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 MARCH 31,
2008
|
[ ]
|
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: 001-16701
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, a
non-accelerated filer or a smaller reporting company. See definition of “large
accelerated filer”, “accelerated filer” and “smaller reporting
company” in Rule 12b-2 of the Exchange Act. (Check One)
Large accelerated filer [ ]
|
Accelerated
filer [ X ]
|
Non-accelerated filer [ ]
(Do not mark if a smaller reporting company)
|
Smaller
reporting company [ ]
|
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 of the issuer’s common stock outstanding as of
May 8, 2008 was:
Class
|
Shares
Outstanding
|
Common Stock, $.01 Par
Value
|
49,099,518
|
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 headings
“Management’s Discussion and Analysis of Financial Condition and Results of
Operations” but may be found in other locations as well. These forward-looking
statements generally relate to our plans and objectives for future operations and are based
upon our management’s reasonable estimates of future results or trends. The factors
that may affect our expectations regarding our operations include, among others, the
following:
|
•
|
our success in development, exploitation and exploration
activities;
|
|
•
|
our ability to make planned capital expenditures;
|
|
•
|
declines in our production of natural gas and crude
oil;
|
|
•
|
prices for natural gas and crude oil;
|
|
•
|
our ability to raise equity capital or incur additional
indebtedness;
|
|
•
|
political and economic conditions in oil producing
countries, especially those in the Middle East;
|
|
•
|
prices and availability of alternative fuels;
|
|
•
|
our restrictive debt covenants;
|
|
•
|
our acquisition and divestiture activities;
|
|
•
|
results of our hedging activities; and
|
|
•
|
other factors discussed elsewhere in this report.
|
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, 2007. 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.
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
FORM
10 – Q
INDEX
PART
I
FINANCIAL INFORMATION
ITEM 1 -
|
Consolidated Financial Statements (unaudited)
|
Condensed Consolidated Balance Sheets - March 31, 2008
Condensed Consolidated Statements of Operations -
|
Three Months Ended March 31, 2008 and 2007
|
6
|
Condensed Consolidated Statements of Cash Flows -
|
Three Months Ended March 31, 2008 and 2007
|
7
|
|
Notes to Condensed Consolidated Financial
Statements
|
8
|
ITEM 2 -
|
Management’s Discussion and Analysis of Financial
Condition and
|
ITEM 3 -
|
Quantitative and Qualitative Disclosure about Market
Risk
|
21
|
ITEM 4 -
|
Controls and Procedures
|
22
|
PART
II
OTHER
INFORMATION
ITEM 1 -
|
Legal Proceedings
|
23
|
ITEM 2 -
|
Unregistered Sales of Equity Securities and Use of
Proceeds
|
23
|
ITEM 3 -
|
Defaults Upon Senior Securities
|
23
|
ITEM 4 -
|
Submission of Matters to a Vote of Security
Holders
|
23
|
ITEM 5 -
|
Other Information
|
23
|
Abraxas Petroleum Corporation
Condensed Consolidated Balance Sheets
(unaudited)
(in
thousands)
|
|
March 31,
|
|
December 31,
|
|
|
|
2008
|
|
2007
|
|
|
|
(Unaudited)
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
6,571
|
|
$
|
18,936
|
|
Accounts receivable, net:
|
|
|
|
|
|
|
|
Joint owners
|
|
|
1,726
|
|
|
840
|
|
Oil and gas production
|
|
|
12,856
|
|
|
5,288
|
|
Other
|
|
|
55
|
|
