UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One) FORM10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarter Ended March 31, 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 May 14,
2002 was:
Class Shares Outstanding
Common Stock, $.01 Par Value 29,979,397
1 of 35
Abraxas Petroleum Corporation is filing this Amendment Number 1 to
Quarterly Report on Form 10-Q for the period ended March 31, 2002, in order to
correct the Consolidated Statement of Operations, Other (income) expense for
items reported in the wrong column. This revision is due to the correction of
errors iincurred in the Edgar conversion process. Pursuant to Rule 12b-15 under
the Securities Exchange Act of 1934, the complete text of Form 10-Q as revised
is included in this filing
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
FORM 10 - Q
INDEX
PART I
FINANCIAL INFORMATION
ITEM 1 - Financial Statements (Unaudited)
Consolidated Balance Sheets - March 31, 2002
and December 31, 2001................................3
Consolidated Statements of Operations -
Three Months Ended March 31, 2002 and 2001...........5
Consolidated Statement of Stockholders Equity (Deficit)
March 31, 2002 and December 31, 2001.................6
Consolidated Statements of Cash Flows -
Three Months Ended March 31, 2002 and 2001...........7
Notes to Consolidated Financial Statements....................8
ITEM 2 - Managements Discussion and Analysis of Financial
Condition and Results of Operations.................20
ITEM 3 - Quantitative and Qualitative Disclosure about Market Risks...32
PART II
OTHER INFORMATION
ITEM 1 - Legal proceedings 34
ITEM 2 - Changes in Securities.............................................34
ITEM 3 - Defaults Upon Senior Securities...................................34
ITEM 4 - Submission of Matters to a Vote of Security Holders...............34
ITEM 5 - Other Information 34
ITEM 6 - Exhibits and Reports on Form 8-K..................................34
Signatures ................................................35
2
Abraxas Petroleum Corporation and Subsidiaries
Part 1- Financial Information
Item 1 - Financial Statements
Consolidated Balance Sheets
March 31, December 31,
2002 2001
(Unaudited)
------------------------
(In Thousands)
Assets:
Current assets:
Cash ....................................................... $ 3,851 $ 7,605
Accounts receivable, less allowances for doubtful
accounts:
Joint owners ........................................ 2,884 2,785
Oil and gas production .............................. 3,824 4,758
Other ............................................... 548 504
-------- --------
7,256 8,047
Equipment inventory ......................................... 1,160 1,251
Other current assets ........................................ 1,050 443
-------- --------
Total current assets ...................................... 13,317 17,346
Property and equipment:
Oil and gas properties, full cost method of accounting:
Proved .................................................. 505,195 486,098
Unproved, not subject to amortization ................... 5,937 10,626
Other property and equipment ............................... 69,962 67,632
-------- --------
Total .............................................. 581,094 564,356
Less accumulated depreciation, depletion, and
amortization .......................................... 289,028 282,462
-------- --------
Total property and equipment - net ...................... 292,066 281,894
Deferred financing fees, net of accumulated amortization
of $9,095 and $8,668 at March 31, 2002 and December 31, 2001,
respectively ................................................ 3,464 3,928
Other assets .................................................. 447 448
-------- --------
Total assets ................................................ $309,294 $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)
March 31, December 31,
2002 2001
(Unaudited)
-----------------------
(In Thousands)
Liabilities and Shareholder's Equity (Deficit)
Current liabilities:
Accounts payable ......................................... $ 17,805 $ 10,542
Oil and gas production payable ........................... 2,307 3,596
Accrued interest ......................................... 9,378 6,013
Other accrued expenses ................................... 1,521 1,116
Hedge liability .......................................... 3,256 658
Current maturities of long-term debt ..................... 63,911 415
--------- ---------
Total current liabilities ...................... 98,178 22,340
Long-term debt ............................................. 227,103 285,184
Deferred income taxes ...................................... 19,742 20,621
Future site restoration .................................... 3,997 4,056
Shareholders' equity (deficit):
Common Stock, par value $.01 per share-
Authorized 200,000,000 shares; issued,
30,145,280 at March 31, 2002 and December 31, 2001....... 301 301
Additional paid-in capital .............................. 136,733 136,733
Accumulated deficit ...................................... (159,793) (151,094)
Treasury stock, at cost, 165,883 shares .................. (964) (964)
Accumulated other comprehensive loss ..................... (16,003) (13,561)
--------- ---------
Total shareholders' deficit .......................... (39,726) (28,585)
--------- ---------
Total liabilities and shareholders' equity (deficit)....... $ 309,294 $ 303,616
========= =========
See accompanying notes to consolidated financial statements
4
Abraxas Petroleum Corporation and Subsidiaries
Consolidated Statements of Operations
(Unaudited)
Three Months Ended
March 31,
-----------------------
2002 2001
-----------------------
(In thousands except
per share data)
Revenue:
Oil and gas production revenues ........................... $ 10,886 $ 28,249
Gas processing revenue .................................... 670 436
Rig revenues .............................................. 151 183
Other ..................................................... 100 218
-------- --------
11,807 29,086
Operating costs and expenses:
Lease operating and production taxes ...................... 3,909 4,859
Depreciation, depletion and amortization .................. 6,814 8,841
Rig operations ............................................ 121 153
General and administrative ................................ 1,698 2,109
General and administrative (Stock-based Compensation) ..... -- 931
-------- --------
12,542 16,893
-------- --------
Operating Income (Loss) ...................................... (735) 12,193
Other (income) expense
Interest income ........................................... (33) (16)
Interest expense .......................................... 8,413 7,781
Amortization of deferred financing fees ................... 427 455
Other ..................................................... -- 16
-------- --------
8,807 8,236
-------- --------
Income (Loss) from operations before taxes ................... (9,542) 3,957
Income tax expense (benefit) ................................. (843) 2,776
Minority interest in income of consolidated foreign subsidiary -- (926)
-------- --------
Net Income (Loss) ............................................ $ (8,699) $ 255
======== ========
Earnings per share:
Net income per common share - basic ...................... $ (0.29) $ .01
======== ========
Net income per common - diluted .......................... $ (0.29) $ .01
======== ========
See accompanying notes to consolidated financial statements
5
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)
(In thousands except share amounts)
Accumulated
Common Stock Treasury Stock Additional Other
-------------------- ---------- ----------- Paid-In Accumulated Comprehensive
