UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One) [ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30,
2006
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO COMMISSION FILE NUMBER: 0-19118
ABRAXAS PETROLEUM CORPORATION (Exact name of registrant as specified in its
charter)
Nevada 74-2584033
(State of Incorporation) (I.R.S. Employer Identification No.)
500 N. Loop 1604 East, Suite 100, San Antonio, TX 78232
(Address of principal executive offices) (Zip Code)
210-490-4788
(Registrant's telephone number, including area code)
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 for such shorter period that the registrant was
required to file such reports), and (2) has been subject to the filing
requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark whether the registrant is a large accelerated filer, an
accelerated filer (as defined in Rule 12b-2 of the Exchange Act) or a
non-accelerated filer. See definition of "accelerated filer" and " large
accelerated filer" in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer [ ] Accelerated Filer [X] Non-Accelerated Filer [ ]
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act). [ ] Yes [ X] No
The number of shares outstanding of each of the issuer's classes of common
stock, as of November 3, 2006.
Class Shares Outstanding
Common Stock $.01 Par Value 42,666,577
Forward-Looking Information
We make forward-looking statements throughout this document. Whenever you
read a statement that is not simply a statement of historical fact (such as
statements including words like "believe", "expect", "anticipate", "intend",
"plan", "seek", "estimate", "could", "potentially" or similar expressions), you
must remember that these are forward-looking statements and that our
expectations may not be correct, even though we believe they are reasonable. The
forward-looking information contained in this document is generally located in
the material set forth under the heading "Management's Discussion and Analysis
of Financial Condition and Results of Operations" but may be found in other
locations as well. These forward-looking statements generally relate to our
plans and objectives for future operations and are based upon our management's
reasonable estimates of future results or trends. The factors that may affect
our expectations regarding our operations include, among others, the following:
o our high debt level;
o our success in development, exploitation and exploration
activities;
o our ability to make planned capital expenditures;
o declines in our production of natural gas and crude oil;
o prices for natural gas and crude oil;
o our ability to raise equity capital or incur additional
indebtedness;
o economic and business conditions;
o political and economic conditions in oil producing countries,
especially those in the Middle East;
o price and availability of alternative fuels;
o our restrictive debt covenants;
o our acquisition and divestiture activities;
o results of our hedging activities; and
o other factors discussed elsewhere in this document.
In addition to these factors, important factors that could cause actual
results to differ materially from our expectations ("Cautionary Statements") are
disclosed under "Risk Factors" in our Annual Report on Form 10-K for the year
ended December 31, 2005 which are incorporated by reference herein. All
subsequent written and oral forward-looking statements attributable to us, or
persons acting on our behalf, are expressly qualified in their entirety by the
Cautionary Statements.
2
ABRAXAS PETROLEUM CORPORATION
FORM 10 - Q
INDEX
PART I
FINANCIAL INFORMATION
ITEM 1 - Financial Statements
Condensed Consolidated Balance Sheets--September 30, 2006
and December 31, 2005..............................................................4
Condensed Consolidated Statements of Operations -
Three and Nine Months Ended September 30, 2006 and 2005.......................6
Condensed Consolidated Statements of Cash Flows -
Nine Months Ended September 30, 2006 and 2005.................................7
Notes to Condensed Consolidated Financial Statements...............................8
ITEM 2 - Management's Discussion and Analysis of Financial Condition and
Results of Operations........................................................13
ITEM 3 - Quantitative and Qualitative Disclosure about Market Risk.............................27
ITEM 4 - Controls and Procedures...............................................................28
PART II
OTHER INFORMATION
ITEM 1 - Legal Proceedings.....................................................................29
ITEM 1a - Risk Factors..........................................................................29
ITEM 2 - Unregistered Sales of Equity Securities and Use of Proceeds...........................29
ITEM 3 - Defaults Upon Senior Securities.......................................................29
ITEM 4 - Submission of Matters to a Vote of Security Holders...................................29
ITEM 5 - Other Information.....................................................................29
ITEM 6 - Exhibits..............................................................................29
Signatures............................................................................30
3
Abraxas Petroleum Corporation
Condensed Consolidated Balance Sheets
(in thousands)
September 30,
2006 December 31,
(Unaudited) 2005
------------------ -------------------
Assets:
Current assets:
Cash ................................................... $ 1,029 $ 42
Accounts receivable, net
Joint owners.......................................... 412 540
Oil and gas production................................ 6,325 7,957
Other................................................. 38 100
------------------ -------------------
6,775 8,597
Other current assets.......................................... 576 1,638
------------------ -------------------
Total current assets..................................... 8,380 10,277
Property and equipment:
Oil and gas properties, full cost method of accounting:
Proved.................................................... 342,645 333,373
Other property and equipment.................................. 3,438 3,289
------------------ -------------------
Total..................................................... 346,083 336,662
Less accumulated depreciation, depletion, and
amortization............................................ 242,181 231,414
------------------ -------------------
Total property and equipment - net........................ 103,902 105,248
Deferred financing fees, net ................................... 4,844 6,037
Other assets .................................................. 1,205 304
------------------ -------------------
Total assets.................................................. $ 118,331 $ 121,866
================== ===================
See accompanying notes to condensed consolidated financial statements
4
Abraxas Petroleum Corporation
Condensed Consolidated Balance Sheets (continued)
(in thousands)
September 30,
2006 December 31,
(Unaudited) 2005
-------------------- -------------------
Liabilities and Stockholders' Deficit
Current liabilities:
Accounts payable.............................................. $ 1,949 $ 9,814
Oil and gas production payable................................ 2,637 3,481
Accrued interest.............................................. 5,527 1,368
Other accrued expenses........................................ 1,490 494
-------------------- -------------------
Total current liabilities................................... 11,603 15,157
Long-term debt.................................................. 126,077 129,527
Future site restoration......................................... 986 883
-------------------- -------------------
Total liabilities...................................... 138,666 145,567
Stockholders' deficit:
Common Stock, par value $.01 per share-
Authorized 200,000,000 shares; issued, 42,638,577 and
42,063,167 .................................................. 426 421
Additional paid-in capital.................................... 163,812 162,795
Accumulated deficit........................................... (185,398) (188,193)
Treasury stock, at cost, 35,562 and 56,477 shares............. (285) (408)
Accumulated other comprehensive loss.......................... 1,110 1,684
-------------------- -------------------
Total stockholders' deficit............................... (20,335) (23,701)
-------------------- -------------------
Total liabilities and stockholders' deficit..................... $ 118,331 $ 121,866
==================== ===================
See accompanying notes to condensed consolidated financial statements
5
Abraxas Petroleum Corporation
Consolidated Statements of Operations
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------- ------------------------------
2006 2005 (1) 2006 2005 (1)
-------------- ------------- --------------- --------------
(in thousands, except per share data)
Revenue:
Oil and gas production revenues................. $ 12,847 $ 13,829 $ 38,642 $ 30,690
Rig revenues.................................... 363 330 1,168 909
Other........................................... 6 5 15 14
-------------- -------------- --------------- --------------
13,216 14,164 39,825 31,613
Operating costs and expenses:
Lease operating and production taxes............ 2,929 3,007 8,467 7,807
Depreciation, depletion, and amortization....... 3,631 2,107 10,767 5,622
Rig operations.................................. 178 176 608 560
General and administrative (including
stock-based compensation of $207, $16, $578 and 1,052 969 3,474 3,054
$57)............................................
-------------- -------------- --------------- --------------
7,790 6,259 23,316 17,043
-------------- -------------- --------------- --------------
Operating income .................................. 5,426 7,905 16,509 14,570
Other (income) expense:
Interest income................................. (1) (11) (2) (12)
Interest expense................................ 4,440 3,700 12,526 10,241
Amortization of deferred financing fees......... 398 403 1,193 1,257
Other expense................................... - 30 - 274
-------------- -------------- --------------- --------------
4,837 4,122 13,717 11,760
-------------- -------------- --------------- --------------
Earnings from continuing operations ................ 589 3,783 2,792 2,810
Net income from discontinued operations (net of $6,060
income tax expense in 2005).......................... - - - 12,894
-------------- -------------- --------------- --------------
Net earnings ........................................ $ 589 $ 3,783 $ 2,792 $ 15,704
============== ============== =============== ==============
Basic earnings per common share:
Net earnings per common from continuing operations $ 0.01 $ 0.09 $ 0.07 $ 0.07
Discontinued operations........................... - - - 0.34
-------------- -------------- --------------- --------------
Net earnings per common share - basic................ $ 0.01 $ 0.09 $ 0.07 $ 0.41
============== ============== =============== ==============
Diluted earnings per common share:
Net earnings per common from continuing operations $ 0.01 $ 0.09 $ 0.06 $ 0.07
Discontinued operations.............................. - - - 0.32
-------------- -------------- --------------- --------------
Net earnings per common share - diluted............. $ 0.01 $ 0.09 $ 0.06 $ 0.39
============== ============== =============== ==============
1. Reflects retrospective adoption of SFAS 123R.
See accompanying notes to condensed consolidated financial statements
6
Abraxas Petroleum Corporation
Condensed Consolidated Statements of Cash Flows
(Unaudited)
(in thousands)
Nine Months Ended
September 30,
----------------------------------------------
2006 2005
---------------------- ------------------
Operating Activities
Net earnings ................................................. $ 2,792 $ 15,704
Income from discontinued operations........................... - (12,894)
---------------- ------------------
Income from continuing operations............................. 2,792 2,810
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion, and amortization.................... 10,767 5,622
Amortization of deferred financing fees...................... 1,193 1,257
Accretion of future site restoration......................... 76 71
Stock-based compensation..................................... 578 57
Changes in operating assets and liabilities:
Accounts receivable...................................... 1,822 (2,774)
Other ................................................... (413) 2,849
Accounts payable and accrued expenses.................... (3,525) 4,877
---------------- ------------------
Net cash provided by continuing operations.................... 13,290 14,769
Net cash (used in) provided by discontinued operations........ - (4,132)
---------------- ------------------
Net cash provided by operations 13,290 10,637
Investing Activities
Capital expenditures, including purchases and development of
properties ................................................ (21,290) (28,604)
Proceeds from the sale of oil and gas properties.............. 11,869
---------------- ------------------
Net cash used in continuing operations........................ (9,421) (28,604)
Net cash provided by discontinued operations.................. - 25,719
---------------- ------------------
Net cash used in investing activities......................... (9,421) (2,885)
Financing Activities
Proceeds from long-term borrowings............................ 14,850 17,688
Payments on long-term borrowings.............................. (18,300) (14,271)
Proceeds from issuance of common stock (net).................. - 11,275
Issuance of stock for compensation............................ 116 102
Deferred financing fees ...................................... - (57)
Exercise of stock options ................................... 452 397
---------------- ------------------
Net cash (used in) provided by continuing operations.......... (2,882) 15,134
Net cash used in discontinued operations...................... - (23,407)
---------------- ------------------
Net cash used in financing activities......................... (2,882) (8,273)
---------------- ------------------
Increase (decrease)in cash.................................... 987 (521)
Cash, at beginning of period.................................. 42 1,284
---------------- ------------------
Cash, at end of period........................................ $ 1,029 $ 763
================ ==================
Supplemental disclosure of cash flow information:
Interest paid................................................. $ 8,291 $ 7,635
================ ==================
Non-cash items:
Future site restoration....................................... $ 27 $ 29
================ ==================
See accompanying notes to condensed consolidated financial statements
7
Abraxas Petroleum Corporation
Notes to Condensed Consolidated Financial Statements
(Unaudited)
(tabular amounts in thousands, except per share data)
Note 1. Basis of Presentation
The accounting policies followed by Abraxas Petroleum Corporation and its
subsidiaries (the "Company" or "Abraxas") are set forth in the notes to the
Company's audited financial statements in the Annual Report on Form 10-K filed
for the year ended December 31, 2005. 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 Company's financial
position and results of operations. Any and all adjustments are of a normal and
recurring nature. The results of operations for the three and nine months ended
September 30, 2006 are not necessarily indicative of results to be expected for
the full year.
The consolidated financial statements include the accounts of the Company
and its then wholly-owned foreign subsidiary, Grey Wolf Exploration Inc. ("Grey
Wolf") for the 2005 period. On February 28, 2005 Grey Wolf closed an initial
public offering, resulting in our substantial divestiture of our capital stock
and operations in Grey Wolf. As a result of the disposal of Grey Wolf, the
results of operations of Grey Wolf through February 28, 2005 are reflected in
our financial statements as discontinued operations.
Stock-based Compensation.
In December 2004, the FASB issued SFAS No. 123R, "Share-Based Payment".
SFAS No. 123R is a revision of SFAS No. 123, "Accounting for Stock Based
Compensation", and supersedes APB 25. Among other items, SFAS 123R eliminates
the use of APB 25 and the intrinsic value method of accounting, and requires
companies to recognize the cost of employee services received in exchange for
awards of equity instruments, based on the grant date fair value of those
awards, in the financial statements.
The Company adopted SFAS 123R in the fourth quarter of 2005 using the
"modified retrospective method". Under the "modified retrospective method"
entities are permitted to restate financial statements of previous periods based
on proforma disclosures made in accordance with SFAS 123. This standard requires
the cost of all share-based payments, including stock options, to be measured at
fair value on the grant date and recognized in the statement of operations. In
accordance with this standard, all periods prior to January 1, 2005 were
restated to reflect the impact of the standard as if it had been adopted on
January 1, 1995, the original effective date of SFAS No. 123, "Accounting for
Stock-Based Compensation". Also in accordance with the standard, the amounts
that are reported in the statement of operations for the restated periods are
the pro forma amounts previously disclosed under SFAS No. 123.
The Company currently utilizes a standard option pricing model (i.e.,
Black-Scholes) to measure the fair value of stock options granted to employees.
While SFAS 123R permits entities to continue to use such a model, the standard
also permits the use of a more complex binomial, or "lattice" model. Based upon
research done by the Company on the alternative models available to value option
grants, and in conjunction with the type and number of stock options expected to
be issued in the future, the Company has determined that it will continue to use
the Black-Scholes model for option valuation as of the current time.
SFAS 123R includes several modifications to the way that income taxes are
recorded in the financial statements. The expense for certain types of option
grants is only deductible for tax purposes at the time that the taxable event
takes place, which could cause variability in the Company's effective tax rates
recorded throughout the year. SFAS 123R does not allow companies to "predict"
when these taxable events will take place. Furthermore, it requires that the
benefits associated with the tax deductions in excess of recognized compensation
cost be reported as a financing cash flow, rather than as an operating cash flow
8
as required under current literature. This requirement will reduce net operating
cash flows and increase net financing cash flows in periods after the effective
date. These future amounts cannot be estimated, because they depend on, among
other things, when employees exercise stock options.
The following table summarizes the stock option activities for the nine
months ended September 30, 2006 (in thousands except per share data):
Weighted Weighted
Average Average
Option Grant
Exercise Date Fair Aggregate
Price Per Value Per Intrinsic
Shares Share Share Value
--------------- -------------- -------------- --------------
Outstanding December 31, 2005....... 3,016 $ 1.75 $ 1.27 $ 3,837
Granted............................ 188 $ 5.32 $ 3.82 718
Exercised.......................... (575) $ 0.78 $ 0.45 (257)
Expired or canceled................. (3) $ 4.39 $ 3.33 (8)
--------------- --------------
Outstanding September 30, 2006...... 2,626 $ 2.21 $ 1.64 $ 4,290
=============== ==============
The following table shows the weighted average assumptions used in the
Black Scholes valuation of the fair value of option grants during 2006.
Expected dividend yield...................................... 0%
Volatility................................................... .884
Risk free interest rate...................................... 4.81%
Expected life................................................ 5.09
Fair value of options granted (in thousands)................. $ 718
Weighted average grant date fair value of options granted.... $ 3.82
Additional information related to options at September 30, 2006 and December 31,
2005 is as follows:
September 30, December 31,
2006 2005
---------------------- --------------------
Options exercisable....... 2,001,463 2,224,998
====================== ====================
As of September 30, 2006 there was approximately $2.2 million of unamortized
compensation expense related to outstanding options that will be recognized
through the period ended September 30, 2010.
9
Note 2. Discontinued operations
On February 28, 2005, Grey Wolf completed an IPO resulting in Abraxas
substantially divesting itself of its investment in Grey Wolf.
The operations of Grey Wolf, previously reported as a business segment, are
reported as discontinued operations for all periods presented in the
accompanying financial statements and the operating results are reflected
separately from the results of continuing operations.
Income from discontinued operations for the period ended September 30, 2005
includes a gain on the disposal of Grey Wolf of $21.8 million, less non-cash
income tax of $6.1 million, and a loss from operations, including debt
retirement costs, of $2.8 million.
Note 3. Income Taxes
The Company records income taxes using the liability method. Under this
method, deferred tax assets and liabilities are determined based on differences
between financial reporting and tax basis of assets and liabilities and are
measured using the enacted tax rates and laws that will be in effect when the
differences are expected to reverse.
For the period ended September 30, 2006, there is no current or deferred
income tax expense or benefit due to losses and/or loss carryforwards and a
valuation allowance which has been recorded against such benefits.
Note 4. Long-Term Debt
Long-term debt consisted of the following:
September 30, December 31,
2006 2005
---------------- -----------------
Floating rate senior secured notes due 2009............................ $ 125,000 $ 125,000
Senior secured revolving credit facility............................... 1,077 4,527
---------------- -----------------
126,077 129,527
Less current maturities ............................................... - -
---------------- -----------------
$ 126,077 $ 129,527
================ =================
Floating Rate Senior Secured Notes due 2009. In connection with the October
2004 financial restructuring, Abraxas issued $125 million in aggregate principal
amount of floating rate senior secured notes due 2009. The notes will mature on
December 1, 2009. Interest is payable at a per annum floating rate of six-month
LIBOR plus 7.50%. The interest rate was 12.82% per annum as of September 30,
2006. The interest rate is reset semi-annually on each June 1 and December 1.
Interest is payable semi-annually in arrears on June 1 and December 1 of each
year.
Senior Secured Revolving Credit Facility. On October 28, 2004, Abraxas
entered into an agreement for a revolving credit facility having a maximum
commitment of $15 million, which includes a $2.5 million subfacility for letters
of credit. Availability under the revolving credit facility is subject to a
borrowing base consistent with normal and customary natural gas and crude oil
lending transactions.
Outstanding amounts under the revolving credit facility bear interest at
the prime rate announced by Wells Fargo Bank, National Association plus 1.00%.
The interest rate was 9.25% per annum as of September 30, 2006.