|
—
|
|
|
|
|
14,637
|
|
|
6,240
|
|
|
|
|
|
|
|
|
|
Hedge asset – current
|
|
|
—
|
|
|
2,658
|
|
Other current assets
|
|
|
343
|
|
|
377
|
|
Total current assets
|
|
|
21,551
|
|
|
28,099
|
|
|
|
|
|
|
|
|
|
Property and equipment:
|
|
|
|
|
|
|
|
Oil and gas properties, full cost method of
accounting:
|
|
|
|
|
|
|
|
Proved
|
|
|
402,761
|
|
|
265,090
|
|
Unproved properties excluded from depletion
|
|
|
—
|
|
|
—
|
|
Other property and equipment
|
|
|
3,819
|
|
|
3,633
|
|
Total
|
|
|
406,580
|
|
|
268,723
|
|
Less accumulated depreciation, depletion, and
amortization
|
|
|
156,788
|
|
|
151,696
|
|
Total property and equipment – net
|
|
|
249,792
|
|
|
117,027
|
|
|
|
|
|
|
|
|
|
Deferred financing fees, net
|
|
|
2,161
|
|
|
856
|
|
Hedge asset – Long-term
|
|
|
—
|
|
|
359
|
|
Other assets
|
|
|
908
|
|
|
778
|
|
Total assets
|
|
$
|
274,412
|
|
$
|
147,119
|
|
See
accompanying notes to condensed consolidated financial statements
Abraxas Petroleum Corporation
Condensed Consolidated Balance Sheets (continued)
(unaudited)
(in
thousands)
|
|
March 31,
|
|
December 31,
|
|
|
|
2008
|
|
2007
|
|
|
|
(Unaudited)
|
|
|
|
Liabilities and Stockholders’ Equity
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
5,261
|
|
$
|
7,413
|
|
Oil and gas production payable
|
|
|
3,028
|
|
|
2,429
|
|
Accrued interest
|
|
|
1,569
|
|
|
241
|
|
Other accrued expenses
|
|
|
1,666
|
|
|
1,514
|
|
Hedge liability – current
|
|
|
12,073
|
|
|
5,154
|
|
Current maturities of long-term debt
|
|
|
50,000
|
|
|
—
|
|
Total current liabilities
|
|
|
73,597
|
|
|
16,751
|
|
|
|
|
|
|
|
|
|
Long-term debt, excluding current maturities
|
|
|
115,600
|
|
|
45,900
|
|
|
|
|
|
|
|
|
|
Hedge liability – long-term
|
|
|
17,546
|
|
|
3,941
|
|
Future site restoration
|
|
|
9,971
|
|
|
1,019
|
|
Total liabilities
|
|
|
216,714
|
|
|
67,775
|
|
|
|
|
|
|
|
|
|
Minority interest in partnership
|
|
|
10,433
|
|
|
23,497
|
|
|
|
|
|
|
|
|
|
Stockholders’ equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock, par value $.01 per share-authorized
200,000,000 shares; issued 49,054,018 and, 49,020,949
|
|
|
491
|
|
|
490
|
|
Additional paid-in capital
|
|
|
185,927
|
|
|
185,646
|
|
Accumulated deficit
|
|
|
(139,782
|
)
|
|
(130,791
|
)
|
Accumulated other comprehensive income
|
|
|
629
|
|
|
502
|
|
Total stockholders’ equity
|
|
|
47,265
|
|
|
55,847
|
|
Total liabilities and stockholders’ equity
|
|
$
|
274,412
|
|
$
|
147,119
|
|
See
accompanying notes to condensed consolidated financial statements
Abraxas Petroleum Corporation
Condensed Consolidated Statements of Operations
(Unaudited)
(in thousands except per share data)
|
|
Three Months Ended
March 31,
|
|
|
|
2008
|
|
2007
|
|
Revenue:
|
|
|
|
|
|
|
|
Oil and gas production revenues
|
|
$
|
21,863
|
|
$
|
11,532
|
|
Rig revenues151
|
|
|
306
|
|
|
328
|
|
Realized hedge loss
|
|
|
(883
|
)
|
|
(81
|
)
|
Unrealized hedge loss
|
|
|
(26,075
|
)
|
|
(129
|
)
|
Other
|
|
|
1
|
|
|
1
|
|
|
|
|
(4,788
|
)
|
|
11,651
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
Lease operating and production taxes
|
|
|
5,202
|
|
|
2,962
|
|
Depreciation, depletion and amortization
|
|
|
5,094
|
|
|
3,655
|
|
Rig operations
|
|
|
210
|
|
|
171
|
|
General and administrative (including stock-based
compensation of $246 and $171)
|
|
|
1,799
|
|
|
1,316
|
|
|
|
|
12,305
|
|
|
8,104
|
|
Operating income (loss)
|
|
|
(17,093
|
)
|
|
