UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One) FORM 10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarter Ended June 30, 2002
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 0-19118
ABRAXAS PETROLEUM CORPORATION
----------------------------------------------------------------------
(Exact name of Registrant as specified in its charter)
Nevada 74-2584033
-------------- -----------------
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization Identification Number)
500 N. Loop 1604, East, Suite 100, San Antonio, Texas 78232
(Address of Principal Executive Offices) (Zip Code)
Registrant's telephone number, including area code
(210) 490-4788
--------------
Not Applicable
(Former name, former address and former fiscal year,
if changed since last report)
- -----------------------------------------------------------------------------
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or such shorter period that the restraint
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X or No __
The number of shares of the issuer's common stock outstanding as of August
14, 2002 was:
Class Shares Outstanding
Common Stock, $.01 Par Value 29,979,397
1 of 42
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
FORM 10 - Q
INDEX
PART I
FINANCIAL INFORMATION
ITEM 1 - Financial Statements (Unaudited)
Consolidated Balance Sheets - June 30, 2002
and December 31, 2001.......................................3
Consolidated Statements of Operations -
Three and Six Months Ended June 30, 2002 and 2001...........5
Consolidated Statement of Stockholders'Equity (Deficit)
Six months ended June 30, 2002..............................6
Consolidated Statements of Cash Flows -
Six Months Ended June 30, 2002 and 2001.....................7
Notes to Consolidated Financial Statements............................8
ITEM 2 - Managements Discussion and Analysis of Financial Condition and
Results of Operations......................................23
ITEM 3 - Quantitative and Qualitative Disclosure about Market Risks...........36
PART II
OTHER INFORMATION
ITEM 1 - Legal proceedings 39
ITEM 2 - Changes in Securities................................................39
ITEM 3 - Defaults Upon Senior Securities......................................39
ITEM 4 - Submission of Matters to a Vote of Security Holders..................39
ITEM 5 - Other Information 39
ITEM 6 - Exhibits and Reports on Form 8-K.....................................39
Signatures ...................................................40
Abraxas Petroleum Corporation and Subsidiaries
Part 1- Financial Information
Item 1 - Financial Statements
Consolidated Balance Sheets
(Unaudited)
June 30 December 31,
2002 2001
-------- --------
(In Thousands)
Assets:
Current assets:
Cash ................................................. $ 6,837 $ 7,605
Restricted cash ...................................... 9,895 --
Accounts receivable, less allowances for doubtful
accounts:
Joint owners .................................. 2,250 2,785
Oil and gas production ........................ 4,888 4,758
Other ......................................... 1,480 504
-------- --------
8,618 8,047
Equipment inventory ................................... 1,129 1,251
Other current assets .................................. 817 443
-------- --------
Total current assets ................................ 27,296 17,346
Property and equipment:
Oil and gas properties, full cost method of accounting:
Proved ............................................ 519,824 486,098
Unproved, not subject to amortization ............. 6,375 10,626
Other property and equipment ......................... 42,950 67,632
-------- --------
Total ........................................ 569,149 564,356
Less accumulated depreciation, depletion, and
amortization .................................... 420,090 282,462
-------- --------
Total property and equipment - net ................ 149,059 281,894
Deferred financing fees, net of accumulated
amortization of$9,526 and $8,668 at June 30,
2002 and December 31, 2001, respectively .............. 3,077 3,928
rred income taxes ....................................... 8,618 --
Other assets ............................................ 447 448
-------- --------
Total assets .......................................... $188,497 $303,616
======== ========
See accompanying notes to consolidated financial statements
3
Abraxas Petroleum Corporation and Subsidiaries
Part 1- Financial Information
Item 1 - Financial Statements
Consolidated Balance Sheets (continued)
(Unaudited)
June 30, December 31,
2002 2001
--------- ---------
(In Thousands)
Liabilities and Stockholder's Equity (Deficit)
Current liabilities:
Accounts payable ............................................ $ 7,723 $ 10,542
Oil and gas production payable .............................. 3,421 3,596
Accrued interest ............................................ 5,921 6,013
Other accrued expenses ...................................... 3,307 1,116
Hedge liability ............................................. 1,727 658
Current maturities of long-term debt ........................ 63,500 415
--------- ---------
Total current liabilities ......................... 85,599 22,340
Long-term debt ................................................ 227,297 285,184
Deferred income taxes ......................................... -- 20,621
Future site restoration ....................................... 4,244 4,056
Stockholders' equity (deficit):
Common Stock, par value $.01 per share-
Authorized 200,000,000 shares; issued, 30,145,280 at June 30,
2002 and December 31, 2001 ................................. 301 301
Additional paid-in capital ................................. 136,830 136,830
Accumulated deficit ......................................... (255,483) (151,094)
Receivables from stock sales ................................ (97) (97)
Treasury stock, at cost, 165,883 shares ..................... (964) (964)
Accumulated other comprehensive loss ........................ (9,230) (13,561)
--------- ---------
Total stockholders' deficit ............................. (128,643) (28,585)
--------- ---------
Total liabilities and shareholders' equity (deficit) .......... $ 188,497 $ 303,616
========= =========
See accompanying notes to consolidated financial statements
4
Abraxas Petroleum Corporation and Subsidiaries
Consolidated Statements of Operations
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ----------------------
2002 2001 2002 2001
--------- --------- --------- ---------
(In thousands except per share data)
Revenue:
Oil and gas production revenues ................ $ 13,143 $ 20,127 $ 24,029 $ 48,376
Gas processing revenues ........................ 741 498 1,411 934
Rig revenues ................................... 193 225 344 408
Other .......................................... 158 266 258 484
--------- --------- --------- ---------
14,235 21,116 26,042 50,202
Operating costs and expenses:
Lease operating and production taxes ........... 3,353 4,332 7,262 9,191
Depreciation, depletion, and amortization ...... 9,110 8,288 15,924 17,129
Proved property impairment ..................... 115,995 -- 115,995 --
Rig operations ................................. 175 191 296 344
General and administrative ..................... 1,481 1,575 3,179 3,684
General and administrative (Stock-based
compensation) ................................ -- (2,332) -- (1,401)
--------- --------- --------- ---------
130,114 12,054 142,656 28,947
--------- --------- --------- ---------
Operating income (loss) ........................... (115,879) 9,062 (116,614) 21,255
Other (income) expense:
Interest income ................................ (8) (12) (41) (28)
Amortization of deferred financing fee ......... 431 455 858 910
Interest expense ............................... 8,761 7,829 17,174 15,610
Other expense .................................. -- -- -- 16
--------- --------- --------- ---------
9,184 8,272 17,991 16,508
--------- --------- --------- ---------
Net income (loss) from operations before taxes .... (125,063) 790 (134,605) 4,747
Income tax expense (benefit) ...................... (29,373) 1,509 (30,216) 4,285
Minority interest in income of consolidated foreign
subsidiary ..................................... -- 555 -- 1,481
--------- --------- --------- ---------
Net loss .......................................... $ (95,690) $ (1,274) $(104,389) $ (1,019)
========= ========= ========= =========
Loss per common share:
Net loss per common share - basic and diluted . $ (3.19) $ (0.05) $ (3.48) $ (0.04)
========= ========= ========= =========
See accompanying notes to consolidated financial statements
5
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)
(Unaudited)
(In thousands except share amounts)
Accumulated Receiv-
Other ables
Common Stock Treasury Stock Additional Accumu- Compre- from
------------------- ---------------- Paid-In lated hensive Stock
Shares Amount Shares Amount Capital Deficit Income(Loss) Sale Total
----------- ------- ------- -------- ----------- ---------- ------------- -------- --------
Balance at December 31, 2001.........30,145,280 $ 301 165,883 $ (964) $ 136,830 $(151,094) $ (13,561) $ (97) $ (28,585)
Comprehensive income (loss) - Note 10
Net loss........................... - - - - - (104,389) - - (104,389)
Other comprehensive income:
Hedge loss....................... - - - - - - (825) - (825)
Foreign currency translation
adjustment.................... - - - - - - 5,156 - 5,156
-------
Comprehensive income (loss)... - - - - - - - - (100,058)
----------- ------- ------- -------- ----------- --------- ---------- --------- -------
Balance at June 30, 2002............30,145,280 $ 301 165,883 $ (964) $ 136,830 $ (255,483) $ (9,230) $ (97 ) $(128,643)
=========== ======= ======= ======== =========== ========= ========== ========= =======
See accompanying notes to consolidated financial statements
6
Abraxas Petroleum Corporation and Subsidiaries
Consolidated Statements of Cash Flows
(Unaudited)
Six Months Ended
June 30,
-----------------------
2002 2001
---------- ----------
(In thousands)
Operating Activities
Net loss ................................................ $(104,389) $ (1,019)
Adjustments to reconcile net income to net
cash provided by operating activities:
Minority interest in income of foreign subsidiary ...... -- 1,481
Depreciation, depletion, and amortization .............. 15,924 17,129
Proved property impairment ............................. 115,995 --
Deferred income tax (benefit) expense .................. (30,216) 3,639
Amortization of deferred financing fees ................ 858 909
Amortization of debt discount .......................... 230 --
Stock-based compensation ............................... -- (1,401)
Changes in operating assets and liabilities:
Accounts receivable ................................ (453) 10,307
Equipment inventory ................................ 131 (98)
Other .............................................. (157) (1,099)
Accounts payable and accrued expenses .............. 281 (13,442)
--------- ---------
Net cash provided (used in) by operating activities ..... (1,796) 16,406
--------- ---------
Investing Activities
Capital expenditures, including purchases and development
of properties ......................................... (23,838) (30,433)
Proceeds from sale of oil and gas producing properties... 32,902 9,695
Increase in restricted cash ............................. (9,895) --
--------- ---------
Net cash used in investing activities ................... $ (831) $ (20,738)
--------- ---------
Financing Activities
Proceeds from long-term borrowings ...................... 11,614 11,316
Payments on long-term borrowings ........................ (8,145) (6,188)
Deferred financing fees ................................. -- (10)
Exercise of stock options ............................... -- 16
Other ................................................... -- 183
--------- ---------
Net cash provided by financing activities ............... 3,469 5,317
--------- ---------
Effect of exchange rate changes on cash ................. (1,610) 24
--------- ---------
Increase (decrease) in cash ............................. (768) 1,009
Cash, at beginning of period ............................ 7,605 2,004
--------- ---------
Cash, at end of period .................................. $ 6,837 $ 3,013
========= =========
Supplemental disclosures of cash flow information:
Interest paid ........................................... $ 17,036 $ 15,702
========= =========
Taxes paid .............................................. $ -- $ 505
========= =========
See accompanying notes to consolidated financial statements
7
Abraxas Petroleum Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Unaudited)
June 30, 2002
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 consolidated financial statements in the Annual Report on Form
10-K filed for the year ended December 31, 2001. Such policies have been
continued without change. Also, refer to the notes to those financial statements
for additional details of the Company's financial condition, results of
operations, and cash flows. All the material items included in those notes have
not changed except as a result of normal transactions in the interim, or as
disclosed within this report. The accompanying interim consolidated financial
statements have not been audited by independent accountants, but in the opinion
of management, reflect all adjustments necessary for a fair presentation of the
financial position and results of operations. Any and all adjustments are of a
normal and recurring nature. The results of operations for the three and six
months ended June 30, 2002 are not necessarily indicative of results to be
expected for the full year.
The consolidated financial statements include the accounts of the Company,
its wholly-owned foreign subsidiaries, Canadian Abraxas Petroleum Limited
("Canadian Abraxas") and Grey Wolf Exploration Inc. ("Grey Wolf"). Minority
interest in 2001 represents the minority shareholders' proportionate share of
the equity and income of Grey Wolf prior to the Company's acquiring the
remaining interest in September 2001.
Canadian Abraxas' and 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.
Certain prior years balances have been reclassified for comparative
purposes.
Note 2. Business Conditions and Liquidity Requirements
The accompanying consolidated financial statements have been prepared on a
going concern basis, which contemplates the realization of assets and the
satisfaction of liabilities in the normal course of business. The Company has
experienced net losses from operations before taxes during the six months ended
June 30, 2002, of $134.6 million due primarily to proved property impairments of
$116 million resulting primarily from volatile commodity prices - See note 11.
At June 30, 2002, the Company's current liabilities of approximately $85.6
million exceeded current assets of $27.3 million resulting in a working capital
deficit of $58.3 million. The Company also had a stockholders' deficit of $128.6
million. The Company's principal sources of liquidity are cash on hand, cash
flow from operations and proceeds from sales of assets and properties, in
addition to funding remaining available under the Grey Wolf credit facility with
Mirant Canada.
The Company's continued existence as a going concern is dependent upon
several factors. The Company will need additional funds in the future for both
the development of its assets and the service of its debt, including the
repayment of the $63.5 million in principal amount of the First Lien Notes
maturing in March 2003 and the $191 million of the Second Lien Notes and Old
Notes maturing in November 2004. In order to meet the goals of developing its
assets and servicing its debt obligations, the Company will be required to
obtain additional sources of liquidity and capital and/or reduce or reschedule
its existing cash requirements including repayment of the First Lien Note. In
order to do so, the Company may pursue one or more of the following
alternatives:
o refinancing existing debt;
o repaying debt with proceeds from the sale of assets;
o exchanging debt for equity;
o managing the timing and reducing the scope of its capital
expenditures;
o issuing debt or equity securities or otherwise raising additional
funds; or
o selling all or a portion of its existing assets, including
interests in its assets.
