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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One) FORM 10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the Quarter Ended June 30, 2004
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 0-19118
ABRAXAS PETROLEUM CORPORATION
----------------------------------------------------------------------
(Exact name of Registrant as specified in its charter)
Nevada 74-2584033
---------- ------------------------
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization Identification Number)
500 N. Loop 1604 East, Suite 100, San Antonio, Texas 78232
(Address of Principal Executive Offices) (Zip Code)
Registrant's telephone number, including area code (210) 490-4788
Not Applicable
(Former name, former address and former fiscal year,
if changed since last report)
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 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 or No __
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act.) Yes ___ No_X__
The number of shares of the issuer's common stock outstanding as of August
9, 2004 was:
Class Shares Outstanding
Common Stock, $.01 Par Value 36,276,827
1 of 32
FORWARD-LOOKING INFORMATION
We make forward-looking statements throughout this document. Whenever you
read a statement that is not simply a statement of historical fact (such as when
we describe what we "believe", "expect" or "anticipate" will occur or what we
"intend" to do, and other similar statements), you must remember that our
expectations may not be correct, even though we believe they are reasonable. The
forward-looking information contained in this document is generally located in
the material set forth under the headings "Management's Discussion and Analysis
of Financial Condition and Results of Operations" and "Outlook for 2004" but may
be found in other locations as well. These forward-looking statements generally
relate to our plans and objectives for future operations and are based upon our
management's reasonable estimates of future results or trends. The factors that
may affect our expectations regarding our operations include, among others, the
following:
o our high debt level;
o our ability to raise capital;
o economic and business conditions;
o price and availability of alternative fuels;
o political and economic conditions in oil producing countries, especially
those in the Middle East;
o our success in development, exploitation and exploration activities;
o planned capital expenditures;
o prices for crude oil and natural gas;
o rates of production of crude oil and natural gas;
o our acquisition and divestiture activities;
o results of our hedging activities; and
o other factors discussed elsewhere in this document.
In addition to these factors, important factors that could cause actual
results to differ materially from our expectations ("Cautionary Statements") are
disclosed under "Risk Factors" in our Annual Report on Form 10-K for the year
ended December 31, 2003 which is incorporated by reference herein. All
subsequent written and oral forward-looking statements attributable to us, or
persons acting on our behalf, are expressly qualified in their entirety by the
Cautionary Statements.
2
ABRAXAS PETROLEUM CORPORATION
FORM 10 - Q
INDEX
PART I
FINANCIAL INFORMATION
ITEM 1 - Financial Statements (Unaudited)
Condensed Consolidated Balance Sheets -
June 30, 2004 and December 31, 2003........................4
Condensed Consolidated Statements of Operations -
Three and Six Months Ended June 30, 2004 and 2003..........6
Condensed Consolidated Statements of Cash Flows -
Six Months Ended June 30, 2004 and 2003....................7
Notes to Condensed Consolidated Financial Statements................8
ITEM 2 - Managements Discussion and Analysis of Financial Condition and
Results of Operations.....................................17
ITEM 3 - Quantitative and Qualitative Disclosure about Market Risks.........28
ITEM 4 - Controls and Procedures............................................29
PART II
OTHER INFORMATION
ITEM 1 - Legal proceedings 30
ITEM 2 - Changes in Securities, Use of Proceeds and Issuers
Purchase of Equity Securities......................................30
ITEM 3 - Defaults Upon Senior Securities......................................30
ITEM 4 - Submission of Matters to a Vote of Security Holders..................30
ITEM 5 - Other Information 30
ITEM 6 - Exhibits and Reports on Form 8-K.....................................30
Signatures ...................................................32
3
Abraxas Petroleum Corporation
Condensed Consolidated Balance Sheets
(in thousands)
June 30,
2004 December 31,
(Unaudited) 2003
----------- ------------
Assets:
Current assets:
Cash .......................................................... $ 1,491 $ 493
Accounts receivable, net
Joint owners ........................................... 297 1,360
Oil and gas production ................................. 5,306 5,873
Other .................................................. 482 1,090
-------- --------
6,085 8,323
Equipment inventory ............................................ 778 782
Other current assets ........................................... 666 572
-------- --------
Total current assets ......................................... 9,020 10,170
Property and equipment:
Oil and gas properties, full cost method of accounting:
Proved ..................................................... 331,732 325,222
Unproved, not subject to amortization ...................... 2,483 4,304
Other property and equipment .................................. 5,334 4,540
-------- --------
Total ................................................. 339,549 334,066
Less accumulated depreciation, depletion, and
amortization ............................................. 228,434 222,503
-------- --------
Total property and equipment - net ......................... 111,115 111,563
Deferred financing fees, net ..................................... 5,151 4,410
Other assets ..................................................... 294 294
-------- --------
Total assets ................................................... $125,580 $126,437
======== ========
See accompanying notes to condensed consolidated financial statements
4
Abraxas Petroleum Corporation
Condensed Consolidated Balance Sheets (continued)
(in thousands)
June 30,
2004 December 31,
(Unaudited) 2003
----------- ------------
Liabilities and Stockholders' Deficit
Current liabilities:
Accounts payable ............................................... $ 2,793 $ 6,756
Oil and gas production payable ................................. 2,905 2,290
Accrued interest ............................................... 2,410 2,340
Other accrued expenses ......................................... 1,698 1,228
--------- ---------
Total current liabilities ................................ 9,806 12,614
Long-term debt ................................................... 192,387 184,649
Future site restoration .......................................... 1,759 1,377
--------- ---------
Total liabilities ....................................... 203,952 198,640
Stockholders' deficit:
Common Stock, par value $.01 per share-
Authorized 200,000,000 shares; issued, 36,354,066
and 36,024,308 at June 30, 2004 and
December 31, 2003 respectively ................................ 363 360
Additional paid-in capital .................................... 141,662 141,835
Accumulated deficit ............................................ (218,885) (213,701)
Receivables from stock sales ................................... -- (97)
Treasury stock, at cost, 105,898 and 165,883 shares at June
30, 2004 and December 31, 2003 respectively ................... (525) (964)
Accumulated other comprehensive loss ........................... (987) 364
--------- ---------
Total stockholders' deficit ................................ (78,372) (72,203)
--------- ---------
Total liabilities and stockholders' deficit ...................... $ 125,580 $ 126,437
========= =========
See accompanying notes to condensed consolidated financial statements
5
Abraxas Petroleum Corporation
Condensed Consolidated Statements of Operations
(Unaudited)
(in thousands except per share data)
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- --------------------
2004 2003 2004 2003
-------- -------- -------- --------
Revenue:
Oil and gas production revenues .................................. $ 12,039 $ 8,261 $ 22,771 $ 21,033
Gas processing revenues .......................................... -- -- -- 132
Rig revenues ..................................................... 129 158 304 339
Other ............................................................ 99 11 127 37
-------- -------- -------- --------
12,267 8,430 23,202 21,541
Operating costs and expenses:
Lease operating and production taxes ............................. 3,305 2,066 6,672 4,792
Depreciation, depletion, and amortization ........................ 3,222 2,301 6,257 5,443
Rig operations ................................................... 123 148 268 314
General and administrative ....................................... 2,226 1,231 3,568 2,627
Stock-based compensation ......................................... (2,316) 757 (253) 792
-------- -------- -------- --------
6,560 6,503 16,512 13,968
-------- -------- -------- --------
Operating income (loss) ............................................. 5,707 1,927 6,690 7,573
Other (income) expense:
Interest income .................................................. (2) (7) (8) (17)
Interest expense ................................................. 4,268 3,846 9,387 9,010
Amortization of deferred financing fee ........................... 467 434 912 811
Financing cost ................................................... 602 -- 1,573 3,601
Gain on sale of foreign subsidiaries ............................. -- -- -- (66,960)
Other ............................................................ -- -- 11 --
-------- -------- -------- --------
5,335 4,273 11,875 (53,555)
-------- -------- -------- --------
Earnings (loss) before cumulative effect of
accounting change and taxes ...................................... 372 (2,346) (5,185) 61,128
Cumulative effect of accounting change .............................. -- -- -- (395)
Income tax (expense) benefit ........................................ -- -- -- (377)
-------- -------- -------- --------
Net earnings (loss) ................................................. $ 372 $ (2,346) $ (5,185) $ 60,356
======== ======== ======== ========
Basic earnings (loss) per common share:
Net earnings (loss) .............................................. $ 0.01 $ (0.07) $ (0.14) $ 1.74
Cumulative effect of accounting change ........................... -- -- -- (0.01)
-------- -------- -------- --------
Net earnings (loss) per common share - basic ........................ $ 0.01 $ (0.07) $ (0.14) $ 1.73
======== ======== ======== ========
Diluted earnings (loss) per common share:
Net earnings (loss) .............................................. $ 0.01 $ (0.07) $ (0.14) $ 1.72
Cumulative effect of accounting change ........................... -- -- -- (0.01)
-------- -------- -------- --------
Net earnings (loss) per common share - diluted ...................... $ 0.01 $ (0.07) $ (0.14) $ 1.71
======== ======== ======== ========
See accompanying notes to condensed consolidated financial statements
6
Abraxas Petroleum Corporation
Condensed Consolidated Statements of Cash Flows
(Unaudited)
(in thousands)
Six Months Ended
June 30,
--------------------------
2004 2003
Operating Activities
Net earnings (loss) ..................................... $ (5,185) $ 60,356
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion, and amortization .............. 6,257 5,443
Deferred income tax (benefit) expense .................. -- 377
Amortization of deferred financing fees ................ 912 811
Accretion of future sit restoration .................... 336 439
Non-cash interest and financing cost ................... 5,966 3,115
Stock-based compensation ............................... (253) 792
Gain on sale of foreign subsidiaries ................... -- (66,960)
Changes in operating assets and liabilities:
Accounts receivable ................................ 2,301 (314)
Equipment inventory ................................ 4 142
Other .............................................. (169) 597
Accounts payable and accrued expenses .............. (2,861) (838)
--------- ---------
Net cash provided by operating activities ............... 7,308 3,960
--------- ---------
Investing Activities
Capital expenditures, including purchases and development
of properties ......................................... (7,085) (9,990)
Proceeds from sale of foreign subsidiaries .............. -- 86,553
--------- ---------
Net cash (used in) provided by investing activities ..... (7,085) 76,563
--------- ---------
Financing Activities
Proceeds from long-term borrowings ........................... 5,372 47,293
Payments on long-term borrowings ............................. (3,600) (128,315)
Proceeds from stock sale receivable .......................... 98 --
Issuance of stock for compensation ........................... 328 --
Deferred financing fees ...................................... (1,653) (2,604)
Exercise of stock options .................................... 193 19
--------- ---------
Net cash provided by (used in) financing activities .......... 738 (83,607)
--------- ---------
Effect of exchange rate changes on cash ...................... 37 301
--------- ---------
Increase (decrease) in cash .................................. 998 (2,783)
Cash, at beginning of period ................................. 493 4,882
--------- ---------
Cash, at end of period ....................................... $ 1,491 $ 2,099
========= =========
Supplemental disclosure of cash flow information:
Interest paid ................................................ $ 2,321 $ 3,932
========= =========
Non-cash items:
Future site restoration ...................................... $ 147 $ (3,068)
========= =========
See accompanying notes to condensed consolidated financial statements
7
Abraxas Petroleum Corporation
Notes to Condensed Consolidated Financial Statements
(Unaudited)
(tabular amounts in thousands, except per share data)
Note 1. Basis of Presentation
The accounting policies followed by Abraxas Petroleum Corporation and its
subsidiaries (the "Company" or "Abraxas") are set forth in the notes to the
Company's audited financial statements in the Annual Report on Form 10-K filed
for the year ended December 31, 2003. Such policies have been continued without
change. Also, refer to the notes to those financial statements for additional
details of the Company's financial condition, results of operations, and cash
flows. All the material items included in those notes have not changed except as
a result of normal transactions in the interim, or as disclosed within this
report. The accompanying interim consolidated financial statements have not been
audited by independent accountants, but in the opinion of management, reflect
all adjustments necessary for a fair presentation of the financial position and
results of operations. Any and all adjustments are of a normal and recurring
nature. The results of operations for the three and six months ended June 30,
2004 are not necessarily indicative of results to be expected for the full year.
