Prospectus Supplement No. 1 Filed Pursuant to Rule 424(b)(3)
to Prospectus dated August 11, 2003 Registration Statement No. 333-103027
ABRAXAS PETROLEUM CORPORATION
11 1/2% Secured Notes due 2007, Series A
6,592,699 Shares of Abraxas Common Stock
----------------------
We are supplementing the prospectus dated August 11, 2003, to add certain
information contained in our Quarterly Report on Form 10-Q for the quarter ended
June 30, 2003. This prospectus supplement is not complete without, and may not
be delivered or utilized except in connection with, the prospectus dated August
11, 2003, with respect to the securities described above, including any
amendments or supplements thereto.
This prospectus supplement, together with the prospectus listed above, is
to be used by certain holders of the above-referenced securities or by their
transferees, pledges, donees or their successors in connection with the offer
and sale of the above referenced securities. This prospectus supplement should
be read in conjunction with the prospectus dated August 11, 2003 that is to be
delivered with this prospectus supplement. All capitalized terms used but not
defined in this prospectus supplement shall have the meanings given them in the
prospectus dated August 11, 2003.
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You should carefully consider the risk factors beginning on page 12 of the
prospectus dated August 11, 2003, before making an investment in the notes or
common stock.
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Neither the SEC nor any state securities commission has approved or
disapproved of the notes or the Abraxas common stock or determined if this
prospectus supplement or the prospectus dated August 11, 2003 is accurate or
complete. Any representation to the contrary is a criminal offense.
August 15, 2003
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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" 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 our limited liquidity;
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 declines in our 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.
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Abraxas Petroleum Corporation
Condensed Consolidated Balance Sheets
(in thousands)
June 30, December 31,
2003 2002
(Unaudited)
------------------ -------------------
Assets:
Current assets:
Cash ................................................... $ 2,099 $ 4,882
Accounts receivable, less allowances for doubtful
accounts:
Joint owners.......................................... 1,855 2,215
Oil and gas production................................ 4,522 7,466
Other................................................. 232 364
------------------ -------------------
6,609 10,045
Equipment inventory........................................... 718 1,014
Other current assets.......................................... 722 1,240
------------------ -------------------
Total current assets........................................ 10,148 17,181
Property and equipment:
Oil and gas properties, full cost method of accounting:
Proved.................................................... 316,780 521,995
Unproved, not subject to amortization.............. 3,622 7,052
Other property and equipment................................. 3,293 44,189
------------------ -------------------
Total................................................ 323,695 573,236
Less accumulated depreciation, depletion, and
amortization............................................ 217,098 422,842
------------------ -------------------
Total property and equipment - net........................ 106,597 150,394
Deferred financing fees, net ................................... 4,958 5,671
Deferred income taxes .......................................... - 7,820
Other assets .................................................. 366 359
------------------ -------------------
Total assets.................................................. $ 122,069 $ 181,425
================== ===================
See accompanying notes to condensed consolidated financial statements
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Abraxas Petroleum Corporation
Condensed Consolidated Balance Sheets (continued)
(in thousands)
June 30, December 31,
2003 2002
(Unaudited)
------------------- -------------------
Liabilities and Stockholders' Equity (Deficit)
Current liabilities:
Accounts payable.............................................. $ 5,336 $ 9,687
Oil and gas production payable................................ 3,263 2,432
Accrued interest.............................................. 2,229 6,009
Other accrued expenses........................................ 2,857 1,162
Current maturities of long-term debt.......................... - 63,500
------------------- -------------------
Total current liabilities........................... 13,685 82,790
Long-term debt.................................................. 176,646 236,943
Future site restoration......................................... 1,280 3,946
Stockholders' equity (deficit):
Common Stock, par value $.01 per share-
Authorized 200,000,000 shares; issued, 35,650,887 and
30,145,280 at June 30, 2003 and December 31, 2002
respectively................................................. 358 301
Additional paid-in capital.................................... 141,365 136,830
Accumulated deficit........................................... (209,265) (269,621)
Receivables from stock sales.................................. (97) (97)
Treasury stock, at cost, 165,883 shares ...................... (964) (964)
Accumulated other comprehensive loss.......................... (939) (8,703)
------------------- -------------------
Total stockholders' deficit............................... (69,542) (142,254)
------------------- -------------------
Total liabilities and stockholders' equity (deficit)............ $ 122,069 $ 181,425
=================== ===================
See accompanying notes to condensed consolidated financial statements
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Abraxas Petroleum Corporation
Condensed Consolidated Statements of Operations
(Unaudited)
(in thousands except per share data)
Three Months Ended June 30, Six Months Ended June 30,
2003 2002 2003 2002
------------------- ----------------- ----------------- -------------------
Revenue:
Oil and gas production revenues ................... $ 8,261 $ 13,143 $ 21,033 $ 24,029
Gas processing revenues ........................... - 741 132 1,411
Rig revenues ...................................... 158 193 339 344
Other ............................................ 11 158 37 258
------------------- ----------------- ----------------- -------------------
8,430 14,235 21,541 26,042
Operating costs and expenses:
Lease operating and production taxes .............. 2,066 3,353 4,792 7,262
Depreciation, depletion, and amortization ......... 2,301 9,110 5,443 15,924
Proved property impairment......................... - 115,995 - 115,995
Rig operations .................................... 148 175 314 296
General and administrative ........................ 1,231 1,481 2,627 3,179
General and administrative (Stock-based
compensation) ................................... 757 - 792 -
------------------- ----------------- ----------------- -------------------
6,503 130,114 13,968 142,656
------------------- ----------------- ----------------- -------------------
Operating income (loss) .............................. 1,927 (115,879) 7,573 (116,614)
Other (income) expense:
Interest income ................................... (7) (8) (17) (41)
Interest expense .................................. 3,846 8,761 9,010 17,174
Amortization of deferred financing fee ............ 434 431 811 858
Financing cost..................................... - - 3,601 -
Gain on sale of foreign subsidiaries............... - - (66,960) -
4,273 9,184 (53,555) 17,991
------------------- ----------------- ----------------- -------------------
Earnings (loss) before cumulative effect of
accounting change and taxes .................... (2,346) (125,063) 61,128 (134,605)
Cumulative effect of accounting change................ - - (395) -
Income tax (expense) benefit.......................... - 29,373 (377) 30,216
------------------- ----------------- ----------------- -------------------
Net earnings (loss)................................ (2,346) $ (95,690) $ 60,356 $ (104,389)
=================== ================= ================= ===================
Basic earnings (loss) per common share:
Net earnings (loss)............................. $ (0.07) $ (3.19) $ 1.74 $ (3.48)
Cumulative effect of accounting change.......... - - (0.01) -
------------------- ----------------- ----------------- -------------------
Net earnings (loss) per common share - basic....... $ (0.07) $ (3.19) $ 1.73 $ (3.48)
=================== ================= ================= ===================
Diluted earnings (loss) per common share:
Net earnings (loss)............................. $ (0.07) $ (3.19) $ 1.72 $ (3.48)
Cumulative effect of accounting change.......... - - (0.01) -
------------------- ----------------- ----------------- -------------------
Net earnings (loss) per common share - diluted..... $ (0.07) $ (3.19) $ 1.71 $ (3.48)
=================== ================= ================= ===================
See accompanying notes to condensed consolidated financial statements
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Abraxas Petroleum Corporation
Condensed Consolidated Statements of Cash Flows
(Unaudited)
(in thousands)
Six Months Ended
June 30,
---------------------------------------------
2003 2002
---------------------------------------------
Operating Activities
Net income (loss)............................................ $ 60,356 $ (104,389)
Adjustments to reconcile net income to net
cash provided by (used in) operating activities:
Depreciation, depletion, and amortization.................... 5,443 15,924
Proved property impairment................................... - 115,995
Deferred income tax (benefit) expense........................ 377 (30,216)
Amortization of deferred financing fees...................... 811 858
Amortization of debt discount................................ - 230
Stock-based compensation 792 -
Gain on sale of foreign subsidiaries......................... (66,960) -
Changes in operating assets and liabilities:
Accounts receivable...................................... (314) (453)
Equipment inventory...................................... 142 131
Other ................................................... 597 (157)
Accounts payable and accrued expenses.................... 2,716 281
----------------- -----------------
Net cash provided by (used in) operating activities........... 3,960 (1,796)
----------------- -----------------
Investing Activities
Capital expenditures, including purchases and development
of properties............................................... (9,990) (23,838)
Proceeds from sale of oil and gas producing properties........ - 32,902
Proceeds from sale of foreign subsidiaries.................... 86,553 -
Increase in restricted cash................................... - (9,895)
----------------- -----------------
Net cash provided by (used in) investing activities........... 76,563 (831)
----------------- -----------------
Financing Activities
Proceeds from long-term borrowings............................. 47,293 11,614
Payments on long-term borrowings............................... (132,096) (8,145)
Issuance of common stock in connection with exchange........... 3,781 -
Deferred financing fees ....................................... (2,604) -
Exercise of stock options .................................... 19 -
----------------- ----------------
Net cash (used in) provided by financing activities............ (83,607) 3,469
----------------- ----------------
Effect of exchange rate changes on cash............................ 301 (1,610)
----------------- ----------------
Decrease in cash (2,783) (768)
Cash, at beginning of period................................. 4,882 7,605
----------------- ----------------
Cash, at end of period....................................... $ 2,099 $ 6,837
================= ================
Supplemental disclosure of cash flow information:
Interest paid................................................ $ 3,932 $ 17,036
================= ================
See accompanying notes to condensed consolidated financial statements
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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, 2002, as amended by the annual report on Form
10-K/A No. 1 filed on July 22, 2003. Such policies have been continued without
change. You should 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 Company's
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, 2003 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.
