.0 million.
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. 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. In March
2004, Credit Suisse First Boston Private Equity Entities (the "CSFB Parties")
contributed additional funds of $11.8 million into Pinnacle to fund its 2004
development program, which increased the CSFB Parties' ownership to 66.7% on a
fully diluted basis assuming we and RMG each elect not to exercise our available
options.
In March 2005, Pinnacle entered into a purchase and sale agreement to acquire
additional undeveloped acreage, which would also significantly increase its
development program budget in 2005. On or before May 12, 2005, CCBM and the
other Pinnacle shareholders have the option to participate in the equity
contribution into Pinnacle needed to finance this acquisition and its
development program in 2005. Should we elect to maintain our proportionate
ownership interest in Pinnacle on a fully diluted basis, we estimate that we
would be required to contribute approximately $3.2 million in May 2005 and, if
requested by Pinnacle's Board of Directors, up to an additional $3.2 million by
December 31, 2006. If CCBM opts not to contribute any or all of its share of the
equity contribution, its fully diluted ownership in Pinnacle would be reduced.
CCBM currently plans to purchase additional Pinnacle capital stock valued at
$3.0 million in May 2005, its approximate share of the first installment of the
equity capital needed to fund the acquisition and part of the additional
development program. Subject to approval from our board of directors and
lenders, CCMB may elect to increase its contribution in May 2005 from $3.0
million to $4.1 million, if additional equity participation becomes available.
There can be no assurance regarding CCBM's level of participation in future
equity contributions, if any.
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In addition to our interest in Pinnacle, we have maintained interests in
approximately 162,000 gross acres in the Castle Rock coalbed methane project
area in Montana and the Oyster Ridge project area in Wyoming. Our discussion of
future drilling and capital expenditures does not reflect operations conducted
through Pinnacle.
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 March 31, 2005,
Compared to the Three Months Ended March 31, 2004
Oil and natural gas revenues for the three months ended March 31, 2005 increased
42% to $15.4 million from $10.9 million for the same period in 2004. Production
volumes for natural gas during the three months ended March 31, 2005 increased
to 2.0 Bcf from 1.3 Bcf for the same period in 2004. Average natural gas prices
increased 4% to $6.19 per Mcf in the first quarter of 2005 from $5.95 per Mcf in
the same period in 2004. Production volumes for oil in the first quarter of 2005
decreased 25% to 65 MBbls from 87 MBbls for the same period in 2004. Average oil
prices increased 52% to $50.65 per barrel in the first quarter of 2005 from
$33.33 per barrel in the same period in 2004. The increase in natural gas
production was due to the commencement of production at the Peal Ranch,
Encinitas, LL&E #1 and #2, BP America #1, Callison #2 and the Barnett Shale
wells partially offset by the natural decline in production at the Beach House
#1 and #2, Espree #1 and other wells. The decrease in oil production was due
primarily to the natural decline of production at the Beach House #1 and #2,
Pauline Huebner A-382 #1 and #2, Hankamer #1 and other wells partially offset by
the commencement of production from the LL&E #1 and #2, BP America #1 and from
other wells. Oil and natural gas revenues include the impact of hedging
activities as discussed above under "General Overview."
The following table summarizes production volumes, average sales prices and
operating revenues for the Company's oil and natural gas operations for the
three months ended March 31, 2004 and 2005:
-19-
2005 PERIOD
COMPARED TO 2004 PERIOD
MARCH 31, -----------------------
----------------- INCREASE % INCREASE
2004 2005 (DECREASE) (DECREASE)
------- ------- ---------- ----------
Production volumes -
Oil and condensate (MBbls) 87 65 (22) (25)%
Natural gas (MMcf) 1,339 1,966 627 47%
Average sales prices - (1)
Oil and condensate (per Bbls) $ 33.33 $ 50.65 $17.32 52%
Natural gas (per Mcf) 5.95 6.19 0.24 4%
Operating revenues (In thousands)-
Oil and condensate $ 2,904 $ 3,281 $ 377 13%
Natural gas 7,969 12,177 4,208 53%
------- ------- ------
Total $10,873 $15,458 $4,585 42%
======= ======= ======
- ----------
(1) Includes impact of hedging activities.
Oil and natural gas operating expenses for the three months ended March 31, 2005
increased to $2.2 million from $1.7 million for the same period in 2004.
Operating expenses per equivalent unit increased to $0.95 per Mcfe in the first
quarter of 2005 compared to $0.90 per Mcfe in the same period in 2004.
Depreciation, depletion and amortization (DD&A) expense for the three months
ended March 31, 2005 increased 44% to $4.7 million from $3.2 million for the
same period in 2004. DD&A increased primarily due to increased production and
expenses resulting from additional seismic and drilling costs.