Shares Amount Shares Amount Capital Deficit Income(Loss) Total
----------- ---------- -------- --------- ----------- ----------- ----------- ----------
Balance at December 31, 2001.............. 30,145,280 $ 301 165,883 $ (964) $ 136,733 $ (151,094) $(13,561) $ (28,585)
Comprehensive income (loss) - Note 8
Net loss................................ - - - - - (8,699) - (8,699)
Other comprehensive income:
Hedge loss............................ - - - - - - (2,075) (2,075)
Foreign currency translation
adjustment........................... - - - - - - (367) (367)
---------
Comprehensive income (loss)........ - - - - - - - (11,141)
----------- --------- ---------- -------- ------------- ----------- ---------- ---------
Balance at March 31, 2002................. 30,145,280 $ 301 165,883 $ (964) $ 136,733 $ (159,793) (16,003) $ (39,726)
=========== ========= ========== ======== ============= =========== ========== =========
See accompanying notes to consolidated financial statements
6
Abraxas Petroleum Corporation and Subsidiaries
Consolidated Statements of Cash Flows
(Unaudited)
Three Months Ended
March 31,
-----------------------
2002 2001
------------ ----------
(In thousands)
Operating Activities
Net income (loss) ................................................... $ (8,699) $ 255
Adjustments to reconcile net income to net cash provided by operating
activities:
Minority interest in income of foreign subsidiary .................. -- 926
Depreciation, depletion, and amortization .......................... 6,814 8,841
Deferred income tax (benefit) expense .............................. (843) 2,695
Amortization of deferred financing fees ............................ 427 455
Amortization of debt discount ...................................... 113
Stock-based compensation ........................................... -- 931
Changes in operating assets and liabilities:
Accounts receivable ............................................ 1,099 6,585
Equipment inventory ............................................ 91 44
Other .......................................................... (87) (54)
Accounts payable and accrued expenses .......................... 9,367 (3,254)
-------- --------
Net cash provided by operating activities ........................... 8,282 17,424
-------- --------
Investing Activities
Capital expenditures, including purchases and development
of properties ..................................................... (17,408) (17,861)
Proceeds from sale of oil and gas producing properties .............. -- 44
-------- --------
Net cash used in investing activities ............................... $(17,408) $(17,817)
-------- --------
Financing Activities
Proceeds from long-term borrowings .................................. 6,096 3,320
Payments on long-term borrowings .................................... (719) (2,827)
Deferred financing fees ............................................. (8)
Exercise of stock options ........................................... -- 10
-------- --------
Net cash provided by financing activities ........................... 5,377 495
-------- --------
Effect of exchange rate changes on cash ............................. (5) (38)
-------- --------
Increase (decrease) in cash ......................................... (3,754) 64
Cash, at beginning of period ........................................ 7,605 2,004
-------- --------
Cash, at end of period .............................................. $ 3,851 $ 2,068
======== ========
Supplemental disclosures of cash flow information:
Interest paid ....................................................... $ 4,935 $ 4,414
======== ========
See accompanying notes to consolidated financial statements
7
Abraxas Petroleum Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Unaudited)
March 31, 2002
Note 1. Basis of Presentation
Theaccounting policies followed by Abraxas Petroleum Corporation and its
subsidiaries (the "Company" or "Abraxas") are set forth in the notes to the
Company's audited financial statements in the Annual Report on Form 10-K filed
for the year ended December 31, 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 months ended March 31, 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. Liquidity
At March 31, 2002 the Company's current liabilities of approximately $98.2
million exceeded its current assets of $13.3 million. Included in current
liabilities are trade payables of $17.8 million, revenues due third parties of
$2.3 million, accrued interest of $9.4 million and current maturities of
long-term debt of $63.9 million. Current maturities of long-term debt includes
$63.5 million of the Second Lien Notes, due March 2003.
Included in the $9.4 million of accrued interest is $ 9.1 million of the $
11.0 million due May 1, 2002 on the Old Notes and the Second Lien Notes, which
payment was not made. The Company has a 30-day grace period in which to make
this $11.0 million payment before an "event of default" occurs. The total
interest due is $11.0 million. Should such 30-day period expire without the
interest payment being made, the event of default would also result in an event
of default under the indenture related to the First Lien Notes. Such event of
default would allow for the holders of the Old Notes, the First Lien Notes and
the Second Lien Notes to declare the entire principal and unpaid interest on all
of the Company's outstanding notes ($254.5 million) to be due and payable.
The Company has four principal sources of liquidity going forward: (i) cash
on hand, (ii) cash flow from operations, (iii) a production payment related to
certain U.S. properties, and (iv) sale of assets and property. Grey Wolf also
has availability under its financing agreement entered into in December 2001.
The First Lien Notes indenture, the Second Lien Notes indenture and the Old
Notes indenture substantially limit the use of proceeds from asset sales. Most
of the Company's capital expenditures are discretionary and can be delayed to
maintain current liquidity.
In December 2001, the Company's wholly owned subsidiary, Grey Wolf, entered
into a financing agreement ("Grey Wolf Facility") with Mirant Canada Energy
Capital, Ltd. ("Mirant Canada") for US $96 million (CDN $150 million) senior
secured facility, which is non-recourse to Abraxas. Initial proceeds from this
facility of approximately US $25 million were used to retire Grey Wolf's
existing bank debt and for general corporate purposes. Up to US $71 million is
available to finance the drilling of wells and related activities in the Grey
Wolf development plan, as anticipated over the next two years.
8
The Company's wholly owned Canadian subsidiaries, Canadian Abraxas and Grey
Wolf, entered into a definitive Purchase and Sale Agreement related to the sale
of their interest in a natural gas plant and the associated reserves. The sale,
effective March 1, 2002, is expected to close on or about May 23, 2002 with
estimated net proceeds of US $21.5 million.
The Company has recently engaged Randall & Dewey, Inc. to explore a
potential sale of certain properties located in Texas. The data room was opened
in March of 2002, with bids due in the second quarter of 2002. There are no
definitive agreements related to this potential sale and there can be no
assurance that any sale will occur or, if it does, the sales price that would be
received.
If all of the potential sales are ultimately closed, we anticipate
aggregate proceeds in the range of $50 million to $100 million.
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 capital and/or reduce or reschedule its existing cash
requirements. 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.