The consolidated financial statements include the accounts of the Company
and its wholly-owned foreign subsidiary, Grey Wolf Exploration Inc. ("New Grey
Wolf"). In January 2003, the Company sold all of the common stock of its
wholly-owned foreign subsidiaries, Canadian Abraxas Petroleum Limited ("Canadian
Abraxas") and Grey Wolf Exploration Inc. ("Old Grey Wolf"). Certain oil and gas
properties were retained and transferred into New Grey Wolf which was
incorporated in January 2003. The operations of Canadian Abraxas and Old Grey
Wolf are included in the consolidated financial statements through January 23,
2003.
New Grey Wolf's assets and liabilities are translated to U.S. dollars at
period-end exchange rates. Income and expense items are translated at average
rates of exchange prevailing during the period. Translation adjustments are
accumulated as a separate component of shareholders' equity.
Stock-based Compensation:
The Company accounts for stock-based compensation using the intrinsic value
method prescribed in Accounting Principles Board Opinion ("APB") No. 25,
"Accounting for Stock Issued to Employees," and related interpretations.
Accordingly, compensation cost for stock options is measured as the excess, if
any, of the quoted market price of the Company's stock at the date of the grant
over the amount an employee must pay to acquire the stock.
Effective July 1, 2000, the Financial Accounting Standards Board ("FASB")
issued FIN 44, "Accounting for Certain Transactions Involving Stock
Compensation", an interpretation of APB No. 25. Under the interpretation,
certain modifications to fixed stock option awards which were made subsequent to
December 15, 1998, and were not exercised prior to July 1, 2000, require that
the awards be accounted for as variable until they are exercised, forfeited, or
expired. In January 2003, the Company amended the exercise price to $0.66 on
certain options with an existing exercise price greater than $0.66. The Company
recognized approximately $757,000 and $792,000 in expense during the quarter and
six months ended June 30, 2003, respectively, as stock-based compensation
expense in the accompanying consolidated financial statements. For the quarter
and six months ended June 30, 2004 the Company recognized credits of
approximately $2.3 million and $253,000, respectively, due to a decline in the
price of its common stock during the period.
Pro forma information regarding net income (loss) and earnings (loss) per
share is required by SFAS 123, "Accounting for Stock-Based Compensation" (SFAS
123), which also requires that the information be determined as if the Company
has accounted for its employee stock options granted subsequent to December 31,
1995 under the fair value method prescribed by SFAS 123. The fair value for
8
these options was estimated at the date of grant using a Black-Scholes option
pricing model with the following weighted-average assumptions for the quarter
and six months ended June 30, 2004 and 2003, risk-free interest rates of 1.5%;
dividend yields of -0-%; volatility factor of the expected market price of the
Company's common stock of 0.35; and a weighted-average expected life of the
option of ten years.
The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions including the expected stock price
volatility. Because the Company's employee stock options have characteristics
significantly different from those of traded options, and because changes in the
subjective input assumptions can materially affect the fair value estimate, in
management's opinion, the existing models do not necessarily provide a reliable
single measure of the fair value of its employee stock options.
In October 2002, the FASB issued Statement No. 148 "Accounting for
Stock-Based Compensation-Transition and Disclosure", (SFAS No. 148), providing
alternative methods of transition for a voluntary change to the fair value based
method of accounting for stock-based employee compensation. SFAS No. 148 also
amends the disclosure requirement of SFAS No. 123, "Accounting for Stock-Based
Compensation" to include prominent disclosures in annual and interim financial
statements about the method of accounting for stock-based compensation and the
effect of the method used on reported results. The Company adopted the
disclosure provisions of SFAS No. 148 on December 31, 2002.
Had the Company determined stock-based compensation costs based on the
estimated fair value at the grant date for its stock options, the Company's net
income (loss) per share for the three and six months ended June 30, 2004 and
June 30, 2003 would have been:
Three Months Ended June 30, Six Months Ended June 30,
---------------------------- --------------------------
2004 2003 2004 2003
(In Thousands, except per share data)
----------------------------------------------------------
Net income (loss) as reported $ 372 $ (2,346) $ (5,185) $ 60,356
Add: Stock-based employee compensation
expense included in reported net
income, net of related tax effects (2,316) 757 (253) 792
Deduct: Total stock-based employee
compensation expense determined under
fair value based method for all
awards, net of related tax effects (35) (271) (71) (140)
------------- ------------ ---------- ------------
Pro forma net income (loss) $ (1,979) $ (1,860) $ (5,509) $ 61,008
============= ============ ========== ============
Earnings (loss) per share:
Basic - as reported $ 0.01 $ (0.07) $ (0.14) $ 1.73
============= ============ ========== ============
Basic - pro forma $ (0.05) $ (0.05) $ (0.15) $ 1.75
============= ============ ========== ============
Diluted - as reported $ 0.01 $ (0.07) $ (0.14) $ 1.71
============= ============ ========== ============
Diluted - pro forma $ (0.05) $ (0.05) (0.15) $ 1.73
============= ============ $========== ============
Certain prior year balances have been reclassified for comparative
purposes.
Note 2. Income Taxes
The Company records income taxes using the liability method. Under this
method, deferred tax assets and liabilities are determined based on differences
between financial reporting and tax basis of assets and liabilities and are
measured using the enacted tax rates and laws that will be in effect when the
differences are expected to reverse.
9
For the period ended June 30, 2004, there is no current or deferred income
tax expense or benefit due to losses or loss carryforwards and valuation
allowance which has been recorded against such benefits.
Note 3. Long-Term Debt
Long-term debt consisted of the following:
June 30, December 31,
-----------------------------------
2004 2003
---------------- -----------------
(In thousands)
11.5% Secured Notes due 2007 ("new notes")............ $ 143,154 $ 137,258
Senior Credit Agreement............................... 49,233 47,391
---------------- -----------------
192,387 184,649
Less current maturities .............................. - -
---------------- -----------------
$ 192,387 $ 184,649
================ =================
New Notes. In connection with the financial restructuring completed in
January 2003, Abraxas issued $109.7 million in principal amount of it's 11 1/2%
Secured Notes due 2007, Series A, or new notes, in exchange for our 11 1/2%
Senior Notes due 2004 tendered in the exchange offer. The new notes were issued
under an indenture with U.S. Bank, N. A. In accordance with SFAS 15, the basis
of the new notes at issue date exceeded the face amount of the new notes by
approximately $19.0 million. Such amount will be amortized over the term of the
new notes as an adjustment to the yield of the new notes.
The new notes accrue interest from the date of issuance, at a fixed annual
rate of 11 1/2%, payable in cash semi-annually on each May 1 and November 1,
commencing May 1, 2003, provided that, if we fail, or are not permitted pursuant
to our senior credit agreement or the intercreditor agreement between the
trustee under the indenture for the new notes and the lenders under the senior
credit agreement, to make such cash interest payments in full, we will pay such
unpaid interest in kind by the issuance of additional new notes with a principal
amount equal to the amount of accrued and unpaid cash interest on the new notes
plus an additional 1% accrued interest for the applicable period. Upon an event
of default, the new notes accrue interest at an annual rate of 16.5%.
The new notes are secured by a second lien or charge on all of our current
and future assets, including, but not limited to, all of our crude oil and
natural gas properties. All of Abraxas' current subsidiaries, Sandia Oil & Gas
Corp., Sandia Operating Company, Wamsutter Holdings, Inc., New Grey Wolf,
Western Associated Energy Corporation and Eastside Coal Company, Inc. are
guarantors of the new notes, and all of Abraxas' future subsidiaries will
guarantee the new notes. If Abraxas cannot make payments on the new notes when
they are due, the guarantors must make them instead.
The new notes and related guarantees
o are subordinated to the indebtedness under the senior credit
agreement;
o rank equally with all of Abraxas' current and future senior
indebtedness; and
o rank senior to all of Abraxas' current and future subordinated
indebtedness, in each case, if any.
The new notes are subordinated to amounts outstanding under the senior
credit agreement both in right of payment and with respect to lien priority and
are subject to an intercreditor agreement.