Subject to earlier termination rights and events of default, the stated
maturity date under the revolving credit facility is October 28, 2008.
10
Note 5. Earnings Per Share
The following table sets forth the computation of basic and diluted
earnings per share:
Three Months Ended September Nine Months Ended
30, September 30,
------------------------------- -------------------------------
2006 2005 2006 2005
------------- ------------- -------------- -------------
Numerator:
Net income before effect of discontinued
operations................................. $ 589 $ 3,783 $ 2,792 $ 2,810
Discontinued operations....................... - - - 12,894
------------- ------------- -------------- -------------
Net earnings available to common stockholders.. 589 3,783 2,792 15,704
============= ============= ============== =============
Denominator:
Denominator for basic earnings per share -
Weighted-average shares..................... 42,584,045 40,962,427 42,550,022 38,478,355
Effect of dilutive securities:
Stock options and warrants.................. 1,326,731 1,870,121 1,494,866 1,662,562
------------- ------------- -------------- -------------
Dilutive potential common shares
Denominator for diluted earnings per share -
adjusted weighted-average shares and assumed
Conversions................................. 43,910,776 42,832,548 44,044,888 40,140,917
Basic earnings (loss) per share:
Net income (loss) from continuing
operations ................................ $ 0.01 $ 0.09 $ 0.07 $ 0.07
Discontinued operations..................... - - - 0.34
------------- ------------- -------------- -------------
Net earnings (loss) per common share - basic.... $ 0.01 $ 0.09 $ 0.07 $ 0.41
============= ============= ============== =============
Diluted earnings (loss) per share:
Net income (loss) from continuing
operations ................................ $ 0.01 $ 0.09 $ 0.06 $ 0.07
Discontinued operations..................... - - - 0.32
------------- ------------- -------------- -------------
Net earnings (loss) per common share - basic.... $ 0.01 $ 0.09 $ 0.06 $ 0.39
============= ============= ============== =============
Note 6. Hedging Program and Derivatives
On January 1, 2001, the Company adopted SFAS 133 "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133) as amended by SFAS 137
"Accounting for Derivative Instruments and Hedging Activities - Deferral of the
Effective Date of FASB 133" and SFAS 138 "Accounting for Certain Derivative
Instruments and Certain Hedging Activities". Under SFAS 133, all derivative
instruments are recorded on the balance sheet at fair value. If the derivative
does not qualify as a hedge or is not designated as a hedge, the gain or loss on
the derivative is recognized currently in earnings. To qualify for hedge
accounting, the derivative must qualify either as a fair value hedge, cash flow
hedge or foreign currency hedge. As of September 30, 2006, the derivatives that
the Company had in place were not designated as hedges and, accordingly, changes
in the fair value of the derivatives are recorded in current period oil and gas
revenue.
Under the terms of our revolving credit facility, we are required to
maintain hedging positions on not less than 25% nor more than 75% of our
projected natural gas and crude oil production for a rolling six month period.
The following table sets forth the Company's current hedge position:
Time Period Notional Quantities Price
--------------------------------------------------------------------------------
November 2006 10,000 MMbtu of production per day Floor of $6.00
December 2006 10,000 MMbtu of production per day Floor of $5.50
January 2007 10,000 MMbtu of production per day Floor of $5.50
February 2007 10,000 MMbtu of production per day Floor of $5.50
March 2007 10,000 MMbtu of production per day Floor of $5.00
April 2007 10,000 MMbtu of production per day Floor of $4.50
11
Note 7. Contingencies - Litigation
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 September 30,
2006, the Company was not engaged in any legal proceedings that are expected,
individually or in the aggregate, to have a material adverse effect on its
operations.
Note 8. 2005 Employee Long-Term Equity Incentive Plan
On May 25, 2006, the stockholders of the Company approved the Abraxas
Petroleum Corporation 2005 Employee Long-Term Equity Incentive Plan. The
following is a summary of some of the material terms of the 2005 Employee Plan.
Purpose. The purpose of the 2005 Employee Plan is to employ and retain
qualified and competent personnel and promote the growth and success of Abraxas
by aligning the long-term interests of Abraxas' key employees with those of
Abraxas' stockholders by providing an opportunity to acquire an interest in
Abraxas and by providing both rewards for exceptional performance and long-term
incentives for future contributions to the success of Abraxas.
Administration and Eligibility. The 2005 Employee Plan will be administered
by the Compensation Committee of the Board of Directors and authorizes the Board
to grant non-qualified stock options, incentive stock options or issue
restricted stock to those persons who are employees of Abraxas.
Shares Reserved and Awards. The 2005 Employee Plan reserves 1,200,000
shares of Abraxas common stock, subject to adjustment following certain events,
as discussed below. The maximum annual award for any one employee is 200,000
shares of Abraxas common stock. If options, as opposed to restricted stock, are
awarded, the exercise share price shall be no less than 100% of the fair market
value on the date of the award, unless the employee is awarded incentive stock
options and at the time of the award, owns more than 10% of the voting power of
all classes of stock of Abraxas. Under this circumstance, the exercise share
price shall be no less than 110% of the fair market value on the date of the
award. Option terms and vesting schedules are at the discretion of the
Compensation Committee.
12
ABRAXAS PETROLEUM CORPORATION
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operation
Prior to February 2005, Grey Wolf Exploration Inc. was a wholly-owned
Canadian subsidiary of Abraxas. In February 2005, Grey Wolf, closed an initial
public offering resulting in the divestiture of a substantial amount of our
capital stock in Grey Wolf. As a result of the Grey Wolf IPO and the significant
divestiture of our interest in Grey Wolf, the results of operations of Grey Wolf
are reflected in our Financial Statements and in this document as "Discontinued
Operations" and our remaining operations are referred to in our Financial
Statements and in this document as "Continuing Operations" or "Continued
Operations". Unless otherwise noted, all disclosures are for continuing
operations.
The following is a discussion of our financial condition, results of
operations, liquidity and capital resources. This discussion should be read in
conjunction with our consolidated financial statements and the notes thereto,
included in our Annual Report on Form 10-K filed for the year ended December 31,
2005.
Critical Accounting Policies
There have been no changes from the Critical Accounting Polices described
in our Annual Report on Form 10-K for the year ended December 31, 2005.
General
We are an independent energy company primarily engaged in the development
and production of natural gas and crude oil. Historically we have grown through
the acquisition and subsequent development and exploitation of producing
properties, principally through the redevelopment of old fields utilizing new
technologies such as modern log analysis and reservoir modeling techniques as
well as 3-D seismic surveys and horizontal drilling. As a result of these
activities, we believe that we have a substantial inventory of development
opportunities, which provide a basis for significant production and reserve
increases. In addition, we intend to expand upon our exploitation and
development activities with complementary exploration projects in our core areas
of operation.
Our financial results depend upon many factors which significantly affect
our results of operations including the following:
o the sales prices of natural gas and crude oil;
o the level of total sales volumes of natural gas and crude oil;
o the availability of, and our ability to raise additional 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 exploitation, exploration and development
activity.
Commodity Prices and Hedging Activities. Our results of operations are
significantly affected by fluctuations in commodity prices. Price volatility in
the natural gas market has remained prevalent in the last few years. In January
2001, our realized prices for natural gas and crude oil were at high levels.
However, over the course of 2001 and the beginning of the first quarter of 2002,
prices again became depressed, primarily due to the economic downturn. Beginning
in March 2002, commodity prices began to increase and continued higher through
December 2005. Crude oil prices have continued to remain strong during the first
nine months of 2006 compared to historical levels; however natural gas prices
have weakened significantly from levels during the latter part of 2005 and first
quarter of 2006. If natural gas prices continue to weaken, our cash flow from
operations will be adversely affected.
The table below illustrates how natural gas prices have fluctuated over the
eight quarters prior to and including the quarter ended September 30, 2006 and
contains the average of the last three days of NYMEX traded contracts price for
13
each contract month in the quarter and the prices we realized during each
quarter presented, including the impact of our hedging activities.
Natural Gas Prices by Quarter (in $ per Mcf)
Quarter Ended
--------------------------------------------------------------------------------------------
Dec. 31, Mar. 31, June 30, Sept. 30, Dec. 31, Mar. 31, June 30, Sept. 30,
2004 2005 2005 2005 2005 2006 2006 2006
--------- --------- ----------- ---------- ---------- --------- ---------- ----------
Index $6.77 $6.30 $ 6.80 $ 8.21 $ 12.85 $ 9.18 $ 6.89 $ 6.53
Realized $6.14 $5.26 $ 6.33 $ 8.15 $ 9.12 $ 6.52 $ 5.78 $ 5.43
The NYMEX natural gas price on November 3, 2006 was $7.88 per Mcf.
The table below illustrates how crude oil prices have fluctuated over the
eight quarters prior to and including the quarter ended September 30, 2006 and
contains the average of the last three days of NYMEX traded contracts price for
each contract month in the quarter presented and the prices we realized during
each quarter presented, including the impact of our hedging activities.
Crude Oil Prices by Quarter (in $ per Bbl)
Quarter Ended
--------------------------------------------------------------------------------------------
Dec. 31, Mar. 31, June 30, Sept. 30, Dec. 31, Mar. 31, June 30, Sept. 30,
2004 2005 2005 2005 2005 2006 2006 2006
--------- --------- ----------- ---------- ---------- --------- ---------- ----------
Index $ 49.46 $ 47.33 $ 51.76 $ 60.26 $ 61.51 $ 61.53 $ 67.38 $ 71.72
Realized $ 46.81 $ 47.13 $ 49.43 $ 60.24 $ 57.18 $ 59.57 $ 66.09 $ 66.62
The NYMEX crude oil price on November 3, 2006 was $59.14 per Bbl.