General and administrative expense for the three months ended March 31, 2005
increased by $0.5 million to $2.6 million from $2.1 million for the same period
in 2004. This increase in G&A expense was primarily due to higher incentive
compensation costs of $0.3 million, higher base salaries of $0.1 million and a
$0.1 million increase in general office expenses.
Stock option compensation expense was $1.0 million for the quarter ended March
31, 2005 compared to $0.01 million for the same period in 2004. 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 $0.2 million after tax charge, or $0.01 per fully diluted share,
on our minority interest in Pinnacle for the three months ended March 31, 2005.
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.
Capitalized interest increased to $1.0 million in the first quarter of 2005 from
$0.7 million for the first quarter of 2004 as a result of increased interest due
to additional Senior Secured Notes and advances on the Credit Facility.
Income taxes increased to $1.6 million for the three months ended March 31, 2005
from $1.4 million for the same period in 2004 as a result of higher taxable
income based on the factors described above.
Dividends and accretion of discount on preferred stock decreased to zero from
$0.2 million in the first quarter of 2004 as the result of the conversion of all
of the Series B Preferred Stock into common stock during the second quarter of
2004.
Net income available to common shareholders for the three months ended March 31,
2005 increased by $0.6 million from $2.0 million for the same period in 2004
primarily as a result of the factors described above.
-20-
LIQUIDITY AND CAPITAL RESOURCES
During the first quarter ended March 31, 2005, we made capital expenditures in
excess of our net cash flows provided by operating activities, using the
proceeds of $9.0 million from the sale of certain oil and natural gas
properties, $2.0 million of proceeds from the exercise of warrants and stock
options and draws on the Credit Facility. For future capital expenditures in
2005, we expect to use cash on hand and cash generated by operating activities,
draws on the Credit Facility and additional sales of Senior Secured Notes to
partially fund our planned drilling expenditures and fund leasehold costs and
geological and geophysical costs on our exploration projects in 2005 and
possible equity and debt financings.
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 oil and natural gas exploration
and development program, thereby adversely affecting the recoverability and
ultimate value of our oil and natural gas properties.
Our liquidity position was enhanced by our receipt of approximately $23.3
million in net proceeds from the completion of the 2004 public offering, the
increase in availability of funds under the Credit Facility and the proceeds
from the October 2004 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. We also increased our
liquidity through the sale of our interest in the Patterson Prospect Area in St.
Mary Parish, Louisiana, including the Shadyside #1 well and any anticipated
follow-up wells, for $9.0 million in the first quarter of 2005. See "General
Overview - Recent Developments" for further discussion of this property sale.
Cash flows provided by operating activities were $6.4 million and $7.4 million
for the three months ended March 31, 2004 and 2005, respectively. The increase
was primarily due to a change in working capital components.
We have planned capital expenditures in 2005 of approximately $85 to $90
million, of which $70.0 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. We plan
to drill approximately 34 gross wells (14.4 net) in the onshore Gulf Coast area
and 37 gross wells (24.0) net in our Barnett Shale area and nine gross wells
(7.7 net) in our East Texas areas in 2005. As described above, we expect to seek
additional financing to fund a portion of our acquisition, exploration and
development program in 2005. If we are not successful in obtaining this
financing, our capital expenditures could be reduced by $15 to $20 million in
2005. The actual number of wells drilled and capital expended is dependent upon
available financing, cash flow, availability and cost of drilling rigs, land and
partner issues and other factors. The planned capital expenditures do not
include the additional contributions to Pinnacle as described under "General
Overview- Pinnacle Gas Resources, Inc."
We have continued to reinvest a substantial portion of our cash flows into
increasing our 3-D prospect portfolio, improving our 3-D seismic interpretation
technology and funding our drilling program. Oil and natural gas capital
expenditures were $21.3 million (including our $8.2 million Barnett Shale
acquisition) and $19.2 million (excluding the $9.0 million of proceeds from the
aforementioned property sale) for the three months ended March 31, 2004 and
2005, respectively.
Our drilling efforts in the Gulf Coast region resulted in the successful
drilling of six gross wells (2.1 net) and two gross wells (0.3 net) during the
three months ended March 31, 2004 and 2005, respectively. In our Barnett Shale
area, we successfully drilled eight gross wells (4.0 net) and nine gross wells
(4.8 net) during the first quarter of 2004 and 2005, respectively. In our East
Texas area, we successfully drilled five gross wells (4.2 net) during the first
quarter of 2005. We have completed 12 of these wells and were in the process of
completing four of these wells as of March 31, 2005.