The Company has implemented a number of measures to conserve its cash
resources, including postponement of certain exploration and development
projects. However, while these measures will help conserve the Company's cash
resources in the near term, they will also limit the Company's ability to
replenish its depleting reserves, which could negatively impact the Company's
operating cash flow and results of operations in the future.
Due to our current debt levels and the restrictions contained in the
indentures, our best opportunity for additional sources of 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. While the availability of capital resources and future liquidity cannot
be predicted with certainty and is dependent upon a number of factors including
factors outside of management's control, management believes that the net cash
flow from operations plus cash on hand, cash available under other arrangements
and the proceeds from the sale of properties will be adequate to fund operations
and planned capital expenditures for the foreseeable future, and the repayment
of the $63.5 million in principal amount of the First Lien Notes maturing in
March 2003.
Note 3. Long-Term Debt
Long-term debt consists of the following:
March 31 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
9.5% Senior Credit Facility ("Grey Wolf Facility"), providing for
borrowings up to approximately US $96 million (CDN $150 million).
Secured by the assets of Grey Wolf and non-recourse to Abraxas,
net of US $2.1 and $2.3 million discount at March 31, 2002 and
December 31, 2001, respectively.................................. 29,112 22,944
Production Payment ................................................... 7,423 8,176
----------------- -----------------
291,014 285,599
Less current maturities ............................................... 63,911 415
----------------- -----------------
$ 227,103 $ 285,184
================= =================
9
Old Notes. On November 14, 1996, the Company consummated the offering of
$215.0 million of it's 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.
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
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
10
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
Grey Wolf Facility
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.
11
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 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.
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.
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.
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.
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.
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.
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 result 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. As of March 31, 2002, the Company had
received $22.1 million under this agreement. The outstanding balance as of March
31, 2002 is $7.4 million.
Note 4. Earnings Per Share
The following table sets forth the computation of basic and diluted earnings
per share:
12
Three Months Ended March 31,
-------------------------------
2002 2001
--------------- ---------------
Numerator:
Numerator for basic and diluted earnings per share - income (in
thousands) ......................................................... $ (8,699) $ 255
Denominator:
Denominator for basic earnings per share - weighted-average shares .... 29,979,397 22,595,969
Effect of dilutive securities:
Stock options, Warrants and CVRs ................................... -- 4,681,387
------------ ------------
Dilutive potential common shares
Denominator for diluted earnings per share - adjusted weighted-average
shares and assumed Conversions ..................................... 29,979,397 27,277,356
Basic earnings per share: ............................................... $ (0.29) $ 0.01
============ ============
Diluted earnings per share: ............................................. $ (0.29) $ 0.01
============ ============
For the three months ended March 31, 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 45,982 shares for the three months ended March 31, 2002.
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 5. 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 March 31, 2002 and December 31, 2001 and the related
consolidating statements of operations for the three months ended March 31, 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.
Condensed Consolidating Parent Company, Restricted Subsidiaries
and Non-Guarantor Balance Sheet
March 31, 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 .................................... $ (220) $ 1,215 $ 2,856 $ - $ 3,851
Accounts receivable, less allowance for
doubtful accounts...................... 15,642 777 12,320 (21,483) 7,256
Equipment inventory ..................... 970 178 12 - 1,160
Other current assets .................... 230 696 124 - 1,050
13
------------- ------------- ------------- -------------- ---------------
Total current assets .................. 16,622 2,866 15,312 (21,483) 13,317
Property and equipment - net................ 116,328 121,767 53,971 - 292,066
Deferred financing fees, net .............. 2,393 950 121 - 3,464
Other assets ............................... 108,708 783 - (109,044) 447
------------- ------------- ------------ --------------- --------------
Total assets ............................ $ 244,051 $ 126,366 $ 69,404 $ (130,527) 309,294
============= ============= ============ ================ ==============
Liabilities and Stockholder's deficit:
Current liabilities:
Accounts payable ............................. $ 10,060 $ 17,461 $ 13,992 $ (21,401) $ 20,112
Accrued interest ............................. 6,856 2,522 - - 9,378
Other accrued expenses ....................... 1,521 - - - 1,521
Hedge liability .............................. 1,791 1,465 - - 3,256
Current maturities of long-term debt ......... 63,911 - - - 63,911
------------- ------------- ------------ --------------- --------------
Total current liabilities .................. 84,139 21,448 13,992 (21,401) 98,178
Long-term debt .................................. 145,362 52,629 29,112 - 227,103
Deferred income taxes ........................... - 16,885 2,857 - 19,742
Future site restoration ........................ - 3,323 674 - 3,997
------------- ------------- ------------ --------------- --------------
229,501 94,285 46,635 (21,401) 349,020
Stockholders' equity (deficit)................... 14,550 32,081 22,769 (109,126) (39,726)
------------- ------------- ------------ --------------- --------------
Total liabilities and stockholders' equity
(deficit)........................................ $ 244,051 $ 126,366 $ 69,404 $ (130,527) $ 309,294
============= ============= ============ ================ ==============
(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
------------- ------------- ------------ --------------- --------------
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
14
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 March 31, 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 ............... $ 4,461 $ 3,794 $ 2,631 $ - $ 10,886
Gas processing revenues ....................... - 552 118 - 670
Rig revenues .................................. 151 - - - 151
Other ........................................ 4 55 41 - 100
----------- ----------- ------------ ------------ ------------
4,616 4,401 2,790 - 11,807
Operating costs and expenses:
Lease operating and production taxes .......... 1,878 1,324 707 - 3,909
Depreciation, depletion, and amortization ..... 2,253 3,169 1,392 - 6,814
Rig operations ................................ 121 - - - 121
General and administrative .................... 900 511 287 - 1,698
----------- ----------- ------------ ------------ ------------
5,152 5,004 2,386 - 12,542
----------- ----------- ------------ ------------ ------------