Abraxas may redeem the new notes, at its option, in whole at any time or in
part from time to time, at redemption prices expressed as percentages of the
principal amount set forth below. If Abraxas redeems all or any new notes, it
must also pay all interest accrued and unpaid to the applicable redemption date.
The redemption prices for the new notes during the indicated time periods are as
follows:
10
Period Percentage
From June 24, 2004 to January 23, 2005.....................98.5837%
Thereafter................................................100.0000%
Under the indenture, the Company is subject to customary covenants which, among
other things, restricts our ability to:
o borrow money or issue preferred stock;
o pay dividends on stock or purchase stock;
o make other asset transfers;
o transact business with affiliates;
o sell stock of subsidiaries;
o engage in any new line of business;
o impair the security interest in any collateral for the notes;
o use assets as security in other transactions; and
o sell certain assets or merge with or into other companies.
In addition, we are subject to certain financial covenants including covenants
limiting our selling, general and administrative expenses and capital
expenditures, a covenant requiring Abraxas to maintain a specified ratio of
consolidated EBITDA, as defined in the indenture, to cash interest and a
covenant requiring Abraxas to permanently, to the extent permitted, pay down
debt under the senior credit agreement and, to the extent permitted by the
senior credit agreement, the new notes or, if not permitted, paying indebtedness
under the senior credit agreement.
The indenture contains customary events of default, including nonpayment of
principal or interest, violations of covenants, inaccuracy of representations or
warranties in any material respect, cross default and cross acceleration to
certain other indebtedness, bankruptcy, material judgments and liabilities,
change of control and any material adverse change in our financial condition.
Senior Credit Agreement. In connection with the financial restructuring,
Abraxas entered into a new senior credit agreement providing a term loan
facility and a revolving credit facility. On February 23, 2004, the Company
entered into an amendment to our existing senior credit agreement providing for
two revolving credit facilities and a new non-revolving credit facility as
described below. Subject to earlier termination on the occurrence of events of
default or other events, the stated maturity date for these credit facilities is
February 1, 2007. In the event of an early termination, we will be required to
pay a prepayment premium, except in the limited circumstances described in the
amended senior credit agreement.
First Revolving Credit Facility. Lenders under the amended senior credit
agreement have provided Abraxas a revolving credit facility with a maximum
borrowing base of up to $20 million. The Company's current borrowing base under
this revolving credit facility is the full $20.0 million, subject to adjustments
based on periodic calculations and mandatory prepayments under the senior credit
agreement. The Company has borrowed $6.6 million under this revolving credit
facility, which was used to refinance principal and interest on advances under
it's preexisting revolving credit facility under the senior credit agreement,
and to pay certain fees and expenses relating to the transaction. The
outstanding balance under this facility was $4.2 million as of June 30, 2004.
Outstanding amounts under this revolving credit facility bear interest at the
prime rate announced by Wells Fargo Bank, N.A. plus 1.125%.
Second Revolving Credit Facility. Lenders under the amended senior credit
agreement have provided a second revolving credit facility, with a maximum
borrowing of up to $30.0 million. This revolving credit facility is not subject
to a borrowing base. The Company has borrowed $30.0 million under this revolving
credit facility, which was used to refinance principal and interest on advances
under our preexisting revolving credit facility, and to pay certain transaction
fees and expenses. As of June 30, 2004 the outstanding balance of this facility
11
was $30.0 million. Outstanding amounts under this revolving credit facility bear
interest at the prime rate announced by Wells Fargo Bank, N.A. plus 3.00%.
Non-Revolving Credit Facility. The Company has borrowed $15.0 million
pursuant to a non-revolving credit facility, which was used to repay the
preexisting term loan under its senior credit agreement, to refinance principal
and interest on advances under the preexisting revolving credit facility, and to
pay certain transaction fees and expenses. This non-revolving credit facility is
not subject to a borrowing base. As of June 30, 2004 the outstanding balance of
this facility was $15.0 million. Outstanding amounts under this credit facility
bear interest at the prime rate announced by Wells Fargo Bank, N.A. plus 8.00%.
Covenants. Under the amended senior credit agreement, we are subject to
customary covenants and reporting requirements. Certain financial covenants
require us to maintain minimum ratios of consolidated EBITDA (as defined in the
amended senior credit agreement) to adjusted fixed charges (which includes
certain capital expenditures), minimum ratios of consolidated EBITDA to cash
interest expense, a minimum level of unrestricted cash and revolving credit
availability, minimum hydrocarbon production volumes and minimum proved
developed hydrocarbon reserves. In addition, if on the day before the end of
each fiscal quarter the aggregate amount of our cash and cash equivalents
exceeds $2.0 million, we are required to repay the loans under the amended
senior credit agreement in an amount equal to such excess. The amended senior
credit agreement also requires us to enter into hedging agreements on not less
than 40% or more than 75% of our projected oil and gas production. We are also
required to establish deposit accounts at financial institutions acceptable to
the lenders and we are required to direct our customers to make all payments
into these accounts. The amounts in these accounts will be transferred to the
lenders upon the occurrence and during the continuance of an event of default
under the amended senior credit agreement.
In addition to the foregoing and other customary covenants, the amended
senior credit agreement contains a number of covenants that, among other things,
restrict our ability to:
o incur additional indebtedness;
o create or permit to be created liens on any of our properties;
o enter into change of control transactions;
o dispose of our assets;
o change our name or the nature of our business;
o make guarantees with respect to the obligations of third parties;
o enter into forward sales contracts;
o make payments in connection with distributions, dividends or
redemptions relating to our outstanding securities, or
o make investments or incur liabilities.
Security. The obligations of Abraxas under the amended senior credit
agreement continue to be secured by a first lien security interest in
substantially all of Abraxas' assets, including all crude oil and natural gas
properties.
Guarantees. The obligations of Abraxas under the amended senior credit
agreement continue to be guaranteed by Abraxas' subsidiaries, Sandia Oil & Gas,
Sandia Operating, Wamsutter Holdings., New Grey Wolf, Western Associated Energy
and Eastside Coal Company. The guarantees under the amended senior credit
agreement continue to be secured by a first lien security interest in
substantially all of the guarantors' assets, including all crude oil and natural
gas properties.
12
Events of Default. The amended senior credit agreement contains customary
events of default, including nonpayment of principal or interest, violations of
covenants, inaccuracy of representations or warranties in any material respect,
cross default and cross acceleration to certain other indebtedness, bankruptcy,
material judgments and liabilities, change of control and any material adverse
change in our financial condition.
Note 4. Earnings Per Share
The following table sets forth the computation of basic and diluted earnings
per share:
Three Months Ended June 30, Six Months Ended June 30,
------------------------------- -------------------------------
2004 2003 2004 2003
Numerator:
Net income (loss) before cumulative effect of
accounting change (in thousands) $ 372 $ (2,346) $ (5,185) $ 60,751
Cumulative effect of accounting change - - - (395)
------------- ------------- -------------- -------------
$ 372 $ (2,346) $ (5,185) $ 60,356
============= ============= ============== =============
Denominator:
Denominator for basic earnings per share -
Weighted-average shares 36,191,155 35,634,998 36,112,112 34,912,075
Effect of dilutive securities:
Stock options and warrants 1,769,614 - - 446,323
------------- ------------- -------------- -------------
Dilutive potential common shares Denominator for diluted earnings per share -
adjusted weighted-average shares and assumed
Conversions 37,960,769 35,634,998 36,112,112 35,358,398
Basic earnings (loss) per share:
Net income (loss) before cumulative effect
of accounting change $ 0.01 $ (0.07) $ (0.14$ 1.74
Cumulative effect of accounting change - - - (0.01)
------------- ------------- -------------- -------------
Net earnings (loss) per common share - basic $ 0.01 $ (0.07) $ (0.14) $ 1.73
============= ============= ============== =============
Diluted earnings (loss) per share:
Net income (loss) before cumulative effect
of accounting change $ 0.01 $ (0.07) $ (0.14) $ 1.72
Cumulative affect of accounting change - - - (0.01)
------------- ------------- -------------- -------------
Net earnings (loss) per common share - diluted $ 0.01 $ (0.07) $ (0.14) $ 1.71
============= ============= ============== =============
For the three months ended June 30, 2003 and six months ended June 30,
2004, none of the shares issuable in connection with stock options or warrants
are included in diluted shares. Inclusion of these shares would be antidilutive
due to losses incurred in the period. Had there not been losses in this period,
dilutive shares would have been 580,427 shares and 1,866,245 shares for the
three months ended June 30, 2003 and the six months ended June 30, 2004,
respectively.
Note 5. Hedging Program and Derivatives
On January 1, 2001, the Company adopted SFAS 133 "Accounting for Derivative
Instruments and Hedging Activities" SFAS 133 as amended by SFAS 137 "Accounting
for Derivative Instruments and Hedging Activities - Deferral of the Effective
Date of FASB 133" and SFAS 138 "Accounting for Certain Derivative Instruments
and Certain Hedging Activities". Under SFAS 133, all derivative instruments are
recorded on the balance sheet at fair value. If the derivative does not qualify
as a hedge or is not designated as a hedge, the gain or loss on the derivative
is recognized currently in earnings. To qualify for hedge accounting, the
derivative must qualify either as a fair value hedge, cash flow hedge or foreign
currency hedge. As of June 30, 2004, the derivatives that the Company had in
place were not designated as hedges, accordingly, changes in the fair value of
the derivatives are recorded in current period oil and gas revenue.
Under the terms of our new senior credit agreement, the Company is required
to maintain hedging agreements with respect to not less than 40% nor more than
75% of it crude oil and natural gas production for a rolling six month period.