The Company has incurred net losses in five of the last six years, and
there can be no assurance that operating income and net earnings will be
achieved in future periods. The Company's revenues, profitability and future
rate of growth are substantially dependent upon prevailing prices for crude oil
and natural gas and the volumes of crude oil, natural gas and natural gas
liquids we produce. During 2002, crude oil and natural gas prices began to
increase from 2001 levels and increased further in the first half of 2003. In
addition, because the Company's proved reserves will decline as crude oil,
natural gas and natural gas liquids are produced, unless it acquires additional
properties containing proved reserves or conducts successful exploration and
development activities, its reserves and production will decrease. The Company's
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, exploration and development projects. In order to provide
liquidity and capital resources, the Company has sold certain of its producing
properties. However, production levels have declined as the Company has been
unable to replace the production represented by the properties sold with new
production from the producing properties it has invested in with the proceeds of
property sales. In addition, under the terms of its new senior credit agreement
and New Notes (which are described below), the Company is subject to limitations
on capital expenditures. As a result, the Company may be limited in its ability
to replace existing production with new production and might suffer a decrease
in the volume of crude oil and natural gas it produces. If crude oil and natural
gas prices return to depressed levels or if production levels continue to
decrease, the Company's revenues, cash flow from operations and financial
condition may be materially adversely affected.
Certain prior years 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. There is no current or deferred income tax benefit for
the U.S. net losses due to the valuation allowance which has been recorded
against such benefits.
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Note 3. Recent Events
Exchange Offer. On January 23, 2003, the Company completed an exchange
offer, pursuant to which it offered to exchange cash and securities for all of
the outstanding 11 1/2% Senior Secured Notes due 2004, Series A ("Second Lien
Notes") and 11 1/2% Senior Notes due 2004, Series D ("Old Notes"), issued by
Abraxas and Canadian Abraxas. In exchange for each $1,000 principal amount of
such notes tendered in the exchange offer, tendering note holders received:
o cash in the amount of $264;
o an 11 1/2% Secured Note due 2007, Series A ("New Notes"), with a
principal amount equal to $610; and
o 31.36 shares of Abraxas common stock.
At the time the exchange offer was made, there were approximately $190.1
million of the Second Lien Notes and $800,000 of the Old Notes outstanding.
Holders of approximately 94% of the aggregate outstanding principal amount of
the Second Lien Notes and Old Notes tendered their notes for exchange in the
offer. Pursuant to the procedures for redemption under the applicable indenture
provisions, the remaining 6% of the aggregate outstanding principal amount of
the Second Lien Notes and Old Notes were redeemed at 100% of the principal
amount plus accrued and unpaid interest, for approximately $11.5 million ($11.1
million in principal and $0.4 million in interest). The indentures for the
Second Lien Notes and Old Notes have been duly discharged. In connection with
the exchange offer, Abraxas made cash payments of approximately $47.5 million
and issued approximately $109.7 million in principal amount of New Notes and
5,642,699 shares of Abraxas common stock. Fees and expenses incurred in
connection with the exchange offer were approximately $3.8 million.
Redemption of First Lien Notes. On January 24, 2003, the Company completed
the redemption of 100% of its outstanding 12?% Senior Secured Notes, Series B
("First Lien Notes"), with approximately $66.4 million of the proceeds from the
sale of Canadian Abraxas and Old Grey Wolf. Prior to the redemption, the Company
had $63.5 million of its First Lien Notes outstanding. Under the terms of the
indenture for the First Lien Notes, the Company had the right to redeem the
First Lien Notes at 100% of the outstanding principal amount of the notes, plus
accrued and unpaid interest to the date of redemption, and to discharge the
indenture upon call of the First Lien Notes for redemption and deposit of the
redemption funds with the trustee. The Company exercised these rights on January
23, 2003 and upon the discharge of the indenture, the trustee released the
collateral securing the Company's obligations under the First Lien Notes.
Note 4. Long-Term Debt
Long-term debt consisted of the following:
June 30 December 31
2003 2002
---------------- -----------------
(In thousands)
11.5% Senior Notes due 2004 ("Old Notes") ............................. $ - $ 801
12.875% Senior Secured Notes due 2003 ("First Lien Notes") ............ - 63,500
11.5% Second Lien Notes due 2004 ("Second Lien Notes")................. - 190,178
11.5% Senior Credit Facility("Grey Wolf Facility") providing for
borrowings up to approximately US $96 million (CDN $150 million)
Secured by the assets of Grey Wolf and non-recourse to Abraxas - 45,964
11.5% Secured Notes due 2007 ("New Notes")............................. 131,605 -
Senior Secured Credit Agreement........................................ 45,041 -
---------------- -----------------
176,646 300,443
Less current maturities ............................................... - 63,500
---------------- -----------------
$ 176,646 $ 236,943
================ =================
New Notes. - In connection with the financial restructuring, Abraxas issued
$109.7 million in principal amount of it's 11 1/2% Secured Notes due 2007,
Series A, in exchange for the second lien notes and old notes 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 exceeds the face
amount of the New Notes by approximately $19.0 million. Such amount will be
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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 new senior credit agreement or the intercreditor agreement between the
trustee under the indenture for the New Notes and the lenders under the new
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
Corporation, Sandia Operating Corp. (a wholly-owned subsidiary of Sandia Oil &
Gas), 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 new 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 new 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:
Period Percentage
From June 24, 2003 to January 23, 2004.................................91.4592%
From January 24, 2004 to June 23, 2004.................................97.1674%
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, restrict our ability to:
o borrow money or issue preferred stock;o
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
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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 new senior credit agreement and, to the extent permitted by the
new senior credit agreement, the New Notes or, if not permitted, paying
indebtedness under the new senior credit agreement.
The indenture also 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.
New 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. Subject
to earlier termination on the occurrence of events of default or other events,
the stated maturity date for both the term loan facility and the revolving
credit facility is January 22, 2006. In the event of an early termination, we
will be required to pay a prepayment premium, except in the limited
circumstances described in the new senior credit agreement. Outstanding amounts
under both facilities bear interest at the prime rate announced by Wells Fargo
Bank, N.A. plus 4.5%. Any amounts in default under the term loan facility will
accrue interest at an additional 4%. At no time will the amounts outstanding
under the new senior credit agreement bear interest at a rate less than 9%.
Term Loan Facility. Abraxas borrowed $4.2 million pursuant to a term loan
facility on January 23, 2003, all of which was used to make cash payments in
connection with the financial restructuring. Accrued interest under the term
loan facility will be capitalized and added to the principal amount of the term
loan facility until maturity.
Revolving Credit Facility. Lenders under the new senior credit agreement
have provided a revolving credit facility to Abraxas with a maximum borrowing
base of up to $50 million. Our current borrowing base under the revolving credit
facility is $48.0 million, subject to adjustments based on periodic calculations
and mandatory prepayments under the senior credit agreement. Portions of accrued
interest under the revolving credit facility may be capitalized and added to the
principal amount of the revolving credit facility. We have borrowed $42.5
million under the revolving credit facility, all of which was used to make cash
payments in connection with the financial restructuring. As of June 30, 2003,
the balance of the facility was $40.7 million, after principal reductions during
the first six months of 2003. We plan to use the remaining borrowing
availability under the new senior credit agreement to fund our operations,
including capital expenditures.