Due to our current debt levels and the restrictions contained in the
indentures governing the First Lien Notes, Second Lien Notes and Old Notes, our
best opportunity for additional sources of liquidity and capital will be through
the disposition of assets and some of the other alternatives discussed above.
There can be no assurance that any of the above alternatives, or some
combination thereof, will be available or, if available, will be on terms
acceptable to us or that such efforts will produce enough cash to fund the
8
Company's operating and capital requirements or make interest payments and
principal payments due on the First Lien Notes, Second Lien Notes and Old Notes.
In order to meet its need for additional funds, the Company is exploring
strategic opportunities through the establishment of a Planning Committee of the
Board of Directors. The Planning Committee has engaged an investment banking
firm to assist with a strategic review and to formulate a proposed plan of
action for consideration by the Board of Directors. Because the Planning
Committee is currently conducting its review and formulation of a proposed plan
of action, of the Company cannot assess the likelihood that it can effectively
implement any such proposed plan of action. Regardless of the outcome of the
strategic review, a refinancing of the Company's existing debt and the sale of
additional properties likely will be required for the Company to meet its
liquidity and capital requirements. Management believes that the Company can
implement a successful plan of action to improve its liquidity and capital
requirements. However, management cannot give any assurances that such actions
will result in the Company being able to continue as a going concern. The June
30, 2002 financial statements do not include any adjustments that might result
from the outcome of these uncertainties.
Note 3. Divestiture of Assets
In May of 2002, the wholly owned Canadian subsidiaries, Grey Wolf and
Canadian Abraxas, sold their interest in a natural gas processing plant and
associated crude oil and natural gas reserves in the Quirk Creek and Mahaska
fields in Alberta, Canada for approximately $22.9 million.
In June 2002, Abraxas sold its interest in the East White Point field in
South Texas for approximately $9.8 million.
The condensed pro forma financial information presented below summarizes on
an pro forma basis, approximate results of the Company's consolidated results of
operations for the three and six months ended June 30, 2002, assuming the
divestiture had occurred on January 1, 2002, and the three and six months ended
June 30, 2001, assuming the divestiture had occurred on January 1, 2001.
Additionally, the pro forma information reflects an interest savings assuming
that the Company had applied a portion of the proceeds to reacquire the
Production Payment (see Note 4) on January 1st of the respective years.
--------------------------------------------------------
Three Months Ended June 30, Six Months Ended June 30,
--------------------------------------------------------
2002 2001 2002 2001
--------------------------------------------------------
(in thousands, except per share data)
---------- ----------- --------------- --------
Revenue ............... $ 12,899 $ 17,781 $ 23,107 $ 41,833
========== =========== =============== ========
Net loss .............. $ (95,552) $ (2,547) $ (104,185) $ (4,838)
========== =========== =============== ========
Loss per common
share--basic and
diluted ........ $ (3.19) $ (0.11) $ (3.48) $ (0.21)
========== =========== =============== ========
In July 2002, Canadian Abraxas and Grey Wolf sold their interest in the
Millarville field in Alberta, Canada for approximately $1.1 million.
Proceeds from these property sales were deposited at the Trustee for the
First Lien Notes, to be held as restricted cash until disbursement to the
Company under terms permitted by the appropriate indenture, or if not disbursed
in accordance with the indenture within 180 days of receipt, to be applied
against the outstanding First Lien Notes. As of June 30, 2002, approximately
$9.8 million of these proceeds remained in the Trustee's account and available
to the Company under the terms of the indenture. The other portion of the
proceeds were used in accordance with the indentures, including reacquiring the
Production Payment (See Note 4).
Note 4. Long-Term Debt
Long-term debt consists of the following:
June 30 December 31
-------------------
2002 2001
-------- --------
(In thousands)
11.5% Senior Notes due 2004 ("Old Notes") ........................... $ 801 $ 801
12.875% Senior Secured Notes due 2003 ("First Lien Notes") .......... 63,500 63,500
11.5% Second Lien Notes due 2004 ("Second Lien Notes") .............. 190,178 190,178
9
9.5% Senior Credit Facility ("Grey Wolf Facility"), providing for
borrowings up to approximately US $96 million (CDN $150 million)
and secured by the assets of Grey Wolf and non-recourse to
Abraxas, net of US $2.1 and $2.3 million discount at June 30,
2002 and December 31, 2001, respectively ....................... 36,318 22,944
Production Payment .................................................. -- 8,176
-------- --------
290,797 285,599
Less current maturities First Lien Notes ............................ 63,500 415
-------- --------
$227,297 $285,184
======== ========
Old Notes. On November 14, 1996, the Company consummated the offering of
$215.0 million of its 11.5% Senior Notes due 2004, Series A, which were
exchanged for the Series B Notes in February 1997. On January 27, 1998, the
Company completed the sale of $60.0 million of its 11.5% Senior Notes due 2004,
Series C. The Series B Notes and the Series C Notes were subsequently combined
into $275.0 million in principal amount of the Old Notes in June 1998. In
December 1999, Abraxas and Canadian Abraxas completed an exchange offer which
reduced the amount of outstanding Old Notes to $801,000. See the description of
the Second Lien Notes below for more information.
Interest on the Old Notes is payable semi-annually in arrears on May 1 and
November 1 of each year at the rate of 11.5% per annum. The Old Notes are
redeemable, in whole or in part, at the option of the Company at the redemption
prices set forth below, plus accrued and unpaid interest to the date of
redemption, if redeemed during the 12-month period commencing on November 1 of
the years set forth below:
Year Percentage
---- ----------
2001.................................... 102.875%
2002 and thereafter..................... 100.000%
The Old Notes are joint and several obligations of Abraxas and Canadian
Abraxas and rank pari passu in right of payment to all existing and future
unsubordinated indebtedness of Abraxas and Canadian Abraxas. The Old Notes rank
senior in right of payment to all future subordinated indebtedness of Abraxas
and Canadian Abraxas. The Old Notes are, however, effectively subordinated to
the First Lien Notes to the extent of the value of the collateral securing the
First Lien Notes and to the Second Lien Notes to the extent of the value of the
collateral securing the Second Lien Notes. The Old Notes are unconditionally
guaranteed, on a senior basis by Sandia Oil and Gas Company ("Sandia"), a wholly
owned subsidiary of the Company. The guarantee is a general unsecured obligation
of Sandia and ranks pari passu in right of payment to all unsubordinated
indebtedness of Sandia and senior in right of payment to all subordinated
indebtedness of Sandia. The guarantee is effectively subordinated to the First
Lien Notes and the Second Lien Notes to the extent of the value of the
collateral securing the First Lien Notes and the Second Lien Notes.
Upon a Change of Control, as defined in the Old Notes Indenture, each
holder of the Old Notes will have the right to require the Company to repurchase
all or a portion of such holder's Old Notes at a redemption price equal to 101%
of the principal amount thereof, plus accrued and unpaid interest to the date of
repurchase. In addition, the Company will be obligated to offer to repurchase
the Old Notes at 100% of the principal amount thereof plus accrued and unpaid
interest to the date of repurchase in the event of certain asset sales.
First Lien Notes. In March 1999, Abraxas consummated the sale of $63.5
million of the First Lien Notes. Interest on the First Lien Notes is payable
semi-annually in arrears on March 15 and September 15, commencing September 15,
1999. Beginning March 15, 2002, the First Lien Notes are redeemable, in whole or
in part, at the option of Abraxas at 100% of the principal amount thereof, plus
accrued and unpaid interest to the date of redemption.
The First Lien Notes are senior indebtedness of Abraxas secured by a first
lien on substantially all of the crude oil and natural gas properties of Abraxas
and the shares of Grey Wolf owned by Abraxas. The First Lien Notes are
unconditionally guaranteed on a senior basis, jointly and severally, by Canadian
Abraxas, Sandia and Wamsutter, wholly-owned subsidiaries of the Company (the
"Restricted Subsidiaries"). The guarantees are secured by substantially all of
the crude oil and natural gas properties of the guarantors and the shares of
Grey Wolf owned by Abraxas and Canadian Abraxas.
Upon a Change of Control, as defined in the First Lien Notes Indenture,
each holder of the First Lien Notes will have the right to require Abraxas to
repurchase such holder's First Lien Notes at a redemption price equal to 101% of
10
the principal amount thereof plus accrued and unpaid interest to the date of
repurchase. In addition, Abraxas will be obligated to offer to repurchase the
First Lien Notes at 100% of the principal amount thereof plus accrued and unpaid
interest to the date of redemption in the event of certain asset sales.
The First Lien Notes indenture contains certain covenants that limit the
ability of Abraxas and certain of its subsidiaries, including the guarantors of
the First Lien Notes to, among other things, incur additional indebtedness, pay
dividends or make certain other restricted payments, consummate certain asset
sales, enter into certain transactions with affiliates, incur liens, merge or
consolidate with any other person or sell, assign, transfer, lease, convey or
otherwise dispose of all or substantially all of the assets of Abraxas.
The First Lien Notes indenture provides, among other things, that Abraxas
may not, and may not cause or permit the Restricted Subsidiaries, to, directly
or indirectly, create or otherwise cause to permit to exist or become effective
any encumbrance or restriction on the ability of such subsidiary to pay
dividends or make distributions on or in respect of its capital stock, make
loans or advances or pay debts owed to Abraxas or any other Restricted
Subsidiary, guarantee any indebtedness of Abraxas or any other Restricted
Subsidiary or transfer any of its assets to Abraxas or any other Restricted
Subsidiary except in certain situations as described in the First Lien Notes
indenture.
Second Lien Notes. In December 1999, Abraxas and Canadian Abraxas
consummated an exchange offer whereby $269,699,000 of the Old Notes were
exchanged for $188,778,000 of the Second Lien Notes, and 16,078,990 shares of
Abraxas common stock and contingent value rights. An additional $5,000,000 of
the Second Lien Notes were issued in payment of fees and expenses.
Interest on the Second Lien Notes is payable semi-annually in arrears on
May 1 and November 1, commencing May 1, 2000. The Second Lien Notes are
redeemable, in whole or in part, at the option of Abraxas and Canadian Abraxas
at the redemption prices set forth below, plus accrued and unpaid interest to
the date of redemption, if redeemed during the 12-month period commencing on
December 1 of the years set forth below:
Year Percentage
----- ----------
2001.................................... 102.875%
2002 and thereafter..................... 100.000%
The Second Lien Notes are senior indebtedness of Abraxas and Canadian
Abraxas and are secured by a second lien on substantially all of the crude oil
and natural gas properties of Abraxas and Canadian Abraxas and the shares of
Grey Wolf owned by Abraxas and Canadian Abraxas. The Second Lien Notes are
unconditionally guaranteed on a senior basis, jointly and severally, by Sandia
and Wamsutter. The guarantees are secured by substantially all of the crude oil
and natural gas properties of the guarantors. The Second Lien Notes are,
however, effectively subordinated to the First Lien Notes and related guarantees
to the extent the value of the collateral securing the Second Lien Notes and
related guarantees and the First Lien Notes and related guarantees is
insufficient to pay both the Second Lien Notes and the First Lien Notes.
Upon a Change of Control, as defined in the Second Lien Notes Indenture,
each holder of the Second Lien Notes will have the right to require Abraxas and
Canadian Abraxas to repurchase such holder's Second Lien Notes at a redemption
price equal to 101% of the principal amount thereof plus accrued and unpaid
interest to the date of repurchase. In addition, Abraxas and Canadian Abraxas
will be obligated to offer to repurchase the Second Lien Notes at 100% of the
principal amount thereof plus accrued and unpaid interest to the date of
redemption in the event of certain asset sales.
The Second Lien Notes indenture contains certain covenants that limit the
ability of Abraxas and Canadian Abraxas and certain of their subsidiaries,
including the guarantors of the Second Lien Notes (the "Restricted
Subsidiaries") to, among other things, incur additional indebtedness, pay
dividends or make certain other restricted payments, consummate certain asset
sales, enter into certain transactions with affiliates, incur liens, merge or
consolidate with any other person or sell, assign, transfer, lease, convey or
otherwise dispose of all or substantially all of the assets of Abraxas or
Canadian Abraxas.
The Second Lien Notes indenture provides, among other things, that Abraxas
and Canadian Abraxas may not, and may not cause or permit the Restricted
Subsidiaries, to, directly or indirectly, create or otherwise cause to permit to
exist or become effective any encumbrance or restriction on the ability of such
subsidiary to pay dividends or make distributions on or in respect of its
capital stock, make loans or advances or pay debts owed to Abraxas, Canadian
Abraxas or any other Restricted Subsidiary, guarantee any indebtedness of
Abraxas, Canadian Abraxas or any other Restricted Subsidiary or transfer any of
its assets to Abraxas, Canadian Abraxas or any other Restricted Subsidiary
except in certain situations as described in the Second Lien Notes indenture.
11
The fair value of the Old Notes, First Lien Notes and Second Lien Notes was
approximately $168.6 million as of June 30, 2002. The Company has approximately
$325,000 of standby letters of credit and a $10,000 performance bond open at
June 30, 2002. Approximately $336,000 of cash is restricted and in escrow
related to certain of the letters of credit and the bond.