13
The following table sets forth the Company's hedge position:
Time Period Notional Quantities Price
- ---------------------------------------- ------------------------------------------ ------------------
July 2004 2,000 MMbtu of production per day Floor of $4.00
4,500 MMbtu of production per day Floor of $4.25
500 Bbl of crude oil production per day Floor of $22.00
August 2004 7,100 MMbtu of production per day Floor of $4.25
400 Bbl of crude oil production per day Floor of $24.00
September 2004 7,100 MMbtu of production per day Floor of $4.25
400 Bbl of crude oil production per day Floor of $24.00
October 2004 7,100 MMbtu of production per day Floor of $4.25
400 Bbl of crude oil production per day Floor of $24.00
November 2004 7,100 MMbtu of production per day Floor of $4.25
400 Bbl of crude oil production per day Floor of $24.00
December 2004 7,100 MMbtu of production per day Floor of $4.50
400 Bbl of crude oil production per day Floor of $25.00
January 2005 7,100 MMbtu of production per day Floor of $4.50
400 Bbl of crude oil production per day Floor of $25.00
Note 6. Contingencies - Litigation
In 2001 the Company and a limited partnership, of which Wamsutter is the
general partner (the "Partnership"), were named in a lawsuit filed in U.S.
District Court in the District of Wyoming. The claim asserts breach of contract,
fraud and negligent misrepresentation by the Company and the Partnership related
to the responsibility for year 2000 ad valorem taxes on crude oil and natural
gas properties sold by the Company and the Partnership. In February 2002, a
summary judgment was granted to the plaintiff in this matter and a final
judgment in the amount of $1.3 million was entered. The Company and the
Partnership have filed an appeal. The Company has established a reserve in the
amount of $845,000, which represents the Company's share of the judgment. The
Company believes these charges are without merit
Additionally, from time to time, the Company is involved in litigation
relating to claims arising out of its operations in the normal course of
business. At June 30, 2004, the Company was not engaged in any legal proceedings
that are expected, individually or in the aggregate, to have a material adverse
effect on the Company.
Note 7. Comprehensive Income
Comprehensive income includes net income, losses and certain items recorded
directly to Stockholder's Equity and classified as Other Comprehensive Income.
The following table illustrates the calculation of comprehensive income
(loss) for the three and six months ended June 30, 2003 and 2004:
Three Months Ended June 30, Six Months Ended June 30,
---------------------------------- -------------------------------
2004 2003 2004 2003
---------------- -------------- -------------- -------------
(In Thousands)
-------------------------------------------------------------------
Net (loss) income........................... $ 372 $ (2,346) $ (5,185) $ 60,356
Other Comprehensive loss:
Hedging derivatives
Change in fair market value of
outstanding hedge positions............... - (151) - (49)
Foreign currency translation adjustment...... (860) 2,386 (1,351) 7,813
---------------- -------------- -------------- -------------
Other comprehensive income (860) 2,235 (1,351) 7,764
---------------- -------------- -------------- -------------
Comprehensive (loss) income.................... $ (488) $ (111) $ (6,536) $ 68,120
================ ============== ============== =============
14
Note 8. Business Segments
Business segment information about the three months and six months ended June
30, 2004 and 2003 in different geographic areas is as follows:
Three Months Ended June 30, 2004
--------------------------------------------------------------
U.S. Canada Total
------------------- ----------------- -------------------
(In thousands)
Revenues ............................... $ 8,504 $ 3,763 $ 12,267
=================== ================ ===================
Operating income........................ $ 4,243 $ 860 $ 5,103
=================== ================
General Corporate.................................................................. 604
Interest expense, financing cost and amortization of
deferred financing fees......................................................... (5,335)
..................................................................................
-------------------
Income before income taxes......................................................... $ 372
===================
Three Months Ended June 30, 2003
--------------------------------------------------------------
U.S. Canada Total
------------------- ----------------- -------------------
(In thousands)
Revenues ............................... $ 7,218 $ 1,212 $ 8,430
=================== ================= ===================
Operating loss.......................... $ 3,335 $ 288 $ 3,623
=================== =================
General Corporate.................................................................. (1,696)
Interest expense and amortization of
deferred financing fees......................................................... (4,273)
..................................................................................
-------------------
Loss before income taxes........................................................... $ (2,346)
===================
Six Months Ended June 30, 2004
--------------------------------------------------------------
U.S. Canada Total
------------------- ----------------- -------------------
(In thousands)
Revenues ............................... $ 16,464 $ 6,738 $ 23,202
=================== ================= ===================
Operating income........................ $ 7,955 $ 1,267 $ 9,222
=================== =================
General Corporate.................................................................. (2,532)
Interest expense, financing cost and amortization of
deferred financing fees......................................................... (11,864)
..................................................................................
Other.............................................................................. (11)
-------------------
Loss before income taxes........................................................... $ (5,185)
===================
Six Months Ended June 30, 2003
--------------------------------------------------------------
U.S. Canada Total
------------------- ----------------- -------------------
(In thousands)
Revenues ............................... $ 16,017 $ 5,524 $ 21,541
=================== ================= ===================
Operating loss.......................... $ 8,071 $ 2,531 $ 10,602
=================== =================
General Corporate.................................................................. (3,029)
Interest expense and amortization of
deferred financing fees......................................................... (13,010)
..................................................................................
-------------------
Income before income taxes......................................................... 66,960
===================
At June 30, 2004
--------------------------------------------------------------
U.S. Canada Total
------------------- ----------------- -------------------
(In Thousands)
Identifiable assets .................... $ 82,820 $ 36,896 $ 119,716
=================== =================
Corporate assets................................................................... 5,864
-------------------
Total assets ...................................................................... $ 125,580
===================
15
Note 9. New Accounting Standards
In March 2004, the Emerging Issues Task Force ("EITF") reached a consensus
that mineral rights, as defined in EITF Issue No. 04-2, "Whether Mineral Rights
Are Tangible or Intangible Assets," are tangible assets and that they should be
removed as examples of intangible assets in SFAS No. 141, "Business
Combinations" and No. 142, "Goodwill and Other Intangible Assets". The FASB has
recently ratified this consensus and directed the FASB staff to amend SFAS Nos.
141 and 142 through the issuance of FASB Staff Position FAS Nos. 141-1 and
142-1. Historically, the Company has included the costs of such mineral rights
as tangible assets, which is consistent with the EITF's consensus. As such, EITF
04-02 has not affected the Company's consolidated financial statements.
Note 10. Accounting Change
The Company adopted SFAS 143 effective January 1, 2003. For the six months
ended June 30, 2003 the Company recorded a charge of approximately $395,000 for
the cumulative effect of the change in accounting principle and an additional
liability of approximately $712,000. During the period ended June 30, 2004 the
Company recorded an additional liability of approximately $382,000.
16
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
PART I
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operation
The following is a discussion of our financial condition, results of
operations, liquidity and capital resources. This discussion should be read in
conjunction with our consolidated financial statements and the notes thereto,
included in our Annual Report on Form 10-K filed for the year ended December 31,
2003. The results of operations of Canadian Abraxas and Old Grey Wolf are
included in this report through January 23, 2003, the date of the consummation
of the sale.
General
We are an independent energy company engaged primarily in the acquisition,
exploration, exploitation and production of crude oil and natural gas. Our
principal means of growth has been through the acquisition and subsequent
development and exploitation of producing properties. As a result of our
historical acquisition activities, we believe that we have a substantial
inventory of low risk exploitation and development opportunities, the successful
completion of which is critical to the maintenance and growth of our current
production levels.
We have incurred net losses in three of the last five years, and there can
be no assurance that operating income and net earnings will be achieved in
future periods. Our financial results depend upon many factors, particularly the
following factors which most significantly affect our results of operations:
o the sales prices of crude oil, natural gas liquids and natural
gas;
o the level of total sales volumes of crude oil, natural gas liquids
and natural gas;
o the ability to raise capital resources and provide liquidity to
meet cash flow needs;
o the level of and interest rates on borrowings; and
o the level and success of exploration and development activity.
Commodity Prices and Hedging Activities. Our results of operations are
significantly affected by fluctuations in commodity prices. Price volatility in
the natural gas market has remained prevalent in the last few years. In January
2001, the market price of natural gas was at its highest level in our operating
history and the price of crude oil was also at a high level. However, over the
course of 2001 and the beginning of the first quarter of 2002, prices again
became depressed, primarily due to the economic downturn. Beginning in March
2002, commodity prices began to increase and continued higher through 2003 and
have remained strong during the first half of 2004.
The table below illustrates how natural gas prices fluctuated over the
eight quarters prior to and including the quarter ended June 30, 2004. The table
below also contains the last three day average of NYMEX traded contracts price
and the prices we realized during each quarter presented, including the impact
of our hedging activities.
Natural Gas Prices by Quarter (in $ per Mcf)
----------------------------------------------------------------------------------------------------
Quarter Ended
----------------------------------------------------------------------------------------------------
Sept. 30, Dec. 31, March 31, June 30, Sept. 30, Dec. 31, March 31, June 30,
2002 2002 2003 2003 2003 2003 2004 2004
------------ ----------- ----------- ------------ ----------- ------------- ------------ -----------
Index $ 3.28 $ 3.99 $ 6.61 $ 5.51 $ 5.10 $ 4.60 $ 5.69 $ 5.97
Realized $ 2.08 $ 3.47 $ 5.13 $ 5.11 $ 4.50 $ 4.30 $ 4.83 $ 5.23
17
The NYMEX natural gas price on August 9, 2004 was $5.69 per Mcf.
The table below illustrates how crude oil prices fluctuated over the
eight quarters prior to and including the quarter ended June 30, 2004. The table
below also contains the last three day average of NYMEX traded contracts price
and the prices we realized during each quarter presented, including the impact
of our hedging activities.
Crude Oil Prices by Quarter (in $ per Bbl)
-------------------------------------------------------------------------------------------------------
Quarter Ended
-------------------------------------------------------------------------------------------------------
Sept. 30, Dec. 31, March 31, June 30, Sept. 30, Dec. 31, March 31, June 30,
2002 2002 2003 2003 2003 2003 2004 2004
----------- ----------- ------------ -------------- ------------- ----------- ------------ ------------
Index $ 27.50 $ 28.29 $ 33.71 $ 29.87 $ 30.85 $ 29.64 $ 34.76 $ 38.48
Realized $ 23.47 $ 24.83 $ 33.22 $ 28.53 $ 29.52 $ 29.73 $ 34.19 $ 37.09
The NYMEX crude oil price on August 9, 2004 was $44.84 per Bbl.
We seek to reduce our exposure to price volatility by hedging our
production through swaps, floors, options and other commodity derivative
instruments.