Covenants. Under the new senior credit agreement, Abraxas is subject to
customary covenants and reporting requirements. Certain financial covenants
require Abraxas to maintain minimum levels of consolidated EBITDA (as defined in
the new senior credit agreement), minimum ratios of consolidated EBITDA to cash
interest expense and a limitation on annual capital expenditures. In addition,
at the end of each fiscal quarter, if the aggregate amount of our cash and cash
equivalents exceeds $2.0 million, we are required to repay the loans under the
new senior credit agreement in an amount equal to such excess. The new senior
credit agreement also requires us to enter into hedging agreements on not less
than 25% 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 new senior credit agreement.
In addition to the foregoing and other customary covenants, the new 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 any liens on any of our properties;
o enter into any change of control transactions;
o dispose of our assets;
o change our name or the nature of our business;
o make any guarantees with respect to the obligations of third parties;
o enter into any forward sales contracts;
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o make any 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 new senior credit agreement
are secured by a first lien security interest in all of Abraxas' assets,
including all crude oil and natural gas properties.
Guarantees. The obligations of Abraxas under the new senior secured credit
agreement are guaranteed by Sandia Oil & Gas, Sandia Operating, Wamsutter, New
Grey Wolf, Western Associated Energy and Eastside Coal. The guarantees under the
new senior credit agreement are 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 new senior credit facility 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 5. 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 general and administrative
(stock-based compensation) expense in the accompanying consolidated financial
statements.
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 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, 2003 and 2002, 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 .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.
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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, 2003 and
June 30, 2002 would have been:
Three Months Ended June 30, Six Months Ended June 30,
---------------------------- --------------------------
2003 2002 2003 2002
------------- ------------ ---------- -- ------------
Net income (loss) as reported $ (2,346) $ (125,063) $ 60,356 $ (104,389)
Add: Stock-based employee compensation
expense included in reported net
income, net of related tax effects
757 - 792 -
Deduct: Total stock-based employee
compensation expense determined under
fair value based method for all
awards, net of related tax effects (271) (312) (140) (135)
------------- ------------ ---------- ------------
Pro forma net income (loss) $ (1,860) $ (125,375) $ 61,008 $ (104,524)
============= ============ ========== ============
Earnings (loss) per share:
Basic - as reported $ (0.07) $ (3.19) $ 1.73 $ (3.48)
============= ============ ========== ============
Basic - pro forma $ (0.05) $ (3.18) $ 1.75 $ (3.49)
============= ============ ========== ============
Diluted - as reported $ (0.07) $ (3.19) $ 1.71 $ (3.48)
============= ============ ========== ============
Diluted - pro forma $ (0.05) $ (3.18) $ 1.73 $ (3.49)
============= ============ ========== ============
Note 6. 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,
------------------------------- -------------------------------
2003 2002 2003 2002
------------- ------------- -------------- -------------
Numerator:
Net income (loss) before cumulative effect of
accounting change (in thousands) $ (2,346) $ (95,690) $ 60,751 $ (104,389)
Cumulative effect of accounting change - - (395) -
------------- ------------- -------------- -------------
(2,346) (95,690) 60,356 (104,389)
============= ============= ============== =============
Denominator:
Denominator for basic earnings per share -
Weighted-average shares 35,634,998 29,979,397 34,912,075 29,979,397
Effect of dilutive securities:
Stock options, warrants and CVR's - - 446,323 -
------------- ------------- -------------- -------------
Dilutive potential common shares
Denominator for diluted earnings per share -
adjusted weighted-average shares and assumed
Conversions 35,634,998 29,979,397 35,358,398 29,979,397
Basic earnings (loss) per share:
Net income (loss) before cumulative effect
of accounting change $ (0.07) $ (3.19) $ 1.74 $ (3.48)
Cumulative effect of accounting change - - (0.01) -
------------- ------------- -------------- -------------
Net earnings (loss) per common share - basic $ (0.07) $ (3.19) $ 1.73 $ (3.48)
============= ============= ============== =============
S-12
Diluted earnings (loss) per share:
Net income (loss) before cumulative effect
of accounting change $ (0.07) $ (3.19) $ 1.72 $ (3.48)
Cumulative affect of accounting change - - (0.01) -
------------- ------------- -------------- -------------
Net earnings (loss) per common share - diluted $ (0.07) $ (3.19) $ 1.71 $ (3.48)
============= ============= ============== =============
For the three months ended June 30, 2003 and 2002 and six months ended June
30, 2002, 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, 210 shares and
17,243 shares for the three months ended June 30, 2003 and 2002 and the six
months ended June 30, 2002, respectively.
Note 7. Business Segments
Business segment information about the three months and six months ended June
30, 2003 in different geographic areas is as follows:
Three Months Ended June 30, 2003
-------------------------------------------------------------
U.S. Canada Total
------------------ ----------------- -------------------
(In thousands)
Revenues ............................... $ 7,218 $ 1,212 $ 8,430
================== ================ ===================
Operating income........................ $ 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)
===================
Three Months Ended June 30, 2002
-------------------------------------------------------------
U.S. Canada Total
------------------ ----------------- -------------------
(In thousands)
Revenues ............................... $ 5,759 $ 8,476 $ 14,235
================== ================= ===================
Operating loss.......................... $ (27,292) $ (87,280) $ (114,572)
================== =================
General Corporate................................................................. (1,307)
Interest expense and amortization of
deferred financing fees........................................................ (9,184)
-------------------
Loss before income taxes.......................................................... $ (125,063)
===================
Six Months Ended June 30, 2003
-------------------------------------------------------------
U.S. Canada Total
------------------ ----------------- -------------------
(In thousands)
Revenues ............................... $ 16,017 $ 5,524 $ 21,541
================== ================= ===================
Operating income........................ $ 8,071 $ 2,531 $ 10,602
================== =================
General Corporate................................................................. (3,029)
Interest expense, financing cost and amortization of
deferred financing fees........................................................ (13,010)
Gain on sale of foreign subsidiaries.............................................. 66,960
Cumulative effect of accounting change............................................ (395)
-------------------
Income before income taxes........................................................ $ 61,128
===================
Six Months Ended June 30, 2002
-------------------------------------------------------------
U.S. Canada Total
------------------ ----------------- -------------------
(In thousands)
Revenues ............................... $ 10,375 $ 15,667 $ 26,042
================== ================= ===================
Operating loss.......................... $ (26,838) $ (87,479) $ (114,317)
================== =================
General Corporate................................................................. (2,297)
Interest expense and amortization of
deferred financing fees........................................................ (17,991)
S-13
-------------------
Loss before income taxes.......................................................... $ (134,605)
===================
At June 30, 2003
-------------------------------------------------------------
U.S. Canada Total
------------------ ----------------- -------------------
(In Thousands)
Identifiable assets .................... $ 83,062 $ 33,180 $ 116,242
================== =================
Corporate assets.................................................................. 5,827
-------------------
Total assets ..................................................................... $ 122,069
===================
Note 8. 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. Currently, the Company uses only cash flow hedges and the
remaining discussion will relate exclusively to this type of derivative
instrument. If the derivative qualifies for hedge accounting, the gain or loss
on the derivative is deferred in other comprehensive income (loss), a component
of stockholders' equity, to the extent that the hedge is effective.
The relationship between the hedging instrument and the hedged item must be
highly effective in achieving the offset of changes in cash flows attributable
to the hedged risk both at the inception of the contract and on an ongoing
basis. Hedge accounting is discontinued prospectively when a hedge instrument
becomes ineffective. Gains and losses deferred in accumulated other
comprehensive income (loss) related to a cash flow hedge that becomes
ineffective remain unchanged until the related production is delivered. If the
Company determines that it is probable that a hedged transaction will not occur,
deferred gains or losses on the hedging instrument are recognized in earnings
immediately.
Gains and losses on hedging instruments related to accumulated other
comprehensive income (loss) and adjustments to carrying amounts on hedged
production are included in natural gas or crude oil production revenue in the
period that the related production is delivered.
Under the terms of our new senior credit agreement, the Company is required
to maintain hedging agreements with respect to not less than 25% nor more than
75% of it crude oil and natural gas production for a rolling six month period.
On January 23, 2003, the Company entered into a collar option agreement with
respect to 5,000 MMBtu per day, or approximately 25% of the Company's
production, at a call price of $6.25 per MMBtu and a put price of $4.00 per
MMBtu, for the calendar months of February through July 2003. In February 2003,
the Company entered into an additional hedge agreement for 5,000 MMbtu per day
with a floor of $4.50 per MMBtu for the calendar months of March 2003 through
February 2004.