Grey Wolf Facility
General. On December 20, 2001, Grey Wolf entered into a credit facility
with Mirant Canada Energy Capital, Ltd. ("Mirant Canada"). The Grey Wolf
Facility established a revolving credit facility with a commitment amount of CDN
$150 million, (approximately US $96 million). Subject to certain restrictions,
the borrowing base may be reduced at the discretion of Mirant Canada upon 30
days written notice. Subject to earlier termination on the occurrence of events
of default or other events, the stated maturity date is December 20, 2007. The
applicable interest rate charged on the outstanding balance under the Grey Wolf
Facility is 9.5%. Any amounts in default will accrue interest at 15%. The Grey
Wolf Facility is non-recourse to Abraxas and its properties, other than Grey
Wolf properties, and Abraxas has no additional direct obligations to Mirant
Canada under the facility.
Principal Payments. Prior to maturity, Grey Wolf is required to make
principal payments under the Grey Wolf Facility as follows: (i) on the date of
the sale of any of its producing properties, Grey Wolf is required to make a
payment equal to the amount of the net sales proceeds; (ii) on a monthly basis,
Grey Wolf is required to make a payment equal to its net cash flow for the month
prior to the date of the payment; and (iii) on the date that any reduction in
the commitment amount becomes effective, Grey Wolf must repay all amounts over
the commitment amount so reduced.
Under the Grey Wolf Facility, "net cash flow" generally means the amount of
proceeds received by Grey Wolf from the sale of hydrocarbons less taxes, royalty
and similar payments (including overriding royalty interest payments made to
Mirant Canada), interest payments made to Mirant Canada and operating and other
expenses including approved capital and G&A expenses.
Grey Wolf may also make pre-payments at any time after December 20, 2002
with no pre-payment penalty.
The Company treats the Grey Wolf Facility as a revolving line of credit
since, under ordinary circumstances, the lender is paid on a net cash flow
basis. It is anticipated that the Company will be a net borrower for the next
several years due to a large number of exploration and exploitation projects and
the associated capital needs to complete the projects.
Security. Obligations under the Grey Wolf Facility are secured by a
security interest in substantially all of Grey Wolf's assets, including, without
limitation, working interests in producing properties and related assets owned
by Grey Wolf. None of Abraxas' assets are subject to a security interest under
the Grey Wolf Facility.
Covenants. The Grey Wolf Facility contains a number of covenants that,
among other things, restrict the ability of Grey Wolf to (i) enter into new
business areas, (ii) incur additional indebtedness, (iii) create or permit to be
created any liens on any of its properties, (iv) make certain payments,
dividends and distributions, (v) make any unapproved capital expenditures, (vi)
sell any of its accounts receivable, (vii) enter into any unapproved leasing
arrangements, (viii) enter into any take-or-pay contracts, (ix) liquidate,
dissolve, consolidate with or merge into any other entity, (x) dispose of its
assets, (xi) abandon any property subject to Mirant Canada's security interest,
(xii) modify any of its operating agreements, (xiii) enter into any unapproved
hedging agreements, and (xiv) enter into any new agreements affecting existing
agreements relating to or affecting properties subject to Mirant Canada's
security interests. In addition, Grey Wolf is required to submit a quarterly
development plan for Mirant Canada's approval and Grey Wolf must comply with
specified financial ratios and tests, including a minimum collateral coverage
ratio. Grey Wolf was in compliance with these covenants at June 30, 2002.
Upon receipt by the Company of a written request from Mirant Canada, the
Company shall promptly, and in any event within 10 days of receipt of such
request, have entered into one or more swap, hedge, floor, collar or similar
agreements which are satisfactory to the lender at a price and for a term which
is mutually acceptable to the Company and Mirant Canada.
Events of Default. The Grey Wolf 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 the financial condition of Grey Wolf.
12
Overriding Royalty Interests. As a condition to the Grey Wolf Facility,
Grey Wolf has granted two overriding royalty interests to Mirant Canada, each in
the amount of 2.5% of the revenues received by Grey Wolf from oil and gas sales
from all of its properties. These overriding royalty interest resulted in the
recording of a $2.3 million discount on the Grey Wolf Facility borrowings at
December 31, 2001.
Production Payment
In October 1999 the Company entered into a non-recourse Dollar Denominated
Production Payment agreement (the "Production Payment") with a third party. The
Production Payment has an aggregate total availability of up to $50 million at
15% interest. The Production Payment relates to a portion of the production from
several natural gas wells in South Texas. The Company reacquired the Production
Payment in June 2002, for approximately $6.8 million.
Note 5. 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,
----------------------------- -----------------------------
2002 2001 2002 2001
------------- -------------- ------------- ------------
Numerator:
Net income (loss) from continuing operations $ (95,690) $ (1,274) $ (104,389) $ (1,019)
------------ ------------ ------------ ------------
Denominator:
Denominator for basic earnings per share -
Weighted-average shares .................... 29,979,397 23,616,197 29,979,397 23,106,111
Effect of dilutive securities:
Stock options, warrants and CVR's .......... -- -- -- --
------------ ------------ ------------ ------------
Dilutive potential common shares Denominator
for diluted earnings per share -
adjusted weighted-average shares and assumed
Conversions ................................ 29,979,397 23,616,197 29,979,397 23,106,111
Basic earnings (loss) per share:
Income (loss) from continuing operations ... $ (3.19) $ (0.05) $ (3.48) $ (0.04)
============ ============ ============ ============
Diluted earnings (loss) per share:
Income (loss) from continuing operations ... $ (3.19) $ (0.05) $ (3.48) $ (0.04)
============ ============ ============ ============
For the three 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 210 shares and 17,243 shares for the three and six months ended June
30, 2002, respectively.
Contingent Value Rights ("CVRs")
As part of the exchange offer consummated by the Company in December 1999,
Abraxas issued contingent value rights or CVRs, which entitled the holders to
receive up to a total of 105,408,978 of Abraxas common stock under certain
circumstances as defined. On May 21, 2001, Abraxas issued 3,386,488 shares upon
the expiration of the CVRs.
Note 6. Guarantor Condensed Consolidating Financial Statements
The following table presents condensed consolidating balance sheets of
Abraxas, as a parent company, and its significant subsidiaries, Canadian Abraxas
and Grey Wolf, as June 30, 2002 and December 31, 2001 and the related
consolidating statements of operations and cash flows for the three and six
months ended June 30, 2002 and 2001. Canadian Abraxas is a guarantor of the
First Lien Notes ($63.5 million) and jointly and severally liable with Abraxas
for the Second Lien Notes ($190.2 million) and the Old Notes ($801,000). Grey
Wolf is a non-guarantor with respect to the First Lien Notes, the Second Lien
Notes, and the Old Notes.
13
Condensed Consolidating Parent Company, Restricted Subsidiaries and Non-Guarantor Balance Sheet
June 30, 2002
(In thousands)
Abraxas
Petroleum Restricted Reclassifi- Abraxas
Corporation Subsidiary Non-Guarantor cations Petroleum
Inc. - Parent (Canadian Subsidiary and Corporation and
Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries
------------- ------------- ----------- ------------ ------------
Assets:
Current assets:
Cash .................................... $ 3,239 $ 348 $ 3,250 $ - $ 6,837
Restricted cash.......................... 9,895 - - - 9,895
Accounts receivable, less allowance for
doubtful accounts...................... 3,924 5,581 9,454 (10,341) 8,618
Equipment inventory ..................... 930 187 12 - 1,129
Other current assets .................... 284 401 132 - 817
------------- ------------- ----------- ------------ ------------
Total current assets ................... 18,272 6,517 12,848 (10,341) 27,296
Property and equipment - net................ 76,516 42,871 29,672 - 149,059
Deferred financing fees, net .............. 2,063 903 111 - 3,077
Other assets ............................... 108,708 822 8,618 (109,083) 9,065
------------- ------------- ----------- ------------ ------------
Total assets ........................... $ 205,559 $ 51,113 $ 51,249 $ (119,424) $ 188,497
============= ============= =========== ============ ============
Liabilities and Stockholder's deficit:
Current liabilities:
Accounts payable ......................... $ 14,369 $ 666 $ 6,325 $ (10,216) $ 11,144
Accrued interest ......................... 4,912 1,009 - - 5,921
Other accrued expenses ................... 3,307 - - - 3,307
Hedge liability .......................... 950 777 - - 1,727
Current maturities of long-term debt ..... 63,500 - - - 63.500
------------- ------------- ----------- ------------ ------------
Total current liabilities .............. 87,038 2,452 6,325 (10,216) 85,599
Long-term debt .............................. 138,350 52,629 36,318 - 227,297
Future site restoration .................... - 3,498 746 - 4,244
------------- ------------- ----------- ------------ ------------
225,388 58,579 43,389 (10,216) 317,140
------------- ------------- ----------- ------------ ------------
Stockholders' equity (deficit)............... (19,829) (7,466) 7,860 (109,208) (128,643)
------------- ------------- ----------- ------------ ------------
Total liabilities and stockholders' equity
(deficit).................................... $ 205,559 $ 51,113 $ 51,249 $ (119,424) $ 188,497
============= ============= =========== ============ ============
(1) Includes amounts for insignificant U.S. subsidiaries, Sandia and
Wamsutter, which are guarantors of the First and Second Lien Notes.
Sandia is also a guarantor of the Old Notes. Additionally, these
subsidiaries are designated as Restricted Subsidiaries along with
Canadian Abraxas.
Condensed Consolidating Parent Company, Restricted Subsidiaries and Non-Guarantor Balance Sheet
December 31, 2001
(In thousands)
Abraxas
Petroleum Restricted Reclassifi- Abraxas
Corporation Subsidiary Non-Guarantor cations Petroleum
Inc. - Parent (Canadian Subsidiary and Corporation and
Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries
------------- ------------- ----------- ------------ ------------
Assets:
Current assets:
Cash .................................... $ 3,593 $ 1,245 $ 2,767 $ - $ 7,605
Accounts receivable, less allowance for
doubtful accounts...................... 17,281 792 6,782 (16,808) 8,047
Equipment inventory ..................... 1,061 178 12 - 1,251
Other current assets .................... 250 99 94 - 443
------------- ------------- ----------- ------------ ------------
Total current assets .................. 22,185 2,314 9,655 (16,808) 17,346
Property and equipment - net................ 116,462 122,486 42,946 - 281,894
Deferred financing fees, net .............. 2,779 1,042 107 - 3,928
Other assets ............................... 108,704 784 6,281 (115,321) 448
14
------------- ------------- ----------- ------------ ------------
Total assets ............................ $ 250,130 $ 126,626 $ 58,989 $ (132,129) $ 303,616
============= ============= =========== ============ ============
Liabilities and Stockholder's deficit:
Current liabilities:
Accounts payable ........................ $ 10,642 $ 17,009 $ 9,472 $ (22,985) $ 14,138
Accrued interest ........................ 5,000 1,009 4 - 6,013
Other accrued expenses .................. 1,052 - 64 - 1,116
Hedge liability ......................... 438 220 - - 658
Current maturities of long-term debt .... 415 - - - 415
------------- ------------- ----------- ------------ ------------
Total current liabilities ............. 17,547 18,238 9,540 (22,985) 22,340
Long-term debt ............................. 209,611 52,629 22,944 - 285,184
Deferred income taxes ...................... - 17,718 2,903 - 20,621
Future site restoration ................... - 3,399 657 - 4,056
------------- ------------- ----------- ------------ ------------
227,158 91,984 36,044 (22,985) 332,201
Stockholders' equity (deficit).............. 22,972 34,642 22,945 (109,144) (28,585)
------------- ------------- ----------- ------------ ------------
Total liabilities and stockholders' equity
(deficit)................................... $ 250,130 $ 126,626 $ 58,989 $ (132,129) $ 303,616
============= ============= =========== ============ ============
Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Statement of Operations
For the three months ended June 30, 2002
(In thousands)
Abraxas
Petroleum Restricted Reclassifi- Abraxas
Corporation Subsidiary Non-Guarantor cations Petroleum
Inc. - Parent (Canadian Subsidiary and Corporation and
Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries
------------- ------------- ----------- ------------ ------------
Revenues:
Oil and gas production revenues ............... $ 5,501 $ 3,981 $ 3,661 $ - $ 13,143
Gas processing revenues ....................... - 605 136 - 741
Rig revenues .................................. 193 - - - 193
Other ........................................ 65 52 41 - 158
------------- ------------- ----------- ------------ ------------
5,759 4,638 3,838 - 14,235
Operating costs and expenses:
Lease operating and production taxes .......... 1,891 510 952 - 3,353
Depreciation, depletion, and amortization ..... 2,806 4,124 2,180 - 9,110
Proved property impairment..................... 28,179 60,501 27,315 - 115,995
Rig operations ................................ 175 - - - 175
General and administrative .................... 1,307 (150) 324 - 1,481
------------- ------------- ----------- ------------ ------------
34,358 64,985 30,771 - 130,114
------------- ------------- ----------- ------------ ------------
Operating income (loss)........................... (28,599) (60,347) (26,933) - (115,879)
Other (income) expense:
Interest income ............................... (8) - - - (8)
Amortization of deferred financing fees........ 332 93 6 - 431
Interest expense............................... 6,296 1,660 805 - 8,761
------------- ------------- ----------- ------------ ------------
6,620 1,753 811 - 9,184
------------- ------------- ----------- ------------ ------------
Income (loss) from operations before income tax
and extraordinary item......................... (35,219) (62,100) (27,744) - (125,063)
Income tax expense (benefit)...................... - (17,712) (11,661) - (29,373)
------------- ------------- ----------- ------------ ------------
Net income (loss)................................ $ (35,219 $ (44,388) $ (16,083) $ - $ (95,690)
============= ============= =========== ============ ============
15
Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Statement of Operations
For the six months ended June 30, 2002
(In thousands)
Abraxas
Petroleum Restricted Reclassifi- Abraxas
Corporation Subsidiary Non-Guarantor cations Petroleum
Inc. - Parent (Canadian Subsidiary and Corporation and
Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries
------------- ------------- ----------- ------------ ------------
Revenues:
Oil and gas production revenues ............... $9,962 $ 7,775 $ 6,292 $ - $ 24,029
Gas processing revenues ....................... - 1,157 254 - 1,411
Rig revenues .................................. 344 - - - 344
Other ........................................ 69 107 82 - 258
------------- ------------- ----------- ------------ -----------
10,375 9,039 6,628 - 26,042
Operating costs and expenses:
Lease operating and production taxes .......... 3,769 1,834 1,659 - 7,262
Depreciation, depletion, and amortization ..... 5,059 7,293 3,572 - 15,924
Proved property impairment..................... 28,179 60,501 27,315 - 115,995
Rig operations ................................ 296 - - - 296
General and administrative .................... 2,207 361 611 - 3,179
------------- ------------- ----------- ------------ ------------
39,510 69,989 33,157 - 142,656
------------- ------------- ----------- ------------ ------------
Operating income (loss)........................... (29,135) (60,950) (26,529) - (116,614)
Other (income) expense:
Interest income ............................... (41) - - - (41)
Amortization of deferred financing fees........ 663 183 12 - 858
Interest expense............................... 12,531 3,342 1,301 - 17,174
------------- ------------- ----------- ------------ ------------
13,153 3,525 1,313 - 17,991
------------- ------------- ----------- ------------ ------------
Income (loss) from operations before income tax
and extraordinary item......................... (42,288) (64,475) (27,842) - (134,605)
Income tax expense (benefit)...................... - (18,514) (11,702) - (30,216)
------------- ------------- ----------- ------------ ------------
Net income (loss)................................ $ (42,288) $ (45,961) $ (16,140) $ - $ (104,389)
============= ============= =========== ============ ============
Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Statement of Operations
For the three months ended June 30, 2001
(In thousands)
Abraxas
Petroleum Restricted Reclassifi- Abraxas
Corporation Subsidiary Non-Guarantor cations Petroleum
Inc. - Parent (Canadian Subsidiary and Corporation and
Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries
------------- ------------- ----------- ------------ ------------
Revenues:
Oil and gas production revenues ............... $ 9,517 $ 6,781 $ 3,829 $ - $ 20,127
Gas processing revenues ....................... - 425 73 - 498
Rig revenues .................................. 225 - - - 225
Other ........................................ 76 106 84 - 266
------------- ------------- ----------- ------------ ------------
9,818 7,312 3,986 - 21,116
Operating costs and expenses:
Lease operating and production taxes .......... 2,074 1,650 608 - 4,332
Depreciation, depletion, and amortization ..... 2,983 3,904 1,401 - 8,288
Rig operations ................................ 191 - - - 191
General and administrative .................... 1,235 251 89 - 1,575
General and administrative (Stock-based
Compensation)................................ (2,332) - - - (2,332)
------------- ------------- ----------- ------------ ------------
4,151 5,805 2,098 - 12,054
------------- ------------- ----------- ------------ ------------
Operating income (loss)........................... 5,667 1,507 1,888 - 9,062
16
Other (income) expense:
Interest income ............................... (305) - - 293 (12)
Amortization of deferred financing fees........ 348 107 - - 455
Interest expense .............................. 6,259 1,737 126 (293) 7,829
------------- ------------- ----------- ------------ ------------
6,302 1,844 126 - 8,272
------------- ------------- ----------- ------------ ------------
Income (loss) from operations before income tax
and extraordinary item......................... (635) (337) 1,762 - 790
Income tax expense (benefit)...................... 505 546 458 - 1,509
Minority interest in income of consolidated 112
foreign subsidiary ............................ - - - (555) 555
------------- ------------- ----------- ------------ ------------
Net income (loss)................................. $ (1,140) $ (883) $ 1,304 $ (555) $ (1,274)
============= ============= =========== ============ ============
Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Statement of Operations
For the six months ended June 30, 2001
(In thousands)
Abraxas
Petroleum Restricted Reclassifi- Abraxas
Corporation Subsidiary Non-Guarantor cations Petroleum
Inc. - Parent (Canadian Subsidiary and Corporation and
Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries
------------- ------------- ----------- ------------ ------------
Revenues:
Oil and gas production revenues ............... $ 22,548 $ 16,423 $ 9,405 $ - $ 48,376
Gas processing revenues ....................... - 793 141 - 934
Rig revenues .................................. 408 - - - 408
Other ........................................ 79 235 170 - 484
------------- ------------- ----------- ------------ ------------
23,035 17,451 9,716 - 50,202
Operating costs and expenses:
Lease operating and production taxes .......... 4,741 3,349 1,101 - 9,191
Depreciation, depletion, and amortization ..... 6,187 8,156 2,786 - 17,129
Rig operations ................................ 344 - - - 344
General and administrative .................... 2,550 699 435 - 3,684
General and administrative (Stock-based
Compensation)................................ (1,401) - - - (1,401)
------------- ------------- ----------- ------------ ------------
12,421 12,204 4,322 - 28,947
------------- ------------- ----------- ------------ ------------
Operating income (loss)........................... 10,614 5,247 5,394 - 21,255
Other (income) expense:
Interest income ............................... (704) - - 676 (28)
Amortization of deferred financing fees........ 695 215 - - 910
Interest expense .............................. 12,431 3,624 231 (676) 15,610
Other ......................................... 16 - - - 16
------------- ------------- ----------- ------------ ------------
12,438 3,839 231 - 16,508
------------- ------------- ----------- ------------ ------------
Income (loss) from operations before income tax
and extraordinary item......................... (1,824) 1,408 5,163 - 4,747
Income tax expense (benefit)...................... 505 1,725 2,055 - 4,285
Minority interest in income of consolidated
foreign subsidiary ............................ - - - (1,481) (1,481)
------------ ------------- ----------- ------------ ------------
Net income (loss)................................. $ (2,329) $ (317) $ 3,108 $ (1,481) $ (1,019)
============ ============= =========== ============ ============
17
Condensed Consolidating Parent, Restricted Subsidiary and Non-Guarantor Statement of Cash Flow
For the Six months ended June 30, 2002
(In thousands)
Abraxas
Petroleum Restricted Reclassifi- Abraxas
Corporation Subsidiary Non-Guarantor cations Petroleum
Inc. - Parent (Canadian Subsidiary and Corporation and
Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries
------------- ------------- ----------- ------------ ------------
Operating Activities
Net loss .................................... $ (42,288) $ (45,961) $ (16,140) $ - $ (104,389)
Adjustments to reconcile net income (loss)
to net cash provided by operating
activities:
Depreciation, depletion, and
amortization ......................... 5,059 7,293 3,572 - 15,924
Proved property impairment.............. 28,179 60,501 27,315 - 115,995
Deferred income tax benefit............. - (18,514) (11,702) - (30,216)
Amortization of deferred financing fees. 663 183 12 - 858
Amortization of debt discount........... - - 230 - 230
Changes in operating assets and
liabilities:
Accounts receivable ................ 18,329 (20,265) 3,435 (1,952) (453)
Equipment inventory ................ 131 - - - 131
Other ............................. (39) (102) (16) - (157)
Accounts payables and accrued
expenses ......................... 922 354 (2,947) 1,952 281
------------- ------------- ----------- ------------ ------------
Net cash provided (used) by operating
activities ............................... 10,956 (16,511) 3,759 - (1,796)
Investing Activities
Capital expenditures, including purchases
and development of properties............. (3,242) (3,592) (17,004) - (23,838)
Proceeds from sale of oil and gas properties. 9,950 20,783 2,169 - 32,902
Increase in restricted cash.................. (9,895) - - - (9,895)
------------- ------------- ----------- ------------ ------------
Net cash provided (used) by investing
activities ............................... (3,187) 17,191 (14,835) - (831)
Financing Activities
Proceeds from long-term borrowings .......... - - 11,614 - 11,614
Payments on long-term borrowings ............ (8,123) - (22) - (8,145)
------------- ------------- ----------- ------------ ------------
Net cash provided (used) by financing
Activities.................................. (8,123) - 11,592 - 3,469
------------- ------------- ----------- ------------ ------------
-
Effect of exchange rate changes on cash ..... - (1,577) (33) - (1,610)
------------- ------------- ----------- ------------ ------------
Increase (decrease) in cash ................. (354) (897) 483 - (768)
Cash at beginning of year ................... 3,593 1,245 2,767 - 7,605
------------- ------------- ----------- ------------ ------------
Cash at end of year.......................... $ 3,239 $ 348 $ 3,250 $ - $ 6,837
============= ============= =========== ============ ============
Condensed Consolidating Parent, Restricted Subsidiary and Non-Guarantor Statement of Cash Flow
For the six months ended June 30, 2001
(In thousands)
Abraxas
Petroleum Restricted Reclassifi- Abraxas
Corporation Subsidiary Non-Guarantor cations Petroleum
Inc. - Parent (Canadian Subsidiary and Corporation and
Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries
------------- ------------- ----------- ------------ ------------
Operating Activities
Net income (loss) ........................... $ (2,329) $ (317) $ 3,108 $ (1,481) $ (1,019)
18
Adjustments to reconcile net income (loss)
to net cash provided by operating activities:
Minority interest in income of foreign
subsidiary ........................... - - - 1,481 1,481
Depreciation, depletion, and
amortization ......................... 6,187 8,156 2,786 - 17,129
Deferred income tax expense (benefit)... - 1,610 2,029 - 3,639
Amortization of deferred financing fees. 694 215 - - 909
Stock-based compensation ............... (1,401) - - - (1,401)
Changes in operating assets and
liabilities:
Accounts receivable ................ 16,963 (8,804) 2,148 - 10,307
Equipment inventory ................ (98) - - - (98)
Other ............................. (919) (67) (113) - (1,099)
Accounts payables and accrued
expenses ......................... (8,736) (372) (4,334) (13,442)
------------- ------------- ----------- ------------ ------------
Net cash provided by operating activities ... 10,361 421 5,624 - 16,406
Investing Activities
Capital expenditures, including purchases
and development of properties ............ (12,382) (10,916) (7,135) - (30,433)
Proceeds from sale of oil and gas
properties ............................... - 9,186 509 - 9,695
------------- ------------- ----------- ------------ ------------
Net cash provided (used) by investing
activities ............................... (12,382) (1,730) (6,626) - (20,738)
Financing Activities
Proceeds from long-term borrowings .......... 10,500 - 816 - 11,316
Payments on long-term borrowings ............ (6,188) - - - (6,188)
Exercise of stock options ................... 16 - - - 16
Deferred financing fees...................... (10) - - - (10)
Other........................................ - - 183 - 183
------------- ------------- ----------- ------------ ------------
Net cash provided (used) by financing
activities ............................... 4,318 - 999 - 5,317
------------- ------------- ----------- ------------ ------------
Effect of exchange rate changes on cash ..... - 21 3 - 24
------------- ------------- ----------- ------------ ------------
Increase (decrease) in cash ................. 2,297 (1,288) - - 1,009
Cash at beginning of period ................. 326 1,678 - - 2,004
------------- ------------- ----------- ------------ ------------
Cash at end of period........................ $ 2,623 $ 390 $ - $ - $ 3,013
============= ============= =========== ============ ============
Note 7. Business Segments
Business segment information about the three months and six months ended
June 30, 2002 in different geographic areas is as follows:
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)
===================
19
Three Months Ended June 30, 2001
-------------------------------------------------------------
U.S. Canada Total
------------------ ----------------- -------------------
(In thousands)
Revenues ............................... $ 9,818 $ 11,298 $ 21,116
================== ================= ===================
Operating profit........................ $ 4,660 $ 3,395 $ 8,055
================== =================
General Corporate................................................................. 1,007
Interest expense and amortization of deferred financing fees...................... (8,272)
-------------------
Income before income taxes........................................................ $ 790
===================
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)
-------------------
Loss before income taxes.......................................................... $ (134,605)
===================
Six Months Ended June 30, 2001
-------------------------------------------------------------
U.S. Canada Total
------------------ ----------------- -------------------
(In thousands)
Revenues ............................... $ 23,035 $ 27,167 $ 50,202
================== ================= ===================
Operating profit........................ $ 11,853 $ 10,641 $ 22,494
================== =================
General Corporate................................................................. (1,239)
Interest expense and amortization of deferred financing fees...................... (16,508)
-------------------
Income before income taxes........................................................ $ 4,747
===================
At June 30, 2002
-------------------------------------------------------------
U.S. Canada Total
------------------ ----------------- -------------------
(In Thousands)
Identifiable assets .................... $ 94,890 $ 89,713 $ 184,603
================== =================
Corporate assets.................................................................. 3,894
-------------------
Total assets ..................................................................... $ 188,497
===================
At December 31, 2001
-------------------------------------------------------------
U.S. Canada Total
------------------ ----------------- -------------------
(In Thousands)
Identifiable assets .................... $ 124,993 $ 174,063 $ 299,056
================== =================
Corporate assets.................................................................. 4,657
-------------------
Total assets ..................................................................... $ 303,713
===================
Note 8. Hedging Program and Derivatives
On January 1, 2001, the Company adopted SFAS 133 "Accounting for Derivative
Instruments and Hedging Activities" 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, 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. Any ineffective portion is reflected in current
operations.
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,
20
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.
The following table sets forth the Company's hedge position as of June 30,
2002.