3,547
|
|
|
|
|
|
|
|
|
|
Other (income) expense
|
|
|
|
|
|
|
|
Interest income
|
|
|
(96
|
)
|
|
(14
|
)
|
Interest expense
|
|
|
2,466
|
|
|
4,151
|
|
Amortization of deferred financing fees
|
|
|
194
|
|
|
398
|
|
|
|
|
2,564
|
|
|
4,535
|
|
Loss before minority interest
|
|
|
(19,657
|
)
|
|
(988
|
)
|
Minority interest in loss of partnership
|
|
|
10,666
|
|
|
—
|
|
Net loss
|
|
|
(8,991
|
)
|
$
|
(988
|
)
|
|
|
|
|
|
|
|
|
Net income per common share – basic
|
|
$
|
(0.18
|
)
|
$
|
(0.02
|
)
|
Net income per common share – diluted
|
|
$
|
(0.18
|
)
|
$
|
(0.02
|
)
|
See
accompanying notes to condensed consolidated financial statements
Abraxas Petroleum Corporation
Condensed Consolidated Statements of Cash Flows
(Unaudited)
(in
thousands)
|
|
Three Months Ended
March 31,
|
|
|
|
2008
|
|
2007
|
|
Cash flows from Operating Activities
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(8,991
|
)
|
$
|
(988
|
)
|
Adjustments to reconcile net income (loss) to net
|
|
|
|
|
|
|
|
cash provided by operating activities:
|
|
|
|
|
|
|
|
Minority interest in partnership loss
|
|
|
(10,666
|
)
|
|
—
|
|
Change in derivative fair value
|
|
|
23,541
|
|
|
(129
|
)
|
Depreciation, depletion, and amortization
|
|
|
5,094
|
|
|
3,655
|
|
Accretion of future site restoration
|
|
|
120
|
|
|
27
|
|
Amortization of deferred financing fees
|
|
|
194
|
|
|
398
|
|
Stock-based compensation
|
|
|
246
|
|
|
172
|
|
Other non-cash items
|
|
|
21
|
|
|
128
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(8,509
|
)
|
|
(31
|
)
|
Other
|
|
|
31
|
|
|
575
|
|
Accounts payable and accrued expenses
|
|
|
8,595
|
|
|
953
|
|
Net cash provided by operations
|
|
|
9,676
|
|
|
4,760
|
|
|
|
|
|
|
|
|
|
Cash flows from Investing Activities
|
|
|
|
|
|
|
|
Capital expenditures, including purchases and development of
properties
|
|
|
(137,859
|
)
|
|
(3,900
|
)
|
Net cash used in investing activities
|
|
|
(137,859
|
)
|
|
(3,900
|
)
|
|
|
|
|
|
|
|
|
Cash flows from Financing Activities
|
|
|
|
|
|
|
|
Proceeds from long-term borrowings
|
|
|
119,700
|
|
|
708
|
|
Payments on long-term borrowings
|
|
|
—
|
|
|
(1,000
|
)
|
Proceeds from exercise of stock options
|
|
|
15
|
|
|
—
|
|
Deferred financing fees
|
|
|
(1,499
|
)
|
|
(1
|
)
|
Partnership distributions
|
|
|
(2,398
|
)
|
|
—
|
|
Net cash provided by (used in) financing
operations
|
|
|
115,818
|
|
|
(293
|
)
|
Increase (decrease) in cash
|
|
|
(12,365
|
)
|
|
567
|
|
Cash, at beginning of period
|
|
|
18,936
|
|
|
43
|
|
Cash, at end of period
|
|
$
|
6,571
|
|
$
|
610
|
|
|
|
|
|
|
|
|
|
Supplemental disclosures of cash flow
information:
|
|
|
|
|
|
|
|
Interest paid
|
|
$
|
2,314
|
|
$
|
108
|
|
See
accompanying notes to condensed consolidated financial statements
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”) are set forth in the notes to the Company’s
audited consolidated financial statements in the Annual Report on Form 10-K filed for the
year ended December 31, 2007. 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 registered public accountants, but in the
opinion of management, reflect all adjustments necessary for a fair presentation of the
financial position and results of operations. Any and all adjustments are of a normal and
recurring nature. The results of operations for the three months ended March 31, 2008 are
not necessarily indicative of results to be expected for the full year.