The following table sets forth the Company's hedge position as of June 30,
2003:
Time Period Notional Quantities Price Fair Value
---------------------------------------- ------------------------------ ------------------------------ ----------------
February 1, 2003--July 31, 2003 5,000 MMBtu of production Collar with floor of $4.00 $ -
per day and ceiling of $6.25 per
MMbtu
March 1, 2003 - February 29, 2004 5,000 MMBtu of production Floor of $4.50 Mmbtu $ 139,617
per day
All hedge transactions are subject to the Company's risk management policy,
approved by the Board of Directors. The Company formally documents all
relationships between hedging instruments and hedged items, as well as its risk
management objectives and strategy for undertaking the hedge. This process
includes specific identification of the hedging instrument and the hedged
transaction, the nature of the risk being hedged and how the hedging
instrument's effectiveness will be assessed. Both at the inception of the hedge
and on an ongoing basis, the Company assesses whether the derivatives that are
used in hedging transactions are highly effective in offsetting changes in cash
flows of hedged items.
S-14
The fair value of the hedging instrument was determined based on the base
price of the hedged item and NYMEX forward price quotes. As of June 30, 2003, a
commodity price increase of 10% would have resulted in an unfavorable change in
the fair market value of $14,000 and a commodity price decrease of 10% would
have resulted in a favorable change in fair market value of $14,000.
Note 9. Contingencies
Litigation. - In 2001 the Company and a limited partnership, of which a
subsidiary of the Company 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
In late 2000, the Company received a Final De Minimis Settlement Offer from
the United States Environmental Protection Agency concerning the Casmalia
Disposal Site, Santa Barbara County, California. The Company's liability for the
cleanup at the Superfund site is based on its acquisition of Bennett Petroleum
Corporation, which is alleged to have transported or arranged for the
transportation of oil field waste and drilling muds to the Superfund site. The
Company has engaged California counsel to evaluate the notice of proposed de
minimis settlement and its notice of potential strict liability under the
Comprehensive Environmental Response, Compensation and Liability Act. Defense of
the action is handled through a joint group of companies, all of which are
claiming a petroleum exclusion that would limit the Company's liability. The
potential financial exposure and any settlement posture has yet not been
developed, but is considered by the Company to be immaterial.
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, 2003, 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 10. 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, 2002 and 2003:
Three Months Ended June 30 Six Months Ended June 30,
2003 2002 2003 2002
------------ ------------- -------------- -------------
Net (loss) income.................................. $ (2,346) $ (95,690) $ 60,356 $ (104,389)
Other Comprehensive loss:
Hedging derivatives (net of tax) - See Note
Change in fair market value of outstanding
hedge positions............................... (151) 1,250 (49) (825)
Foreign currency translation adjustment.......... 2,386 5,523 7,813 5,156
------------ ------------- -------------- -------------
Other comprehensive income 2,235 6,773 7,764 4,331
------------ ------------- -------------- -------------
Comprehensive (loss) income........................ $ (111) $ (88,917) $ 68,120 $ (100,058)
============ ============= ============== =============
Note 11. Proved Property Impairment
In accordance with the Securities and Exchange Commission requirements, the
estimated discounted future net cash flows from proved reserves are generally
based on prices and costs as of the end of a period, or alternatively, if prices
subsequent to that date have increased, a price near the periodic filing date of
the Company's financial statements. As of June 30, 2002, the Company's net
S-15
capitalized costs of crude oil and natural gas properties exceeded the present
value of its estimated proved reserves by $138.7 million ($28.2 million on the
U.S. properties and $110.5 million on the Canadian properties). As a result,
during the quarter ended June 30, 2002 we incurred a proved property impairment
write-down of approximately $116 million primarily due to volatile commodity
prices. These amounts were calculated considering June 30, 2002 period-end
prices of $26.12 per Bbl for crude oil and $2.16 per Mcf for natural gas as
adjusted to reflect the expected realized prices for each of the full cost
pools. The Company used the subsequent increased prices in Canada to evaluate
its Canadian properties, and reduced the period end June 30, 2002 write-down to
an amount of $87.8 million on those properties. The subsequent prices in the
U.S. would not have resulted in a reduction of the write-down for the U.S.
properties. An expense recorded in one period may not be reversed in a
subsequent period even though higher crude oil and natural gas prices may have
increased the ceiling applicable to the subsequent period.
The Company cannot assure you that it will not experience additional
write-downs in the future. Should commodity prices decline or if any of our
proved reserves are revised downward, a further write-down of the carrying value
of our crude oil and natural gas properties may be required.
Note 12. New Accounting Standards
In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 141, "Business Combinations," which requires the purchase method of
accounting for business combinations initiated after June 30, 2001 and
eliminates the pooling-of-interests method. In July 2001, the FASB also issued
SFAS No. 142, "Goodwill and Other Intangible Assets," which discontinues the
practice of amortizing goodwill and indefinite lived intangible assets and
initiates an annual review for impairment. Intangible assets with a determinable
useful life will continue to be amortized over that period. The amortization
provisions apply to goodwill and intangible assets acquired after June 30, 2001.
SFAS No. 141 and 142 clarify that more assets should be distinguished and
classified between tangible and intangible. The Company did not change or
reclassify contractual mineral rights included in oil and gas properties on the
balance sheet upon adoption of SFAS No. 142. The Company believes the treatment
of such mineral rights as tangible assets under the full cost method of
accounting for crude oil and natural gas properties is appropriate. An issue has
arisen regarding whether contractual mineral rights should be classified as
intangible rather that tangible assets. If it is determined that
reclassification is necessary, the Company's oil and gas properties would be
reduced by $3.1 million and intangible assets would have increased by a like
amount at June 30, 2003, representing cost incurred from the effective date of
June 30, 2001. The provisions of SFAS No. 141 and 142 impact only the balance
sheet and associated footnote disclosure, and reclassifications necessary would
not impact the Company's cash flow or results of operations.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations" (SFAS 143). SFAS 143 addresses accounting and reporting
for obligations associated with the retirement of tangible long-lived assets and
the associated asset retirement costs. SFAS 143 is effective for us January 1,
2003. SFAS 143 requires that the fair value of a liability for an asset's
retirement obligation be recorded in the period in which it is incurred and the
corresponding cost capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its then present value each
period, and the capitalized cost is depreciated over the useful life of the
related asset. If the liability is settled for an amount other than the recorded
amount, a gain or loss is recognized. For all periods presented, we have
included estimated future costs of abandonment and dismantlement in our full
cost amortization base and amortize these costs as a component of our depletion
expense in the accompanying consolidated financial statements.
The Company adopted SFAS 143 effective January 1, 2003. For the six months
ended June 30, 2003 the Company recorded a charge of $395,341 for the cumulative
effect of the change in accounting principal and a liability of $1.3 million.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB No. 4, 44,
and 64, Amendments of FASB Statement No. 13 and Technical Corrections" (SFAS
145). SFAS 145 clarifies guidance related to the reporting of gains and losses
from extinguishment of debt and resolves inconsistencies related to the required
accounting treatment of certain lease modifications. SFAS 145 also amends other
existing pronouncements to make various technical corrections, clarify meanings
or describe their applicability under changed conditions. The provisions
relating to the reporting of gains and losses from extinguishment of debt were
effective for us beginning January 1, 2003. All other provisions of this
standard have been effective for the Company as of May 15, 2002 and did not have
a significant impact on the Company's financial condition or results of
operations.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" (SFAS 146). SFAS 146 requires costs
associated with exit of disposal activities to be recognized when they are
S-16
incurred rather than at the date of commitment to an exit or disposal plan. SFAS
146 was effective for us beginning January 1, 2003. For the six months ended
June 30, 2003 this standard had no impact on the Company's financial condition
or results of operation.
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-based
Compensation--Transition and Disclosure, an amendment of FASB Statement No.
123," which amends SFAS 123 to provide alternative methods of transition for a
voluntary change to the fair value based method of accounting for stock-based
employee compensation. It also amends the disclosure provisions of SFAS 123 to
require prominent disclosure in both annual and interim financial statements
about the method of accounting for stock-based employee compensation and the
effect of the method used on reported results. The provisions of SFAS 148 are
effective for annual financial statements for fiscal years ending after December
15, 2002, and for financial reports containing condensed financial statements
for interim periods beginning after December 15, 2002. The Company will continue
to use APB No. 25 to account for stock based compensation, while providing the
disclosures required by SFAS 123 as amended by SFAS 148.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts, and for
hedging activities under SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities." SFAS No. 149, among other things, clarifies the
circumstances under which a contract with an initial net investment meets the
characteristic of a derivative and amends the definition of an "underlying" to
conform it to language used in FIN 45. SFAS No. 149 is effective for contracts
entered into or modified after June 30, 2003. The Company adopted this statement
effective July 1, 2003. Implementation of this new standard did not have an
effect on the Company's consolidated financial position or results of
operations. In May 2003, the FASB issued FAS No. 150, entitled "Accounting for
Certain Financial Instruments with Characteristics of both Liabilities and
Equity". This statement is effective for financial instruments entered into or
modified after May 31, 2003, and is otherwise effective at the beginning of the
first interim period beginning after June 15, 2003. The Company has no financial
instruments affected by FAS No. 150, therefore adoption by the Company as of
July 1, 2003 will not impact the Company's financial statements.