Through the end of the first quarter of 2005, Pinnacle has reported that it has
drilled 290 gross wells since inception and estimates that 96% of these wells
have been completed. Pinnacle reportedly added approximately 13.8 Bcfe of net
proved reserves through development drilling through March 31, 2005, excluding
the 10.6 Bcfe contributed or acquired at inception. Its gross operated
production has increased by approximately 213% since its inception (to
approximately 15.0 MMcf/d at March 31, 2005), and its total well count stands at
528 gross operated wells, according to Pinnacle. Because of the nature of
coalbed methane wells that require an extended dewatering period before
significant natural gas production, Pinnacle has not been able to complete its
determination on commerciality of all of these wells.
-21-
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"), maturing on September 30, 2007. 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 are scheduled to be determined by the lenders at
least semi-annually on each November 1 and May 1. The May 1, 2005
redetermination has not yet been completed. The Facility A Borrowing Base, under
the Credit Facility, on December 31, 2004 and March 31, 2005 was $30.0 million
and $37.0 million, respectively, of which $18.0 and $21.0 million, respectively,
were drawn and outstanding.
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 borrowing base reductions are $3.0 million per quarter
currently increasing to $4.0 million per quarter effective May 1, 2005. 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.
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
$108.8 million, plus 100% of all subsequent common and preferred equity
contributed by shareholders subsequent to December 31, 2004, plus 50% of all
positive earnings occurring subsequent to December 31, 2004, 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 our common stock, speculative
commodity transactions and other matters.
On April 27, 2005 we amended the Credit Facility to, among other things, add a
provision restricting loans from us to our subsidiaries or guarantors of the
Credit Facility if the proceeds of such loans will be invested in an entity in
which we hold an equity interest.
At December 31, 2004 and March 31, 2005, 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 was 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. All of these
amounts have been paid. The RMG note was secured solely by CCBM's interests in
the oil and natural gas leases in
-22-
Wyoming and Montana. 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. In the second quarter of 2004, we opted to exercise our
right to cancel one-half of the remaining note payable to RMG, or approximately
$0.3 million, in exchange for assigning one-half of our mineral interest in the
Oyster Ridge leases to RMG.
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.
Depreciation on the capital leases for the three months ended March 31, 2004 and
2005 amounted to $12,000 and $11,000, respectively, and accumulated depreciation
on the leased equipment at December 31, 2004 and March 31, 2005 amounted to
$124,000 and $135,000, 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 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. As amended and described below, the Subordinated
Notes allow us, by annual election and we have historically elected, to increase
the amount of the Subordinated Notes by 60% of the interest which would
otherwise be payable in cash through December 15, 2006. As a result, our cash
obligation on the Subordinated Notes will increase significantly after December
2006. As of December 31, 2004 and March 31, 2005, the outstanding balance of the
Subordinated Notes had been increased by $6.8 million and $7.2 million,
respectively, for such interest paid in kind. Concurrently with the sale of the
Subordinated Notes, we sold to the original purchasers 3,636,634 shares of our
common stock at a price of $2.20 per share and warrants expiring in December
2007 to purchase up to 2,760,189 shares of our common stock at an exercise price
of $2.20 per share. For accounting purposes, the warrants were valued at $0.25
each.
In 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, (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 is being amortized over the remaining life of
the Subordinated Notes using the effective interest method.
We are subject to certain other 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, (c) a
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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
(d) a limitation on our Total Debt (as defined in the securities purchase
agreement related to the Subordinated Notes) to 3.5 times EBITDA for any twelve
month period.
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. The debt discount is being amortized to
interest expense using the effective interest method over the life of the notes.
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. As of March 31, 2005, the outstanding balance of the Senior Secured
Notes had been increased by $0.3 million for such interest paid-in-kind. 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 $0.5 million and are being amortized over the life of the
Senior Secured Notes using the effective interest method.
As contemplated by the Senior Secured Notes 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.
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 the 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.
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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. In the first quarter of 2004, Mellon Ventures exercised all
168,422 of its 2002 Warrants on a cashless basis and received 36,570 shares
which were sold in the 2004 public offering.
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 442,026 shares of common stock on June 30,
2004. As a result, no shares of Series B Preferred Stock remain outstanding.
The 2002 Warrants had a five-year term and entitled 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 were exercisable at any time after issuance. The
2002 Warrants were exercisable on a cashless exercise basis. During 2004 Mellon
Ventures, Inc. exercised all of its 168,422 2002 Warrants on a cashless exercise
basis for a total of 36,570 shares of common stock and during the first quarter
of 2005 Mr. Webster exercised all of his 84,210 2002 Warrants on a cashless
basis for a total of 54,669 shares of common stock.