Time Period Notional Quantities Price Fair Value
- -------------------------------------- ---------------------------------- ------------------------------ ------------
July 1, 2002 - October 31, 2002 20,000 Mcf/day of natural gas Fixed price swap $2.60-$2.95 $(1.7)
or 1,000 Bbl/day of crude oil natural gas or million
$18.90 Crude oil
On January 1, 2001, in accordance with the transition provisions of SFAS
133, the Company recorded $31.0 million, net of tax, in Other Comprehensive
Income/Loss representing the cumulative effect of an accounting change to
recognize the fair value of cash flow derivatives. The Company recorded cash
flow hedge derivative liabilities of $38.2 million on that date and a deferred
tax asset of $7.2 million.
During the first six months of 2002 the fair value of the hedge increased
by $2.5 million. For the three and six months ended June 30, 2002, the
ineffective portion of the cash flow hedges were not material.
As of June 30, 2002, $1.4 million of deferred net losses on derivative
instruments were recorded in other comprehensive income, of which $1.4 million
is expected to be reclassified to earnings during the next four-month period.
All hedge transactions are subject to the Company's risk management policy,
which has been 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.
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 believes these charges are
without merit. The Company has established a reserve in the amount of $845,000,
which represents the Company's share of the judgment. The Company believes that
the remaining portion of the judgment represents the other partner's share of
such judgment.
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 oil 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, 2002, 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.
21
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:
Accumulated
Other
Comprehensive
Comprehensive Income (loss) Income (loss)
---------------------------------- ------------------
Six Months Three Months
Ended Ended As of
June 30, 2002 June 30, 2002
---------------------------------- ------------------
(In thousands)
Accumulated other comprehensive loss at
December 31, 2001.............................. $ (13,561)
Net loss.................................... $ (104,389) $ (95,690)
Other Comprehensive loss:
Hedging derivatives (net of tax) - See Note
Reclassification adjustment for settled
hedge contracts........................... 1,151 1,151
Change in fair market value of
outstanding hedge positions............... (1,976) 99
Foreign currency translation adjustment..... 5,156 5,523
----------------- ---------------
Other comprehensive income (loss).............. 4,331 6,773 4,331
----------------- ---------------
Comprehensive income (loss).................... $ (100,058) $ (88,917)
================= =============== -----------------
Accumulated other comprehensive loss at June 30, 2002................ $ (9,230)
=================
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
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). 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 future write-down of the carrying value
of it crude oil and natural gas properties may be required.
Note 12. New Accounting Standards
In June 2001, the FASB issued SFAS No. 143, " Accounting for Asset
Retirement Obligations." SFAS No. 143 requires an asset retirement obligation to
be recorded at fair value during the period incurred and an equal amount
recorded as an increase in the value of the related long-lived asset. The
22
capitalized cost is depreciated over the useful life of the asset and the
obligation is accreted to its present value each period. SFAS No. 143 is
effective for the Company beginning January 1,2003. The Company is currently
evaluating the impact the standard will have on its future results of operations
and financial condition.
Effective January 1, 2002, the Company adopted SFAS No. 144 " Accounting
for the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 retains the
requirement to recognize an impairment loss only where the carrying value of a
long-lived asset is not recoverable from its undiscounted cash flows and to
measure such loss as the difference between the carrying amount and fair value
of the asset. SFAS No. 144, among other things, changes the criteria that have
to be met to classify an asset as held-for-sale and requires that operating
losses from discontinued operations be recognized in the period that the losses
are incurred rather than as of the measurement date. This new standard had no
impact on the Company's consolidated financial statements during the first six
months of 2002.
In April 2002, the FASB issued SFAS No. 145, "Recission of FASB No. 4, 44,
and 64, Amendments of FASB Statement No. 13 and Technical Corrections." SFAS No.
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 No. 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 become effective for the Company beginning January 1, 2003 with earlier
adoption encouraged. 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 its
financial condition or results of operations.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Cost Associated
with Exit or Disposal Activities." SFAS No. 146 requires costs associated with
exit of disposal activities to be recognized when they are incurred rather than
at the date of commitment to an exit or disposal plan. SFAS No. 146 is effective
for the Company beginning January 1, 2003. The Company is currently evaluating
the impact the standard will have on its results of operations and financial
condition.
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.
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
PART I
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
- --------------------------------------------------------------------------------
The following is a discussion of our financial condition, results of
operations, liquidity and capital resources. This discussion should be read in
conjunction with our consolidated financial statements and the notes thereto,
included in our Annual Report on Form 10-K filed for the year ended December 31,
2001.
General
We have incurred net losses in four of the last five years and for the
first six months of 2002, 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. Natural gas and crude oil prices weakened during 1998.
Crude oil and natural gas prices increased somewhat in 1999 and increased
substantially in 2000. During 2001, crude oil and natural gas prices weakened
substantially from the 2000 levels. During the first six months of 2002, prices
began to increase. 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. If crude oil and natural gas
prices return to the depressed levels experienced in the last six months of
2001, or if our production levels decrease, our revenues, cash flow from
operations and financial condition will be materially adversely affected. For
more information, see "Liquidity and Capital Resources-Current Liquidity
Requirements" and "-Future Capital Resources."
23
Results of Operations
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.
Price volatility in the natural gas market has remained prevalent in the
last few years. In the first quarter of 2002, we experienced a decline in energy
commodity prices from the prices that we received in the first quarter of 2001.
During the first quarter of 2001, we had certain crude oil and natural gas
hedges in place that prevented us from realizing the full impact of a favorable
price environment. In January 2001, the market price of natural gas was at its
highest level in our operating history and the price of crude oil was also at a
high level. However, over the course of 2001 and the beginning of the first
quarter of 2002, prices again became depressed, primarily due to the economic
downturn. Beginning in March 2002, commodity prices began to increase and
continued higher through June 2002.
The table below illustrates how natural gas prices fluctuated over the
course of 2001 and the first two quarters of 2002. The table below contains the
last three days average of NYMEX traded contracts index price and the prices we
realized during each quarter for 2001 and the first two quarters of 2002,
including the impact of our hedging activities.
(in $ per Mcf) Natural Gas Prices by Quarter
- -------------------------------------------------------------------------------------------------------------------
Quarter ended
---------------------------------------------------------------------------------------
March 31, June 30, September 30, December 31, March 31, June 30,
2001 2001 2001 2001 2002 2002
------------ ----------- ----------------- ---------------- ------------ --------------
Index $ 7.27 $ 4.82 $ 2.98 $ 2.47 $ 2.38 $ 3.36
Realize 4.85 3.41 2.26 2.09 2.21 2.44
The NYMEX natural gas price on August 9, 2002 was $2.76 per Mcf.
Prices for crude oil have followed a similar path as the commodity market
fell throughout 2001and the first quarter of 2002. The table below contains the
last three days average of NYMEX traded contracts index price and the prices we
realized during each quarter for 2001 and the first two quarters of 2002.
(in $ per Bbl) Crude Oil Prices by Quarter
- ------------------------------------------------------------------------------------------------------------------
March 31, June 30, September 30, December 31, March 31, June 30,
2001 2001 2001 2001 2002 2002
------------ ------------ ----------------- --------------- ------------ --------------
Index $ 29.86 $ 27.94 $ 26.50 $ 22.12 $ 19.48 $ 26.40
Realized 27.22 25.32 25.06 18.72 16.64 23.47
The NYMEX crude oil price on August 9, 2002 was $26.86 per Bbl.
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.
As of June 30, 2002, we had an open position on a swap call agreement for
either 1,000 Bbls of crude oil or 20,000 MMBtu of natural gas per day, at the
counterparty's option, at fixed prices ($18.90 for crude oil or $2.95 to $2.60
for natural gas) through October 31, 2002. As of June 30, 2002, the fair market
value of the remaining fixed price hedge agreement was a liability of
approximately $1.7 million, which is expected to be charged to revenues in 2002.
Selected operating data. The following table sets forth certain of our
operating data for the periods presented.
24
Three Months Ended Six Months Ended
June 30 June 30
2002 2001 2002 2001
----------- ----------- ------------- ------------
Operating Revenue (in thousands):
Crude Oil Sales ................................ $ 1,766 $ 3,104 $ 2,998 $ 6,706
Natural Gas Sales ................................ 10,287 15,438 19,069 37,864
Natural Gas Liquids Sales......................... 1,090 1,585 1,962 3,806
Processing Revenue................................ 741 498 1,411 934
Rig Operations.................................... 193 225 344 408
Other............................................. 158 266 258 484
----------- ----------- ------------- ------------
$ 14,235 $ 21,116 $ 26,042 $ 50,202
=========== =========== ============= ============
Operating Income (Loss) in thousands)............. $ (115,879) $ 9,062 $ (116,614) $ 21,255
Crude Oil Production (MBBLS)...................... 75 123 149 255
Natural Gas Production (MMCFS).................... 4,218 4,529 8,191 9,156
Natural Gas Liquids Production (MBBLS)............ 62 66 130 144
Average Crude Oil Sales Price ($/BBL)............. $ 23.47 $ 25.32 $ 20.08 $ 26.31
Average Natural Gas Sales Price ($/MCF)........... $ 2.44 $ 3.41 $ 2.33 $ 4.14
Average Liquids Sales Price ($/BBL)............... $ 17.73 $ 24.10 $ 15.11 $ 26.46
Comparison of Three Months Ended June 30, 2002 to Three Months Ended June 30,
2001
Operating Revenue. During the three months ended June 30, 2002, operating
revenue from crude oil, natural gas and natural gas liquid sales decreased to
$13.1 million compared to $20.1 million in the three months ended June 30, 2001.
The decrease in revenue was primarily due to decreased prices realized during
the period together with a decline in production volumes caused by the
disposition of producing properties. Lower commodity prices reduced crude oil
and natural gas revenue by $5.0 million while decreased production volumes
reduced revenue by $1.9 million.
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
Average sales prices net of hedging losses for the quarter ended June 30, 2001
were:
o $25.32 per Bbl of crude oil,
o $24.10 per Bbl of natural gas liquid, and
o $3.41 per Mcf of natural gas
Crude oil production volumes declined from 122.6 MBbls during the quarter
ended June 30, 2001 to 75.2 MBbls for the same period of 2002. This decline
resulted from a de-emphasis on crude oil drilling in prior periods, the
disposition of crude oil producing properties in the later part of 2001 and the
first six months of 2002, and a natural decline in production. Natural gas
production volumes declined to 4,218 MMcf for the three months ended June 30,
2002 from 4,529 MMcf for the same period of 2001. This decline was primarily due
to the sale of non-core properties in late 2001 and the first six months of 2002
and the natural decline in production which was partially offset by new
production from current drilling activities.
Lease Operating Expenses. Lease operating expenses and natural gas
processing costs ("LOE") for the three months ended June 30, 2002 decreased to
$3.4 million from $4.3 million for the same period in 2001. The decrease in LOE
is primarily due to a decrease in production tax expense due to lower commodity
prices in the quarter ended June 30, 2002 as compared to the same period of
2001. Our LOE on a per MCFE basis for the three months ended June 30, 2002 was
$0.67 per MCFE compared to $0.77 for the same period of 2001. The decrease in
the per MCFE expense was due to a reduced expense offset by a decline in
production volumes in the second quarter of 2002 compared to the same period in
2001.
General and adminsitrative ("G&A") Expenses. G&A expenses decreased from
$1.6 million for the quarter ended June 30, 2001 to $1.5 million for the same
period of 2002. G&A expense on a per MCFE basis was $0.29 for the second quarter
of 2002 compared to $0.28 for the same period of 2001. Although G&A expense
decreased, the G&A expense on a per MCFE basis increased due to a decline in
production volumes during the second quarter of 2002 as compared to the same
period in 2001.
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
25
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 March 1999, we amended the exercise price to $2.06 per
share on all options with an existing exercise price greater than $2.06 per
share. We recognized income of approximately $2.3 million during the quarter
ended June 30, 2001 related to these repricings. This income was recorded as a
reduction of expense. The income recognized in the second quarter of 2001 was
due to a decline in the price of our common stock. During 2002, we did not
recognize any stock-based compensation because the price of our common stock has
remained below the exercise price.
Depreciation, Depletion and Amortization Expenses. Depreciation, depletion
and amortization ("DD&A") expense increased to $9.1 million for the three months
ended June 30, 2002 from $8.3 million for the same period of 2001. Our DD&A on a
per MCFE basis for the three months ended June 30, 2002 was $1.81 per MCFE as
compared to $1.46 in 2001. The increase was due to a reduction in reserves, due
to lower commodity prices and sales of properties, and higher finding costs in
the latter part of 2001 and the first six months of 2002.
Interest Expense. Interest expense increased to $8.8 million for the second
quarter of 2002 compared to $7.8 million in 2001. The increase was due to an
increase in long-term debt primarily relating to the Grey Wolf credit facility.
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.
Minority interest. We owned a 49% controlling interest in the earnings of
Grey Wolf through August 2001. The consolidated financial statements include the
results of Grey Wolf. The net income attributable to the minority interest in
Grey Wolf for the second quarter of 2001 was $555,000. As of June 30, 2002, we
owned 100% of the outstanding capital stock of Grey Wolf. We obtained the
additional interest in Grey Wolf pursuant to a tender offer and subsequent
compulsory merger, completed in September 2001.