Operating income (loss)........................... (536) (603) 404 - (735)
Other (income) expense:
Interest income ............................... (33) - - - (33)
Amortization of deferred financing fees........ 331 90 6 - 427
Interest expense............................... 6,235 1,682 496 - 8,413
----------- ----------- ------------ ------------ ------------
6,533 1,772 502 - 8,807
----------- ----------- ------------ ------------ ------------
Income (loss) from operations before income tax
and extraordinary item......................... (7,069) (2,375) (98) - (9,542)
Income tax expense (benefit)...................... - (802) (41) - (843)
----------- ----------- ------------ ------------ ------------
Net income (loss)................................ $ (7,069) $ (1,573) $ (57) $ - $ (8,699)
=========== =========== ============ ============ ============
Condensed Consolidating Parent Company, Restricted Subsidiary and
Non-Guarantor Statement of Operations
For the three months ended March 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
----------- ----------- ------------ ------------ ------------
Revenues:
Oil and gas production revenues ............... $ 13,031 $ 9,642 $ 5,576 $ - $ 28,249
Gas processing revenues ....................... - 368 68 - 436
Rig revenues .................................. 183 - - - 183
Other ........................................ 3 129 86 - 218
----------- ----------- ------------ ------------ ------------
13,217 10,139 5,730 - 29,086
15
Operating costs and expenses:
Lease operating and production taxes .......... 2,667 1,699 493 - 4,859
Depreciation, depletion, and amortization ..... 3,204 4,252 1,385 - 8,841
Rig operations ................................ 153 - - - 153
General and administrative .................... 1,315 448 346 - 2,109
General and administrative (Stock-based
Compensation)................................ 931 - - - 931
----------- ----------- ------------ ------------ ------------
8,270 6,399 2,224 - 16,893
----------- ----------- ------------ ------------ ------------
Operating income (loss)........................... 4,947 3,740 3,506 - 12,193
Other (income) expense:
Interest income ............................... (399) - - 383 (16)
Amortization of deferred financing fees........ 347 108 - - 455
Interest expense .............................. 6,172 1,887 105 (383) 7,781
Other ......................................... 16 - - - 16
----------- ----------- ------------ ------------ ------------
6,136 1,995 105 - 8,236
----------- ----------- ------------ ------------ ------------
Income (loss) from operations before income tax
and extraordinary item......................... (1,189) 1,745 3,401 - 3,957
Income tax expense (benefit)...................... - 1,179 1,597 - 2,776
Minority interest in income of consolidated 112
foreign subsidiary ............................ - - - (926) (926)
----------- ----------- ------------ ------------ ------------
Net income (loss)................................. $ (1,189) $ 566 $ 1,804 $ (926) $ 255
=========== =========== ============ ============ ============
Condensed Consolidating Partent, Restricted Subsidiary and
Non-Guarantor Statement of Cash Flow
For the three months ended March 31, 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 .................................... $ (7,069) $ (1,573) $ (57) $ $ (8,699)
Adjustments to reconcile net income (loss)
to net cash provided by operating
activities:
Depreciation, depletion, and
amortization ......................... 2,253 3,169 1,392 - 6,814
Deferred income tax benefit............. - (802) (41) - (843)
Amortization of deferred financing fees. 331 90 6 - 427
Amortization of debt discount........... - - 113 113
Changes in operating assets and
liabilities:
Accounts receivable ................ 1,639 (612) 72 - 1,099
Equipment inventory ................ 91 - - - 91
Other ............................. 16 (90) (13) - (87)
Accounts payables and accrued
expenses ......................... 1,743 2,532 5,092 - 9,367
-------------- ------------ ------------- --------------- --------------
Net cash provided (used) by operating
activities ............................... (996) 2,714 6,564 - 8,282
Investing Activities
Capital expenditures, including purchases
and development of properties ............ (2,119 (2,740) (12,549) - (17,408)
-------------- ------------ ------------- --------------- --------------
Net cash used by investing activities ...... (2,119) (2,740) (12,549) - (17,408)
16
Financing Activities
Proceeds from long-term borrowings .......... - - 6,096 - 6,096
Payments on long-term borrowings ............ (698) - (21) - (719)
-------------- ------------ ------------- --------------- --------------
Net cash provided (used) by financing
Activities.................................. (698) - 6,075 - 5,377
-------------- ------------ ------------- --------------- --------------
-
Effect of exchange rate changes on cash ..... - (4) (1) - (5)
-------------- ------------ ------------- --------------- --------------
Increase (decrease) in cash ................. (3,813) (30) 89 - (3,754)
Cash at beginning of year ................... 3,593 1,245 2,767 - 7,605
-------------- ------------ ------------- --------------- --------------
Cash at end of year.......................... $ (220) $ 1,215 $ 2,856 $ - $ 3,851
============== ============ ============= =============== ==============
Condensed Consolidating Partent, Restricted Subsidiary and
Non-Guarantor Statement of Cash Flow
For the three months ended March 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
-------------- ------------ ------------- --------------- --------------
Operating Activities
Net income (loss) ........................... $ (1,189)$ 566 $ 1,804 $ (926) $ 255
Adjustments to reconcile net income (loss)
to net cash provided by operating activities:
Minority interest in income of foreign
subsidiary ........................... - - - 926 926
Depreciation, depletion, and
amortization ......................... 3,204 4,252 1,385 - 8,841
Deferred income tax expense (benefit)... - 1,114 1,581 - 2,695
Amortization of deferred financing fees. 347 108 - - 455
Stock-based compensation ............... 931 - - - 931
Changes in operating assets and
liabilities:
Accounts receivable ................ 8,475 (1,456) (1,062) 628 6,585
Equipment inventory ................ 44 - - - 44
Other ............................. (141) - 87 - (54)
Accounts payables and accrued
expenses ......................... (4,668) 2,415 (373) (628) (3,254)
-------------- ------------ ------------- --------------- --------------
Net cash provided by operating activities ... 7,003 6,999 3,422 - 17,424
Investing Activities
Capital expenditures, including purchases
and development of properties ............ (6,872) (6,736) (4,253) - (17,861)
Proceeds from sale of oil and gas
properties ............................... - 32 12 - 44
-------------- ------------ ------------- --------------- --------------
Net cash provided (used) by investing
activities ............................... (6,872) (6,704) (4,241) - (17,817)
Financing Activities
Proceeds from long-term borrowings .......... 2,500 - 820 - 3,320
Payments on long-term borrowings ............ (2,827) - - - (2,827)
Exercise of stock options ................... 10 - - - 10
Deferred financing fees...................... (8) - - - (8)
-------------- ------------ ------------- --------------- --------------
Net cash provided (used) by financing
activities ............................... (325) - 820 - 495
-------------- ------------ ------------- --------------- --------------
-
Effect of exchange rate changes on cash ..... - (37) (1) - (38)
-------------- ------------ ------------- --------------- --------------
Increase (decrease) in cash ................. (194) 258 - - 64
Cash at beginning of period ................. 326 1,678 - - 2,004
-------------- ------------ ------------- --------------- --------------