The American Institute of Certified Public Accountants has issued an
Exposure Draft for a Proposed Statement of Position, " Accounting for Certain
Costs and Activities Related to Property, Plant and Equipment" which would
require major maintenance activities to be expensed as costs are incurred. The
Company is currently evaluating the impact on its results of operations and
financial condition if this proposed Statement of Position is adopted in its
current form.
Note 13. Accounting Change
The Company adopted SFAS 143 effective January 1, 2003. For the six months
period ended June 30, 2003 the Company recorded a charge of $395,341 for the
cumulative effect of the change in accounting principal.
Note 14. Subsequent Event
Subsequent to June 30, 2003, on July 29, 2003 the Company acquired all of
the shares of the capital stock of Wind River Resources Corporation which owned
an airplane. The sole shareholder of Wind River was Robert Watson, Abraxas'
Chairman of the Board, President and Chief Executive Officer. The consideration
for the purchase was 106,977 shares of Abraxas common stock and $35,000 in cash.
Simultaneously with this transaction, the airplane was sold. The airplane had
previously been made available to Abraxas' employees for business use.
S-17
Management's Discussion and Analysis of Financial Condition
and Results of OperationS
General
We have incurred net losses in five of the last six years, and there can be
no assurance that operating income and net earnings will be achieved in future
periods. Our revenues, profitability and future rate of growth are substantially
dependent upon prevailing prices for crude oil and natural gas and the volumes
of crude oil, natural gas and natural gas liquids we produce. During 2002, crude
oil and natural gas prices began to increase from 2001 levels and increased
further in the first quarter of 2003. In addition, 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, exploration and development projects. In order to
provide us with liquidity and capital resources, we have sold certain of our
producing properties. However, our production levels have declined as we have
been unable to replace the production represented by the properties we have sold
with new production from the producing properties we have invested in with the
proceeds of our property sales. In addition, under the terms of our new 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 continue to decrease, our
revenues, cash flows from operations and financial condition will be materially
adversely affected. For more information, see "Liquidity and Capital Resources."
Results of Operations
General. 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. 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 the first six months of 2003, we
experienced an increase in energy commodity prices from the prices that we
received in the same period of 2002. Price declines experienced in 2001
continued during the first quarter of 2002, primarily due to the economic
downturn. Beginning in March 2002, commodity prices began to increase and
continued higher through 2002 and have continued to increase during the first
half of 2003.
The table below illustrates how natural gas prices fluctuated over the
eight quarters prior to and including the quarter ended June 30, 2003. 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,
2001 2001 2002 2002 2002 2002 2003 2003
------------ ---------- ------------ ------------ ----------- ------------- ----------- ------------
Index $ 2.98 $ 2.47 $ 2.38 $ 3.36 $ 3.28 $ 3.99 $ 6.61 $ 5.51
Realized $ 2.26 $ 2.09 $ 2.21 $ 2.44 $ 2.08 $ 3.47 $ 5.13 $ 5.11
The NYMEX natural gas price on August 11, 2003 was $5.13 per Mcf.
S-18
Prices for crude oil have followed a similar path as the commodity market
fell throughout 2001 and the first quarter of 2002. The table below contains the
last three day average of NYMEX traded contracts price and the prices we
realized during each quarter presented.
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,
2001 2001 2002 2002 2002 2002 2003 2003
----------- ---------- ------------- -------------- ------------- ---------- ------------- ------------
Index $ 26.50 $ 22.12 $ 19.48 $ 26.40 $ 27.50 $ 28.29 $ 33.71 $ 29.87
Realized $ 25.06 $ 18.72 $ 16.64 $ 23.47 $ 27.19 $ 24.83 $ 33.22 $ 28.53
The NYMEX crude oil price on August 11, 2003 was $32.01 per Bbl.
Hedging Activities. We seek to reduce our exposure to price volatility by
hedging our production through swaps, options and other commodity derivative
instruments. During the first six months of 2002 we experienced hedging losses
of $1.7 million. In October 2002, all of these hedge agreements expired. Under
the expired hedge agreements, we made total payments over the term of these
arrangements to various counterparties in the amount of $35.1 million.
Under the terms of our new senior credit agreement, we are required to
maintain hedging positions with respect to not less than 25% nor more than 75%
of our crude oil and natural gas production for a rolling six month period. On
January 23, 2003, we entered into a collar option agreement with respect to
5,000 MMBtu per day, or approximately 25% of our production, at a call price of
$6.25 per MMBtu and a put price of $4.00 per MMBtu agreement, for the calendar
months of February through July 2003. In February 2003, we entered into a second
hedge agreement for the calendar months of March 2003 through February 2004,
related to 5,000 MMBtu which provides for a floor price of $4.50 per MMBtu.
During the first six months of 2003, we incurred hedging costs of $542,965.
Selected operating data. The following table sets forth certain of our
operating data for the periods presented.
Three Months Ended Six Months Ended
June 30 June 30
2003 2002 2003 2002
-------------- --------------- ---------------- -----------------
Operating Revenue (in thousands):
Crude Oil Sales ................................ $ 1,651 $ 1,766 $ 3,826 $ 2,998
Natural Gas Sales ................................ 6,494 10,287 16,580 19,069
Natural Gas Liquids Sales......................... 116 1,090 627 1,962
Processing Revenue................................ - 741 132 1,411
Rig Operations.................................... 158 193 339 344
Other............................................. 11 158 37 258
----------- ----------- ------------- ------------
$ 8,430 $ 14,235 $ 21,541 $ 26,042
=========== =========== ============= ============
Operating Income (Loss) in thousands)............. $ 1,927 $ (115,879) $ 7,573 $ (116,614)
Crude Oil Production (MBbls)...................... 58 75 123 149
Natural Gas Production (MMcfs).................... 1,272 4,218 3,237 8,191
Natural Gas Liquids Production (MBbls)............ 5 62 25 130
Average Crude Oil Sales Price ($/Bbl)............. $ 28.53 $ 23.47 $ 31.03 $ 20.08
Average Natural Gas Sales Price ($/Mcf)........... $ 5.11 $ 2.44 $ 5.12 $ 2.33
Average Liquids Sales Price ($/Bbl)............... $ 22.10 $ 17.73 $ 24.64 $ 15.11
Comparison of Three Months Ended June 30, 2003 to Three Months Ended June 30,
2002
Operating Revenue. During the three months ended June 30, 2003, operating
revenue from crude oil, natural gas and natural gas liquid sales decreased to
$8.3 million compared to $13.1 million in the three months ended June 30, 2002.
S-19
The decrease in revenue was primarily due to decreased production volumes,
primarily due to the sale of our Canadian subsidiaries, partially offset by
higher commodity prices realized during the period. Higher commodity prices
contributed $3.7 million to crude oil and natural gas revenue while reduced
production volumes had a $8.5 million negative impact on revenue.
Average sales prices net of hedging losses 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
Average sales prices net of hedging losses for the quarter ended June 30, 2002
were:
o $ 23.47 per Bbl of crude oil,
o $ 17.73 per Bbl of natural gas liquid, and
o $ 2.44 per Mcf of natural gas
Crude oil production volumes declined from 75.2 MBbls during the quarter
ended June 30, 2002 to 57.9 MBbls for the same period of 2003. The decline in
production volumes was due to property sales in the second quarter of 2002, as
well as the properties sold in connection with the sale of Canadian Abraxas and
Old Grey Wolf in January 2003. The properties sold in the second quarter of 2002
contributed 9.1 MBbls for the quarter ended June 30, 2002. The Canadian
properties sold in January 2003 contributed 5.4 MBbls in the quarter ended June
30, 2002. Natural gas production volumes declined to 1,272 MMcf for the three
months ended June 30, 2003 from 4,218 MMcf for the same period of 2002. As
discussed above, property sales were primarily responsible for the decline in
production volumes. Properties sold in the second quarter of 2002 contributed
107 MMcf for the quarter ended June 30, 2002. The Canadian properties sold in
January 2003 contributed 2,745 MMcf in the second quarter of 2002.