Income taxes. Income taxes decreased to a benefit of $29.4 million for the
three months ended June 30, 2002 compared to an expense of $1.5 million for the
same period of 2001. This decrease is due to reduced profitability in our
operations, primarily as a result of ceiling limitation write-downs and lower
commodity prices. 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. This results in a low consolidated effective tax rate for the three
months ended June 30, 2002.
26
Comparison of Six Months Ended June 30, 2002 to Six Months Ended June 30, 2001
Operating Revenue. During the six months ended June 30, 2002, operating
revenue from crude oil, natural gas and natural gas liquid sales decreased to
$24.0 million as compared to $48.4 million in the six months ended June 30,
2001. The decrease in revenue was primarily due to decreased prices realized
during the period, as well as a decrease in production volumes. Production
volumes decreased primarily as a result of producing property sales in the later
part of 2001 and in the first six months of 2002. Lower commodity prices
impacted crude oil and natural gas revenue by $19.8 million while reduced
production volumes had a $4.6 million negative impact on revenue.
Average sales prices net of hedging losses for the six months ended June 30,
2002 were:
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
Average sales prices net of hedging losses for the six months ended June 30,
2001 were:
o $26.31 per Bbl of crude oil,
o $26.46 per Bbl of natural gas liquid, and
o $4.14 per Mcf of natural gas
Crude oil production volumes declined from 254.9 MBbls during the six months
ended June 30, 2001 to 149.2 MBbls for the same period of 2002, primarily as a
result of a de-emphasis on crude oil drilling in prior periods, and the sale of
crude oil producing properties in the later part of 2001 and in the first half
of 2002. Natural gas production volumes declined to 8,191 MMcf for the six
months ended June 30, 2002 from 9,156 MMcf for the same period of 2001. This
decline was primarily due to the sale of non-core properties in late 2001 and
the first half of 2002 and the natural decline in production which 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, 2002 decreased to
$7.3 million from $9.2 million for the same period in 2001. The decrease in LOE
was primarily due to a decrease in production tax expense due to higher
commodity prices in the six months ended June 30, 2001 as compared to the same
period of 2002. Our LOE on a per MCFE basis for the six months ended June 30,
2002 was $0.74 per MCFE as compared to $0.80 for the same period of 2001. The
decrease in the per MCFE expense was due to a reduced expense offset by a
decline in production volumes in the first two quarters of 2002 as compared to
the same period in 2001.
General and adminsitrative ("G&A") Expenses. G&A expenses decreased from
$3.7 million for the first six months of 2001 to $3.2 million for the first six
months of 2002. G&A expense on a per MCFE basis was $0.32 for the first six
months of 2002 and 2001. The decrease in G&A expense was primarily due to a
decrease in consulting fees in the first quarter of 2002 as compared to the
first quarter of 2001
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 March 1999, we amended the exercise price to $2.06 per
share on all options with an existing exercise price greater than $2.06 per
share. We recognized income of approximately $1.4 million during the six months
ended June 30, 2001 related to these repricings. The income was recorded as a
reduction of expense. The income recognized in 2001 was due to a decline in the
price of our common stock. During 2002, we did not recognize any stock -based
compensation due to the decline in the price of our common stock.
Depreciation, Depletion and Amortization Expenses. Depreciation, depletion
and amortization ("DD&A") expense decreased to $15.9 million for the six months
ended June 30, 2002 from $17.1 million for the same period of 2001. Our DD&A on
a per MCFE basis for the six months ended June 30, 2002 was $1.61 per MCFE as
compared to $1.48 in 2001. These decreases were due to reduced production
volumes in 2002 and prior ceiling limitation write-downs.
Interest Expense. Interest expense increased to $17.2 million for the first
six months of 2002 compared to $15.6 million in 2001. The increase was due to an
increase in long-term debt primarily relating to the Grey Wolf credit facility.
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
27
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 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.
Minority interest. We owned a 49% controlling interest in the earnings of
Grey Wolf through August 2001. The consolidated financial statements include the
results of Grey Wolf. The net income attributable to the minority interest in
Grey Wolf for the first six months of 2001 was $1.5 million. As of June 30,
2002, we owned 100% of the outstanding capital stock of Grey Wolf. We obtained
the additional interest in Grey Wolf pursuant to a tender offer and subsequent
compulsory merger, completed in September 2001.
Income taxes. Income taxes decreased to a benefit of $30.2 million for the
first six months of 2002 compared to an expense of $4.3 million for the same
period of 2001. This decrease is due to reduced profitability in our operations,
primarily as a result of ceiling limitation write-downs and lower commodity
prices. 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. This results in a low consolidated effective tax rate for the six
months ended June 30, 2002.
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
lack of liquidity and high debt levels have had a substantial impact on our
ability to develop existing properties and acquire new producing properties.
Our sources of capital are primarily cash on hand, cash from operating
activities, the sale of properties and financing activities, including sales of
production payments to Mirant Americas and funding from the Grey Wolf credit
facility with Mirant Canada. 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 six 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 may continue this practice,
future crude oil and natural gas price declines would have a material adverse
effect on our overall results, and therefore, our liquidity. Furthermore, low
28
crude oil and natural gas prices could affect our ability to raise capital on
terms favorable to us. Similarly, our cash flow from operations will decrease if
the volume of crude oil and natural gas we produce decreases. Our production
volumes will decline as reserves are produced. In addition, we have sold, and
intend to continue to sell, certain of our properties. To offset the loss in
production volumes resulting from natural field declines and sales of producing
properties, we must conduct successful exploration, exploitation and development
activities, acquire additional producing properties or identify additional
behind-pipe zones or secondary recovery reserves. While we have had some success
in pursuing these activities, we have not been able to fully replace the
production volumes lost from natural field declines and property sales.
Working Capital. At June 30, 2002, we had current assets of $27.3 million
and current liabilities of $85.6 million resulting in a working capital deficit
of $58.3 million. This compares to a working capital deficit of $5.0 million at
December 31, 2001 and working capital deficit of $13.6 million at June 30, 2001.
The majority of our current liabilities at June 30, 2002 were current maturities
of long-term debt of $63.5 million of our First Lien Notes due March 2003, trade
accounts payable of $7.7 million, revenues due third parties of $3.4 million,
accrued interest of $5.9 million and hedge liability of $1.7 million. Our
capital resources and liquidity are affected by the timing of our interest
payments of approximately $4.1 million each March 15, $11.0 million each May 1,
$4.1 million each September 15, and $11.0 million each November 1. As a result
of these periodic interest payments on our outstanding debt obligations, our
cash balances will decrease dramatically on certain dates during the year.
Capital expenditures. Capital expenditures, excluding property divestitures
during the first six months of 2002, were $23.8 million compared to $30.4
million during the same period of 2001. The table below sets forth the
components of these capital expenditures on a historical basis for the six
months ended June 30, 2002 and 2001.
Six Months Ended
June 30
--------------------------------------------
2002 2001
---------------------- ---------------------
Expenditure category (in thousands):
Acquisitions................................................ $ - $ -
Development................................................. 23,699 30,046
Facilities and other........................................ 139 387
--------------- ---------------
Total................................................... $ 23,838 $ 30,433
=============== ===============
Investing activities used $886,000 net during the first six months of 2002.
$32.9 million was provided from the proceeds of property sales during the
period. $23.7 million was utilized primarily for the development of crude oil
and natural gas properties and other facilities. This compares to using $20.7
million net during the first six months of 2001, $30.4 million of which was
utilized for the development of crude oil and natural gas properties and $9.7
million of which was provided from the sale of non-core assets in Canada.
As cash flow permits our current budget for capital expenditures for the
last six months of 2002 other than acquisition expenditures is approximately $14
million. The remaining portion of such expenditures is primarily to be conducted
by Grey Wolf, and will be funded by cash flow and the Grey Wolf credit facility
with Mirant Canada. Additional capital expenditures may be made 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 further decline, our cash flows will decrease which may
result in a further reduction of the capital expenditures budget. If we decrease
our capital expenditures budget, we will 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,
---------------------------------------
2002 2001
------------------ ---------------
Net cash (used) provided by operating activities $ (1,796) $ 16,406
Net cash used in investing activities (831) (20,738)
Net cash provided by financing activities 3,469 5,317
------------------ ---------------
Total $ 842 $ 985
================== ===============
29
Operating activities during the six months ended June 30, 2002 used $1.8
million cash compared to providing $16.4 million in the same period in 2001. Net
loss plus non-cash expense items during 2002 and net changes in operating assets
and liabilities accounted for most of these funds. Financing activities provided
$3.5 million for the first six months of 2002 compared to providing $5.3 million
for the same period of 2001.
Current Liquidity Requirements. We currently have substantial indebtedness
and debt service requirements and we have had recurring net losses in three of
the last four years and the quarter ended June 30, 2002. Our loss of
approximately $125.1 million during the quarter ended June 30, 2002 was due
primarily to proved property impairments of approximately $116 million resulting
from depressed commodity prices. At June 30, 2002, the Company's current
liabilities of approximately $85.6 million exceeded current assets of $27.3
million resulting in a working capital deficit of $58.3 million. The Company
also had a shareholders' deficit of $128.6 million. The success of our future
operations will require us to meet our significant debt obligations and to make
substantial capital expenditures for the exploitation, development, exploration
and production of crude oil and natural gas. In the past, we have funded our
operations and capital expenditures primarily through cash flow from operations,
sales of properties and borrowings under credit facilities and other sources.
Recently, our cash flow from operations has been severely impacted by depressed
commodity prices and reduced production resulting from sales of producing
properties. Our reduced operating cash flow has put significant strain on our
liquidity and cash position. At June 30, 2002, we had unrestricted cash of $6.8
million and $9.8 million of restricted cash from the proceeds of asset
divestitures after repayments of certain obligations (See Note 3 to the
Consolidated Financial Statements). Our reduced operating cash flow and
resulting limited liquidity has also caused us to reduce capital expenditures,
including exploration, exploitation and development projects. These measures
will limit our ability to replenish our depleting reserves, which could
negatively impact our cash flow from operations and results of operations in the
future.
We will need additional funds in the future for both the development of our
assets and the service of our debt, including the payment of periodic interest
and the repayment of the $63.5 million in principal amount of the First Lien
Notes maturing in March 2003 and the $191.0 million of the Second Lien Notes and
Old Notes maturing in November 2004. In order to meet the goals of developing
our assets and servicing our debt obligations, we will be required to obtain
additional sources of capital and/or reduce or reschedule our existing cash
requirements including repayment of the First Lien Notes. In order to do so, we
may pursue one or more of the following alternatives:
o refinancing existing debt;
o repaying debt with proceeds from the sale of assets;
o exchanging debt for equity;
o managing the timing and reducing the scope of our capital expenditures;
o issuing debt or equity securities or otherwise raising additional funds;
or
o selling all or a portion of our existing assets, including interests in
our assets.
There can be no assurance that any of the above alternatives, or some
combination thereof, will be available or, if available, will be on terms
acceptable to us. In addition, the volatility of crude oil and natural gas
prices reduce our cash flow from operations.
In order to meet our need for additional funds, we are exploring strategic
opportunities through the establishment of a Planning Committee of the Board of
Directors. The Planning Committee has engaged an investment banking firm to
assist with a strategic review and to formulate proposed plans and actions for
consideration by our Board of Directors. Because the Planning Committee is
currently conducting its review and formulation of a proposed plan of action,
the Company cannot assess the likelihood that we can effectively implement any
such proposed plan of action. Regardless of the outcome of the strategic review,
a refinancing of our existing debt and the sale of additional properties likely
will be required for us to meet our liquidity and capital requirements. We
believe that we can implement a successful plan of action to improve our
liquidity and capital requirements. However, we cannot give any assurances that
such actions will result in our being able to continue as a going concern. The
June 30, 2002 financial statements do not include any adjustments that might
result from the outcome of these uncertainties. See Note 2 to our Consolidated
Financial Statements-"Business Conditions and Liquidity Requirements" for more
information.
Future Capital Resources. We will have three principal sources of liquidity
going forward: (i) cash on hand, (ii) cash flow from operations and (iii) sales
of properties. In addition, Grey Wolf has additional borrowing capacity under
its credit facility with Mirant Canada. The terms of the First Lien Notes
indenture, the Second Lien Notes indenture and the Old Notes indenture
substantially limit our use of proceeds from sales of properties.
Our indentures restrict, among other things, our ability to:
o incur additional indebtedness;
o incur liens;
o pay dividends or make certain other restricted payments;
30
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.
Furthermore, our ability to raise funds through additional indebtedness
will be limited because a large portion of our crude oil and natural gas
properties and natural gas processing facilities are subject to a first lien or
floating charge for the benefit of the holders of the First Lien Notes and a
second lien or floating charge for the benefit of the holders of the Second Lien
Notes. Finally, our indentures also place restrictions on the use of proceeds
from asset sales. Proceeds from asset sales must generally be used for
investments in producing properties or related assets. In addition, the
indenture for the Second Lien Notes permits using proceeds to make payments
under the First Lien Notes. In the event that such proceeds are not used in this
manner, we must make an offer to note holders to purchase notes at 100% of the
principal amount. Such an offer must be made within 180 days of a property sale.
If commodity prices remain at, or fall below their current levels, it will
be necessary for us to delay discretionary capital expenditures and seek
alternative sources of capital in order to maintain liquidity.
Due to our current debt levels and the restrictions contained in the
indentures described above, our best opportunity for additional sources of
liquidity and capital will be through the disposition of assets and some of the
other alternatives discussed above. We cannot assure you that we will be
successful in any of our efforts to improve liquidity or that such efforts will
produce enough cash to fund our operating and capital requirements, make our
interest payments or to make the principal payments due on our First Lien Notes,
Old Notes and Second Lien Notes.