17
Cash at end of period........................ $ 132 $ 1,936 $ - $ - $ 2,068
============== ============ ============= =============== =============
Note 6. Business Segments
Business segment information about our first quarter operations in different
geographic areas is as follows:
Three Months Ended March 31, 2002
----------------------------------------------------------
U.S. Canada Total
------------------ ------------------ -------------------
(In thousands)
Revenues ................................ $ 4,616 $ 7,191 $ 11,807
================== ================== ===================
Operating profit ........................ $ 454 $ (199) $ 255
================== ==================
General corporate ....................... (990)
Interest expense and amortization of
deferred financing fees .............. (8,807)
-------------------
Income before income taxes ........... $ (9,542)
===================
Identifiable assets at March 31, 2002 ... $ 177,214 $ 127,505 $ 304,719
================== ==================
Corporate assets ........................ 4,575
-------------------
Total assets ......................... $ 309,294
===================
Three Months Ended March 31, 2001
----------------------------------------------------------
U.S. Canada Total
------------------ ------------------ -------------------
(In thousands)
Revenues ................................ $ 13,217 $ 15,869 $ 29,086
================== ================== ===================
Operating profit ........................ $ 7,246 $ 7,283 $ 14,529
================== ==================
General corporate ....................... (2,336)
Interest expense and amortization of
deferred financing fees .............. (8,220)
Other income............................. (16)
-------------------
Income before income taxes ........... $ 3,957
===================
Year Ended December 31, 2001
----------------------------------------------------------
U.S. Canada Total
------------------ ------------------ -------------------
Identifiable assets...................... $ 124,993 $ 174,063 $ 299,056
================== ==================
Corporate assets......................... 4,657
-------------------
Total assets.......................... $ 303,713
===================
Note 7. 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.
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
18
basis. Hedge accounting is discontinued prospectively when a hedge instrument
becomes ineffective. Gains and losses deferred in accumulated Other
Comprehensive Income/Loss related to a cash flow hedge that becomes ineffective,
remain unchanged until the related production is delivered. If the Company
determines that it is probable that a hedged transaction will not occur,
deferred gains or losses on the hedging instrument are recognized in earnings
immediately.
Gains and losses on hedging instruments related to accumulated Other
Comprehensive Income/Loss and adjustments to carrying amounts on hedged
production are included in natural gas or crude oil production revenue in the
period that the related production is delivered.
The following table sets forth the Company's hedge position as of March 31,
2002.
Time Period Notional Quantities Price Fair Value
-------------------------------------- ---------------------------------- ------------------------------ ------------
April 1, 2002 - October 31, 2002 20,000 Mcf/day of natural gas Fixed price swap $2.60-$2.95 $(3.3)
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 quarter of 2002 the fair value of the hedge increased by
$2.6 million. For the three months ended March 31, 2002, the ineffective portion
of the cash flow hedges were not material
As of March 31, 2002, $2.6 million of deferred net losses on derivative
instruments were recorded in other comprehensive income, of which $2.6 million
is expected to be reclassified to earnings during the next seven-month period.
All hedge transactions are subject to the Company's risk management policy,
approved by the Board of Directors. The Company formally documents all
relationships between hedging instruments and hedged items, as well as its risk
management objectives and strategy for undertaking the hedge. This process
includes specific identification of the hedging instrument and the hedged
transaction, the nature of the risk being hedged and how the hedging
instrument's effectiveness will be assessed. Both at the inception of the hedge
and on an ongoing basis, the Company assesses whether the derivatives that are
used in hedging transactions are highly effective in offsetting changes in cash
flows of hedged items.
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 March 31, 2002, a
commodity price increase of 10% would have resulted in an unfavorable change in
the fair market value of $1.4 million and a commodity price decrease of 10%
would have resulted in a favorable change in fair market value of $1.4 million.
Note 8. 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 interest in the 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 limits 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 March 31, 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
19
Note 9. 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 quarter ended March 31, 2002:
Three Months Ending
March 31, 2002
(In thousands)
---------------------------------
Accumulated other comprehensive loss at December 31, 2001....................... $ (13,561)
Net loss..................................................................... $ (8,699)
Other Comprehensive loss :
Hedging derivatives (net of tax) - See Note 6
Change in fair market value of outstanding hedge positions................. (2,075)
Foreign currency translation adjustment...................................... (367)
-------------
Other comprehensive loss........................................................ (2,442) (2,442)
-------------
Comprehensive loss.............................................................. (11,141)
============= ------------
Accumulated other comprehensive loss at March 31, 2002.......................... $ (16,003)
============
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
PART I
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of perations
-------------------------------------------------------------------------------
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 three of the last four years and the quarter
ended March 31, 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. During 2001 crude oil and natural gas prices weakened
substantially from the 2000 levels. Prices improved during the first quarter of
2002 from their year end 2001 levels. In addition, because our proved reserves
will decline as crude oil, natural gas and natural gas liquids are produced,
unless we are successful in acquiring 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.
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.
20
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.
The table below illustrates how natural gas prices fluctuated over the
course of 2001 and the first quarter of 2002. "Index" represents the last three
days average of NYMEX traded contracts index price. The "Realized" price is the
natural gas price realized by the Company during the quarter, and it includes
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,
2001 2001 2001 2001 2002
------------- ------------ ----------------- --------------- -------------
Index $ 7.27 $ 4.82 $ 2.98 $ 2.47 $ 2.38
Realized 4.85 3.41 2.26 2.09 2.21
The NYMEX natural gas price on May 14, 2002 was $3.85 per Mcf.
Prices for crude oil have followed a similar path as the commodity market
fell throughout 2001and the quarter of 2002. The table below contains the last
three days average of NYMEX traded contracts index price ("Index") and the
prices realized by the Company during each quarter for 2001 and the first
quarter of 2002..