The terms “Abraxas” or “Abraxas Petroleum” refer to
Abraxas Petroleum Corporation and its subsidiaries other than Abraxas Energy Partners,
L.P., which we refer to as “Abraxas Energy Partners” or the
“Partnership”, and its subsidiary, Abraxas Operating, LLC, which we refer to as
“Abraxas Operating” and the terms “we”, “us”,
“our” or the “Company” refer to Abraxas Petroleum Corporation and
all of its consolidated subsidiaries including Abraxas Energy Partners and Abraxas
Operating effective May 25, 2007. The operations of Abraxas Petroleum and the Partnership
are consolidated for financial reporting purposes with the interest of the 52.8% minority
owners of the Partnership presented as minority interest. Abraxas owns the remaining 47.2%
of the partnership interests. The Company has determined that based on its control of the
general partner of the Partnership, this 47.2% owned entity should be consolidated for
financial reporting purposes.
The condensed consolidated financial statements included herein have been
prepared by Abraxas and are unaudited, except for the balance sheet at December 31, 2007,
which has been derived from the audited consolidated financial statements at that date. In
the opinion of management, the unaudited condensed consolidated financial statements
include all recurring adjustments necessary for a fair presentation of the financial
position as of March 31, 2008 and 2007, and the cash flows for each of the three-month
periods ended March 31, 2008 and 2007. Although management believes the unaudited interim
related disclosures in these consolidated financial statements are adequate to make the
information presented not misleading, certain information and footnote disclosures normally
included in annual audited consolidated financial statements prepared in accordance with
accounting principles generally accepted in the United States of America have been
condensed or omitted pursuant to the rules and regulations of the Securities and Exchange
Commission. The results of operations and the cash flows for the three-month period ended
March 31, 2008 are not necessarily indicative of the results to be expected for the full
year. The condensed consolidated financial statements included herein should be read in
conjunction with the consolidated audited financial statements and the notes thereto
included in the Company’s Annual Report on Form 10-K for the year ended December 31,
2007.
Use of
Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities as of the date of the
financial statements and reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
Stock-based Compensation
The Company currently utilizes a standard option-pricing model (i.e.,
Black-Scholes) to measure the fair value of stock options granted to employees. The Company
uses the Black-Scholes model for option valuation as of the current time.
The following table summarizes the stock option activities for the three
months ended March 31, 2008.
|
|
Shares
|
|
|
Weighted
Average
Option
Exercise
Price Per
Share
|
|
|
Weighted
Average
Grant
Date Fair
Value
Per Share
|
|
|
Aggregate
Intrinsic
Value
|
|
Outstanding, December 31, 2007
|
|
2,526
|
|
|
$
|
2.65
|
|
|
$
|
1.52
|
|
|
$
|
3,847
|
|
Granted
|
|
13
|
|
|
$
|
3.61
|
|
|
$
|
2.16
|
|
|
|
29
|
|
Exercised
|
|
(8)
|
|
|
$
|
1.65
|
|
|
$
|
1.39
|
|
|
|
(12)
|
|
Expired or canceled
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
—
|
|
Outstanding, March 31, 2008
|
|
2,531
|
|
|
$
|
2.66
|
|
|
$
|
1.53
|
|
|
$
|
3,864
|
|
The following table shows the weighted average assumptions used in the
Black-Scholes valuation of the fair value of option grants during 2008.