Lease Operating Expenses. Lease operating expenses ("LOE") for the three
months ended June 30, 2003 decreased to $2.1 million from $3.4 million for the
same period in 2002. The decrease in LOE is primarily due the sale of Canadian
Abraxas and Old Grey Wolf in January 2003. LOE related to the properties owned
by Canadian Abraxas and Old Grey Wolf was $1.5 million for the quarter ended
June 30, 2002. Excluding the properties sold, LOE attributable to on going
operations increased slightly primarily due to higher production taxes
associated with higher commodity prices in the quarter ended June 30, 2003 as
compared to the same period of 2002. Our LOE on a per MCfe basis for the three
months ended June 30, 2003 was $1.25 per MCfe compared to $0.67 for the same
period of 2002 due to the decrease in production volumes.
General and administrative ("G&A") Expenses. G&A expenses decreased from
$1.5 million for the quarter ended June 30, 2002 to $1.2 million for the same
period of 2003. The decrease in G&A expense was primarily due to a reduction in
personnel in connection with the sale of Canadian Abraxas and Old Grey Wolf on
January 23, 2003. G&A expense on a per MCfe basis was $0.75 for the second
quarter of 2003 compared to $0.29 for the same period of 2002. The per MCfe
increase was attributable to lower production volumes in the second quarter of
2003 as compared to the same period of 2002.
G&A - 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 2002, we did not
recognize any stock-based compensation expense.
Depreciation, Depletion and Amortization Expenses. Depreciation, depletion
and amortization ("DD&A") expense decreased to $2.3 million for the three months
ended June 30, 2003 from $9.1 million for the same period of 2002. The decrease
in DD&A was primarily due to the sale of our Canadian subsidiaries in January
2003 as well as ceiling limitation write-downs in the second quarter of 2002.
Our DD&A on a per MCfe basis for the quarter ended June 30, 2003 was $1.39 per
MCfe as compared to $1.81 in 2002. These decreases were due to reduced
production volumes in 2003 and prior ceiling limitation write-downs.
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Interest Expense. Interest expense decreased to $3.8 million for the second
quarter of 2003 compared to $8.8 million for the same period of 2002. The
decrease in interest expense was due to the reduction in long-term debt in the
first six months of 2003. Long-term debt was reduced as a result of the
financial transactions which occurred on January 23, 2003 as described in Note 2
in the Notes to Consolidated Financial Statements.
Proved Property Impairment. We record the carrying value of our crude oil
and natural gas properties using the full cost method of accounting for crude
oil and natural gas properties. Under this method, we capitalize the cost to
acquire, explore for and develop crude oil and natural gas properties. Under the
full cost accounting rules, the net capitalized cost of crude oil and natural
gas properties less related deferred taxes, is limited by country, to the lower
of the unamortized cost or the cost ceiling, (defined as the sum of the present
value of estimated unescalated future net revenues from proved reserves,
discounted at 10%, plus the cost of properties not being amortized, if any, plus
the lower of cost or estimated fair value of unproved properties included in the
costs being amortized, if any, less related income taxes.) If the net
capitalized cost of crude oil and natural gas properties exceeds the ceiling
limit, we are subject to a ceiling limitation write-down to the extent of such
excess. A ceiling limitation write-down is a charge to earnings, which does not
impact cash flow from operating activities. However, such write-downs do impact
the amount of our stockholders' equity. An expense recorded in one period may
not be reversed in a subsequent period even though higher crude oil and natural
gas prices may have increased the ceiling applicable to the subsequent period.
The risk that we will be required to write-down the carrying value of our
crude oil and natural gas assets increases when crude oil and natural gas prices
are depressed or volatile. In addition, write-downs may occur if we have
substantial downward revisions in our estimated proved reserves or if purchasers
or governmental action cause an abrogation of, or if we voluntarily cancel,
long-term contracts for our natural gas. As of June 30, 2002, our net
capitalized costs of crude oil and natural gas properties exceeded the present
value of our estimated proved reserves by $138.7 million ($28.2 million on the
U.S. properties and $110.5 million on the Canadian properties). As a result,
during the quarter ended June 30, 2002, we incurred a proved-property impairment
write-down of approximately $116 million primarily due to volatile commodity
prices. These amounts were calculated considering June 30, 2002 period-end
prices of $26.12 per Bbl for crude oil and $2.16 per Mcf for natural gas as
adjusted to reflect the expected realized prices for each of the full cost
pools. We used the subsequent prices to evaluate our Canadian properties, and
reduced the period end June 30, 2002 write-down to an amount of $87.8 million on
those properties. The subsequent prices in the U.S. would not have resulted in a
reduction of the write-down for the U.S. properties.
We cannot assure you that we will not experience additional write-downs in
the future. Should commodity prices decline or if any of our proved reserves are
revised downward, a further write-down of the carrying value of our crude oil
and natural gas properties may be required.
Income taxes. Income taxes decreased from a benefit of $29.4 million for
the three months ended June 30, 2002 to zero for the same period of 2003. The
benefit in 2002 was related to the ceiling limitation write-down that occurred
in the second quarter of 2002. There is no current or deferred income tax
benefit for the U.S. net losses due to the valuation allowance which has been
recorded against such benefits.
Comparison of Six Months Ended June 30, 2003 to Six Months Ended June 30, 2002
Operating Revenue. During the six months ended June 30, 2003, operating
revenue from crude oil, natural gas and natural gas liquid sales decreased to
$21.0 million as compared to $24.0 million in the six months ended June 30,
2002. The decrease in revenue was primarily due to decreased production volumes,
primarily due to the sale of our Canadian subsidiaries, off set by higher
realized prices during the period. Decreased production had a negative impact on
revenue of $13.6 million, while increased realized prices contributed $10.6
million to revenue. Production volumes decreased primarily as a result of
producing property sales in the first six months of 2002 as well as the
properties sold in January 2003 in connection with the sale of Canadian Abraxas
and Old Grey Wolf.
Average sales prices net of hedging losses 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
Average sales prices net of hedging losses for the six months ended June 30,
2002 were:
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o $ 20.08 per Bbl of crude oil,
o $ 15.11 per Bbl of natural gas liquid, and
o $ 2.33 per Mcf of natural gas
Crude oil production volumes declined from 149.2 MBbls during the six
months ended June 30, 2002 to 123.3 MBbls for the same period of 2003.
Contributing to the decrease in production were properties sold during the
second quarter of 2002 which contributed 13.4 MBbls in the first six months of
2002 and the Canadian properties sold in January 2003 which contributed 11.8
MBbls during the first six months of 2002 compared to 2.4 MBbls during the six
months ended June 30, 2003 (through January 23, 2003). Natural gas production
volumes declined to 3,237 MMcf for the six months ended June 30, 2003 from 8,191
MMcf for the same period of 2002. As discussed above, property sales in the
second quarter of 2002 and in January 2003 contributed to the decline in natural
gas production volumes. Properties sold in the second quarter of 2002
contributed 259.5 MMcf during the six months ended June 30, 2002, through the
date of the sale (May 31, 2002). The Canadian properties sold in January 2003,
contributed 5,251 MMcf for the six months ended June 30, 2002 compared to 345
MMcf for the period ended June 30, 2003 (through January 23, 2003). This decline
was partially offset by new production from current drilling activities.
Lease Operating Expenses. Lease operating expenses and natural gas
processing costs ("LOE") for the six months ended June 30, 2003 decreased to
$4.8 million from $7.3 million for the same period in 2002. The decrease in LOE
was primarily due to the sale of Canadian Abraxas and Old Grey Wolf in January
2003. LOE related to the properties owned by Canadian Abraxas and Old Grey Wolf
was $3.5 million for the six months ended June 30, 2002 compared to $379,000 for
the same period of 2003 through the date of the sale. Excluding the properties
sold, there was an increase in LOE on continuing operations primarily due to
increased production tax expense. Production tax expense was higher due to
higher commodity prices in the six months ended June 30, 2003 as compared to the
same period of 2002. Our LOE on a per MCfe basis for the six months ended June
30, 2003 was $1.16 per MCfe as compared to $0.74 for the same period of 2002 due
to decreased production volumes..
General and administrative ("G&A") Expenses. G&A expenses decreased from
$3.2 million for the first six months of 2002 to $2.6 million for the first six
months of 2003. The decrease in G&A expense was primarily due to a reduction in
personnel in connection with the sale of Canadian Abraxas and Old Grey Wolf on
January 23, 2003. G&A expense on a per MCfe basis was $0.64 for the first six
months of 2003 compared to $0.32 for the same period of 2002. The per MCfe
increase is attributable to lower production volumes in the first six months of
2003 as compared to the same period of 2002.