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.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
On December 16, 2004, the FASB issued SFAS No. 123 (revised 2004), "Share-Based
Payment" (SFAS No. 123(R)"). SFAS No. 123(R) will require companies to measure
all employee stock-based compensation awards using a fair value method and
record such expense in their consolidated financial statements. In addition, the
adoption of SFAS No. 123(R) requires additional accounting and disclosure
related to the income tax and cash flow effects resulting from share-based
payment arrangements. SFAS No. 123(R) was effective beginning as of the first
interim or annual reporting period beginning after June 15, 2005. On April 14,
2005, the SEC recently adopted a new rule that defers the effective date of SFAS
No. 123(R) and allows companies to implement the provisions of SFAS No. 123 (R)
at the beginning of their next fiscal year. We will adopt the provisions of SFAS
No. 123 (R) during the first quarter of 2006 using the modified prospective
method for transition. We believe it is likely that the impact of the
requirements of SFAS No. 123(R) will significantly impact our future results of
operations and continue to evaluate it to determine the degree of significance.
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.
Significant estimates include volumes of oil and natural gas reserves used in
calculating depletion of proved oil and natural gas properties, future net
revenues and abandonment obligations, impairment of undeveloped properties,
future income taxes and related assets/liabilities, bad debts, derivatives,
contingencies and litigation. Oil and natural gas reserve estimates, which are
the basis for unit-of-production depletion and the ceiling test, have numerous
inherent uncertainties. The accuracy of any reserve estimate is a
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function of the quality of available data and of engineering and geological
interpretation and judgment. Results of drilling, testing and production
subsequent to the date of the estimate may justify revision of such estimate.
Accordingly, reserve estimates are often different from the quantities of oil
and natural gas that are ultimately recovered. In addition, reserve estimates
are vulnerable to changes in wellhead prices of crude oil and natural gas. Such
prices have been volatile in the past and can be expected to be volatile in the
future.
The significant estimates are based on current assumptions that may be
materially effected by changes to future economic conditions such as the market
prices received for sales of volumes of oil and natural gas, interest rates, the
market value of our common stock and corresponding volatility and our ability to
generate future taxable income. Future changes to these assumptions may affect
these significant estimates materially in the near term.
Oil and Natural Gas Properties
We account for investments in natural gas and oil properties using the full-cost
method of accounting. All costs directly associated with the acquisition,
exploration and development of natural gas and oil properties are capitalized.
These costs include lease acquisitions, seismic surveys, and drilling and
completion equipment. We proportionally consolidate our interests in natural gas
and oil properties. We capitalized compensation costs for employees working
directly on exploration activities of $0.4 million and $0.6 million for the
three months ended March 31, 2004 and 2005, respectively. We expense maintenance
and repairs as they are incurred.
We amortize oil and natural gas properties based on the unit-of-production
method using estimates of proved reserve quantities. We do not amortize
investments in unproved properties until proved reserves associated with the
projects can be determined or until these investments are impaired. We
periodically evaluate, on a property-by-property basis, unevaluated properties
for impairment. If the results of an assessment indicate that the properties are
impaired, we add the amount of impairment to the proved natural gas and oil
property costs to be amortized. The amortizable base includes estimated future
development costs and, where significant, dismantlement, restoration and
abandonment costs, net of estimated salvage values. The depletion rate per Mcfe
for the three months ended March 31, 2004 and 2005 was $1.73 and $1.99,
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.
However, based upon the oil and natural gas prices in effect on 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 March 31, 2003
and September 30, 2003, the after-tax write-down would have been approximately
$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 we have since
sold in February 2005. 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. No write-down of our oil and natural gas assets was necessary for the
three months ended March 31, 2005.
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In connection with our March 31, 2005 ceiling test computation, a price
sensitivity study also indicated that a 20% increase in commodity prices at
March 31, 2005 would have increased the pre-tax present value of future net
revenues ("NPV") by approximately $62.8 million. Conversely, a 20% decrease in
commodity prices at March 31, 2005 would have reduced our NPV by approximately
$63.8 million. This would have caused our Fuel Cost Ceiling cushion to decline
to approximately $17.5 million. The aforementioned price sensitivity and NPV is
as of March 31, 2005 and, accordingly, does not include any potential changes in
reserves due to second quarter 2005 performance, such as commodity prices,
reserve revisions and drilling results.
The Full Cost Ceiling cushion at the end of March 2005 of approximately $58.9
million was based upon average realized oil and natural gas prices of $6.08 per
Bbl and $51.96 per Mcf, respectively, or a volume weighted average price of
$44.67 per BOE. This cushion, however, would have been zero on such date at an
estimated volume weighted average price of $31.97 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 been higher or substantially higher,
more often for oil than natural gas on an energy equivalent basis, although
there have been periods in which they have been lower or substantially lower.