Expected dividend yield
|
|
|
0
|
%
|
Volatility
|
|
|
0.5198
|
|
Risk free interest rate
|
|
|
3.598
|
%
|
Expected life
|
|
|
7.83
|
|
Fair value of options granted
|
|
$
|
29
|
|
Weighted average grant date fair value of options
granted
|
|
$
|
2.16
|
|
Additional information related to options at March 31, 2008 and
December 31, 2007 is as follows:
|
|
|
|
March 31,
|
|
|
|
December 31,
|
|
|
|
|
|
2008
|
|
|
|
2007
|
|
Options exercisable
|
|
|
|
1,867
|
|
|
|
1,852
|
|
As of March
31, 2008, there was approximately $1.6 million of unamortized compensation expense related
to outstanding options that will be recognized through the period ended March
2010.
Recently
Issued Accounting Pronouncements
Fair Value Measurements (SFAS
No. 157) —
In September 2006, the Financial Accounting
Standards Board (“FASB”) issued Statement of Financial Accounting Standards
(“SFAS”) No. 157, which provides a single definition of fair value,
together with a framework for measuring it, and requires additional disclosure about the
use of fair value to measure assets and liabilities. SFAS No. 157 also emphasizes that
fair value is a market-based measurement, and sets out a fair value hierarchy with the
highest priority being quoted prices in active markets. Fair value measurements are
disclosed by level within that hierarchy. SFAS No. 157 is effective for financial
statements issued for fiscal years beginning after November 15, 2007. The FASB agreed
to defer the effective date of Statement 157 for one year for nonfinancial assets and
nonfinancial liabilities that are recognized or disclosed at fair value in the financial
statements on a nonrecurring basis. There is no deferral for financial assets and financial
liabilities. We are evaluating the impact of SFAS No. 157 on our consolidated
financial statements and do not expect the impact of implementation to be
material.
The Fair Value Option for Financial Assets and Financial Liabilities —
Including an Amendment of FASB Statement No. 115 (SFAS No. 159)
—
In February 2007, the FASB issued SFAS No. 159, which
provides companies with an option to measure, at specified election dates, many financial
instruments and certain other items at fair value that are not currently measured at fair
value. A company that adopts SFAS No. 159 will report unrealized gains and losses on
items, for which the fair value option has been elected, in earnings at each subsequent
reporting date. This statement also establishes presentation and disclosure requirements
designed to facilitate comparisons between entities that choose different measurement
attributes for similar types of assets and liabilities. This statement is effective for
fiscal years beginning after November 15, 2007. We do not expect the implementation of
SFAS No. 159 to have a material impact on our consolidated financial
statements.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about
Derivative Instruments and Hedging Activities,” which amends SFAS No. 133,
“Accounting for Derivative Instruments and Hedging
Activities.” Enhanced disclosures to improve financial reporting
transparency are required and include disclosure about the location and amounts of
derivative instruments in the financial statements, how derivative instruments are
accounted for and how derivatives affect an entity’s financial position, financial
performance and cash flows. A tabular format including the fair value of derivative
instruments and their gains and losses, disclosure about credit risk-related derivative
features and cross-referencing within the footnotes are also new requirements. SFAS
No. 161 is effective for financial statements issued for fiscal years and interim
periods beginning after November 15, 2008, with early application and comparative
disclosures encouraged, but not required. We have not yet adopted SFAS No. 161. We do
not believe that SFAS No. 161 will have a material impact on our financial position,
results of operations or cash flows.