Under the terms of our senior credit agreement, we are required to maintain
hedging positions with respect to not less than 40% nor more than 75% of our
crude oil and natural gas production, on an equivalent basis, for a rolling six
month period. We currently have the following hedges in place:
Time Period Notional Quantities Price
- ---------------------------------------- -------------------------------------- ----------------------
July 2004 2,000 MMbtu of production per day Floor of $4.00
4,500 MMbtu of production per day Floor of $4.25
500 Bbls of crude oil production per Floor of $22.00
day
August 2004 7,100 MMbtu of production per day Floor of $4.25
400 Bbls of crude oil production per Floor of $24.00
day
September 2004 7,100 MMbtu of production per day Floor of $4.25
400 Bbls of crude oil production per Floor of $24.00
day
October 2004 7,100 MMbtu of production per day Floor of $4.25
400 Bbls of crude oil production per Floor of $24.00
day
November 2004 7,100 MMbtu of production per day Floor of $4.25
400 Bbls of crude oil production per Floor of $24.00
day
December 2004 7,100 MMbtu of production per day Floor of $4.50
400 Bbls of crude oil production per Floor of $25.00
day
Januany 2005 7,100 MMbtu of production per day Floor of $4.50
400 Bbls of crude oil production per Floor of $25.00
day
Production Volumes. Because our proved reserves will decline as crude oil,
natural gas and natural gas liquids are produced, unless we acquire additional
properties containing proved reserves or conduct successful exploration and
development activities, our reserves and production will decrease. Our ability
to acquire or find additional reserves in the near future will be dependent, in
part, upon the amount of available funds for acquisition, exploitation and
development projects. For more information on the volumes of crude oil, natural
gas liquids and natural gas we produced during the three and six months ended
June 30, 2003 and 2004, please refer to the information under the caption
"Results of Operations" below.
We have budgeted $10 million for drilling expenditures in 2004, of which
$7.1 million was spent during the first six months of 2004. Under the terms of
our senior credit agreement and our new notes, we are subject to limitations on
capital expenditures. As a result, we will be limited in our ability to replace
existing production with new production and might suffer a decrease in the
volume of crude oil and natural gas we produce. If crude oil and natural gas
prices return to depressed levels or if our production levels decrease, our
revenues, cash flow from operations and financial condition will be materially
adversely affected. For more information, see "Liquidity and Capital Resources"
below.
18
Availability of Capital. As described more fully under "Liquidity and
Capital Resources" below, our sources of capital are primarily cash on hand,
cash from operating activities, funding under our senior credit agreement and
the sale of properties. At June 30, 2004, we had approximately $15.6 million of
availability under our senior credit agreement. Our capital expenditures are
limited to $10 million per year under the terms of the indenture for the notes.
We may also attempt to raise additional capital or refinance our existing
indebtedness through the issuance of debt or equity securities although we
cannot assure you that we will be successful in any such efforts.
Borrowings and Interest. As a result of the financial restructuring we
completed in January 2003, we reduced our indebtedness from approximately $300.4
million at December 31, 2002 to approximately $204.0 million at June 30, 2004.
In addition, we decreased our cash interest expense from $34.2 million during
2002 to $4.3 million during 2003. During the first six months of 2004, our cash
interest expense was $3.0 million. By decreasing the amount of our indebtedness
and required cash interest payments, more of our capital resources can be
utilized for drilling activities and paying other expenses.
Exploitation and Development Activity. During the second quarter of 2004,
we continued exploitation activities on our properties. We invested $7.1million
in capital spending on these activities during the first six months of 2004.
Outlook for 2004. As a result of final 2003 financial results and current
market conditions, Abraxas has updated its operating and financial guidance for
year 2004 as follows:
Production:
BCFE (approximately 80% gas)............... 8-9
Price Differentials (Pre Hedge):
$ Per Bbl.................................. 0.86
$ Per Mcf.................................. 0.64
Lifting Costs, $ Per Mcfe..................... 1.29
G&A, $ Per Mcfe............................... 0.60
Capital Expenditures ($ Millions)............. 10.00
Actual results could materially differ and will depend on, among other
things, our ability to successfully increase our production of crude oil,
natural gas liquids and natural gas through our drilling activities. We
undertake no duty to update these forward-looking statements.
Critical Accounting Policies
There have been no changes from the Critical Accounting Polices described
in our Annual Report on Form 10-K for the year ended December 31, 2003.
Results of Operations
The following table sets forth certain of our operating data for the
periods presented.
Three Months Ended Six Months Ended
June 30, June 30,
--------------------------------- -------------------------------------
2004 2003 2004 2003 (1)
--------------------------------- -------------------------------------
Operating Revenue (in thousands):
Crude Oil Sales* ................................ $ 2,407 $ 1,651 $ 4,594 $ 3,826
Natural Gas Sales*................................ 9,213 6,494 17,366 16,580
Natural Gas Liquids Sales......................... 419 116 811 627
Processing Revenue................................ - - - 132
Rig Operations.................................... 129 158 304 339
Other............................................. 99 11 127 37
----------- ----------- ------------- ------------
$ 12,267 $ 8,430 $ 23,202 $ 21,541
=========== =========== ============= ============
19
Operating Income (Loss) in thousands)............. $ 5,707 $ 1,927 $ 6,690 $ 7,573
Crude Oil Production (MBbls)...................... 65 58 129 123
Natural Gas Production (MMcfs).................... 1,760 1,272 3,447 3,237
Natural Gas Liquids Production (MBbls)............ 14 5 27 25
Average Crude Oil Sales Price ($/Bbl)............. $ 37.09 $ 28.53 $ 35.65 $ 31.03
Average Natural Gas Sales Price ($/Mcf)........... $ 5.23 $ 5.11 $ 5.04 $ 5.12
Average Liquids Sales Price ($/Bbl)............... $ 30.97 $ 22.10 $ 30.25 $ 24.64
(1) Data for the first 23 days of 2003 includes Canadian subsidiaries sold in
January 2003.
*Revenue and average sales prices are net of hedging activities.
Comparison of Three Months Ended June 30, 2004 to Three Months Ended June 30,
2003
Operating Revenue. During the three months ended June 30, 2004, operating
revenue from crude oil, natural gas and natural gas liquid sales increased to
$12.0 million compared to $8.3 million in the three months ended June 30, 2003.
The increase in revenue was due to increased production volumes and by higher
commodity prices realized during the period. Increased production volumes
contributed $2.8 million to revenue while higher commodity prices contributed
$0.9 million to crude oil and natural gas revenue.
Average sales prices net of hedging cost for the quarter ended June 30,
2004 were:
o $ 37.09 per Bbl of crude oil,
o $ 30.97 per Bbl of natural gas liquid, and
o $ 5.23 per Mcf of natural gas
Average sales prices net of hedging cost for the quarter ended June 30, 2003
were:
o $ 28.53 per Bbl of crude oil,
o $ 22.10 per Bbl of natural gas liquid, and
o $ 5.11 per Mcf of natural gas
Crude oil production volumes increased from 57.9 MBbls during the quarter ended
June 30, 2003 to 65.0 MBbls for the same period of 2004. The increase in
production volumes was due to new production during the quarter, primarily
related to our Canadian operations. Crude oil production volumes related to our
Canadian operations increased from 4.2 MBbls during the quarter ended June 30,
2003 to 9.5 MBbls for the same period of 2004. Crude oil production from United
States operations increased from 53.7 MBbls for the quarter ended June 30, 2003
to 55.4 MBbls for the same period of 2004. Natural gas production volumes
increased to 1,760 MMcf for the three months ended June 30, 2004 from 1,272 MMcf
for the same period of 2003. The increase in natural gas production volumes was
attributable to new production during the quarter ended June 30, 2004, primarily
related to our Canadian operations. Natural gas production related to our
Canadian operations increased from 186.4 MMcf for the quarter ended June 30,
2003 to 627.7 MMcf for the same period of 2004.
Lease Operating Expenses. Lease operating expenses ("LOE") for the three
months ended June 30, 2004 increased to $3.3 million from $2.1 million for the
same period in 2003. The increase in LOE was primarily due to increased
production taxes related to higher commodity prices and increased production,
and startup cost related to previously stranded gas in Canada. Our LOE on a per
Mcfe basis for the three months ended June 30, 2004 was $1.48 per Mcfe compared
to $1.25 for the same period of 2003.
General and Administrative Expenses ("G&A"). G&A expenses increased to $2.2
million for the quarter ended June 30, 2004 from $1.2 million for the same
period of 2003. The increase in G&A expense was primarily due to performance
bonuses paid during the quarter ended June 30, 2004. G&A expense on a per Mcfe
basis was $0.99 for the second quarter of 2004 compared to $0.75 for the same
period of 2003. The per Mcfe increase was attributable to higher G&A expense
offset by increased production volumes during the second quarter of 2004 as
compared to the same period of 2003. G&A cost for the balance of 2004 are
expected to return to historical levels.
20
Stock-based Compensation. Effective July 1, 2000, the Financial Accounting
Standards Board ("FASB") issued FIN 44, "Accounting for Certain Transactions
Involving Stock Compensation", an interpretation of Accounting Principles Board
Opinion No. ("APB") 25. Under the interpretation, certain modifications to fixed
stock option awards which were made subsequent to December 15, 1998, and not
exercised prior to July 1, 2000, require that the awards be accounted for as
variable expenses until they are exercised, forfeited, or expired. In January
2003, we amended the exercise price to $0.66 per share on certain options with
an existing exercise price greater than $0.66 per share. We recognized expense
of approximately $757,000 during the quarter ended June 30, 2003 related to
these repricings. During the quarter ended June 30, 2004, we recognized a credit
to stock based compensation of $2.3 million. The credit was due to a decrease in
our common stock price as of June 30, 2004 from the price as of March 31, 2004.
Depreciation, Depletion and Amortization Expenses. Depreciation, depletion
and amortization ("DD&A") expense increased to $3.2 million for the three months
ended June 30, 2004 from $2.3 million for the same period of 2003. The increase
in DD&A was primarily due to increased production volumes during the quarter
ended June 30, 2004 as compared to the same period of 2003. Our DD&A on a per
Mcfe basis for the quarter ended June 30, 2004 was $1.44 per Mcfe as compared to
$1.39 in 2003.