(in $ per Bbl) Crude oil Prices by Quarter
Quarter ended
------------------------------------------------------------------------------
March 31, June 30, September 30, December 31, March 31, 2002
2001 2001 2001 2001 2002
------------- ------------ ----------------- --------------- -----------------
Index $ 29.86 $ 27.94 $ 26.50 $ 22.12 $ 19.48
Realized 27.22 25.32 25.06 18.72 16.64
The NYMEX crude oil price on May 14, 2002 was $29.36 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 March 31, 2002, Barrett Resources Corporation ("Barrett") had a swap
call on either 1,000 Bbls of crude oil or 20,000 MMBtu of natural gas per day at
Barrett'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 March 31, 2002, the fair market
value of the remaining fixed price hedge agreement was a liability of
approximately $3.3 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.
Three Months Ended
March 31,
---------------------------------
2002 2001
----------- --- ----------
Operating Revenue (in thousands):
Crude Oil Sales ........................... $ 1,232 $ 3,602
Natural Gas Sales ........................... 8,782 22,426
Natural Gas Liquids Sales.................... 872 2,221
Processing Revenue........................... 670 436
Rig Operations............................... 151 183
Other........................................ 100 218
----------- --- ----------
$ 11,807 $ 29,086
=========== === ==========
21
Operating Income (Loss) in thousands)........ $ (735) $ 12,193
Crude Oil Production (MBBLS)................. 74.0 132.3
Natural Gas Production (MMCFS)............... 3,973.1 4,626.8
Natural Gas Liquids Production (MBBLS)....... 68.4 78.1
Average Crude Oil Sales Price ($/BBL)........ $ 16.64 $ 27.22
Average Natural Gas Sales Price ($/MCF)...... $ 2.21 $ 4.85
Average Liquids Sales Price ($/BBL).......... $ 12.76 $ 28.44
Comparison of Three Months Ended March 31, 2002 to Three Months Ended March 31,
2001
Operating Revenue. During the three months ended March 31, 2002, operating
revenue from crude oil, natural gas and natural gas liquid sales decreased to
$10.9 million compared to $28.2 million in the three months ended March 31,
2001. The decrease in revenue was primarily due to decreased prices realized
during the period, and by a decline in production volumes. Lower commodity
prices impacted crude oil and natural gas revenue by $14.8 million while reduced
production volumes had a $2.5 million negative impact on revenue.
Average sales prices net of hedging losses for the quarter ended March 31,
2002 were:
o $ 16.64 per Bbl of crude oil,
o $ 12.76 per Bbl of natural gas liquid, and
o $ 2.21 per Mcf of natural gas
Average sales prices net of hedging losses for the quarter ended March 31, 2001
were:
o $27.22 per Bbl of crude oil,
o $28.44 per Bbl of natural gas liquid, and
o $ 4.85 per Mcf of natural gas
Crude oil production volumes declined from 132.3 MBbls during the quarter ended
March 31, 2001 to 74.0 MBbls for the same period of 2002, primarily as a result
of the de-emphasis on crude oil drilling in prior periods, a natural decline in
production and the sale of non-core properties in 2001. Natural gas production
volumes declined to 3,973.1 MMcf for the three months ended March 31, 2002 from
4,626.8 MMcf for the same period of 2001. This decline was primarily due to the
sale of non-core properties in late 2001 and the natural decline in production,
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 March 31, 2002 decreased to
$3.9 million from $4.9 million for the same period in 2001. The decrease in LOE
is primarily due to a decrease in production tax expense due to higher commodity
prices in the quarter ended March 31, 2001 compared to the same period of 2002.
Our LOE on a per MCFE basis for the three months ended March 31, 2002 was $0.81
per MCFE compared to $0.82 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 quarter of 2002 compared to the same period in 2001.
General and adminsitrative ("G&A") Expenses. G&A expenses decreased from
$2.1 million for the first three months of 2001 to $1.7 million for the first
three months of 2002. G&A expense on a per MCFE basis was $0.34 for the first
quarter of 2002 compared to $0.36 for the same period of 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. Additionally we
incurred higher medical insurance cost in the first quarter of 2001 compared to
the same period of 2002. The decrease in G&A expense on a per MCFE basis was due
to lower cost offset by a decline in production volumes during the first quarter
of 2002 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
December 15, 1998, and not exercised prior to July 1, 2000, require that the
awards be accounted for as variable 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
22
recognized approximately $931,000 as stock-based compensation expense during the
quarter ended March 31, 2001 related to these repricings. 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 $6.8 million for the three months
ended March 31, 2002 from $8.8 million for the same period of 2001. Our DD&A on
a per MCFE basis for the three months ended March 31, 2002 was $1.42 per MCFE
compared to $1.50 in 2001. These decreases were due to a reduction in the full
cost pool as the result of a ceiling limitation write-down relating to our
Canadian producing properties at December 31, 2001 as well as reduced production
volumes in 2002.
Interest Expense. Interest expense increased to $8.4 million for the first
three months 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 facility.
Minority interest. We owned a 49% 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 thee months of 2001 was $926,000. As of March 31, 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 $843,000 for the first
three months of 2002 compared to an expense of $2.8 million for the same period
of 2001. This decrease is due to reduced profitability in our operations,
primarily as a result of lower commodity prices.
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 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 down-turns 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. Prices for natural gas and
crude oil have increased substantially since March 31, 2002; however, we cannot
assure you that these prices can be sustained in the future. Furthermore, low
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 produced by us 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 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
The Company deferred an interest payment of $11 million dollars, related to
Old Notes and the Second Lien Notes, due on May 1, 2002. The Company has a
30-day grace period in which to make this $11 million payment before an "event
of default" occurs. Should such 30-day period expire without the interest
payment being made, the event of default would also result in an event of
default under the indenture related to the First Lien Notes. Such event of
default would allow for the holders of the Old Notes, the First Lien Notes and
the Second Lien Notes to declare the entire principal and unpaid interest on all
of the Company's outstanding notes($254.5 million) to be due and payable.
23
Working Capital. At March 31, 2002, we had current assets of $13.3 million
and current liabilities of $98.2 million resulting in a working capital deficit
of $84.9 million. This compares to a working capital deficit of $5.0 million at
December 31, 2001 and working capital deficit of $31.1 million at March 31,
2001. The majority of our current liabilities at March 31, 2002, were current
maturities of long-term debt of $63.9 million, including $63.5 million of our
First Lien Notes due March 2003, trade accounts payable of $17.8 million,
revenues due third parties of $2.3 million, accrued interest of $9.4 million and
hedge liability of $3.3 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.
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. 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.