We seek to reduce our exposure to price volatility by hedging a portion of
our production through price floors.
Under the terms of our revolving credit facility, we are required to
maintain hedging positions with respect to not less than 25% nor more than 75%
of our crude oil and natural gas production, on an equivalent basis, for a
rolling six-month period. We currently have the following hedges in place:
Time Period Notional Quantities Price
------------------------------------------------------------------------------
November 2006 10,000 MMbtu of production per day Floor of $6.00
December 2006 10,000 MMbtu of production per day Floor of $5.50
January 2007 10,000 MMbtu of production per day Floor of $5.50
February 2007 10,000 MMbtu of production per day Floor of $5.50
March 2007 10,000 MMbtu of production per day Floor of $5.00
April 2007 10,000 MMbtu of production per day Floor of $4.50
At September 30, 2006, the aggregate fair market value of our hedges was
approximately $392,000.
Production Volumes. Because our proved reserves will decline as natural gas
and crude oil are produced, unless we acquire additional properties containing
proved reserves or conduct successful exploitation, exploration or 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, exploration, exploitation and
development projects.
We had capital expenditures of $21.3 million in the first nine months of
2006. As a result of the capital spending limitations included in our previous
credit agreement and our 11 1/2 notes due 2007 which were eliminated in
connection with our October 2004 refinancing, we were limited for most of 2004
in our ability to replace existing production and, consequently, our production
volumes decreased during 2004 and continued to decrease in the first quarter of
2005. Beginning in the second quarter of 2005, our production volumes began to
increase and have continued to increase through the first nine months of 2006.
14
If crude oil and natural gas prices return to depressed levels or if our
production levels decrease, our revenues, cash flow from operations and
financial condition will be materially adversely affected.
Availability of Capital. As described more fully under "Liquidity and
Capital Resources" below, our sources of capital going forward will primarily be
cash from operating activities, funding under our revolving credit facility,
cash on hand, and if an appropriate opportunity presents itself, proceeds from
the sale of properties. We currently have approximately $15.0 million of
availability under our revolving credit facility.
Exploitation, Exploration and Development Activity. We believe that our
high quality asset base, high degree of operational control and large inventory
of drilling projects position us for future growth. Our properties are
concentrated in locations that facilitate substantial economies of scale in
drilling and production operations and more efficient reservoir management
practices. At year end December 31, 2005 we operated 95% of the properties
accounting for approximately 94% of our PV-10, giving us substantial control
over the timing and incurrence of operating and capital expenditures. In
addition, we had 53 proved undeveloped locations and have identified over 184
drilling and recompletion opportunities on our existing acreage, the successful
development of which we believe could significantly increase our daily
production and proved reserves. During the first nine months of 2006, we made
capital expenditures of approximately $21.3 million for wells in south Texas,
west Texas and Wyoming. We are currently re-entering a Devonian well in west
Texas and are recompleting a Wilcox well in south Texas. In the Oates SW Field,
two wells drilled earlier this year have been placed on production naturally
(without stimulation) to enable us to evaluate the productive capability of the
wells, which will allow us to effectively design fracture stimulations. We
continue to perform general well maintenance and work-overs utilizing our own
work-over rigs.
Our future natural gas and crude oil production, and therefore our success,
is highly dependent upon our ability to find, acquire and develop additional
reserves that are profitable to produce. The rate of production from our natural
gas and crude oil properties and our proved reserves will decline as our
reserves are produced unless we acquire additional properties containing proved
reserves, conduct successful development, exploitation and exploration
activities or, through engineering studies, identify additional behind-pipe
zones or secondary recovery reserves. We cannot assure you that our exploration,
exploitation and development activities will result in increases in our proved
reserves. In addition, approximately 52% of our total estimated proved reserves
at December 31, 2005 were undeveloped. By their nature, estimates of undeveloped
reserves are less certain. Recovery of such reserves will require significant
capital expenditures and successful drilling operations.
Borrowings and Interest. At November 1, 2006, we had indebtedness of
approximately $125.0 million under the notes and $0 under the revolving credit
facility and availability of $15.0 million. Unlike the 11 1/2% secured notes due
2007 (which were redeemed in October 2004), interest on the notes is payable in
cash.
Recent events. On September 28, 2006 we closed on the sale of certain
non-core assets located in South Texas for a total consideration of $12 million,
subject to closing adjustments. The effective date of the sale was August 1,
2006.The non-core assets were located in the Three Rivers (Edwards) Field of
Live Oak County, Texas and represented less than 2% of the Company's net proved
reserves as of December 31, 2005 and approximately 3% of the Company's current
daily net production at July 31, 2006. The net proceeds were used to repay
outstanding indebtedness under the Company's revolving credit facility.
Outlook for 2006. As a result of final 2005 financial results and current market
conditions, our operating and financial guidance for 2006 is as follows:
Production:
BCFE (approximately 80% gas)....................... 7.5 - 8.5
Exit Rate (Mmcfe/d)................................... 22 - 24
Price Differentials (Pre Hedge):
Gas (% Mcf)........................................ 15%
Oil ($/Bbl)........................................ 2.00
Production taxes (% of Revenue)....................... 10%
Direct Lease Operating Expenses ($/ Mcfe)............. 1.10
G&A ($/ Mcfe)......................................... 0.55
Interest ($/Mcfe)..................................... 2.00
15
DD&A ($/Mcfe)......................................... 1.80
Capital Expenditures ($ Millions)..................... 23.0 - 25.0 (1)
(1) Our capital expenditures are subject to adequate
cash flow from operations and availability under our
revolving credit facility. For more information, please
see "Liquidity Capital Resources - Capital
Expenditures" below.
Results of Operations
The following table sets forth certain of our operating data for the
periods presented.
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------- ---------------------------
2006 2005 2006 2005
--------- --------- ---------- ----------
Operating Revenue (in thousands):
Crude Oil Sales.................................. $ 3,478 $ 2,699 $ 9,620 $ 7,543
Natural Gas Sales................................ 9,369 11,130 29,022 23,147
Rig Operations................................... 363 330 1,168 909
Other............................................ 6 5 15 14
--------- --------- ---------- ----------
$ 13,216 $ 14,164 $ 39,825 $ 31,613
========= ========= ========== ==========
Operating Income (in thousands) ................. $ 5,426 $ 7,905 $ 16,509 $ 14,570
Crude Oil Production (MBbls)..................... 52 45 150 145
Natural Gas Production (MMcfs)................... 1,725 1,366 4,926 3,427
Average Crude Oil Sales Price ($/Bbl)............ $ 66.62 $ 60.24 $ 64.24 $ 51.95
Average Natural Gas Sales Price ($/Mcf).......... $ 5.43 $ 8.15 $ 5.89 $ 6.75
Comparison of Three Months Ended September 30, 2006 to Three Months Ended
September 30, 2005
Operating Revenue. During the three months ended September 30, 2006,
operating revenue from natural gas and crude oil sales decreased by $1.0 million
to $12.8 million compared to $13.8 million during three months ended September
30, 2005. The decrease in revenue was due to a decrease in the price of natural
gas during the third quarter of 2006 as compared to the same period of 2005. The
decrease in revenue related to the decline in the natural gas price was
partially offset by increased production and higher prices received for crude
oil during the quarter. The decline in natural gas prices had a negative impact
on revenue of approximately $3.7 million. Higher natural gas production
contributed $2.0 million to revenue and increased crude oil production
contributed $494,000. The increase in the price of crude oil for the quarter
ended September 30, 2006 contributed $286,000 to revenue.
Average sales prices net of hedging cost for the quarter ended September
30, 2006 were:
o $66.62 per Bbl of crude oil, and
o $5.43 per Mcf of natural gas
Average sales prices net of hedging cost for the quarter ended
September 30, 2005 were:
o $60.24 per Bbl of crude oil, and
o $8.15 per Mcf of natural gas
16
Crude oil production volumes increased from 44.8 MBbls during the quarter
ended September 30, 2005 to 52.2 MBbls for the same period of 2006. The increase
in crude oil production volumes was primarily due to production from new wells
in Wyoming which was partially offset by natural field declines. Natural gas
production volumes increased 359 MMcf to 1,725 MMcf for the three months ended
September 30, 2006 from 1,366 MMcf for the same period of 2005. The increase in
natural gas production was primarily due to new production brought on line since
the third quarter of 2005. Production from wells brought on production during
and since the third quarter of 2005 contributed 793.9 MMcf and 3.7 MBbls during
the third quarter of 2006 compared to 376.4 MMcf and 0.3 MBbls during the third
quarter of 2005. The increase in production attributable to new wells was
partially offset by natural field declines and the sale of properties in Live
Oak County, Texas effective August 1, 2006. The properties sold contributed 91.0
MMcf to production during the third quarter of 2005 compared to 47.8 MMcf for
the two months ended August 31, 2006.