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 72.5 Bcfe and 75.0 Bcfe of proved undeveloped reserves,
representing 66% and 72% of our total proved reserves at December 31, 2004 and
March 31, 2005, respectively. As of December 31, 2004 and March 31, 2005, a
large portion of these proved undeveloped reserves, or approximately 45.7 Bcfe
and 51.4 Bcfe, respectively, are attributable to our Camp Hill properties that
we acquired in 1994. The estimated future development costs to develop our
proved undeveloped reserves on our Camp Hill properties are relatively low, on a
per Mcfe basis, when compared to the estimated future development costs to
develop our proved undeveloped reserves on our other oil and natural gas
properties. Furthermore, the average depletable life of our Camp Hill properties
is considerably higher, or approximately 15 years, when compared to the
depletable life of our remaining oil and natural gas properties of approximately
2.25 years. Accordingly, the combination of a relatively low ratio of future
development costs and a relatively long depletable life on our Camp Hill
properties has resulted in a relatively low overall historical depletion rate
and DD&A expense. This has resulted in a capitalized cost basis associated with
producing properties being depleted over a longer period than the associated
production and revenue stream. It has also resulted in the build-up of
nondepleted capitalized costs associated with properties that have been
completely depleted.
We expect our relatively low historical depletion rate to continue until the
high level of nonproducing reserves to total proved reserves is reduced and the
life of our proved developed reserves is extended through development drilling
and/or the significant addition of new proved producing reserves through
acquisition or exploration. If our level of total proved reserves, finding cost
and current prices were all 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, 2004 included in this document are estimates
prepared by Ryder Scott Company, DeGolyer and MacNaughton, 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 judgment and the 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 our 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.
-27-
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 is dependent on our estimate of proved reserves. If these
reserve estimates decline, the rate at which we record these expenses will
increase. A 10% increase or decrease in our proved reserves would have increased
or decreased our depletion expense by 10% for the three months ended March 31,
2005.
For these reasons, estimates of the economically recoverable quantities of
natural gas and oil attributable to any particular group of properties,
classifications of those reserves based on risk of recovery and estimates of the
future net cash flows expected from them prepared by different engineers or by
the same engineers but at different times may vary substantially. Accordingly,
reserve estimates may be subject to upward or downward adjustment, and actual
production, revenue and expenditures with respect to our reserves likely will
vary, possibly materially, from estimates. Additionally, there recently has been
increased debate and disagreement over the classification of reserves, with
particular focus on proved undeveloped reserves. Changes in interpretations as
to classification standards, or disagreements with our interpretations, could
cause us to write down these reserves.
As of December 31, 2004, approximately 83% of our proved reserves were proved
undeveloped and proved nonproducing. Moreover, some of the producing wells
included in our reserve reports as of December 31, 2004 had produced for a
relatively short period of time as of that date. Because most of our reserve
estimates are calculated using volumetric analysis, those estimates are less
reliable than estimates based on a lengthy production history. Volumetric
analysis involves estimating the volume of a reservoir based on the net feet of
pay of the structure and an estimation of the area covered by the structure
based on seismic analysis. In addition, realization or recognition of our proved
undeveloped reserves will depend on our development schedule and plans. Lack of
certainty with respect to development plans for proved undeveloped reserves
could cause the discontinuation of the classification of these reserves as
proved. We have from time to time chosen to delay development of our proved
undeveloped reserves in the Camp Hill Field in East Texas in favor of pursuing
shorter-term exploration projects with higher potential rates of return, adding
to our lease position in this field and further evaluating additional economic
enhancements for this field's development. The average life of the Camp Hill
proved undeveloped reserves is approximately 15 years, with 50% of these
reserves being booked over 8 years ago. Although we have recently accelerated
the pace of the development of the Camp Hill project, there can be no assurance
that the aforementioned discontinuance will not occur.
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 (loss) 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
(loss) associated with the cash flow hedge are recognized in earnings as oil and
natural gas revenues when the forecasted transaction occurs. All of our
derivative instruments at December 31, 2004 and March 31, 2005 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.
For a discussion of the impact of changes in the prices of oil and gas on our
hedging transactions, see "Volatility of Oil and Natural Gas Prices" below.
Our Board of Directors sets all of our hedging policy, including volumes, types
of instruments and counterparties, on a quarterly basis. These policies are
followed 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
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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. We routinely assess the realizability of our
deferred tax assets. We consider future taxable income in making such
assessments. If we conclude that it is more likely than not that some portion or
all of the deferred tax assets will not be realized under accounting standards,
it is reduced by a valuation allowance. However, despite our attempt to make an
accurate estimate, the ultimate utilization of our deferred tax assets is highly
dependent upon our actual production and the realization of taxable income in
future periods.
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 purchased and sold under swaps and collars during the three months
ended March 31, 2004 and 2005 were 27,300 Bbls and 32,900 Bbls, respectively.