Capital expenditures. Capital expenditures, excluding property divestitures
during the first three months of 2002, were $17.4 million compared to $17.8
million during the same period of 2001. The table below sets forth the
components of these capital expenditures on a historical basis for the three
months ended March 31, 2002 and 2001.
Three Months Ended
March 31
--------------------------------------------
2002 2001
---------------------- ---------------------
Expenditure category (in thousands):
Acquisitions................................... $ 28 $ 22
Development.................................... 17,249 17,726
Facilities and other........................... 131 88
--------------- ---------------
Total...................................... $ 17,408 $ 17,836
=============== ===============
Investing activities used $17.4 million net during the first three months
of 2002, which was utilized primarily for the development of crude oil and
natural gas properties and other facilities. This compares to using $17.8
million net during the first three months of 2001, which was utilized for the
development of crude oil and natural gas properties and other facilities.
As cash flow permits our current budget for capital expenditures for the
last nine months of 2002 other than acquisition expenditures is approximately
$20.0 million. The remaining portion of such expenditures is largely
discretionary and will be made primarily for the development of existing
properties. 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 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:
24
Three Months Ended
March 31,
-----------------------
2002 2001
----------- ---------
Net cash provided by operating activities $ 8,282 $ 17,424
Net cash provided by financing activities 5,377 495
Net cash used in investing activities (17,408) (17,817)
----------- ---------
Total $ (3,749) $ 102
=========== ==========
Operating activities during the three months ended March 31, 2002 provided
us $8.3 million cash compared to $17.4 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
$5.4 million for the first three months of 2002 compared to providing $495,000
for the same period of 2001.
Current Liquidity Needs. For several years, we have sought to improve our
liquidity in order to allow us to meet our debt service requirements and to
maintain and increase existing production.
Our sale in March 1999 of our First Lien Notes allowed us to refinance our
bank debt, meet our near-term debt service requirements and make limited crude
oil and natural gas capital expenditures.
In October 1999, we sold a dollar denominated production payment for $4.0
million relating to existing natural gas wells in South Texas to a unit of
Southern Energy, Inc. which is now known as Mirant Americas Energy Capital, L.P.
and in 2000 and 2001, we sold additional production payments for $6.4 million
and $11.7 million, respectively, relating to additional natural gas wells in the
Edwards Trend to Mirant Americas. We have the ability to sell up to $50 million
to Mirant for drilling opportunities in South Texas.
In December 1999, Abraxas and Canadian Abraxas, completed an Exchange Offer
whereby we exchanged our new 11.5% Senior Secured Notes due 2004 (the "Second
Lien Notes"), common stock and contingent value rights for approximately 98.43%
of our outstanding 11.5% Senior Notes due 2004, Series D (the "Old Notes"). The
Exchange Offer reduced our long-term debt by approximately $76 million after
expenses.
In March 2000, we sold our interest in certain crude oil and natural gas
properties that we owned and operated in Wyoming. Simultaneously, a limited
partnership of which one of our subsidiaries was the general partner, accounted
for on the equity method of accounting sold its interest in crude oil and
natural gas properties in the same area. Our net proceeds from these
transactions were approximately $34.0 million.
During 2001, we sold assets in the United States and Canada. Our net
proceeds from these transactions were approximately $29 million. These proceeds
were used to invest in additional producing properties.
In December 2001, Grey Wolf entered into a financing agreement with Mirant
Canada for CDN $150 million (approximately US $96 million), which is
non-recourse to Abraxas. Initial borrowings from this facility of approximately
US $25 million were used to retire Grey Wolf's existing bank facility and for
general corporate purposes. Up to US $71 million is available to finance
drilling of wells and related activities under this credit facility.
In March 2002, our wholly owned Canadian subsidiaries, Grey Wolf and
Canadian Abraxas, entered into a definitive Purchase and Sale Agreement related
to the sale of their interest in a natural gas plant and the associated
reserves. The sale, effective March 1, 2002, is scheduled to close in the second
quarter of 2002 with estimated net proceeds of US $21.5 million.
We have also recently engaged Randall & Dewey, Inc. to explore a potential
sale of certain properties located in Texas. The data room was opened in March
of 2002, with bids due in the second quarter of 2002. There are no definitive
agreements related to any potential sale and we cannot assure you that any sale
will occur or, if it does, the sale price that we would receive.
The Company deferred an interest payment of $11 million dollars, related to
Old Notes and the Second Lien Notes, due on May 1, 2002. The Company has a
30-day grace period in which to make this $11 million payment before an "event
of default" occurs Should such 30-day period expire without the interest payment
being made, the event of default would also result in an event of default under
the indenture related to the First Lien Notes. Such event of default would allow
for the holders of the Old Notes, the First Lien Notes and the Second Lien Notes
to declare the entire principal and unpaid interest on all of the Company's
outstanding notes ($254.5 million) to be due and payable.
Future Capital Resources. We will have four principal sources of liquidity
going forward: (i) cash on hand, (ii) cash flow from operations, (iii) the
25
production payment with Mirant Americas and (iv) 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.
The First Lien Notes indenture and the Second Lien Notes indenture restrict,
among other things, our ability to:
o incur additional indebtedness;
o incur liens;
o pay dividends or make certain other restricted payments;
o consummate certain asset sales;
o enter into certain transactions with affiliates;
o merge or consolidate with any other person; or
o sell, assign, transfer, lease, convey or otherwise dispose of all or
substantially all of our assets.
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
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 off-balance sheet debt or other such 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
March 31, 2002.
Payments due in:
----------------------------------------------------------------------------
Contractual Obligations
----------------------------------------------------------------------------
2005 and
Total 2002 2003 2004 after
---------------------------------- ----------------------------------------------------------------------------
Dollars in thousands
---------------------------------- --------------- -------------- -------------- --------------- --------------
Long-Term Debt (1) (2) $283,591 $ - $63,500 $190,979 $ 29,112 (3)
Operating Leases (4) 1,381 396 336 236 413
(1) Includes $63.5 million of the First Lien Notes, $191.0 million of the Old
Notes and Second Lien Notes, $29.1 million under the Grey Wolf Facility and $7.4
million under the production payment with Mirant Americas.
(2) Mirant Americas is paid a percentage of revenue from South Texas wells on
which they have advanced production payments, the amount of the future payments
is dependent on production from the subject wells. As a result, no payments are
reflected in the table.