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling
Interest in Consolidated Financial Statements, an amendment of Accounting Research Bulletin
(ARB) No. 51.” SFAS No. 160 clarifies that a noncontrolling interest
(previously commonly referred to as a minority interest) in a subsidiary is an ownership
interest in the consolidated entity and should be reported as equity in the consolidated
financial statements. The presentation of the consolidated income statement has been
changed by SFAS No. 160, and consolidated net income attributable to both the parent
and the noncontrolling interest is now required to be reported separately. Previously, net
income attributable to the noncontrolling interest was typically reported as an expense or
other deduction in arriving at consolidated net income and was often combined with other
financial statement amounts. In addition, the ownership interests in subsidiaries held by
parties other than the parent must be clearly identified, labeled, and presented in the
equity in the consolidated financial statements separately from the parent’s equity.
Subsequent changes in a parent’s ownership interest while the parent retains its
controlling financial interest in its subsidiary should be accounted for consistently, and
when a subsidiary is deconsolidated, any retained noncontrolling equity interest in the
former subsidiary must be initially measured at fair value. Expanded disclosures, including
a reconciliation of equity balances of the parent and noncontrolling interest, are also
required. SFAS No. 160 is effective for fiscal years, and interim periods within those
fiscal years, beginning on or after December 15, 2008 and earlier adoption is
prohibited. Prospective application is required. At this time, we do not have any material
noncontrolling interests in consolidated subsidiaries. Therefore, we do not believe that
the adoption of SFAS No. 160 will have a material impact on our financial position,
results of operations or cash flows.
In December 2007, the FASB issued SFAS No. 141(R), “Business
Combinations.” SFAS No. 141(R) was issued in an effort to continue the movement
toward the greater use of fair values in financial reporting and increased transparency
through expanded disclosures. It changes how business acquisitions are accounted for and
will impact financial statements at the acquisition date and in subsequent periods. Certain
of these changes will introduce more volatility into earnings. The acquirer must now record
all assets and liabilities of the acquired business at fair value, and related transaction
and restructuring costs will be expensed rather than the previous method of being
capitalized as part of the acquisition. SFAS No. 141(R) also impacts the annual
goodwill impairment test associated with acquisitions, including those that close before
the effective date of SFAS No. 141(R). The definitions of a “business” and
a “business combination” have been expanded, resulting in more transactions
qualifying as business combinations. SFAS No. 141(R) is effective for fiscal years,
and interim periods within those fiscal years, beginning on or after December 31, 2008
and earlier adoption is prohibited. We cannot predict the impact that the adoption of SFAS
No. 141(R) will have on our financial position, results of operations or cash flows
with respect to any acquisitions completed after December 31, 2008.
Note 2.
Acquisitions
On January 31, 2008, Abraxas Operating Company, a wholly-owned subsidiary of
the Partnership, consummated the acquisition of certain oil and gas properties located in
various states from St. Mary Land & Exploration Company, (“St. Mary”), and
certain other sellers for $126.0 million. The properties are primarily located in the Rocky
Mountain and Mid-Continent regions of the United States, and, at December 31, 2007,
included approximately 57.5 Bcfe (9.6 MMBOE) of estimated proved reserves.
The Partnership borrowed approximately $115.6 million under its credit
facility and $50 million under a new subordinated credit agreement in order to complete
this acquisition and repay its previously outstanding indebtedness of $45.9 million. For a
complete description of these credit facilities, please see “Management’s
Discussion and Analysis of Financial Condition and Results of Operations–Liquidity
and Capital Resources–Long-Term Indebtedness”.
Simultaneously, Abraxas announced that it had completed the acquisition of
certain oil and gas properties from St. Mary with estimated proved reserves of at December
31, 2007 of approximately 3.1 Bcfe (0.5 MMBOE) for a purchase price of approximately $5.6
million. Abraxas paid the purchase price from its internal funds. The right to purchase
these properties had previously been assigned to Abraxas by the Partnership.
The results of operations from these properties from the effective date of
December 1, 2007 through closing on January 31, 2008 will be accounted for as a purchase
price adjustment. The revenue and expenses relating to these properties for the months of
February and March 2008 are included in the accompanying unaudited condensed consolidated
financial statements.