Interest Expense. Interest expense increased to $4.3 million for the second
quarter of 2004 compared to $3.8 million for the same period of 2003. The
increase in interest expense was due to an increase in our overall long-term
debt from $176.6 million as of June 30, 2003 to $192.4 million as of June 30,
2004. The increase in long-term debt was due to the issuance of additional notes
in payment of interest on our 11.5% Secured Notes.
Income taxes. There is no current or deferred income tax expense or benefit
due to losses or loss carryforwards and valuation allowance which has been
recorded against such benefits.
Comparison of Six Months Ended June 30, 2004 to Six Months Ended June 30, 2003
Operating Revenue. During the six months ended June 30, 2004, operating
revenue from crude oil, natural gas and natural gas liquid sales increased to
$22.8 million as compared to $21.0 million in the six months ended June 30,
2003. The increase in revenue was due to increased production volumes and higher
realized prices during the period. Increased production contributed $1.3 million
to revenue, while higher commodity prices contributed $455,000. The increase in
production volumes was a result of drilling operations in the latter part of
2003 and the first six months of 2004. The increase in production volumes was
partially offset by the loss of production related to the Canadian properties
sold in January 2003.
Average sales prices net of hedging cost for the six months ended June 30,
2004 were:
o $35.65 per Bbl of crude oil,
o $30.25 per Bbl of natural gas liquid, and
o $ 5.04 per Mcf of natural gas
Average sales prices net of hedging cost for the six months ended June 30, 2003
were:
o $31.03 per Bbl of crude oil,
o $24.64 per Bbl of natural gas liquid, and
o $ 5.12 per Mcf of natural gas
Crude oil production volumes increased to 128.9 MBbls during the six months
ended June 30, 2004 from 123.3 MBbls for the same period of 2003. Crude oil
production volumes related to our continuing Canadian operations increased to
17.2 MBbls during the six months ended June 30, 2004 from 8.5 MBbls for the same
period of 2003. Offsetting the increased production was the loss of production
related to the properties sold in connection with the sale of Old Grey Wolf and
Canadian Abraxas in January 2003. The properties sold contributed 2.4 MBbls
during the first 23 days of 2003 prior to the sale. Natural gas production
volumes increased to 3,447 MMcf for the six months ended June 30, 2004 from
3,237 MMcf for the same period of 2003. As with the increase in crude oil
21
volumes, the increase in natural gas production volumes was the result of
drilling activities during the latter part of 2003 and the first six months of
2004, primarily related toour Canadian operations. Natural gas production
related to our continuing Canadian operations increased from 345.3 MMcf for the
first six months of 2003 to 1,149 MMcf for the same period of 2004. Offsetting
the increase was the loss of production related to the Canadian properties sold
in January 2003. Prior to the sale, these properties contributed 559.0 MMcf to
2003.
Lease Operating Expenses. Lease operating expenses for the six months ended
June 30, 2004 increased to $6.7 million from $4.8 million for the same period in
2003. The increase was due to increased production taxes as a result of higher
production volumes as well as pipeline charges in Canada related to startup cost
associated with previously stranded gas. LOE on a per Mcfe basis for the six
months ended June 30, 2004 was $1.52 compared to $1.16 for the same period of
2003.
General and Administrative Expenses. G&A expenses increased to $3.6 million
for the first six months of 2004 from $2.6 million for the first six months of
2003. The increase was primarily due to performance bonuses paid during the
second quarter of 2004. G&A expense on a per Mcfe basis was $0.81 for the first
six months of 2004 compared to $0.64 for the same period of 2003.
Stock-based Compensation. Effective July 1, 2000, the Financial Accounting
Standards Board ("FASB") issued FIN 44, "Accounting for Certain Transactions
Involving Stock Compensation", an interpretation of Accounting Principles Board
Opinion No. ("APB") 25. Under the interpretation, certain modifications to fixed
stock option awards which were made subsequent to December 15, 1998, and not
exercised prior to July 1, 2000, require that the awards be accounted for as
variable expenses until they are exercised, forfeited, or expired. In January
2003, we amended the exercise price to $0.66 per share on certain options with
an existing exercise price greater than $0.66 per share. We recognized a credit
of approximately $253,000 during the six months ended June 30, 2004 due the the
decline in the price of our common stock since December 31, 2003. We recorded an
expense of approximately $792,000 during the first six months of 2003.
Depreciation, Depletion and Amortization Expenses. Depreciation, depletion
and amortization expense increased to $6.3 million for the six months ended June
30, 2004 from $5.4 million for the same period of 2003. The increase was
primarily due to increased production volumes during the six months ended June
30, 2004 as compared to the same period of 2003. Our DD&A on a per Mcfe basis
for the six months ended June 30, 2004 was $1.43 per Mcfe as compared to $1.32
in 2003.
Interest Expense. Interest expense increased to $9.4 million for the first
six months of 2004 compared to $9.0 million in 2003. The increase in interest
expense was due to an increase in our overall long-term debt from $176.6 million
as of June 30, 2003 to $192.4 million as of June 30, 2004. The increase in
long-term debt was due to the issuance of additional notes in payment of
interest on our 11.5% Secured Notes.
Income taxes. Income taxes decreased to zero for the six months ended June
30, 2004 from $377,000 for the six months ended June 30, 2003. There is no
current or deferred income tax benefit for the current net losses due to the
valuation allowance which has been recorded against such benefits.
Liquidity and Capital Resources
General. The crude oil and natural gas industry is a highly capital
intensive and cyclical business. Our capital requirements are driven principally
by our obligations to service debt and to fund the following costs:
o the development of existing properties, including drilling and
completion costs of wells;
o acquisition of interests in crude oil and natural gas properties;
and
o production and transportation facilities.
22
The amount of capital available to us will affect our ability to service our
existing debt obligations and to continue to grow the business through the
development of existing properties and the acquisition of new properties.
Our sources of capital are primarily cash on hand, cash from operating
activities, funding under the senior credit agreement and the sale of
properties. Our overall liquidity depends heavily on the prevailing prices of
crude oil and natural gas and our production volumes of crude oil and natural
gas. Significant downturns in commodity prices, such as that experienced in the
last nine months of 2001 and the first quarter of 2002, can reduce our cash from
operating activities. Although we have hedged a portion of our natural gas and
crude oil production and will continue this practice as required pursuant to the
senior credit agreement, future crude oil and natural gas price declines would
have a material adverse effect on our overall results, and therefore, our
liquidity. Low crude oil and natural gas prices could also negatively affect our
ability to raise capital on terms favorable to us.
If the volume of crude oil and natural gas we produce decreases, our cash
flow from operations will decrease. Our production volumes will decline as
reserves are produced. In addition, due to sales of properties in January 2003,
we now have reduced reserves and production levels. In the future we may sell
additional properties, which could further reduce our production volumes. To
offset the loss in production volumes resulting from natural field declines and
sales of producing properties, we must conduct successful exploration,
exploitation and development activities, acquire additional producing properties
or identify additional behind-pipe zones or secondary recovery reserves. While
we have had some success in pursuing these activities, historically we have not
been able to fully replace the production volumes lost from natural field
declines and property sales.
Working Capital. At June 30, 2004 we had current assets of $9.0 million and
current liabilities of $9.8 million resulting in a working capital deficit of
approximately $800,000. This compares to a working capital deficit of $2.4
million at December 31, 2003 and a working capital deficit of $3.6 million at
June 30, 2003. Current liabilities at June 30, 2004 consisted of trade payables
of $2.8 million, revenues due third parties of $2.9 million, accrued interest of
$2.4, of which $2.0 is non-cash and other accrued liabilities of $1.7 million.
Under our senior credit agreement we will have cash interest expense of
approximately $4.5 million for 2004. We do not expect to make cash interest
payments with respect to the outstanding new notes, and the issuance of
additional new notes in lieu of cash interest payments thereon will not affect
our working capital balance.
Capital expenditures. Capital expenditures, excluding property divestitures
during the first six months of 2004, were $7.1 million compared to $10.0 million
during the same period of 2003. The table below sets forth the components of
these capital expenditures on a historical basis for the six months ended June
30, 2004 and 2003.
Six Months Ended
June 30,
------------------------------------------
2004 2003
---------------------- -------------------
(dollars in thousands)
------------------------------------------
Expenditure category (in thousands):
Development................................................. $ 6,232 $ 9,791
Facilities and other........................................ 856 199
--------------- ----------------
Total................................................... $ 7,085 $ 9,990
=============== ================
During the six months ended June 30, 2004 and 2003, capital expenditures
were primarily for the development of existing properties. For 2004, our capital
expenditures are subject to limitations imposed under the new senior credit
facility and new notes, including a maximum annual capital expenditure budget of
$10 million for 2004, which is subject to reduction in the event of a reduction
in our net assets. Our capital expenditures could include expenditures for
acquisition of producing properties if such opportunities arise, but we
currently have no agreements, arrangements or undertakings regarding any
material acquisitions. We have no material long-term capital commitments and are
consequently able to adjust the level of our expenditures as circumstances
dictate. Additionally, the level of capital expenditures will vary during future
periods depending on market conditions and other related economic factors.
23
Should the prices of crude oil and natural gas decline from current levels, our
cash flows will decrease which may result in a reduction of the capital
expenditures budget. If we decrease our capital expenditures budget, we may not
be able to offset crude oil and natural gas production volumes decreases caused
by natural field declines and sales of producing properties.
Sources of Capital. The net funds provided by and/or used in each of the
operating, investing and financing activities are summarized in the following
table and discussed in further detail below:
Six Months Ended
June 30,
---------------------------------------
2004 2003
---------------------------------------
(dollars in thousands)
---------------------------------------
Net cash provided by operating activities $ 7,308 $ 3,960
Net cash (used) in provided by investing activities (7,085) 76,563
Net cash provided by (used) financing activities 738 (83,607)
------------------ ---------------
Total $ 961 $ (3,084)
================== ===============
Operating activities during the six months ended June 30, 2004 provided us
$7.3 million cash compared to providing $4.0 million in the same period in 2003.