Total natural gas purchased and sold under swaps and collars in the three months
ended March 31, 2004 and 2005 were 726,000 MMBtu and 928,000 MMBtu respectively.
The net gains and (losses) realized by us under such hedging arrangements were
$0.1 million and $0.2 million for the three months ended March 31, 2004 and
2005, 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 including price swaps, costless collars and,
occasionally, put options, in order to establish some price floor protection. We
record the costs and any benefits derived from these price floors as a reduction
or increase, as applicable, in natural gas and oil sales revenue; these
reductions and increases were not significant for any year presented in the
financial information included in this report. The costs to purchase put options
are amortized over the option period. We do not hold or issue derivative
instruments for trading purposes.
As of December 31, 2004 and March 31, 2005, the unrealized gain/(loss) was
$59,000 and ($0.2 million), net of tax of $34,000 and ($0.1 million),
respectively, remained in accumulated other comprehensive income (loss) related
to the valuation of our hedging positions.
While the use of hedging arrangements limits the downside risk of adverse price
movements, it may also limit our ability to benefit from increases in the prices
of natural gas and oil. We enter into the majority of our hedging transactions
with two counterparties and have a netting agreement in place with those
counterparties. We do not obtain collateral to support the agreements but
monitor the financial viability of counterparties and believe our credit risk is
minimal on these transactions. Under these arrangements, payments are received
or made based on the differential between a fixed and a variable product price.
These agreements are settled in cash at expiration or exchanged for physical
delivery contracts. In the event of nonperformance, we would be exposed again to
price risk. We have some risk of financial loss because the price received for
the product at the actual physical delivery point may differ from the prevailing
price at the delivery point required for settlement of the hedging transaction.
Moreover, our hedging arrangements generally do not apply to all of our
production and thus provide only partial price protection against declines in
commodity prices. We expect that the amount of our hedges will vary from time to
time.
Our natural gas derivative transactions are generally settled based upon the
average of the reporting settlement prices on the NYMEX for the last three
trading days of a particular contract month. Our oil derivative transactions are
generally settled based on the average reporting settlement prices on the NYMEX
for each trading day of a particular calendar month. For the month of March
2005, a $0.10
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change in the price per Mcf of gas sold would have changed revenue by $65,000. A
$0.70 change in the price per barrel of oil would have changed revenue by
$18,000.
The table below summarizes our total natural gas production volumes subject to
derivative transactions during the three months ended March 31, 2005 and the
weighted average NYMEX reference price for those volumes.
NATURAL GAS SWAPS
-----------------
Volumes (MMBtu) --
Average price ($/MMBtu) --
NATURAL GAS COLLARS
-------------------
Volumes (MMBtu) 928,000
Average price ($/MMBtu)
Floor $ 5.40
Ceiling $ 8.10
The table below summarizes our total crude oil production volumes subject to
derivative transactions for the three months ended March 31, 2005 and the
weighted average NYMEX reference price for those volumes.
CRUDE OIL SWAPS
---------------
Volumes (Bbls) 5,900
Average price ($/Bbls) $48.57
CRUDE OIL COLLARS
-----------------
Volumes (Bbls) 27,000
Average price ($/Bbls)
Floor $ 41.67
Ceiling $ 50.50
At March 31, 2004 and 2005 we had the following outstanding hedge positions:
AS OF 3/31/2004
--------------------------------------------------------------
CONTRACT VOLUMES
------------------ AVERAGE AVERAGE AVERAGE
QUARTER BBLS MMBTU FIXED PRICE FLOOR PRICE CEILING PRICE
------- ------ --------- ----------- ----------- -------------
Second Quarter 2004 27,300 $31.55
Second Quarter 2004 1,001,000 $4.40 $5.86
Third Quarter 2004 9,300 33.33
Third Quarter 2004 828,000 4.19 6.07
Fourth Quarter 2004 829,000 4.41 6.47
First Quarter 2005 450,000 4.64 8.00
AS OF 3/31/2005
--------------------------------------------------------------
CONTRACT VOLUMES
------------------ AVERAGE AVERAGE AVERAGE
QUARTER BBLS MMBTU FIXED PRICE FLOOR PRICE CEILING PRICE
------- ------ --------- ----------- ----------- -------------
Second Quarter 2005 21,200 $50.64
Second Quarter 2005 819,000 $5.79 $7.31
Second Quarter 2005 91,000 6.03
Third Quarter 2005 736,000 5.70 7.54
Third Quarter 2005 92,000 6.03
Fourth Quarter 2005 552,000 5.25 7.92
Fourth Quarter 2005 92,000 6.03
During April 2005, we entered into costless collar arrangements covering 668,000
MMBtu of natural gas for May 2005 through March 2006 production with an average
floor of $7.39 and an average ceiling of $8.70, and 36,000 Bbls oil for April
2005 through September 2005 production with a floor of $50.00 and an average
ceiling of $67.14.