G&A - 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 $792,000 during the six months
ended June 30, 2003 related to these repricings. During 2002, we did not
recognize any stock -based compensation expense.
Depreciation, Depletion and Amortization Expenses. Depreciation, depletion
and amortization ("DD&A") expense decreased to $5.4 million for the six months
ended June 30, 2003 from $15.9 million for the same period of 2002. The decrease
in DD&A was primarily due to the sale of our Canadian subsidiaries in January
2003 as well as ceiling limitation write-downs in the second quarter of 2002.
Our DD&A on a per MCfe basis for the six months ended June 30, 2003 was $1.32
per MCfe as compared to $1.61 in 2002. These decreases were due to reduced
production volumes in 2003 and prior ceiling limitation write-downs.
Interest Expense. Interest expense decreased to $9.0 million for the first
six months of 2003 compared to $17.2 million in 2002. The decrease in interest
expense was due to the reduction in long-term debt in the first six months of
2003. Long-term debt was reduced as a result of the financial transactions which
occurred on January 23, 2003 as described in Note 2 in the Notes to Consolidated
Financial Statements.
Proved Property Impairment. We record the carrying value of our crude oil
and natural gas properties using the full cost method of accounting for crude
oil and natural gas properties. Under this method, we capitalize the cost to
acquire, explore for and develop crude oil and natural gas properties. Under the
full cost accounting rules, the net capitalized cost of crude oil and natural
gas properties less related deferred taxes, is limited by country, to the lower
of the unamortized cost or the cost ceiling, (defined as the sum of the present
value of estimated unescalated future net revenues from proved reserves,
S-22
discounted at 10%, plus the cost of properties not being amortized, if any, plus
the lower of cost or estimated fair value of unproved properties included in the
costs being amortized, if any, less related income taxes.) If the net
capitalized cost of crude oil and natural gas properties exceeds the ceiling
limit, we are subject to a ceiling limitation write-down to the extent of such
excess. A ceiling limitation write-down is a charge to earnings, which does not
impact cash flow from operating activities. However, such write-downs do impact
the amount of our stockholders' equity. An expense recorded in one period may
not be reversed in a subsequent period even though higher crude oil and natural
gas prices may have increased the ceiling applicable to the subsequent period.
The risk that we will be required to write-down the carrying value of our
crude oil and natural gas assets increases when crude oil and natural gas prices
are depressed or volatile. In addition, write-downs may occur if we have
substantial downward revisions in our estimated proved reserves or if purchasers
or governmental action cause an abrogation of, or if we voluntarily cancel,
long-term contracts for our natural gas. As of June 30, 2002, our net
capitalized costs of crude oil and natural gas properties exceeded the present
value of our estimated proved reserves by $138.7 million ($28.2 million on the
U.S. properties and $110.5 million on the Canadian properties). As a result,
during the six months ended June 30, 2002, we incurred a proved-property
impairment write-down of approximately $116 million primarily due to volatile
commodity prices. These amounts were calculated considering June 30, 2002
period-end prices of $26.12 per Bbl for crude oil and $2.16 per Mcf for natural
gas as adjusted to reflect the expected realized prices for each of the full
cost pools. We used the subsequent prices to evaluate our Canadian properties,
and reduced the period end June 30, 2002 write-down to an amount of $87.8
million on those properties. The subsequent prices in the U.S. would not have
resulted in a reduction of the write-down for the U.S. properties.
We cannot assure you that we will not experience additional write-downs in
the future. Should commodity prices decline or if any of our proved reserves are
revised downward, a further write-down of the carrying value of our crude oil
and natural gas properties may be required.
Income taxes. Income taxes increased to $377,000 for the six months ended
June 30, 2003 from a benefit of $30.2 million for the first six months of 2002.
The benefit in 2002 was related to the ceiling limitation write-down that
occurred in the second quarter of 2002. There is no current or deferred income
tax benefit for the U.S. net losses due 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.
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 new 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
new 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 2002 and
January 2003, we now have significantly 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
S-23
activities historically, we have not been able to fully replace the production
volumes lost from natural field declines and property sales.
Other events. On July 29, 2003 the Company acquired all of the shares of
the capital stock of Wind River Resources Corporation which owned an airplane.
The sole shareholder of Wind River was Robert Watson, Abraxas' Chairman of the
Board, President and Chief Executive Officer. The consideration for the purchase
was 106,977 shares of Abraxas common stock and $35,000 in cash. Simultaneously
with this transaction, the airplane was sold. The airplane had previously been
made available to Abraxas' employees for business use.
Working Capital. At June 30, 2003, we had current assets of $10.1 million
and current liabilities of $13.7 million resulting in a working capital deficit
of $3.6 million. This compares to a working capital deficit of $65.7 million at
December 31, 2002 and working capital deficit of $58.3 million at June 30, 2002.
Current liabilities at June 30, 2003 consisted of trade payables of $5.3
million, revenues due third parties of $3.3 million and accrued interest of $2.2
million related to our new notes and other accrued liabilities of $2.2 million.
After giving effect to the scheduled principal reductions required during 2003
under our new senior credit agreement we will have cash interest expense of
approximately $4.0 million. 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 2003, were $10.0 million compared to $23.8
million during the same period of 2002. The table below sets forth the
components of these capital expenditures on a historical basis for the six
months ended June 30, 2003 and 2002.
Six Months Ended
June 30
--------------------------------------------
2003 2002
---------------------- ---------------------
Expenditure category (in thousands):
Development................................................. $ 9,791 $ 23,699
Facilities and other........................................ 199 139
--------------- ---------------
Total................................................... $ 9,990 $ 23,838
=============== ===============
During the six months ended June 30, 2003 and 2002, capital expenditures
were primarily for the development of existing properties. For 2003, 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
$15 million for 2003, and 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.
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,
---------------------------------------
2003 2002
------------------ ---------------
Net cash (used) provided by operating activities $ 3,960 $ (1,796)
Net cash provided by (used) in investing activities 76,563 (831)
Net cash (used) provided by financing activities (83,607) 3,469
------------------ ---------------
Total $ (3,084) $ 842
================== ===============
Operating activities during the six months ended June 30, 2003 provided us
$4.0 million cash compared to using $1.8 million in the same period in 2002. Net
income plus non-cash expense items during 2003 and net changes in operating
assets and liabilities accounted for most of these funds. Financing activities
used $83.6 million for the first six months of 2003 compared to providing $3.5
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million for the same period of 2002. Most of these funds were used to reduce our
long-term debt and were generated by the sale of our Canadian subsidiaries and
the exchange offer completed in January 2003. Investing activities provided
$76.6 million for the six months ended June 30, 2003 compared to using $831,000
for the same period of 2002. The sale of our Canadian subsidiaries contributed
$86.6 million in 2003 reduced by $10.0 million in exploration and development
expenditures. Expenditures in 2002 were primarily for the development of crude
oil and natural gas properties.
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 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.
Our best opportunity for additional sources of liquidity and capital will be
through the issuance of equity securities or through the disposition of 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, 2003:
Payments due in:
Contractual Obligations
(dollars in thousands)
----------------------------- --------------------------------------------------------------------------
Total Less than More than 5
one year 1-3 years 3-5 years years
----------------------------- ------------- -------------- ------------- -------------- ----------------
Long-Term Debt (1) $ 230,638 $ - $ 46,394 $ 184,244 $ -
Operating Leases (2) 1,369 358 811 200 -
(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 April 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,
S-25
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
New Notes . In connection with the financial restructuring, Abraxas issued
$109.7 million in principal amount of it's 11 1/2% Secured Notes due 2007,
Series A, in exchange for the second lien notes and old notes tendered in the
exchange offer. The new notes were issued under an indenture with U.S. Bank, N.
A. senior secured credit agreement
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 new senior credit agreement or the intercreditor agreement between the
trustee under the indenture for the new notes and the lenders under the new
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,
Sandia Operating (a wholly-owned subsidiary of Sandia Oil & Gas), 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 new 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 new 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:
Period Percentage
From June 24, 2003 to January 23, 2004..................................91.4592%
From January 24, 2004 to June 23, 2004..................................97.1674%
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, 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
S-26
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 new senior credit agreement and, to the extent permitted by the
new senior credit agreement, the new notes or, if not permitted, paying
indebtedness under the new senior credit agreement.
The indenture also 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.