Net income plus non-cash expense items during 2004 and net changes in operating
assets and liabilities accounted for most of these funds. Financing activities
provided approximately $738,000 for the first six months of 2004 compared to
using $83.6 million for the same period of 2003. Investing activities used $7.1
million for the six months ended June 30, 2004 compared to providing $76.6
million for the same period of 2003. Expenditures during the six months ended
June 30, 2004 were primarily for the development of existing properties. The
sale of our Canadian subsidiaries contributed $86.6 million in 2003 reduced by
$10.0 million in exploration and development expenditures.
Future Capital Resources. We will have four principal sources of liquidity going
forward: (i) cash on hand, (ii) cash from operating activities, (iii) funding
under the new senior credit agreement , and (iv) sales of producing properties.
However, covenants under the indenture for the outstanding new notes and the new
senior credit agreement restrict our use of cash on hand, cash from operating
activities and any proceeds from asset sales. We may attempt to raise additional
capital or refinance our existing indebtedness through the issuance of
additional debt or equity securities, though the terms of the new note indenture
and the new senior credit agreement substantially restrict our ability to:
o incur additional indebtedness;
o incur liens;
o pay dividends or make certain other restricted payments;
o consummate certain asset sales;
o enter into certain transactions with affiliates;
o merge or consolidate with any other person; or
o sell, assign, transfer, lease, convey or otherwise dispose of all or
substantially all of our assets.
Contractual Obligations. We are committed to making cash payments in the
future on the following types of agreements:
o Long-term debt
o Operating leases for office facilities
We have no off-balance sheet debt or unrecorded obligations and we have not
guaranteed the debt of any other party. Below is a schedule of the future
payments that we are obligated to make based on agreements in place as of June
30, 2004:
24
Contractual Obligations
(dollars in thousands) Payments due in:
- ----------------------------- --------------------------------------------------------------------------
Total Less than More than 5
one year 1-3 years 3-5 years years
- --------------------------------------------------------------------------------------------------------
Long-Term Debt (1) $ 245,367 $ - $ 245,367 $ - $ -
Operating Leases (2) 1,186 414 692 80 -
------------- -------------- ------------- -------------- -------------
Total $ 246,553 $ 414 $ 246,059 $ 80 $ -
============= ============== ============= ============== =============
(1) These amounts represent the balances outstanding under the term loan
facility, the revolving credit facility and the new notes. These
repayments assume that interest will be capitalized under the term loan
facility and that periodic interest on the revolving credit facility
will be paid on a monthly basis and that we will not draw down
additional funds there under.
(2) Office lease obligations. Leases for office space for Abraxas and New
Grey Wolf expire in April 2006 and December 2008, respectively.
Other obligations. We make and will continue to make substantial capital
expenditures for the acquisition, exploitation, development, exploration and
production of crude oil and natural gas. In the past, we have funded our
operations and capital expenditures primarily through cash flow from operations,
sales of properties, sales of production payments and borrowings under our bank
credit facilities and other sources. Given our high degree of operating control,
the timing and incurrence of operating and capital expenditures is largely
within our discretion.
Long-Term Indebtedness. The following table sets forth our long-term
indebtedness as of June 30, 2004 and December 31, 2003.
June 30, December 31,
-----------------------------------
2004 2003
---------------- -----------------
(dollars in thousands)
11.5% Secured Notes due 2007 ("new notes")................. $ 143,154 $ 137,258
Senior Secured Credit Agreement............................ 49,233 47,391
---------------- -----------------
192,387 184,649
Less current maturities ................................... - -
---------------- -----------------
$ 192,387 $ 184,649
================ =================
For financial reporting purposes, the new notes are reflected at the carrying
value of our 11 1/2% Senior Notes due 2004 of $191.0 million, net of the cash
offered in the exchange of $47.5 million and net of the fair market value
related to equity of $3.8 million offered in January 2003. The face amount of
the new notes was $128.0 million at June 30, 2004 including $18.3 million in new
notes issued for interest.
New Notes. The new notes accrue interest from the date of issuance, at a
fixed annual rate of 11 1/2%, payable in cash semi-annually on each May 1 and
November 1, commencing May 1, 2003. We will pay such unpaid interest in kind by
the issuance of additional new notes with a principal amount equal to the amount
of accrued and unpaid cash interest on the new notes plus an additional 1%
accrued interest for the applicable period. Upon an event of default, the New
Notes accrue interest at an annual rate of 16.5%.
The new notes are secured by a second lien or charge on all of our current
and future assets, including, but not limited to, all of our crude oil and
natural gas properties. All of Abraxas' current subsidiaries, Sandia Oil & Gas,
Sandia Operating, Wamsutter, New Grey Wolf, Western Associated Energy and
Eastside Coal, are guarantors of the new notes, and all of Abraxas' future
subsidiaries will guarantee the new notes. If Abraxas cannot make payments on
the new notes when they are due, the guarantors must make them instead.
The new notes and related guarantees
o are subordinated to the indebtedness under the senior secured credit
agreement;
o rank equally with all of Abraxas' current and future senior
indebtedness; and
25
o rank senior to all of Abraxas' current and future subordinated
indebtedness, in each case, if any.
The new notes are subordinated to amounts outstanding under the senior secured
credit agreement both in right of payment and with respect to lien priority and
are subject to an intercreditor agreement.
Abraxas may redeem the new notes, at its option, in whole at any time or in
part from time to time, at redemption prices expressed as percentages of the
principal amount set forth below. If Abraxas redeems all or any new notes, it
must also pay all interest accrued and unpaid to the applicable redemption date.
The redemption prices for the new notes during the indicated time periods are as
follows:
Period Percentage
From June 24, 2004 to January 23, 2005..............................98.5837%
Thereafter.........................................................100.0000%
Under the indenture, we are subject to customary covenants which, among
other things, restrict our ability to:
o borrow money or issue preferred stock;
o pay dividends on stock or purchase stock;
o make other asset transfers;
o transact business with affiliates;
o sell stock of subsidiaries;
o engage in any new line of business;
o impair the security interest in any collateral for the notes;
o use assets as security in other transactions; and
o sell certain assets or merge with or into other companies.
In addition, we are subject to certain financial covenants including covenants
limiting our selling, general and administrative expenses and capital
expenditures, a covenant requiring Abraxas to maintain a specified ratio of
consolidated EBITDA, as defined in the agreements, to cash interest and a
covenant requiring Abraxas to permanently, to the extent permitted, pay down
debt under the new senior secured credit agreement and, to the extent permitted
by the new senior secured credit agreement, the new notes or, if not permitted,
paying indebtedness under the new senior secured credit agreement.
The indenture contains customary events of default, including nonpayment of
principal or interest, violations of covenants, inaccuracy of representations or
warranties in any material respect, cross default and cross acceleration to
certain other indebtedness, bankruptcy, material judgments and liabilities,
change of control and any material adverse change in our financial condition.
Senior Credit Agreement. In connection with the financial restructuring,
Abraxas entered into a new senior credit agreement providing a term loan
facility and a revolving credit facility as described below. Subsequently, on
February 23, 2004, Abraxas entered into an amendment to its existing senior
credit agreement providing for two revolving credit facilities and a new
non-revolving credit facility as described below. Subject to earlier termination
on the occurrence of events of default or other events, the stated maturity date
for these credit facilities is February 1, 2007. In the event of an early
termination, we will be required to pay a prepayment premium, except in the
limited circumstances described in the amended senior credit agreement.
First Revolving Credit Facility. Lenders under the amended senior credit
agreement have provided a revolving credit facility to Abraxas with a maximum
borrowing base of up to $20.0 million. Our current borrowing base under this
revolving credit facility is the full $20.0 million, subject to adjustments
26
based on periodic calculations. We have borrowed $6.6 million under this
revolving credit facility, which was used to refinance principal and interest on
advances under our preexisting revolving credit facility under the senior credit
agreement, and to pay certain fees and expenses relating to the transaction.
Outstanding amounts under this revolving credit facility bear interest at the
prime rate announced by Wells Fargo Bank, N.A. plus 1.125%. The balance of this
revolving credit facility was $4.2 million as of June 30, 2004.
Second Revolving Credit Facility. Lenders under the amended senior credit
agreement have provided a second revolving credit facility to Abraxas, with a
maximum borrowing of up to $30.0 million. This revolving credit facility is not
subject to a borrowing base. We have borrowed $30.0 million under this revolving
credit facility, which was used to refinance principal and interest on advances
under our preexisting revolving credit facility, and to pay certain transaction
fees and expenses. As of June 30, 2004 the outstanding balance of this facility
was $30.0 million. Outstanding amounts under this revolving credit facility bear
interest at the prime rate announced by Wells Fargo Bank, N.A. plus 3.00%.
Non-Revolving Credit Facility. Abraxas has borrowed $15.0 million pursuant
to a non-revolving credit facility, which was used to repay the preexisting term
loan under our senior credit agreement, to refinance principal and interest on
advances under the preexisting revolving credit facility, and to pay certain
transaction fees and expenses. This non-revolving credit facility is not subject
to a borrowing base. As of June 30, 2004 the outstanding balance of this
facility was $15.0 million. Outstanding amounts under this credit facility bear
interest at the prime rate announced by Wells Fargo Bank, N.A. plus 8.00%.
Covenants. Under the amended senior credit agreement, Abraxas is subject to
customary covenants and reporting requirements. Certain financial covenants
require Abraxas to maintain minimum ratios of consolidated EBITDA (as defined in
the amended senior credit agreement) to adjusted fixed charges (which includes
certain capital expenditures), minimum ratios of consolidated EBITDA to cash
interest expense, a minimum level of unrestricted cash and revolving credit
availability, minimum hydrocarbon production volumes and minimum proved
developed hydrocarbon reserves. In addition, if on the day before the end of
each fiscal quarter the aggregate amount of our cash and cash equivalents
exceeds $2.0 million, we are required to repay the loans under the amended
senior credit agreement in an amount equal to such excess. The amended senior
credit agreement also requires us to enter into hedging agreements on not less
than 40% or more than 75% of our projected oil and gas production. We are also
required to establish deposit accounts at financial institutions acceptable to
the lenders and we are required to direct our customers to make all payments
into these accounts. The amounts in these accounts will be transferred to the
lenders upon the occurrence and during the continuance of an event of default
under the amended senior credit agreement.