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 three-month period ended March 31, 2008, there is no current or
deferred income tax expense or benefit due to losses and/or loss carryforwards and
valuation allowance which has been recorded against such benefits.
In June 2006, the FASB issued FASB Interpretation No. 48,
“Accounting for Uncertainty in Income Taxes” (“FIN 48”). FIN 48 is
an interpretation of SFAS 109, “Accounting for Income Taxes”, and it seeks to
reduce the diversity in practice associated with certain aspects of measurement and
accounting for income taxes and requires expanded disclosure with respect to the
uncertainty in income taxes. FIN 48 is effective for fiscal years beginning after December
15, 2006. Accordingly, the Company adopted FIN 48 on January 1, 2007. The adoption of FIN
48 did not have any effect on the Company’s financial position or results of
operations for the quarter ended March 31, 2008. The Company recognizes interest and
penalties related to uncertain tax positions in income tax expense. As of March 31, 2008,
the Company did not have any accrued interest or penalties related to uncertain tax
positions. The tax years from 1999 through 2007 remain open to examination by the tax
jurisdictions to which the Company is subject.
Long-term debt consisted of the following:
|
|
|
|
|
|
|
|
March 31,
2008
|
|
December 31,
2007
|
|
Partnership credit facility
|
|
$
|
115,600
|
|
$
|
45,900
|
|
Partnership subordinated credit agreement
|
|
|
50,000
|
|
|
—
|
|
Senior secured credit facility
|
|
|
—
|
|
|
—
|
|
|
|
|
165,600
|
|
|
45,900
|
|
Less current maturities
|
|
|
(50,000
|
)
|
|
—
|
|
|
|
$
|
115,600
|
|
$
|
45,900
|
|
Senior Secured Credit Facility.
On June
27, 2007, Abraxas entered into a new senior secured revolving credit facility, which we
refer to as the Credit Facility. The Credit Facility has a maximum commitment of $50
million. Availability under the Credit Facility is subject to a borrowing base. The
borrowing base under the Credit Facility, which is currently $6.5 million, is determined
semi-annually by the lenders based upon our reserve reports, one of which must be prepared
by our independent petroleum engineers and one of which may be prepared internally. The
amount of the borrowing base is calculated by the lenders based upon their valuation of our
proved reserves utilizing these reserve reports and their own internal decisions. In
addition, the lenders, in their sole discretion, may make one additional borrowing base
redetermination during any six-month period between scheduled redeterminations and we may
also request one redetermination during any six-month period between scheduled
redeterminations. The lenders may also make a redetermination in connection with any sales
of producing properties with a market value of 5% or more of our current borrowing base.
Our borrowing base at March 31, 2008 of $6.5 million was determined based upon our reserves
at December 31, 2006 after giving effect to the contribution of properties to the
Partnership in May 2007. Our borrowing base can never exceed the $50.0 million maximum
commitment amount. Outstanding amounts under the Credit Facility will bear interest at (a)
the greater of reference rate announced from time to time by Société
Générale, and (b) the Federal Funds Rate plus ½ of 1%, plus in each
case, (c) 0.5% - 1.5% depending on utilization of the borrowing base, or, if Abraxas
elects, at the London Interbank Offered Rate plus 1.5% - 2.5%, depending on the utilization
of the borrowing base. Subject to earlier termination rights and events of default, the
Credit Facility’s stated maturity date will be June 27, 2011. Interest will be
payable quarterly on reference rate advances and not less than quarterly on Eurodollar
advances.
Abraxas is permitted to terminate the Credit Facility, and may, from time to
time, permanently reduce the lenders’ aggregate commitment under the Credit Facility
in compliance with certain notice and dollar increment requirements.
Each of Abraxas’ subsidiaries other than the Partnership, Abraxas
General Partner, LLC and Abraxas Energy Investments, LLC has guaranteed Abraxas’
obligations under the Credit Facility on a senior secured basis. Obligations under the
Credit Facility are secured by a first priority perfected security interest, subject to
certain permitted encumbrances, in all of Abraxas’ and the subsidiary
guarantors’ material property and assets.