New 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. Subject
to earlier termination on the occurrence of events of default or other events,
the stated maturity date for both the term loan facility and the revolving
credit facility is January 22, 2006. In the event of an early termination, we
will be required to pay a prepayment premium, except in the limited
circumstances described in the new senior credit agreement. Outstanding amounts
under both facilities bear interest at the prime rate announced by Wells Fargo
Bank, N.A. plus 4.5%. Any amounts in default under the term loan facility will
accrue interest at an additional 4%. At no time will the amounts outstanding
under the new senior credit agreement bear interest at a rate less than 9%.
Term Loan Facility. Abraxas has borrowed $4.2 million pursuant to a term
loan facility at January 23, 2003, all of which was used to make cash payments
in connection with the financial restructuring. Accrued interest under the term
loan facility will be added to the principal amount of the term loan facility
until maturity.
Revolving Credit Facility. Lenders under the new senior credit agreement
have provided a revolving credit facility to Abraxas with a maximum borrowing
base of up to $50 million. Our current borrowing base under the revolving credit
facility is $48.0 million, subject to adjustments based on periodic calculations
and mandatory prepayments under the senior credit agreement. We have borrowed
$42.5 million under the revolving credit facility, all of which was used to make
cash payments in connection with the financial restructuring. We plan to use the
remaining borrowing availability under the new senior credit agreement to fund
our operations, including capital expenditures. As of June 30, 2003, the balance
of the facility was $40.7 million
Covenants. Under the new senior credit agreement, Abraxas is subject to
customary covenants and reporting requirements. Certain financial covenants
require Abraxas to maintain minimum levels of consolidated EBITDA (as defined in
the new senior credit agreement), minimum ratios of consolidated EBITDA to cash
interest expense and a limitation on annual capital expenditures. In addition,
at the end of each fiscal quarter, if the aggregate amount of our cash and cash
equivalents exceeds $2.0 million, we are required to repay the loans under the
new senior credit agreement in an amount equal to such excess. The new senior
credit agreement also requires us to enter into hedging agreements on not less
than 25% 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 new senior credit agreement.
In addition to the foregoing and other customary covenants, the new 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 any liens on any of our properties;
o enter into any change of control transactions;
o dispose of our assets;
o change our name or the nature of our business;
o make any guarantees with respect to the obligations of third
parties;
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o enter into any forward sales contracts;
o make any 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 new senior credit agreement
are 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 new senior credit
agreement are guaranteed by Sandia Oil & Gas, Sandia Operating, Wamsutter, New
Grey Wolf, Western Associated Energy and Eastside Coal. The guarantees under the
new senior credit agreement are 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 new 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 swaps, options and other commodity derivative
instruments. Under the new senior credit agreement, we are required to maintain
hedge positions on not less than 25% or more than 75% of our projected oil and
gas production for a six month rolling period. On January 23, 2003, we entered
into a collar option agreement with respect to 5,000 MMBtu per day, or
approximately 25% of our production, at a call price of $6.25 per MMBtu and a
put price of $4.00 per MMBtu, for the calendar months of February through July
2003. In February 2003, we entered into a second hedge agreement related to
5,000 MMBtu for the calendar months of March 2003 through February 2004 which
provides for a floor price of $4.50 per MMBtu.
Net Operating Loss Carryforwards.
At December 31, 2002 the Company had, subject to the limitation discussed
below, $167.1 million of net operating loss carryforwards for U.S. tax purposes.
These loss carryforwards will expire from 2003 through 2022 if not utilized. At
December 31, 2002, the Company had approximately $1.0 million of net operating
loss carryforwards for Canadian tax purposes. These carryforwards will expire
from 2003 through 2009 if not utilized. In connection with January 2003
financial transactions, certain of the loss carryforwards may be utilized.
As a result of the acquisition of certain partnership interests and crude
oil and natural gas properties in 1990 and 1991, an ownership change under
Section 382 occurred in December 1991. Accordingly, it is expected that the use
of the U.S. net operating loss carryforwards generated prior to December 31,
1991 of $3,203,000 will be limited to approximately $235,000 per year.
During 1992, the Company acquired 100% of the common stock of an unrelated
corporation. The use of net operating loss carryforwards of the acquired
corporation of $257,000 acquired in the acquisition are limited to approximately
$115,000 per year.
As a result of the issuance of additional shares of common stock for
acquisitions and sales of common stock, an additional ownership change under
Section 382 occurred in October 1993. Accordingly, it is expected that the use
of all U.S. net operating loss carryforwards generated through October 1993
(including those subject to the 1991 and 1992 ownership changes discussed above)
of $6,590,000 will be limited as described above and in the following paragraph.
An ownership change under Section 382 occurred in December 1999, following
the issuance of additional shares., It is expected that the annual use of U.S.
net operating loss carryforwards subject to this Section 382 limitation will be
limited to approximately $363,000, subject to the lower limitations described
above. Future changes in ownership may further limit the use of the Company's
carryforwards. In 2000 assets with built-in gains were sold, increasing the
Section 382 limitation for 2001 by approximately $31,000,000.
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The annual Section 382 limitation may be increased during any year, within
5 years of a change in ownership, in which built-in gains that existed on the
date of the change in ownership are recognized.
In addition to the Section 382 limitations, 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 $39.7 million and $99.1 million for deferred tax assets
at December 31, 2001 and 2002, respectively.
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, 2003 , 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 $2.1 million for the period.
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.
Currently, we use only cash flow hedges and the remaining discussion will relate
exclusively to this type of derivative instrument. If the derivative qualifies
for hedge accounting, the gain or loss on the derivative is deferred in other
comprehensive income (loss), a component of stockholders' equity, to the extent
that the hedge is effective.
The relationship between the hedging instrument and the hedged item must be
highly effective in achieving the offset of changes in cash flows attributable
to the hedged risk both at the inception of the contract and on an ongoing
basis. Hedge accounting is discontinued prospectively when a hedge instrument
becomes ineffective. Gains and losses deferred in accumulated other
comprehensive income (loss) related to a cash flow hedge that becomes
ineffective, remain unchanged until the related production is delivered. If we
determine that it is probable that a hedged transaction will not occur, deferred
gains or losses on the hedging instrument are recognized in earnings
immediately.
Gains and losses on hedging instruments related to accumulated other
comprehensive income and adjustments to carrying amounts on hedged production
are included in natural gas or crude oil production revenue in the period that
the related production is delivered.
Under the terms of the new senior credit agreement, we are required to
maintain hedging positions with respect to not less than 25% nor more than 75%
of our crude oil and natural gas production for a rolling six month period. On
January 23, 2003, we entered into a collar option agreement with respect to
5,000 MMBtu per day, or approximately 25% of our production, at a call price of
$6.25 per MMBtu and a put price of $4.00 per MMBtu. In February of 2003 we
entered into an additional hedge agreement for 5,000 MMBtu per day with a floor
of $4.50 per MMBtu. For Abraxas, the fair value of the hedging instrument was
determined based on the base price of the hedged item and NYMEX forward price
quotes.
The following table sets forth the Company's hedge position as of June 30,
2003:
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Time Period Notional Quantities Price Fair Value
---------------------------------------- ------------------------------ ------------------------------ ----------------
February 1, 2003--July 31, 2003 5,000 MMBtu of production Collar with floor of $4.00 $ -
per day and ceiling of $6.25
March 1, 2003 - February 29, 2004 5,000 MMBtu of production Floor of $4.50 $ 139,617
per day
All hedge transactions are subject to our risk management policy, which has
been approved by the Board of Directors. We formally document all relationships
between hedging instruments and hedged items, as well as our risk management
objectives and strategy for undertaking the hedge. This process includes
specific identification of the hedging instrument and the hedged transaction,
the nature of the risk being hedged and how the hedging instrument's
effectiveness will be assessed. Both at the inception of the hedge and on an
ongoing basis, we assess whether the derivatives that are used in hedging
transactions are highly effective in offsetting changes in cash flows of hedged
items.
Interest rate risk
As a result of the financial restructuring that occurred in January 2003,
at June 30, 2003 we have $45.0 million in outstanding indebtedness under the new
senior credit agreement, accruing interest at a rate of prime plus 4.5%, subject
to a minimum interest rate of 9.0%. In the event that the prime rate (currently
1.5%) rises above 4.5% the interest rate applicable to our outstanding
indebtedness under the new senior credit agreement will rise accordingly. For
every percentage point that the prime rate rises above 4.5%, our interest
expense would increase by approximately $450,000 on an annual basis. Our new
notes accrue interest at fixed rates and is accordingly not subject to
fluctuations in market rates.
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 $1.8 million for the six months ended
June 30, 2003. 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
$90,000. 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.
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