In addition to the foregoing and other customary covenants, the amended
senior credit agreement contains a number of covenants that, among other things,
restrict our ability to:
o incur additional indebtedness;
o create or permit to be created liens on any of our properties;
o enter into change of control transactions;
o dispose of our assets;
o change our name or the nature of our business;
o make guarantees with respect to the obligations of third parties;
o enter into forward sales contracts;
o make payments in connection with distributions, dividends or
redemptions relating to our outstanding securities, or
o make investments or incur liabilities.
27
Security. The obligations of Abraxas under the amended senior credit
agreement continue to be secured by a first lien security interest in
substantially all of Abraxas' assets, including all crude oil and natural gas
properties.
Guarantees. The obligations of Abraxas under the amended senior credit
agreement continue to be guaranteed by Abraxas' subsidiaries, Sandia Oil & Gas,
Sandia Operating, Wamsutter, New Grey Wolf, Western Associated Energy and
Eastside Coal. The guarantees under the amended senior credit agreement continue
to be secured by a first lien security interest in substantially all of the
guarantors' assets, including all crude oil and natural gas properties.
Events of Default. The amended senior credit agreement contains customary
events of default, including nonpayment of principal or interest, violations of
covenants, inaccuracy of representations or warranties in any material respect,
cross default and cross acceleration to certain other indebtedness, bankruptcy,
material judgments and liabilities, change of control and any material adverse
change in our financial condition.
Hedging Activities.
Our results of operations are significantly affected by fluctuations in
commodity prices and we seek to reduce our exposure to price volatility by
hedging our production through commodity derivative instruments. Under the
senior credit agreement, we are required to maintain hedge positions on not less
than 40% or more than 75% of our projected oil and gas production for a six
month rolling period. See "General - Commodity Prices and Hedging Activities"
and "Item 3--Quantitative and Qualitative Disclosures about Market Risk--Hedging
Sensitivity" for further information.
Net Operating Loss Carryforwards.
At December 31, 2003, the Company had, subject to the limitation discussed
below, $100.6 million of net operating loss carryforwards for U.S. tax purposes.
These loss carryforwards will expire through 2022 if not utilized. In connection
with January 2003 transactions described in Note 2 in Notes to Consolidated
Financial Statements, certain of the loss carryforwards were utilized.
Uncertainties exist as to the future utilization of the operating loss
carryforwards under the criteria set forth under FASB Statement No. 109.
Therefore, the Company has established a valuation allowance of $76.1 million as
of December 31, 2003 and June 30, 2004.
Item 3. Quantitative and Qualitative Disclosures about Market Risk.
Commodity Price Risk
As an independent crude oil and natural gas producer, our revenue, cash
flow from operations, other income and profitability, reserve values, access to
capital and future rate of growth are substantially dependent upon the
prevailing prices of crude oil, natural gas and natural gas liquids. Declines in
commodity prices will materially adversely affect our financial condition,
liquidity, ability to obtain financing and operating results. Lower commodity
prices may reduce the amount of crude oil and natural gas that we can produce
economically. Prevailing prices for such commodities are subject to wide
fluctuation in response to relatively minor changes in supply and demand and a
variety of additional factors beyond our control, such as global political and
economic conditions. Historically, prices received for crude oil and natural gas
production have been volatile and unpredictable, and such volatility is expected
to continue. Most of our production is sold at market prices. Generally, if the
commodity indexes fall, the price that we receive for our production will also
decline. Therefore, the amount of revenue that we realize is partially
determined by factors beyond our control. Assuming the production levels we
attained during the six months ended June 30, 2004 , a 10% decline in crude oil,
natural gas and natural gas liquids prices would have reduced our operating
revenue, cash flow and net income by approximately $2.3 million for the period.
28
Hedging Sensitivity
On January 1, 2001, we adopted SFAS 133 as amended by SFAS 137 and SFAS
138. Under SFAS 133, all derivative instruments are recorded on the balance
sheet at fair value. If the derivative does not qualify as a hedge or is not
designated as a hedge, the gain or loss on the derivative is recognized
currently in earnings. To qualify for hedge accounting, the derivative must
qualify either as a fair value hedge, cash flow hedge or foreign currency hedge.
None of the derivatives in place as of June 30, 2004 are designated as hedges,
accordingly, the change in the market value of the instrument is reflected in
current oil and gas revenue.
Under the terms of the amended senior credit agreement, we are required to
maintain hedging positions with respect to not less than 40% nor more than 75%
of our crude oil and natural gas production for a rolling six month period.
See "General - Commodity Prices and Hedging Activities" for a summary of
our current hedge positions.
Interest rate risk
As a result of the financial restructuring that occurred in January 2003,
and the amendment to the senior credit agreement in February 2004, the debt
under the senior credit agreement bears interest at the bank prime plus various
points. As of June 30, 2004 we had $49.2 million in outstanding indebtedness
under the new agreement. For every percentage point that the prime rate rises,
our interest expense would increase by approximately $492,000 on an annual
basis. Our new notes accrue interest at fixed rates. A change in interest rates
impacts the net market value of the Company's fixed rate debt, but has no impact
on interest incurred or cash flows.
Foreign Currency
Our Canadian operations are measured in the local currency of Canada. As a
result, our financial results are affected by changes in foreign currency
exchange rates or weak economic conditions in the foreign markets. Canadian
operations reported a pre-tax income of $1.0 million for the six months ended
June 30, 2004. It is estimated that a 5% change in the value of the U.S. dollar
to the Canadian dollar would have changed our net income by approximately
$50,000. We do not maintain any derivative instruments to mitigate the exposure
to translation risk. However, this does not preclude the adoption of specific
hedging strategies in the future.
Item 4. Controls and Procedures.
As of the end of the period covered by this report, our Chief Executive
Officer and Chief Financial Officer carried out an evaluation of the
effectiveness of Abraxas' "disclosure controls and procedures" (as defined in
the Securities Exchange Act of 1934 Rules 13a-15(e)and 15d-15(e)) and concluded
that the disclosure controls and procedures were adequate and designed to ensure
that material information relating to Abraxas and our consolidated subsidiaries
which is required to be included in our periodic Securities and Exchange
Commission filings would be made known to them by others within those entities.
There were no changes in our internal controls that could materially affect, or
are reasonably likely to materially affect our financial reporting during the
second quarter of 2004. .
29
ABRAXAS PETROLEUM CORPORATION
PART II
OTHER INFORMATION
Item 1. Legal Proceedings.
There have been no changes in legal proceedings from that described in the
Company's Annual Report of Form 10-K for the year ended December 31, 2003, and
in Note 6 in the Notes to Condensed Consolidated Financial Statements contained
in Part I of this report on Form 10-Q.
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity
Securities.
None
Item 3. Defaults Upon Senior Securities.
None
Item 4. Submission of Matters to a Vote of Security Holders.
At the Annual Meeting of Shareholders held on May 21, 2004 the
following proposals were adopted by the margins indicated:
1.Election of one director for term of two years, to hold office
until the expiration of his term in 2006 or until a successor shall
have been elected & qualified.
Number of Shares
For Against
-------------------------
James C. Phelps 31,090,522 390,474
Election of three directors for term of three years, to hold office
until the expiration of his term in 2007 or until a successor shall
have been elected & qualified.
Number of Shares
For Against
-------------------------
Robert L.G. Watson 31,090,518 390,474
Harold D. Carter 31,090,522 390,470
Barry J. Galt 31,089,862 391,130
2.Approval of the appointment of BDO Seidman, LLP as the Company's
auditors.
Number of Shares
For Against Abstain
-------------------------------------
31,045,953 149,161 285,878
Item 5. Other Information.
None
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits
30
Exhibit 31.1 Certification - Robert L.G. Watson, CEO
Exhibit 31.2 Certification - Chris E. Williford, CFO
Exhibit 32.1 Certification pursuant to 18 U.S.C. Section 1350 -
Robert L.G. Watson, CEO
Exhibit 32.2 Certification pursuant to 18 U.S.C. Section 1350 -
Chris E. Williford, CFO
(b) Reports on Form 8-K:
1. Current Report on Form 8-K filed on May 13, 2004 Financial
Statements and Exhibits, including press release announcing first
quarter financial results and operations update.
2. Current Report on Form 8-K filed on May 18, 2004, Regulation FD
disclosure of slide presentation presented at the Bear Stearns
13th Annual Global Credit Conference.
3. Current Report on Form 8-K filed on June 3, 2004, Regulation FD,
announcing Consent Solicitation.
4. Current Report on Form 8-K filed on June 15, 2004, Regulation FD,
announcing extension of consent solicitation.
5. Current Report on Form 8-K filed on June 16, 2004, Regulation FD,
announcing extension of consent solicitation.
6. Current Report on Form 8-K filed on June 17, 2004, Regulation FD,
announcing extension of consent solicitation.
7. Current Report on Form 8-K filed on June 18, 2004, Regulation FD,
announcing extension of consent solicitation.
8. Current Report on Form 8-K filed on June 21, 2004, Regulation FD,
announcing extension of consent solicitation.
9. Current Report on Form 8-K filed on June 22, 2004, Regulation FD,
announcing extension of consent solicitation.
10.Current Report on Form 8-K filed on June 23, 2004, Regulation FD,
announcing extension of consent solicitation.
11.Current Report on Form 8-K filed on June 29, 2004, Regulation FD,
announcing extension of consent solicitation.
12.Current Report on Form 8-K filed on July 7, 2004, Regulation FD,
announcing expiration of consent solicitation.7
31
ABRAXAS PETROLEUM CORPORATION
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended the Registrant has duly caused this report to be signed on its behalf by
the undersigned thereunto duly authorized.
Date: August 13, 2004 By:/s/ Robert L.G. Watson
---------------- -------------------------------
ROBERT L.G. WATSON,
President and Chief
Executive Officer
Date: August 13, 2004 By:/s/ Chris Williford
-------------------------------
CHRIS WILLIFORD,
Executive Vice President and
Principal Accounting Officer
32