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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, the exploration
and development expenditures in the Barnett Shale trend, the Company's
initiatives designed to eliminate a material weakness in the Company's internal
control over financial reporting by increasing the level of the Company's
professional accounting staff, hiring a financial reporting professional,
expanding the use of independent reviews of outside financial reporting experts
and implementing a new fully-integrated accounting software system and the
results of these initiatives and all and any other statements regarding future
operations, financial results, business plans and cash needs and other
statements that are not historical facts are forward looking statements. When
used in this document, the words "anticipate," "estimate," "expect," "may,"
"project," "believe" and similar expression are intended to be among the
statements that identify forward looking statements. Such statements involve
risks and uncertainties, including, but not limited to, those relating to the
Company's dependence on its exploratory drilling activities, the volatility of
oil and natural gas prices, the need to replace reserves depleted by production,
operating risks of oil and natural gas operations, the Company's dependence on
its key personnel, factors that affect the Company's ability to manage its
growth and achieve its business strategy, risks relating to, limited operating
history, technological changes, significant capital requirements of the Company,
the potential impact of government regulations, litigation, competition, the
uncertainty of reserve information and future net revenue estimates, property
acquisition risks, availability of equipment, weather, availability of financing
, the actual results of the initiatives designed to eliminate a material
weakness in the Company's internal control over financial reporting,
availability of a qualified workforce to fill the Company's accounting
positions, completion of the implementation of the Company's new accounting
software system and the results of audits and assessments and other factors
detailed in the Company's Annual Report on Form 10-K for the year ended December
31, 2004 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.
-31-
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, 2004 except for the
Company's hedging activity subsequent to December 31, 2004 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
2 of the Notes to Unaudited Consolidated Financial Statements in Item 1 of Part
I of this Quarterly Report on Form 10-Q.
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ITEM 4 - CONTROLS AND PROCEDURES
Disclosure Controls and Procedures. We maintain disclosure controls and
procedures that are designed to provide reasonable assurance that information
required to be disclosed by us in the reports that we file or submit to the
Securities and Exchange Commission under the Securities Exchange Act of 1934, as
amended (the "Exchange Act"), is recorded, processed, summarized and reported
within the time periods specified by the Commission's rules and forms, and that
information is accumulated and communicated to our management, including our
Chief Executive Officer and Chief Financial Officer, as appropriate to allow
timely decisions regarding required disclosure.
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. As described in more detail in our Form 10-K/A
filed on May 2, 2005 (the "10-K/A"), we identified a material weakness in the
Company's internal control over financial reporting (as defined in Exchange Act
Rules 13a-15(f) and 15d-15(f)) in connection with the work related to
Management's Annual Report on Internal Control over Financial Reporting. As a
result of this material weakness, our Chief Executive Officer and Chief
Financial Officer concluded that, as of December 31, 2004, the Company's
disclosure controls and procedures were not effective. Because the control
deficiencies leading to such material weakness (a manually intensive accounting
system and the absence of a financial reporting director) are still present, our
Chief Executive Officer and Chief Financial Officer have concluded that as of
the end of the period covered by this report, the Company's disclosure controls
and procedures are not effective. The Company has outlined a number of
initiatives, as discussed below, that it believes will remediate this material
weakness in 2005.
Closing Cycle
Upon completion of the Company's Sarbanes-Oxley Compliance assessment for
its report included in the 10-K/A, the Company identified the following control
deficiencies present in its closing cycle.
- The accounting system is a manually intensive system, requiring
the extensive use of spreadsheets to accumulate data and prepare
the underlying support for reconciliations, account analysis and
routine journal entries, all of which increases the review time
and chance for error.
- The current vacancy on the accounting staff for a financial
reporting director, partially remedied by reliance upon
independent financial reporting consultants for review of
critical accounting areas and disclosures and material
non-standard transactions.
As described below, when considered in the aggregate, these deficiencies
constituted a material weakness over the effectiveness of detection and
monitoring controls over the financial statement close process. These
deficiencies ultimately affect the accuracy of our financial statement reporting
and disclosures. As a result, management has previously concluded that our
internal controls over financial reporting were not effective as of December 31,
2004. The Company had previously noted conditions related to the sufficiency of
review applied to the financial statement closing process in connection with the
finalization of its 2003 financial statements.
The manual year-end closing processes were performed substantially by our
accounting and finance staff, with some reliance on contract professionals and
financial reporting consultants. The combination of our manual, review intensive
accounting system and the absence of a financial reporting director placed
greater burdens of detailed reviews upon our middle and upper-level accounting
professionals which, in turn compromised the level of their qualitative review
of the financial statements and disclosures in the time available. These review
procedures are an important component of our controls surrounding the closing
process. As a result, we believe that the lack of a financial reporting
director, the greater demands on the time of our accounting staff and their
overall workload resulted in inadequate staffing, supervision and financial
reporting expertise in our accounting department, which constituted a material
weakness in our internal controls as of December 31, 2004.