Lease Operating Expenses ("LOE"). LOE for the three months ended September
30, 2006 were consistent with LOE for the three months ended September 30, 2005
at $3.0 million for each period. The general increase in the industry cost of
services was offset by decreased production taxes. The decline in production
taxes was due to the decline in the price received for natural gas during the
third quarter of 2006 as compared to the same period of 2005. Our LOE on a per
Mcfe basis for the three months ended September 30, 2006 decreased to $1.44
compared to $1.84 for the same period of 2005. The decrease in the per Mcfe rate
was primarily due to increased production volumes during the quarter ended
September 30, 2006 as compared to 2005.
General and Administrative ("G&A") Expenses. G&A expenses excluding
stock-based compensation decreased to $844,000 for the quarter ended September
30, 2006 from $953,000 for the same period of 2005. The decrease in G&A expense
was primarily due to lower professional fees in the third quarter of 2006 as
compared to the same period of 2005. G&A expense on a per Mcfe basis was $0.41
for the third quarter of 2006 compared to $0.58 for the same period of 2005. The
per Mcfe decrease was attributable to lower G&A expense as well as higher
production volumes during the third quarter of 2006 as compared to the same
period of 2005.
Stock-based Compensation. In December 2004, the FASB issued SFAS No. 123R,
"Share-Based Payment". SFAS No. 123R is a revision of SFAS No. 123, "Accounting
for Stock Based Compensation", and supersedes APB 25. Among other items, SFAS
123R eliminates the use of APB 25 and the intrinsic value method of accounting,
and requires companies to recognize the cost of employee services received in
exchange for awards of equity instruments, based on the grant date fair value of
those awards, in the financial statements.
The Company adopted SFAS 123R in the fourth quarter of 2005 using the
"modified retrospective method". Under the "modified retrospective method",
entities are permitted to restate financial statements of previous periods based
on proforma disclosures made in accordance with SFAS 123. This standard requires
the cost of all share-based payments, including stock options, to be measured at
fair value on the grant date and recognized in the statement of operations. In
accordance with this standard, all periods prior to January 1, 2005 were
restated to reflect the impact of the standard as if it had been adopted on
January 1, 1995, the original effective date of SFAS No. 123, "Accounting for
Stock-Based Compensation". Also in accordance with the standard, the amounts
that are reported in the statement of operations for the restated periods are
the pro forma amounts previously disclosed under SFAS No. 123.
As a result of the retrospective adoption of SFAS 123R, the expenses
previously recognized under the rules of variable accounting were reversed and a
compensation expense measured according to SFAS 123R was recorded. As a result,
we recognized stock-based compensation expense of $207,000 during the third
quarter of 2006 as a result of the adoption of this accounting change compared
to $16,000 in 2005, as adjusted. Stock-based compensation expense is included as
a component of G&A expense in the accompanying financial statements. The
increase in stock-based compensation expense for the three months ended
September 30, 2006 over the same period of 2005 was due to new options granted
during the latter part of 2005 and the first part of 2006 and the increase in
the calculated fair value of these grants due to higher option prices as a
result of the increase in the price of our Common stock over previous options.
17
We currently utilize a standard option pricing model (i.e., Black-Scholes)
to measure the fair value of stock options granted to employees. While SFAS 123R
permits entities to continue to use such a model, the standard also permits the
use of a more complex binomial, or "lattice" model. Based upon research done by
us on the alternative models available to value option grants, and in
conjunction with the type and number of stock options expected to be issued in
the future, we have determined that we will continue to use the Black-Scholes
model for option valuation as of the current time
Depreciation, Depletion and Amortization("DD&A") Expenses. DD&A expense
increased to $3.6 million for the three months ended September 30, 2006 from
$2.1 million for the same period of 2005. The increase in DD&A was primarily due
to increased production volumes in the third quarter of 2006 as compared to the
same period of 2005 as well as an increase in projected future development cost
in 2006 as compared to 2005. Our DD&A on a per Mcfe basis for the quarter ended
September 30, 2006 was $1.78 per Mcfe as compared to $1.29 in 2005. The increase
in the per Mcfe rate was due to higher production volumes in the quarter ended
September 30, 2006 as compared to 2005 as well as a increased base due to the
increase in projected future development cost in 2006 as compared to 2005.
Interest Expense. Interest expense increased to $4.4 million for the third
quarter of 2006 compared to $3.7 million for the same period of 2005. The
increase in interest expense was due to an increase in our interest rate on our
floating rate senior secured notes and our senior revolving credit facility as
well as an increase in the amount borrowed under our revolving credit facility.
Income taxes. There is no current or deferred income tax expense or benefit
due to losses or loss carryforwards and valuation allowance which has been
recorded against such benefits.
Comparison of Nine Months Ended September 30, 2006 to Nine Months Ended
September 30, 2005
Operating Revenue. During the nine months ended September 30, 2006,
operating revenue from natural gas and crude oil sales increased by $7.9 million
to $38.6 million as compared to $30.7 million in the nine months ended September
30, 2005. The increase in revenue was primarily due to higher production volumes
during the first nine months of 2006 as compared to the same period of 2005
which was partially offset by a decrease in natural gas prices. Increased
natural gas production volumes contributed $10.2 million and increased crude oil
production contributed $237,000 to revenue. The decline in the price of natural
gas during the nine months ended September 30, 2006 had a negative impact on
revenue of $4.2 million which was partially offset by an increase in the
realized crude oil price during the period. Increased crude oil prices
contributed $1.8 million to revenue during the period.
Average sales prices net of hedging cost for the nine months ended
September 30, 2006 were:
o $64.24 per Bbl of crude oil, and
o $5.89 per Mcf of natural gas
Average sales prices net of hedging cost for the nine months ended
September 30, 2005 were:
o $51.95 per Bbl of crude oil, and
o $6.75 per Mcf of natural gas
Crude oil production volumes increased slightly to 149.8 MBbls during the
nine months ended September 30, 2006 from 145.2 MBbls for the same period of
2005. The increase in crude oil production volumes was primarily due to
production from new wells in Wyoming and south Texas, which was partially offset
by natural field declines. Natural gas production volumes increased by 1,499
MMcf to 4,926 MMcf for the nine months ended September 30, 2006 from 3,427 MMcf
MMcf for the same period of 2005. Production from wells brought on to production
during and since the third quarter of 2005 contributed 2,223 MMcf and 5.2 MBbls
during the nine months ended September 30, 2006 compared to 485.0 MMcf and 0.4
MBbls during the same period of 2005. The increase in production attributable to
new wells was partially offset by natural field declines.
18
Lease Operating Expenses. LOE for the nine months ended September 30, 2006
increased to $8.5 million from $7.8 million for the same period of 2005. The
increase was primarily due to a general increase in the cost of field services.
Our LOE on a per Mcfe basis for the nine months ended September 30, 2006
decreased to $1.45 compared to $1.82 for the same period of 2005. The decrease
in the per Mcfe rate was primarily due to increased production volumes in 2006
as compared to 2005.
G&A Expenses. G&A expenses, excluding stock-based compensation decreased to
$2.9 million for the first nine months of 2006 from to $3.0 million for the
first nine months of 2005. The decrease in G&A expense was primarily due to a
decrease in professional fees. G&A expense on a per Mcfe basis was $0.50 for the
first nine months of 2006 compared to $0.70 for the same period of 2005. The per
Mcfe decrease was primarily attributable to higher production volumes in 2006.
Stock-based Compensation. In December 2004, the FASB issued SFAS No. 123R,
"Share-Based Payment". SFAS No. 123R is a revision of SFAS No. 123, "Accounting
for Stock Based Compensation", and supersedes APB 25. Among other items, SFAS
123R eliminates the use of APB 25 and the intrinsic value method of accounting,
and requires companies to recognize the cost of employee services received in
exchange for awards of equity instruments, based on the grant date fair value of
those awards, in the financial statements.
The Company adopted SFAS 123R in the fourth quarter of 2005 using the
"modified prospective method". Under the "modified retrospective method",
entities are permitted to restate financial statements of previous periods based
on proforma disclosures made in accordance with SFAS 123. This standard requires
the cost of all share-based payments, including stock options, to be measured at
fair value on the grant date and recognized in the statement of operations. In
accordance with this standard, all periods prior to January 1, 2005 were
restated to reflect the impact of the standard as if it had been adopted on
January 1, 1995, the original effective date of SFAS No. 123, "Accounting for
Stock-Based Compensation". Also in accordance with the standard, the amounts
that are reported in the statement of operations for the restated periods are
the pro forma amounts previously disclosed under SFAS No. 123.
As a result of the retrospective adoption of SFAS 123R, the expenses
previously recognized under the rules of variable accounting were reversed and a
compensation expense measured according to SFAS 123R was recorded. As a result,
we recognized stock-based compensation expense of $578,000 during the nine
months ended September 30, 2006 as a result of the adoption of this accounting
change compared to $57,000 in 2005, as adjusted. Stock-based compensation
expense is included as a component of G&A expense in the accompanying financial
statements. The increase in stock-based compensation expense for the nine months
ended September 30, 2006 over the same period of 2005 was due to new options
granted during the latter part of 2005 and the first nine months of 2006 and the
increase in the calculated fair value of these grants due to higher option
prices as a result of the increase in the price of our Common stock over
previous options.
We currently utilize a standard option pricing model (i.e., Black-Scholes)
to measure the fair value of stock options granted to employees. While SFAS 123R
permits entities to continue to use such a model, the standard also permits the
use of a more complex binomial, or "lattice" model. Based upon research done by
us on the alternative models available to value option grants, and in
conjunction with the type and number of stock options expected to be issued in
the future, we have determined that we will continue to use the Black-Scholes
model for option valuation as of the current time.