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 other 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, 2002.
Payments due in:
----------------------------------------------------------------------------
Contractual Obligations
(dollars in thousands) 2005 and
Total 2002 2003 2004 after
- ---------------------------------- --------------- -------------- -------------- --------------- --------------
Long-Term Debt (1) $ 290,797 $ - $ 63,500 $ 190,979 $ 36,318 (2)
Operating Leases (3) 1,249 264 336 236 413
(1) Includes $63.5 million of the First Lien Notes, $191.0 million of the
Old Notes and Second Lien Notes and $36.3 million under the Grey Wolf
Facility.
(2) The Grey Wolf credit facility does not have scheduled repayments of
principal prior to its maturing in 2007. Instead, Grey Wolf is required
to pay its net cash flow on a monthly basis to Mirant Canada. We have
included the entire amount outstanding under the Grey Wolf Facility at
June 30, 2002 ($36.3 million) although we will be making payments prior
to 2007. For more information on the Grey Wolf credit facility, you
should read the description under "Grey Wolf Facility."
(3) Office lease obligations.
Other obligations. We make and will continue to make substantial capital
expenditures for the acquisition, exploitation, development, exploration and
production of crude oil and natural gas. In the past, we have funded our
operations and capital expenditures primarily through cash flow from operations,
sales of properties, sales of production payments to Mirant Americas 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. As cash flow permits our capital
expenditure budget for the remainder of 2002 for existing operations and
leaseholds is approximately $14 million.
31
Long-Term Indebtedness.
Old Notes. On November 14, 1996, we consummated the offering of $215.0
million of our 11.5% Senior Notes due 2004, Series A, which were exchanged for
the Series B Notes in February 1997. On January 27, 1998, we completed the sale
of $60.0 million of our 11.5% Senior Notes due 2004, Series C. The Series B
Notes and the Series C Notes were subsequently combined into $275.0 million in
principal amount of the Old Notes in June 1998. In December 1999, Abraxas and
Canadian Abraxas completed an exchange offer which reduced the amount of
outstanding Old Notes to $801,000. See the description of the Second Lien Notes
below for more information.
Interest on the Old Notes is payable semi-annually in arrears on May 1 and
November 1 of each year at the rate of 11.5% per annum. The Old Notes are
redeemable at our option, in whole or in part, at the redemption prices set
forth below, plus accrued and unpaid interest to the date of redemption, if
redeemed during the 12-month period commencing on November 1 of the years set
forth below:
Year Percentage
---- ----------
2001.................................. 102.875%
2002 and thereafter................... 100.000%
The Old Notes are joint and several obligations of Abraxas and Canadian
Abraxas and rank pari passu in right of payment to all existing and future
unsubordinated indebtedness of Abraxas and Canadian Abraxas. The Old Notes rank
senior in right of payment to all future subordinated indebtedness of Abraxas
and Canadian Abraxas. The Old Notes are, however, effectively subordinated to
the First Lien Notes to the extent of the value of the collateral securing the
First Lien Notes and to the Second Lien Notes to the extent of the value of the
collateral securing the Second Lien Notes. The Old Notes are unconditionally
guaranteed, on a senior basis by Sandia Oil and Gas Company, a wholly owned
subsidiary of Abraxas. The guarantee is a general unsecured obligation of Sandia
and ranks pari passu in right of payment to all unsubordinated indebtedness of
Sandia and senior in right of payment to all subordinated indebtedness of
Sandia. The guarantee is effectively subordinated to the First Lien Notes and
the Second Lien Notes to the extent of the value of the collateral securing the
First Lien Notes and the Second Lien Notes.
Upon a Change of Control, as defined in the Old Notes Indenture, each
holder of the Old Notes will have the right to require us to repurchase all or a
portion of such holder's Old Notes at a redemption price equal to 101% of the
principal amount thereof, plus accrued and unpaid interest to the date of
repurchase. In addition, we will be obligated to offer to repurchase the Old
Notes at 100% of the principal amount thereof plus accrued and unpaid interest
to the date of repurchase in the event of certain asset sales.
First Lien Notes. In March 1999, Abraxas consummated the sale of $63.5
million of the First Lien Notes. Interest on the First Lien Notes is payable
semi-annually in arrears on March 15 and September 15, commencing September 15,
1999. Beginning March 15, 2002, the First Lien Notes are redeemable, in whole or
in part, at the option of Abraxas at the par value price, plus accrued and
unpaid interest to the date of redemption.
The First Lien Notes are senior indebtedness of Abraxas secured by a first
lien on substantially all of the crude oil and natural gas properties of Abraxas
and the shares of Grey Wolf owned by Abraxas. The First Lien Notes are
unconditionally guaranteed on a senior basis, jointly and severally, by Canadian
Abraxas, Sandia and Wamsutter, wholly-owned subsidiaries of Abraxas (the
"Restricted Subsidiaries"). The guarantees are secured by substantially all of
the crude oil and natural gas properties of the guarantors and the shares of
Grey Wolf owned by Abraxas and Canadian Abraxas.
Upon a Change of Control, as defined in the First Lien Notes Indenture,
each holder of the First Lien Notes will have the right to require Abraxas to
repurchase such holder's First Lien Notes at a redemption price equal to 101% of
the principal amount thereof plus accrued and unpaid interest to the date of
repurchase. In addition, Abraxas will be obligated to offer to repurchase the
First Lien Notes at 100% of the principal amount thereof plus accrued and unpaid
interest to the date of redemption in the event of certain asset sales.
The First Lien Notes indenture contains certain covenants that limit the
ability of Abraxas and certain of its subsidiaries, including the guarantors of
the First Lien Notes to, among other things, incur additional indebtedness, pay
dividends or make certain other restricted payments, consummate certain asset
sales, enter into certain transactions with affiliates, incur liens, merge or
consolidate with any other person or sell, assign, transfer, lease, convey or
otherwise dispose of all or substantially all of the assets of Abraxas.
The First Lien Notes indenture provides, among other things, that Abraxas
may not, and may not cause or permit the Restricted Subsidiaries, to, directly
or indirectly, create or otherwise cause to permit to exist or become effective
any encumbrance or restriction on the ability of such subsidiary to pay
dividends or make distributions on or in respect of its capital stock, make
loans or advances or pay debts owed to Abraxas or any other Restricted
32
Subsidiary, guarantee any indebtedness of Abraxas or any other Restricted
Subsidiary or transfer any of its assets to Abraxas or any other Restricted
Subsidiary except for such encumbrances or restrictions existing under or by
reason of:
(1) applicable law;
(2) the First Lien Notes indenture;
(3) customary non-assignment provisions of any contract or any lease
governing leasehold interest of such subsidiaries;
(4) any instrument governing indebtedness assumed by us in an
acquisition, which encumbrance or restriction is not applicable to
such Restricted Subsidiary or the properties or assets of such
subsidiary other than the entity or the properties or assets of the
entity so acquired;
(5) agreements existing on the Issue Date (as defined in the First Lien
Notes indenture) to the extent and in the manner such agreements
were in effect on the Issue Date;
(6) customary restrictions with respect to subsidiaries of Abraxas
pursuant to an agreement that has been entered into for the sale or
disposition of capital stock or assets of such Restricted
Subsidiary to be consummated in accordance with the terms of the
First Lien Notes indenture or any Security Documents (as defined in
the First Lien Notes indenture) solely in respect of the assets or
capital stock to be sold or disposed of;
(7) any instrument governing certain liens permitted by the First Lien
Notes indenture, to the extent and only to the extent such
instrument restricts the transfer or other disposition of assets
subject to such lien; or
(8) an agreement governing indebtedness incurred to refinance the
indebtedness issued, assumed or incurred pursuant to an agreement
referred to in clause (2), (4) or (5) above; provided, however,
that the provisions relating to such encumbrance or restriction
contained in any such refinancing indebtedness are no less
favorable to the holders of the First Lien Notes in any material
respect as determined by the Board of Directors of Abraxas in their
reasonable and good faith judgment that the provisions relating to
such encumbrance or restriction contained in the applicable
agreement referred to in such clause (2), (4) or (5) and do not
extend to or cover any new or additional property or assets and,
with respect to newly created liens, (A) such liens are expressly
junior to the liens securing the First Lien Notes, (B) the
refinancing results in an improvement on a pro forma basis in
Abraxas' Consolidated EBITDA Coverage Ratio (as defined in the
First Lien Notes indenture) and (C) the instruments creating such
liens expressly subject the foreclosure rights of the holders of
the refinanced indebtedness to a stand-still of not less than 179
days.
Second Lien Notes. In December 1999, Abraxas and Canadian Abraxas
consummated an exchange offer whereby $269,699,000 of the Old Notes were
exchanged for $188,778,000 of the Second Lien Notes, and 16,078,990 shares of
Abraxas common stock and contingent value rights. An additional $5,000,000 of
the Second Lien Notes were issued in payment of fees and expenses.
Interest on the Second Lien Notes is payable semi-annually in arrears on
May 1 and November 1, commencing May 1, 2000. We deferred an interest payment of
approximately $11 million dollars, related to Old Notes and the Second Lien
Notes, due on May 1, 2002. We had a 30-day grace period in which to make this
$11 million payment before an "event of default" occurred. The interest payment
was made on May 23, 2002, prior to the expiration of the grace period. The
Second Lien Notes are redeemable, in whole or in part, at the option of Abraxas
and Canadian Abraxas at the redemption prices set forth below, plus accrued and
unpaid interest to the date of redemption, if redeemed during the 12-month
period commencing on December 1 of the years set forth below:
Year Percentage
----- ----------
2001........................... 102.875%
2002 and thereafter............ 100.000%
The Second Lien Notes are senior indebtedness of Abraxas and Canadian
Abraxas and are secured by a second lien on substantially all of the crude oil
and natural gas properties of Abraxas and Canadian Abraxas and the shares of
33
Grey Wolf owned by Abraxas and Canadian Abraxas. The Second Lien Notes are
unconditionally guaranteed on a senior basis, jointly and severally, by Sandia
and Wamsutter. The guarantees are secured by substantially all of the crude oil
and natural gas properties of the guarantors. The Second Lien Notes are,
however, effectively subordinated to the First Lien Notes and related guarantees
to the extent the value of the collateral securing the Second Lien Notes and
related guarantees and the First Lien Notes and related guarantees is
insufficient to pay both the Second Lien Notes and the First Lien Notes.
Upon a Change of Control, as defined in the Second Lien Notes Indenture,
each holder of the Second Lien Notes will have the right to require Abraxas and
Canadian Abraxas to repurchase such holder's Second Lien Notes at a redemption
price equal to 101% of the principal amount thereof plus accrued and unpaid
interest to the date of repurchase. In addition, Abraxas and Canadian Abraxas
will be obligated to offer to repurchase the Second Lien Notes at 100% of the
principal amount thereof plus accrued and unpaid interest to the date of
redemption in the event of certain asset sales.
The Second Lien Notes indenture contains certain covenants that limit the
ability of Abraxas and Canadian Abraxas and certain of their subsidiaries,
including the guarantors of the Second Lien Notes (the "Restricted
Subsidiaries") to, among other things, incur additional indebtedness, pay
dividends or make certain other restricted payments, consummate certain asset
sales, enter into certain transactions with affiliates, incur liens, merge or
consolidate with any other person or sell, assign, transfer, lease, convey or
otherwise dispose of all or substantially all of the assets of Abraxas or
Canadian Abraxas.
The Second Lien Notes indenture provides, among other things, that Abraxas
and Canadian Abraxas may not, and may not cause or permit the Restricted
Subsidiaries, to, directly or indirectly, create or otherwise cause to permit to
exist or become effective any encumbrance or restriction on the ability of such
subsidiary to pay dividends or make distributions on or in respect of its
capital stock, make loans or advances or pay debts owed to Abraxas, Canadian
Abraxas or any other Restricted Subsidiary, guarantee any indebtedness of
Abraxas, Canadian Abraxas or any other Restricted Subsidiary or transfer any of
its assets to Abraxas, Canadian Abraxas or any other Restricted Subsidiary
except for such encumbrances or restrictions existing under or by reason of:
(1) applicable law;
(2) the Old Notes indenture, the First Lien Notes indenture, or the
Second Lien Notes indenture;
(3) customary non-assignment provisions of any contract or any lease
governing leasehold interest of such subsidiaries;
(4) any instrument governing indebtedness assumed by us in an
acquisition, which encumbrance or restriction is not applicable to
such Restricted Subsidiary or the properties or assets of such
subsidiary other than the entity or the properties or assets of the
entity so acquired;
(5) agreements existing on the Issue Date (as defined in the Second
Lien Notes indenture) to the extent and in the manner such
agreements were in effect on the Issue Date;
(6) customary restrictions with respect to subsidiaries of Abraxas and
Canadian Abraxas pursuant to an agreement that has been entered
into for the sale or disposition of capital stock or assets of such
Restricted Subsidiary to be consummated in accordance with the
terms of the Second Lien Notes solely in respect of the assets or
capital stock to be sold or disposed of;
(7) any instrument governing certain liens permitted by the Second Lien
Notes indenture, to the extent and only to the extent such
instrument restricts the transfer or other disposition of assets
subject to such lien; or
(8) an agreement governing indebtedness incurred to refinance the
indebtedness issued, assumed or incurred pursuant to an agreement
referred to in clause (2), (4) or (5) above; provided, however,
that the provisions relating to such encumbrance or restriction
contained in any such refinancing indebtedness are no less
favorable to the holders of the Second Lien Notes in any material
respect as determined by the Board of Directors of Abraxas in their
reasonable and good faith judgment that the provisions relating to
such encumbrance or restriction contained in the applicable
agreement referred to in such clause (2), (4) or (5).