(3) The Grey Wolf 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 March 31, 2002 ($29.1 million)
although we will be making payments prior to 2007. For more information on the
Grey Wolf Facility, you should read the description under "Grey Wolf Facility."
26
(4) 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
$20 million.
Long-Term Indebtedness.
Old Notes. On November 14, 1996, the Company consummated the offering of
$215.0 million of it's 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.
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 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 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.
27
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
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.
28
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 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
29
(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).
Grey Wolf Facility
General. On December 20, 2001, Grey Wolf entered into a credit facility
with 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 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 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 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 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.
The Grey Wolf Facility matures in 2007. 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 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 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.
Events of Default. The Grey Wolf Facility contains customary events of
default, including nonpayment of principal or interest, violations of covenants,
30
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 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.
Hedging Activities.
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 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
becomes ineffective. Gains and losses deferred in accumulated Other
Comprehensive Income/Loss related to a cash flow hedge that becomes ineffective,
remain unchanged until the related production is delivered. If the Company
determines that it is probable that a hedged transaction will not occur,
deferred gains or losses on the hedging instrument are recognized in earnings
immediately.
Gains and losses on hedging instruments related to accumulated Other
Comprehensive Income 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 position as of March 31, 2002.
Time Period Notional Quantities Price Fair Value
---------------------------------------- ------------------------------ ------------------------------ ----------------
April 1, 2002 - October 31, 2002 20,000 Mcf/day of natural Fixed price swap $2.60-$2.95 $(3.3) 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, the Company 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. 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 quarter of 2002 the fair value of outstanding liabilities
decreased by $2.6 million. For the three months ended March 31, 2002, the
ineffective portion of the cash flow hedges were not material.
As of March 31, 2002, $2.6 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 seven-month period.
All hedge transactions are subject to the Company's risk management policy,
approved by the Board of Directors. The Company formally documents all
relationships between hedging instruments and hedged items, as well as its risk
management objectives and strategy for undertaking the hedge. This process
includes specific identification of the hedging instrument and the hedged
transaction, the nature of the risk being hedged and how the hedging
instrument's effectiveness will be assessed. Both at the inception of the hedge
and on an ongoing basis, the Company assesses whether the derivatives that are
used in hedging transactions are highly effective in offsetting changes in cash
flows of hedged items.
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 March 31, 2002, a
commodity price increase of 10% would have resulted in an unfavorable change in
the fair market value of $1.4 million and a commodity price decrease of 10%
would have resulted in a favorable change in fair market value of $1.4 million.
31
Net Operating Loss Carryforwards.
At December 31, 2001 the Company 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, the Company 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, the Company acquired 100% of the common stock of an unrelated
corporation. The use of net operating loss carryforwards of the acquired
corporation of $257,000 acquired in the acquisition are limited to approximately
$115,000 per year.
As a result of the issuance of additional shares of common stock for
acquisitions and sales of common stock, an additional ownership change under
Section 382 occurred in October 1993. Accordingly, it is expected that the use
of all U.S. net operating loss carryforwards generated through October 1993
(including those subject to the 1991 and 1992 ownership changes discussed above)
of $6,590,000 will be limited as described above and in the following paragraph.
An ownership change under Section 382 occurred in December 1999, following
the issuance of additional shares, 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 the Company's carryforwards. In 2000 assets with built in gains were
sold, increasing the Section 382 limitation for 2001 by approximately
$31,000,000.
The annual Section 382 limitation may be increased during any year, within
5 years of a change in ownership, in which built-in gains that existed on the
date of the change in ownership are recognized.
In addition to the Section 382 limitations, uncertainties exist as to the
future utilization of the operating loss carryforwards under the criteria set
forth under FASB Statement No. 109. Therefore, the Company has established a
valuation allowance of $39,670,000 for deferred tax assets at December 31, 2001
and March 31,2002.
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 three months ended March 31, 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 $1.1 million
for the three months ended March 31, 2002.
Hedging Sensitivity
The fair value of our hedge instrument was determined based on NYMEX
forward price quotes as of March 31, 2002. As of March 31, 2002, a commodity
price increase of 10% would have resulted in an unfavorable change in the fair
market value of our hedging instrument of $1.4 million and a commodity price
decrease of 10% would have resulted in a favorable change in the fair value of
our hedge instrument of $1.4 million.
The following table sets forth our hedge position as of March 31, 2002.
Time Period Notional Quantities Price Fair Value
--------------------------------------------- ---------------------------- ------------------------- ---------------
April 1, 2002 - October 31, 2002 20,000 Mcf/day of natural Fixed price swap $(3.3) million
gas or 1,000 Bbl/day of $2.60-$2.95 natural gas
crude oil or
$18.90 Crude oil
Interest rate risk
At March 31, 2002, substantially all of our long-term debt is at fixed
interest rates and not subject to fluctuations in market rates.
32
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 $2.5 million for the three months ended
March 31, 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
$125,000. We do not maintain any derivative instruments to mitigate the exposure
to translation risk. However, this does not preclude the adoption of specific
hedging strategies in the future.
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.
33
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
None
Item 5. Other Information
None
Item 6. Exhibits and Reports on Form 8-K (b) Reports on Form 8-K:
1. Current Report on the Form 8-K filed on January 3, 2002. Other
Events, including a press release relating to the announcement of
the Company's Canadian project financing.
2. Current Report on the Form 8-K filed on March 27, 2002. Other
Events, including a press release relating to the announcement of
the Company's 2001 year end and fourth quarter financial results.
3. Current Report on the Form 8-K filed on March 28, 2002. Other
Events, including a press release relating to a definitive
purchase and sale agreement by wholly owned Canadian subsidiaries
for the sale of their interest in a natural gas processing plant
and related reserves.
4. Current Report of the Form 8-K filed on April 23, 2002. Other
Events, including a press release relating to Canadian winter
drilling activity.
5. Current Report on the Form 8-K filed on May 1, 2002. Other Events,
including a press release relating to deferral of interest
payment.
6. 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.
34
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: May 21, 2002 By:/s/
-------------- -------------------------------
ROBERT L.G. WATSON,
President and Chief
Executive Officer
Date: May 21, 2002 By:/s/
-------------- -------------------------------
CHRIS WILLIFORD,
Executive Vice President and
Principal Accounting Officer
35