DD&A Expenses. DD&A expense increased to $10.8 million for the nine months
ended September 30, 2006 from $5.6 million for the same period of 2005. The
increase in DD&A was primarily due to increased production volumes in the nine
months of 2006 as compared to the same period of 2005 as well as an increase in
projected future development cost in 2006 as compared to 2005. Our DD&A on a per
Mcfe basis for the nine months ended September 30, 2006 was $1.85 per Mcfe as
compared to $1.31 in 2005. This increase was the result of higher production
volumes and the increase in projected future development cost in 2006 as
compared to 2005.
Interest Expense. Interest expense increased to $12.5 million for the first
nine months of 2006 compared to $10.2 million for the same period of 2005. The
19
increase in interest expense was due to an increase in our interest rate on our
floating rate senior secured notes and our senior secured revolving credit
facility as well as an increase in the amount borrowed under our revolving
credit facility.
Income taxes. There is no current or deferred income tax expense or benefit
due to losses or loss carryforwards and valuation allowance which has been
recorded against such benefits.
Liquidity and Capital Resources
General. The natural gas and crude oil 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 natural gas and crude oil properties;
and
o production and transportation facilities.
The amount of capital expenditures we are able to make has a direct impact on
our ability to increase cash flow from operations, and, thereby, will directly
affect our ability to service our debt obligations and to continue to grow the
business through the development of existing properties and the acquisition of
new properties.
Our sources of capital going forward will primarily be cash from operating
activities, funding under our revolving credit facility, cash on hand, and if an
appropriate opportunity presents itself, proceeds from the sale of properties.
However, under the terms of the notes, proceeds of optional sales of our assets
that are not timely reinvested in new natural gas and crude oil assets will be
required to be used to reduce indebtedness and proceeds of mandatory sales must
be used to repay or redeem indebtedness. All of the proceeds from the sale of
the Live Oak County, Texas properties in September 2006 were used to re-pay
indebtdness under our revolving credit facility.
Working Capital (Deficit). At September 30, 2006, we had current assets of
$8.4 million and current liabilities of $11.6 million resulting in a working
capital deficit of approximately $3.2 million. This compares to a working
capital deficit of $4.9 million at December 31, 2005. Current liabilities at
September 30, 2006 consisted of trade payables of $2.0 million, revenues due
third parties of $2.6 million, accrued interest of $5.5 million and other
accrued liabilities of $1.5 million.
Capital expenditures. The table below sets forth the components of our
capital expenditures on a historical basis for the nine months ended September
30, 2006 and 2005.
Nine Months Ended
September 30,
------------------------------
2006 2005
------------- -------------
Expenditure category (in thousands):
Development............................... $ 21,141 $ 28,350
Facilities and other...................... 149 254
------------- -------------
Total................................. $ 21,290 $ 28,604
============= =============
We have no material long-term capital commitments and are consequently able
to adjust the level of our expenditures as circumstances dictate. The level of
capital expenditures will vary during future periods depending on market
conditions and other related economic factors effecting cash flow.
At the start of 2006, we anticipated making capital expenditures, primarily
for the development of our current properties, of approximately $40.0 million
which was based upon the anticipated amount of our cash flow from operations and
availability under our revolving credit facility. As natural gas prices have
decreased during the first nine months of 2006, our cash flow from operations
has not reached the levels that we had anticipated. As a result we will spend
less than the original budget of $40.0 million. We expect to spend between $23
million and $25 million on capital expenditures for 2006. Our ability to make
all of our budgeted capital expenditures will also be subject to availability of
drilling rigs and other field equipment and services. Our capital expenditures
could also include expenditures for acquisition of producing properties if such
20
opportunities arise, but we currently have no agreements, arrangements or
undertakings regarding any material acquisitions. Should the prices of natural
gas continue to decline, crude oil prices begin to decline, or if our costs of
operations increase as a result of the scarcity of drilling rigs or if our
production volumes decrease, our cash flow from operations will decrease which
may result in a further reduction of the capital expenditures budget.
Sources of Capital. The net funds provided by and/or used in each of the
operating, investing and financing activities, all relating to continuing
operations, are summarized in the following table:
Nine Months Ended
September 30,
---------------------------------
2006 2005
--------------- --------------
Net cash provided by operating activities $ 13,290 $ 14,769
Net cash used in investing activities (9,421) (28,604)
Net cash (used in) provided by financing activities (2,882) 15,134
--------------- --------------
Total $ 987 $ 1,299
=============== ==============
Operating activities during the nine months ended September 30, 2006
provided $13.3 million in cash compared to providing $14.8 million in the same
period in 2005. Net income plus non-cash expense items and net changes in
operating assets and liabilities accounted for most of these funds. Financing
activities used $2.9 million for the first nine months of 2006 compared to
providing approximately $15.1 million for the first nine months of 2005. For the
nine months ended September 30, 2006, proceeds from long- term borrowing
provided $18.3 million while payments on long-term borrowings used $14.9
million. Proceeds from long-term borrowings provided $17.7 million in 2005 while
payments on long-term borrowings used $14.3 million in 2005. Proceeds from an
equity offering in July 2005 provided $11.3 million for the nine months ended
September 30, 2005. Investing activities used $9.4 million for the nine months
ended September 30, 2006. Capital expenditures of $21.3 million were offset by
proceeds from the sale of non-core oil and gas properties of $11.9 million.
Investing activities used $28.6 million for the nine months ended September 30,
2005. Expenditures during the nine months ended September 30, 2006 and 2005 were
primarily for the development of existing properties.
Future Capital Resources. We currently have three principal sources of
liquidity going forward: (i) cash from operating activities, (ii) funding under
our revolving credit facility, and (iii) if an appropriate opportunity presents
itself, the sale of producing properties. If these sources of liquidity do not
prove to be sufficient, we may also issue additional shares of equity securities
although we may not be able to complete equity financings on terms acceptable to
us, if at all. Covenants under the indenture for the notes and the revolving
credit facility restrict our use of cash from operating activities, cash on hand
and any proceeds from asset sales. Under the terms of the notes, proceeds of
optional sales of our assets that are not timely reinvested in new natural gas
and crude oil assets will be required to be used to reduce indebtedness and
proceeds of mandatory sales must be used to redeem indebtedness. The terms of
the notes and the revolving credit facility also substantially restrict our
ability to:
o incur additional indebtedness;
o grant liens;
o pay dividends or make certain other restricted payments;
o merge or consolidate with any other entity; or
o sell, assign, transfer, lease, convey or otherwise dispose of all
or substantially all of our assets.
Our cash flow from operations depends heavily on the prevailing prices of
natural gas and crude oil and our production volumes of natural gas and crude
oil. Although we have hedged a portion of our natural gas and crude oil
production and will continue this practice as required pursuant to the revolving
credit facility, future natural gas and crude oil price declines would have a
material adverse effect on our overall results, and therefore, our liquidity.
Falling natural gas and crude oil prices could also negatively affect our
ability to raise capital on terms favorable to us or at all.
21
Our cash flow from operations will also depend upon the volume of natural
gas and crude oil that we produce. Unless we otherwise expand reserves, our
production volumes may decline as reserves are produced. Due to sales of
properties in 2002 and 2003, the divestiture of Grey Wolf during the first
quarter of 2005, and restrictions on capital expenditures under the terms of our
11 1/2% secured notes due 2007 (which were refinanced in October 2004), we now
have significantly reduced reserves and production as compared with pre-2003
levels. In the future, if an appropriate opportunity presents itself, we may
sell additional properties, which could further reduce our production volumes.
To offset the loss in production volumes resulting from natural field declines
and sales of producing properties, we must conduct successful, exploitation,
exploration and development activities, acquire additional producing properties
or identify additional behind-pipe zones or secondary recovery reserves. We
believe our numerous drilling opportunities will allow us to increase our
production volumes; however, our drilling activities are subject to numerous
risks, including the risk that no commercially productive natural gas or crude
oil reservoirs will be found. The risk of not finding commercially productive
reservoirs will be compounded by the fact that 52% of our total estimated proved
reserves at December 31, 2005 were undeveloped. During the first nine months of
2006, we expended approximately $21.3 million for wells in south Texas, west
Texas and Wyoming. We are currently re-entering a Devonian well in west Texas
and are recompleting a Wilcox well in south Texas. In the Oates SW Field, two
wells drilled earlier this year have been placed on production naturally
(without stimulation) to enable us to evaluate the productive capability of the
wells which will allow us to effectively design fracture stimulations. We
continue to perform general well maintenance and work-overs utilizing our own
work-over rigs. In addition, approximately 29% of our production at September
30, 2006 was from a single well in west Texas. If production from this well
decreases, the volume of our production would also decrease which, in turn,
would likely cause our cash flow from operations to decrease.
Our total indebtedness and cash interest expense as a result of issuing the
notes and entering into the revolving credit facility require us to increase our
production and cash flow from operations in order to meet our debt service
requirements, as well as to fund the development of our numerous drilling
opportunities. The ability to satisfy these new obligations will depend upon our
drilling success as well as prevailing commodity prices.