34
Grey Wolf Facility.
------------------
General. On December 20, 2001, Grey Wolf entered into a credit facility
with Mirant Canada. The Grey Wolf credit facility established a revolving line
of credit with a commitment amount of CDN $150 million, (approximately US $96
million). Subject to certain restrictions, the borrowing base may be reduced in
the discretion of Mirant Canada upon 30 days written notice. Subject to earlier
termination on the occurrence of events of default or other events, the stated
maturity date of the credit facility is December 20, 2007. The applicable
interest rate charged on the outstanding balance under the Grey Wolf Facility is
9.5%. Any amounts in default under the facility will accrue interest at 15%. The
Grey Wolf credit facility is non-recourse to Abraxas and its properties, other
than Grey Wolf properties, and Abraxas has no additional direct obligations to
Mirant Canada under the facility.
Principal Payments. Prior to maturity, Grey Wolf is required to make
principal payments under the Grey Wolf credit facility as follows:
(i) on the date of the sale of any of its producing properties, Grey Wolf
is required to make a payment equal to the amount of the net sales proceeds;
(ii) on a monthly basis, Grey Wolf is required to make a payment equal to
its net cash flow for the month prior to the date of the payment; and
(iii) on the date of any reduction in the commitment amount becomes
effective, Grey Wolf must repay all amounts over the commitment amount so
reduced.
Under the Grey Wolf credit facility, "net cash flow" generally means the
amount of proceeds received by Grey Wolf from the sale of hydrocarbons less
taxes, royalty and similar payments (including overriding royalty interest
payments made to Mirant Canada), interest payments made to Mirant Canada and
operating and other expenses including approved capital and G&A expenses.
Grey Wolf may also make pre-payments at any time after December 20, 2002
with no pre-payment penalty.
The Grey Wolf credit facility matures in 2007. We treat the Grey Wolf
credit facility as a revolving line of credit since, under ordinary
circumstances, the lender is paid on a net cash flow basis. It is anticipated
that Grey Wolf will be a net borrower for the next several years due to a large
number of exploration and exploitation projects and the associated capital needs
to complete the projects.
Security. Obligations under the Grey Wolf credit facility are secured by a
security interest in substantially all of Grey Wolf's assets, including, without
limitation, working capital interests in producing properties and related assets
owned by Grey Wolf. None of Abraxas' assets are subject to a security interest
under the Grey Wolf credit facility.
Covenants. The Grey Wolf credit facility contains a number of covenants
that, among other things, restrict the ability of Grey Wolf to (i) enter into
new business areas, (ii) incur additional indebtedness, (iii) create or permit
to be created any liens on any of its properties, (iv) make certain payments,
dividends and distributions, (v) make any unapproved capital expenditures, (vi)
sell any of its accounts receivable, (vii) enter into any unapproved leasing
arrangements, (viii) enter into any take-or-pay contracts, (ix) liquidate,
dissolve, consolidate with or merge into any other entity, (x) dispose of its
assets, (xi) abandon any property subject to Mirant Canada's security interest,
(xii) modify any of its operating agreements, (xiii) enter into any unapproved
hedging agreements, and (xiv) enter into any new agreements affecting existing
agreements relating to or affecting properties subject to Mirant Canada's
security interests. In addition, Grey Wolf is required to submit a quarterly
development plan for Mirant Canada's approval and Grey Wolf must comply with
specified financial ratios and tests, including a minimum collateral coverage
ratio. Grey Wolf was in compliance with these covenants at June 30, 2002.
Events of Default. The Grey Wolf 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 the financial condition of Grey Wolf.
Overriding Royalty Interests. As a condition to the Grey Wolf credit
facility, Grey Wolf has granted two overriding royalty interests to Mirant
Canada, each in the amount of 2.5% of the revenues received by Grey Wolf from
crude oil and natural gas sales from all of its properties. These overriding
royalty interests resulted in the recording of a $2.5 million discount on the
Grey Wolf Facility borrowings at December 31, 2001.
35
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. See Hedging Sensitivity in Item 3 for further
information.
Net Operating Loss Carryforwards. At December 31, 2001 we had, subject to
the limitation discussed below, $115,900,000 of net operating loss carryforwards
for U.S. tax purposes. These loss carryforwards will expire from 2002 through
2021 if not utilized. At December 31, 2001, we had approximately $6,700,000 of
net operating loss carryforwards for Canadian tax purposes. These carryforwards
will expire from 2002 through 2008 if not 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, we 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, as described in Note 5. 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 our carryforwards. In 2000 assets with built in gains were sold,
increasing the Section 382 limitation for 2001 by approximately $31,000,000.
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, we have established a valuation
allowance of $39,670,000 and $63,149,000 for deferred tax assets at December 31,
2001 and June 30, 2002 respectively.
Item 3. Quantitative and Qualitative Disclosures about Market Risk.
Commodity Price Risk
Our exposure to market risk rests primarily with the volatile nature of
crude oil, natural gas and natural gas liquids prices. We manage crude oil and
natural gas prices through the periodic use of commodity price hedging
agreements. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations--Liquidity and Capital Resources". Assuming the production
levels we attained during the six months ended June 30, 2002, a 10% decline in
crude oil, natural gas and natural gas liquids prices would have reduced our
operating revenue, cash flow and net income (loss) by approximately $1.4 million
for the six months ended June 30, 2002.
Hedging Sensitivity
On January 1, 2001, we adopted SFAS 133 "Accounting for Derivative
Instruments and Hedging Activities" 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 Stockholder's 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
36
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.
The following table sets forth our hedging position as of June 30, 2002.
Time Period Notional Quantities Price Fair Value
- ---------------------------------------- ------------------------------ ------------------------------ ----------------
July 1, 2002 - October 31, 2002 20,000 Mcf/day of natural Fixed price swap $2.60-$2.95 $(1.7) million
gas or 1,000 Bbl/day of natural gas or
crude oil $18.90 Crude oil
On January 1, 2001, in accordance with the transition provisions of SFAS
133, we recorded $31.0 million, net of tax, in other comprehensive loss
representing the cumulative effect of an accounting change to recognize the fair
value of cash flow derivatives. We recorded cash flow hedge derivative
liabilities of $38.2 million on that date and a deferred tax asset of $7.2
million.
During the first six months of 2002 the fair value of outstanding
liabilities increased by $2.5 million. For the three months and six months ended
June 30, 2002 the ineffective portion of the cash flow hedges were not material.
As of June 30, 2002, $1.4 million of deferred net losses on derivative
instruments were recorded in Other Comprehensive Income/Loss, which is expected
to be reclassified to earnings during the next four-month period.
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.
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, 2002, a
commodity price increase of 10% would have resulted in an unfavorable change in
the fair market value of $812,000 and a commodity price decrease of 10% would
have resulted in a favorable change in fair market value of $812,000.
Interest rate risk
At June 30, 2002, substantially all of our long-term debt is at fixed
interest rates and 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 could be affected by changes in foreign currency
exchange rates or weak economic conditions in the foreign markets. Canadian
operations reported a pre tax loss of $92.3 million for the six months ended
June 30, 2002. It is estimated that a 5% change in the value of the U.S. dollar
to the Canadian dollar would have changed our pre tax income by approximately
$4.6 million. 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.
New Accounting Standards
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 requires an asset retirement obligation to
be recorded at fair value during the period incurred and an equal amount
recorded as an increase in the value of the related long-lived asset. The
capitalized cost is depreciated over the useful life of the asset and the
obligation is accreted to its present value each period. SFAS No. 143 is
effective for us beginning January 1, 2003. We are currently evaluating the
impact the standard will have on our future results of operations and financial
condition.
37
Effective January 1, 2002, we adopted SFAS No. 144 " Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 retains the
requirement to recognize an impairment loss only where the carrying value of a
long-lived asset is not recoverable from its undiscounted cash flows and to
measure such loss as the difference between the carrying amount and fair value
of the asset. SFAS No. 144, among other things, changes the criteria that have
to be met to classify an asset as held-for-sale and requires that operating
losses from discontinued operations be recognized in the period that the losses
are incurred rather than as of the measurement date. This new standard had no
impact on the our consolidated financial statements during the first six months
of 2002.
In April 2002, the FASB issued SFAS No. 145, "Recission of FASB No. 4, 44,
and 64, Amendments of FASB Statement No. 13 and Technical Corrections." SFAS No.
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 No. 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 become effective for us beginning January 1, 2003 with earlier adoption
encouraged. All other provisions of this standard have been effective for the us
as of May 15, 2002 and did not have a significant impact on our financial
condition or results of operations.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Cost Associated
with Exit or Disposal Activities." SFAS No. 146 requires costs associated with
exit of disposal activities to be recognized when they are incurred rather than
at the date of commitment to an exit or disposal plan. SFAS No. 146 is effective
for the us beginning January 1, 2003. We are currently evaluating the impact the
standard will have on its results of operations and financial condition.
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. We
are currently evaluating the impact on our results of operations and financial
condition if this Proposed Statement of Position is adopted in its current form.
Disclosure Regarding Forward-Looking Information
This report includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act and Section 21E of the Exchange Act. All
statements other than statements of historical facts included in this report
regarding our financial position, business strategy, budgets and plans and
objectives of management for future operations are forward-looking statements.
Although we believe that the expectations reflected in such forward-looking
statements are reasonable, we can give no assurance that such expectations will
prove to have been correct. Important factors that could cause actual results to
differ materially from our expectations ("Cautionary Statements") are disclosed
under "Risk Factors" in our Annual Report on Form 10-K which is incorporated by
reference herein and this report. All subsequent written and oral
forward-looking statements attributable to us, or persons acting on our behalf,
are expressly qualified in their entirety by the Cautionary Statements.
38
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
PART II
OTHER INFORMATION
Item 1. Legal Proceedings
None
Item 2. Changes in Securities
None
Item 3. Defaults Upon Senior Securities
None
Item 4. Submission of Matters to a Vote of Security Holders
At the Annual Meeting of Shareholders held on May 24, 2002 the
following proposals were adopted by the margins indicated:
1. Election of four directors for term of three years, to
hold office until the expiration of his term in 2005 or
until a successor shall have been elected & qualified.
Number of Shares
For Against
C. Scott Bartlett, Jr. 25,393,722 1,534,903
Ralph F. Cox 25,393,722 1,534,903
Frederick M. Pevow, Jr. 25,393,422 1,535,203
Joseph A. Wagda 25,393,422 1,535,203
2. Approval of the appointment of Deloitte & Touche LLP as
the Company's auditors.
Number of Shares
For Against Abstain
26,076,505 83,945 768,177
Item 5. Other Information
None
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Exhibit 99.1 Certification pursuant to 18 U.S.C. Section 1350
- Robert L.G. Watson, CEO
Exhibit 99.2 Certification pursuant to 18 U.S.C. Section 1350
- Chris E. Williford, CFO
(b) Reports on Form 8-K:
1. Current Report of the Form 8-K filed on April 23, 2002. Other
Events, including a press release relating to Canadian winter
drilling activity.
2. Current Report on the Form 8-K filed on May 1, 2002. Other
Events, including a press release relating to deferral of
interest payment.
3. Current Report on the Form 8-K filed on May 14, 2002. Other
Events, including a press release relating to the
announcement of the Company's first quarter 2002 financial
results and West Texas drilling results.
4. Current Report on Form 8-K filed on July 9, 2002. Acquisition
or Disposition of Assets, announcing the Company's
divestiture of properties in Alberta, Canada and South Texas.
39
5. Current Report on Form 8-K/A filed on August 8, 2002 to amend
the Form 8-K filed on July 9, 2002, to include the pro-forma
financial statements relating to the property divestitures.
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
ABRAXAS PETROLEUM CORPORATION
(Registrant)
Date: August 19, 2002 By:/s/
----------------- -------------------------------
ROBERT L.G. WATSON,
President and Chief
Executive Officer
Date: August 19, 2002 By:/s/
----------------- -------------------------------
CHRIS WILLIFORD,
Executive Vice President and
Principal Accounting Officer
40
EXHIBIT 99.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of Abraxas Petroleum Corporation (the
"Company") on Form 10-Q for the period ending June 30, 2002 as filed with the
Securities and Exchange Commission on the date thereof (the "Report"), I, Robert
L.G. Watson, Chairman of the Board, President and Chief Executive Officer of the
Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, that:
(1)The report fully complies with the requirements of Section 13(a) or
15(d) of the Securities Act of 1934; and
(2)The information contained in the Report fairly presents, in all
material respects, the financial condition and results of operations
of the Company.
/s/ Robert L.G. Watson
Robert L.G. Watson
Chairman of the Board,
President and Chief Executive Officer
August 19, 2002
41
EXHIBIT 99.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of Abraxas Petroleum Corporation (the
"Company") on Form 10-Q for the period ending June 30, 2002 as filed with the
Securities and Exchange Commission on the date thereof (the "Report"), I, Chris
E, Williford, Executive Vice President and Chief Financial Officer of the
Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, that:
(1)The report fully complies with the requirements of Section 13(a) or
15(d) of the Securities Act of 1934; and
(2)The information contained in the Report fairly presents, in all
material respects, the financial condition and results of operations
of the Company.
42