Accordingly, in connection with the audit of our 2004 financial results,
Pannell Kerr Forster of Texas, P.C. ("PKF"), our independent registered public
accounting firm, detected a number of errors and/or omissions, none of which
were material, individually or in aggregate, but were an indication that the
aforementioned material weakness was present at December 31, 2004, increasing
the likelihood to more than remote that a material misstatement of the Company's
annual or interim financial statements will not be prevented or detected. The
most notable of these errors related to stock based compensation expense and
related footnote
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disclosures. Correcting adjustments were recorded by the Company prior to the
finalization of its 2004 financial statements. The Company has implemented
procedures to prevent these specific errors from occurring in the future.
However, the additional initiatives (outlined below), are needed to remediate
the material weakness in our internal controls, and thus lower the risk level to
remote of other potential material errors or omissions.
While there can be no assurance in this regard, we expect that the
following initiatives will eliminate this material weakness in 2005: (1)
increasing the level of our professional accounting staff, including the
successful placement of a financial reporting professional (recruiting efforts
were begun in the second half of 2004), (2) expanding the use of independent
reviews by outside financial reporting experts during the vacancy of our
financial reporting position, and (3) completing our transition to a new
fully-integrated accounting software system (data conversion began in 2004) to
automate processes and improve qualitative reviews. Until these initiatives are
fully implemented, we will continue to rely on manual processes and require
additional commitment of resources to the closing process to produce our
financial records and reports. We have not yet completed the initiatives
described in (1) and (3) above, but have implemented the initiative described in
(2) above as of the date of the filing of this report.
Changes in Internal Control over Financial Reporting. There have not been
any changes in the Company's internal control over financial reporting during
the fiscal quarter ended March 31, 2005 that have materially affected, or are
reasonably likely to materially affect, the Company's internal control over
financial reporting. As described above, the Company identified a material
weakness in the Company's internal control over financial reporting and has
described a number of planned changes to its internal control over financial
reporting during 2005 designed to remediate this weakness. This Item 4 should be
read in conjunction with Item 9A included in the 10-K/A.
-34-
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
On April 19, 2005, the Company issued a total of 112,697 shares of Common
Stock to a corporation and an individual as partial payment (in addition to a
total of $2.3 million in cash) for certain oil and gas properties in the
Company's Barnett Shale area. This acquisition consisted of approximately 600
net acres and working interests in 14 existing gross wells (7.3 net) with an
estimated 5.4 MMcfe of proved reserves, based upon the Company's internal
estimates. In issuing the shares of Common Stock, the Company relied on the
exemption from registration provided by Section 4(2) of the Securities Act of
1933, as amended, for transactions not involving a public offering.
Item 3 - Defaults Upon Senior Securities
None
Item 4 - Submission of Matters to a Vote of Security Holders
None
Item 5 - Other Information
None.
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).
+10.1 -- Second Amendment to Second Amended and Restated Credit Agreement
dated as of April 27, 2005 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 May 3, 2005).
+10.2 -- Director Restricted Stock Award Agreement under the Incentive
Plan of Carrizo Oil & Gas, Inc. (subject to shareholder approval
of the Fifth Amendment) (incorporated herein by reference to
Exhibit 10.1 to the Company's Current Report on Form 8-K filed on
April 22, 2005).
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+10.3 -- Director Restricted Stock Award Agreement under the Incentive
Plan of Carrizo Oil & Gas, Inc. (incorporated herein by reference
to Exhibit 10.2 to the Company's Current Report on Form 8-K filed
on April 22, 2005).
+10.4 -- Employee Restricted Stock Award Agreement under the Incentive
Plan of Carrizo Oil & Gas, Inc. (incorporated herein by reference
to Exhibit 10.3 to the Company's Current Report on Form 8-K filed
on April 22, 2005).
31.1 -- CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
31.2 -- CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
32.1 -- CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.
32.2 -- CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.
+ Incorporated herein by reference as indicated.
-36-
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this Report to be signed on its
behalf by the undersigned, thereunto duly authorized.
Carrizo Oil & Gas, Inc.
(Registrant)
Date: May 10, 2005 By: /s/ S. P. Johnson, IV
-----------------------------------------
President and Chief Executive Officer
(Principal Executive Officer)
Date: May 10, 2005 By: /s/ Paul F. Boling
-----------------------------------------
Chief Financial Officer
(Principal Financial and Accounting Officer)
-37-
INDEX TO EXHIBIT
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
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.