Contractual Obligations
We are committed to making cash payments in the future on the following
types of agreements:
o Long-term debt
o Operating leases for office facilities
We have no off-balance sheet debt or unrecorded obligations and we have not
guaranteed the debt of any other party. Below is a schedule of the future
payments that we are obligated to make based on agreements in place as of
September 30, 2006:
Payments due in twelve month periods ended:
-------------------------------------------------------------------------------------
Contractual September 30, September 30, September 30,
Obligations (dollars Total 2007 2008-2009 2010-2011 Thereafter
in thousands)
--------------------------------------------------------------------------------------------------------------
Long-Term Debt (1) $ 126,077 $ - $ 1,077 $ 125,000 $ -
Interest on long-term
debt (2) 50,954 16,125 32,158 2,671 -
Operating Leases (3) 589 254 335 - -
--------------- ------------------ ------------------ ----------------- -------------
Total $ 177,620 $ 16,379 $ 33,570 $ 127,671 $ -
=============== ================== ================== ================= =============
(1) These amounts represent the balances outstanding under the revolving
credit facility and the notes. These repayments assume that we will not
draw down additional funds
(2) Interest expense assumes the balances of long-term debt at the end of
the period and current effective interest rates.
(3) Office lease obligations. The lease for office space for Abraxas
expires in 2009
22
Other obligations. We make and will continue to make substantial capital
expenditures for the acquisition, exploitation, development, exploration and
production of natural gas and crude oil. In the past, we have funded our
operations and capital expenditures primarily through cash flow from operations,
sales of properties, sales of production payments and borrowings under our bank
credit facilities and other sources. Given our high degree of operating control,
the timing and incurrence of operating and capital expenditures is largely
within our discretion.
Long-Term Indebtedness
September 30, December 31,
2006 2005
---------------- -----------------
(In thousands)
Floating rate senior secured notes due 2009....... $ 125,000 $ 125,000
Senior secured revolving credit facility.......... 1,077 4,527
---------------- -----------------
126,077 129,527
Less current maturities .......................... - -
---------------- -----------------
$ 126,077 $ 129,527
================ =================
Floating Rate Senior Secured Notes due 2009. In connection with the October
2004 financial restructuring, Abraxas issued $125 million in principal aggregate
amount of Floating Rate Senior Secured Notes due 2009. The notes will mature on
December 1, 2009 and began accruing interest from the date of issuance, October
28, 2004 at a per annum floating rate of six-month LIBOR plus 7.50%. The current
interest rate is 12.82% per annum. The interest rate is reset semi-annually on
each June 1 and December 1. Interest is payable semi-annually in arrears on June
1 and December 1 of each year.
The notes rank equally among themselves and with all of our unsubordinated
and unsecured indebtedness, including our credit facility and senior in right of
payment to our existing and future subordinated indebtedness.
Each of our subsidiaries, Eastside Coal Company, Inc., Sandia Oil & Gas
Corporation, Sandia Operating Corp., Wamsutter Holdings, Inc. and Western
Associated Energy Corporation (collectively, the "Subsidiary Guarantors"), has
unconditionally guaranteed, jointly and severally, the payment of the principal,
premium and interest on the notes on a senior secured basis. In addition, any
other subsidiary or affiliate of ours, that in the future guarantees any other
indebtedness with us, or our restricted subsidiaries, will also be required to
guarantee the notes.
The notes and the Subsidiary Guarantors' guarantees thereof, together with
our revolving credit facility and the Subsidiary Guarantors' guarantees thereof,
are secured by shared first priority perfected security interests, subject to
certain permitted encumbrances, in all of our and each of our restricted
subsidiaries' material property and assets, including substantially all of our
and their natural gas and crude oil properties and all of the capital stock (or
in the case of an unrestricted subsidiary that is a controlled foreign
corporation, up to 65% of the outstanding capital stock) of any entity, owned by
us and our restricted subsidiaries (collectively, the "Collateral").
The notes may be redeemed, at our election, as a whole or from time to time
in part, at any time after April 28, 2007, upon not less than 30 nor more that
60 days' notice to each holder of notes to be redeemed, subject to the
conditions and at the redemption prices (expressed as percentages of principal
amount) set forth below, together with accrued and unpaid interest and
Liquidating Damages( as defined in the indenture) if any, to the applicable
redemption date.
Year Percentage
-------------------------------------------------------------------
From April 29, 2007 to April 28, 2008 104.00%
From April 29, 2008 to April 28, 2009 102.00%
After April 28, 2009 100.00%
23
Prior to April 28, 2007, we may redeem up to 35% of the aggregate original
principal amount of the notes using the net proceeds of one or more equity
offerings, in each case at the redemption price equal to the product of (i) the
principal amount of the notes being so redeemed and (ii) a redemption price
factor of 1.00 plus the per annum interest rate on the notes (expressed as a
decimal) on the applicable redemption date plus accrued and unpaid interest to
the applicable redemption date, provided certain conditions are also met.
If we experience specific kinds of change of control events, each holder of
notes may require us to repurchase all or any portion of such holder's notes at
a purchase price equal to 101% of the principal amount of the notes, plus
accrued and unpaid interest to the date of repurchase.
The indenture governing the notes contains covenants that, among other
things, limit our ability to:
o incur or guarantee additional indebtedness and issue certain types
of preferred stock or redeemable stock;
o transfer or sell assets;
o create liens on assets;
o pay dividends or make other distributions on capital stock or make
other restricted payments, including repurchasing, redeeming or
retiring capital stock or subordinated debt or making certain
investments or acquisitions;
o engage in transactions with affiliates;
o guarantee other indebtedness;
o permit restrictions on the ability of our subsidiaries to
distribute or lend money to us;
o cause a restricted subsidiary to issue or sell its' capital stock;
and
o consolidate, merge or transfer all or substantially all of the
consolidated assets of our and our restricted subsidiaries.
The indenture also contains customary events of default, including nonpayment of
principal or interest, violations of covenants, cross default and cross
acceleration to certain other indebtedness, including our revolving credit
facility, bankruptcy, and material judgments and liabilities.
Senior Secured Revolving Credit Facility. On October 28, 2004, we entered
into an agreement for a revolving credit facility having a maximum commitment of
$15 million, which includes a $2.5 million subfacility for letters of credit.
Availability under the revolving credit facility is subject to a borrowing base
consistent with normal and customary natural gas and crude oil lending
transactions.
Outstanding amounts under the revolving credit facility bear interest at
the prime rate announced by Wells Fargo Bank, National Association plus 1.00%.
The current interest rate is 9.25% per annum. Subject to earlier termination
rights and events of default, the stated maturity date under the revolving
credit facility is October 28, 2008.
We are permitted to terminate the revolving credit facility, and under
certain circumstances, may be required, from time to time, to permanently reduce
the lenders' aggregate commitment under the revolving credit facility. Such
termination and each such reduction is subject to a premium equal to the
percentage listed below multiplied by the lenders' aggregate commitment under
the revolving credit facility, or, in the case of partial reduction, the amount
of such reduction.
24
Year % Premium
-------------- --------------------
1 1.5
2 1.0
3 0.5
4 0.0
Each of our current subsidiaries has guaranteed, and each of our future
restricted subsidiaries will guarantee, our obligations under the revolving
credit facility on a senior secured basis. In addition, any other subsidiary or
affiliate of ours, that in the future guarantees any of our other indebtedness
or of our restricted subsidiaries will be required to guarantee our obligations
under the revolving credit facility. Obligations under the revolving credit
facility are secured, together with the notes, by a shared first priority
perfected security interest, subject to certain permitted encumbrances, in all
of our and each of our restricted subsidiaries' material property and assets,
including substantially all of our and their natural gas and crude oil
properties and all of the capital stock (or in the case of an unrestricted
subsidiary that is a controlled foreign corporation, up to 65% of the
outstanding capital stock) in any entity, owned by us and our restricted
subsidiaries.
Under the revolving credit facility, we are subject to customary covenants,
including certain financial covenants and reporting requirements. The revolving
credit facility requires us to maintain a minimum net cash interest coverage and
also requires us to enter into hedging agreements on not less than 25% or more
than 75% of our projected natural gas and crude oil production.
In addition to the foregoing and other customary covenants, the revolving
credit facility contains a number of covenants that, among other things,
restrict Abraxas' ability to:
o incur or guarantee additional indebtedness and issue certain types
of preferred stock or redeemable stock;
o transfer or sell assets;
o create liens on assets;
o pay dividends or make other distributions on capital stock or make
other restricted payments, including repurchasing, redeeming or
retiring capital stock or subordinated debt or making certain
investments or acquisitions;
o engage in transactions with affiliates;
o guarantee other indebtedness;
o make any change in the principal nature of our business;
o prepay, redeem, purchase or otherwise acquire any of our or our
restricted subsidiaries' indebtedness;
o permit a change of control;
o directly or indirectly make or acquire any investment;
o cause a restricted subsidiary to issue or sell our capital stock;
and
o consolidate, merge or transfer all or substantially all of the
consolidated assets of Abraxas and our restricted subsidiaries.
The revolving credit facility also contains customary events of default,
including nonpayment of principal or interest, violations of covenants, cross
default and cross acceleration to certain other indebtedness, bankruptcy and
material judgments and liabilities, and is subject to an Intercreditor, Security
and Collateral Agency Agreement, which specifies the rights of the parties
thereto to the proceeds from the Collateral.
Intercreditor Agreement. The holders of the notes, together with the
lenders under our credit facility, are subject to an Intercreditor, Security and
Collateral Agency Agreement, which specifies the rights of the parties thereto
to the proceeds from the Collateral. The Intercreditor Agreement, among other
things, (i) creates security interests in the Collateral in favor of a
collateral agent for the benefit of the holders of the notes and the credit
25
facility lenders and (ii) governs the priority of payments among such parties
upon notice of an event of default under the Indenture or the credit facility.
So long as no such event of default exists, the collateral agent will not
collect payments under the new credit facility documents or the indenture
governing the notes and other note documents (collectively, the "Secured
Documents"), and all payments will be made directly to the respective creditor
under the applicable Secured Document. Upon notice of an event of default and
for so long as an event of default exists, payments to each credit facility
lender and holder of the notes from us and our current subsidiaries and proceeds
from any disposition of any collateral, will, subject to limited exceptions, be
collected by the collateral agent for deposit into a collateral account and then
distributed as provided in the following paragraph.
Upon notice of any such event of default and so long as an event of default
exists, funds in the collateral account will be distributed by the collateral
agent generally in the following order of priority:
first, to reimburse the collateral agent for expenses incurred in
protecting and realizing upon the value of the Collateral;
second, to reimburse the credit facility administrative agent and the
trustee, on a pro rata basis, for expenses incurred in protecting and realizing
upon the value of the Collateral while any of these parties was acting on behalf
of the Control Party (as defined below);
third, to reimburse the credit facility administrative agent and the
trustee, on a pro rata basis, for expenses incurred in protecting and realizing
upon the value of the Collateral while any of these parties was not acting on
behalf of the Control Party;
fourth, to pay all accrued and unpaid interest (and then any unpaid
commitment fees) under the credit facility;
fifth, if, the collateral coverage value of three times the outstanding
obligations under the credit facility would be met after giving effect to any
payment under this clause "fifth," to pay all accrued and unpaid interest on the
notes;
sixth, to pay all outstanding principal of (and then any other unpaid
amounts, including, without limitation, any fees, expenses, premiums and
reimbursement obligations) the credit facility;
seventh, to pay all accrued and unpaid interest on the notes (if not
paid under clause "fifth");
eighth, to pay all outstanding principal of (and then any other unpaid
amounts, including, without limitation, any premium with respect to) the notes;
and
ninth, to pay each credit facility lender, holder of the notes, and
other secured party, on a pro rata basis, all other amounts outstanding under
the credit facility and the notes.
To the extent there exists any excess monies or property in the collateral
account after all of ours and our subsidiaries' obligations under the credit
facility, the indenture and the notes are paid in full, the collateral agent
will be required to return such excess to us.
The collateral agent will act in accordance with the Intercreditor
Agreement and as directed by the "Control Party" which for purposes of the
Intercreditor Agreement is the holders of the notes and the credit facility
lenders, acting as a single class, by vote of the holders of a majority of the
aggregate principal amount of outstanding obligations under the notes and the
credit facility.
The Intercreditor Agreement provides that the lien on the assets
constituting part of the Collateral that is sold or otherwise disposed of in
accordance with the terms of each Secured Document may be released if (i) no
default or event of default exists under any of the Secured Documents, (ii) we
have delivered an officers' certificate to each of the collateral agent, the
trustee, the credit facility administrative agent certifying that the proposed
sale or other disposition of assets is either permitted or required by, and is
26
in accordance with the provisions of, the applicable Secured Documents and (iii)
the collateral agent has acknowledged such certificate.
The Intercreditor Agreement provides for the termination of security
interests on the date that all obligations under the Secured Documents are paid
in full.
Hedging Activities
Our results of operations are significantly affected by fluctuations in
commodity prices and we seek to reduce our exposure to price volatility by
hedging our production through commodity derivative instruments. Under the
revolving credit facility, we are required to maintain hedge positions on not
less than 25% nor more than 75% of our projected oil and gas production for a
rolling six month period.
Net Operating Loss Carryforwards
At December 31, 2005, we had $190.0 million of net operating loss
carryforwards for U.S. tax purposes. These loss carryforwards will expire
through 2025 if not utilized.
Uncertainties exist as to the future utilization of the operating loss
carryforwards under the criteria set forth under FASB Statement No. 109.
Therefore there is no current or deferred income tax expense or benefit due to
losses and/or loss carryforwards, and a valuation allowance which has been
recorded against such benefits.
Item 3. Quantitative and Qualitative Disclosures about Market Risk.
Commodity Price Risk
As an independent natural gas and crude oil producer, our revenue, cash
flow from operations, other income and profitability, reserve values, access to
capital and future rate of growth are substantially dependent upon the
prevailing prices of natural gas, natural gas liquids and crude oil. Declines in
commodity prices will materially adversely affect our financial condition,
liquidity, ability to obtain financing and operating results. Lower commodity
prices may reduce the amount of natural gas and crude oil that we can produce
economically. Prevailing prices for such commodities are subject to wide
fluctuation in response to relatively minor changes in supply and demand and a
variety of additional factors beyond our control, such as global political and
economic conditions. Historically, prices received for natural gas and crude oil
production have been volatile and unpredictable, and such volatility is expected
to continue. Most of our production is sold at market prices. Generally, if the
commodity indexes fall, the price that we receive for our production will also
decline. Therefore, the amount of revenue that we realize is partially
determined by factors beyond our control. Assuming the production levels we
attained during the nine months ended September 30, 2006, a 10% decline in
natural gas, natural gas liquids and crude oil prices would have reduced our
operating revenue, cash flow and net income by approximately $3.9 million for
the period.
Hedging Sensitivity
On January 1, 2001, we adopted SFAS 133 as amended by SFAS 137 and SFAS
138. Under SFAS 133, all derivative instruments are recorded on the balance
sheet at fair value. If the derivative does not qualify as a hedge or is not
designated as a hedge, the gain or loss on the derivative is recognized
currently in earnings. To qualify for hedge accounting, the derivative must
qualify either as a fair value hedge, cash flow hedge or foreign currency hedge.
None of the derivatives in place as of September 30, 2005 are designated as
hedges. Accordingly, the change in the market value of the instrument is
reflected in current oil and gas revenue.
Under the terms of the revolving credit facility, we are required to
maintain hedging positions on not less than 25% nor more than 75% of our natural
gas and crude oil production for a rolling six month period.
See "General - Commodity Prices and Hedging Activities" for a summary of
our current hedge positions.
27
Interest Rate Risk
At September 30, 2006 we had $125.0 million in outstanding indebtedness
under the floating rate senior secured notes due 2009. The notes bear interest
at a per annum rate of six-month LIBOR plus 7.5%. The rate is redetermined on
June 1 and December 1 of each year, beginning June 1, 2005. The current rate on
the notes is 12.82%. For every percentage point that the LIBOR rate rises, our
interest expense would increase by approximately $1.3 million on an annual
basis. At September 30, 2006, we had $1.1 million of outstanding indebtedness
under our revolving credit facility. Interest on this facility accrues at the
prime rate announced by Wells Fargo Bank plus 1.00%. For every percentage point
increase in the announced prime rate, our interest expense would increase by
approximately $11,000 on an annual basis.
Item 4. Controls and Procedures.
As of the end of the period covered by this report, our Chief Executive
Officer and Chief Financial Officer carried out an evaluation of the
effectiveness of Abraxas' "disclosure controls and procedures" (as defined in
the Securities Exchange Act of 1934 Rules 13a-15(e)and 15d-15(e)) and concluded
that the disclosure controls and procedures were effective and designed to
ensure that material information relating to Abraxas and our consolidated
subsidiaries which is required to be included in our periodic Securities and
Exchange Commission filings would be made known to them by others within those
entities. There were no changes in our internal controls over financial
reporting during the period covered by this report that could materially affect,
or are reasonably likely to materially affect, our financial reporting.
28
ABRAXAS PETROLEUM CORPORATION
PART II
OTHER INFORMATION
Item 1. Legal Proceedings.
There have been no changes in legal proceedings from that described in the
Company's Annual Report of Form 10-K for the year ended December 31, 2005, and
in Note 7 in the Notes to Condensed Consolidated Financial Statements contained
in Part I of this report on Form 10-Q.
Item 1A. Risk Factors.
In addition to the other information set forth in this report, you should
carefully consider the factors discussed in Part I, "Item 1A. Risk Factors" in
our Annual Report on Form 10-K for the year ended December 31, 2005, which could
materially affect our business, financial condition or future results. The risks
described in our Annual Report on Form 10-K are not the only risks facing
Abraxas. Additional risks and uncertainties not currently known to us or that we
currently deem to be immaterial also may materially adversely affect our
business, financial condition and/or operating results.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
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.
(a) Exhibits
Exhibit 31.1 Certification - Robert L.G. Watson, CEO
Exhibit 31.2 Certification - Chris E. Williford, CFO
Exhibit 32.1 Certification pursuant to 18 U.S.C. Section 1350 - Robert
L.G. Watson, CEO
Exhibit 32.2 Certification pursuant to 18 U.S.C. Section 1350 - Chris
E. Williford, CFO
29
ABRAXAS PETROLEUM CORPORATION
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended the Registrant has duly caused this report to be signed on its behalf by
the undersigned thereunto duly authorized.
Date: November 6, 2006 By:/s/ Robert L.G. Watson
--------------------------
ROBERT L.G. WATSON,
President and Chief
Executive Officer
Date: November 6, 2006 By:/s/ Chris E. Williford
-----------------------------
CHRIS E. WILLIFORD,
Executive Vice President and
Principal Accounting Officer
30
<