Under the Credit Facility, Abraxas is subject to customary covenants,
including certain financial covenants and reporting requirements. The Credit Facility
requires Abraxas to maintain a minimum current ratio as of the last day of each quarter of
not less than 1.00 to 1.00 and an interest coverage ratio (generally defined as the ratio
of consolidated EBITDA to consolidated interest expense as of the last day of such quarter)
of not less than 2.50 to 1.00.
In addition to the foregoing and other customary covenants, the Credit
Facility contains a number of covenants that, among other things, will restrict
Abraxas’ ability to:
|
•
|
incur or guarantee additional indebtedness;
|
|
•
|
transfer or sell assets;
|
|
•
|
create liens on assets;
|
|
•
|
engage in transactions with affiliates other than on an
“arms-length” basis;
|
|
•
|
make any change in the principal nature of its business;
and
|
|
•
|
permit a change of control.
|
The 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.
Amended and Restated Partnership Credit Facility.
On May 25, 2007, the Partnership entered into a senior secured revolving
credit facility which was amended and restated on January 31, 2008, which we refer to as
the Partnership Credit Facility. The Partnership Credit Facility has a maximum commitment
of $300.0 million. Availability under the Partnership Credit Facility is subject to a
borrowing base. The borrowing base under the Partnership Credit Facility, which is
currently $140.0 million, is determined semi-annually by the lenders based upon the
Partnership’s reserve reports, one of which must be prepared by the
Partnership’s independent petroleum engineers and one of which may be prepared
internally. The amount of the borrowing base is calculated by the lenders based upon their
valuation of the Partnership’s proved reserves utilizing these reserve reports and
their own internal decisions. In addition, the lenders, in their sole discretion, may make
one additional borrowing base redetermination during any six-month period between scheduled
redeterminations. The lenders may also make a redetermination in connection with any sales
of producing properties with a market value of 5% or more of the Partnership’s
current borrowing base. The Partnership’s current borrowing base of $140.0 million
was determined based upon its reserves at June 30, 2007 and the reserves attributable to
the oil and gas properties acquired from St. Mary Land & Exploration Company on January
31, 2008. The borrowing base can never exceed the $300 million maximum commitment amount.
Outstanding amounts under the Partnership Credit Facility bear interest at the reference
rate announced from time to time by Société Générale plus .25%
- 1.00%, depending on the utilization of the borrowing base or, if the Partnership elects,
at the London Interbank Offered Rate plus 1.25% - 2.00%, depending on the utilization of
the borrowing base. Subject to earlier termination rights and events of default, the
Partnership Credit Facility’s stated maturity date is January 31, 2013. Interest is
payable quarterly on reference rate advances and not less than quarterly on Eurodollar
advances. The Partnership is permitted to terminate the Partnership Credit Facility, and
under certain circumstances, may be required, from time to time, to permanently reduce the
lenders’ aggregate commitment under the Partnership Credit Facility.
Each of the general partner of the Partnership, Abraxas General Partner,
LLC, which is a wholly-owned subsidiary of Abraxas and which we refer to as the GP, and
Abraxas Operating, LLC, which is a wholly-owned subsidiary of the Partnership and which we
refer to as the Operating Company, has guaranteed the Partnership’s obligations under
the Credit Facility on a senior secured basis. Obligations under the Partnership Credit
Facility are secured by a first priority perfected security interest, subject to certain
permitted encumbrances, in property and assets of the GP, the Partnership and the Operating
Company comprising at least 90% of the PV-10 of their proved reserves and the related oil
and gas properties, other than the GP’s general partner units in the
Partnership.
Under the Partnership Credit Facility, the Partnership is subject to
customary covenants, including certain financial covenants and reporting requirements. The
Partnership Credit Facility requires the Partnership to maintain a minimum current ratio as
of the last day of each quarter of 1.0 to 1.0 and an interest coverage ratio (defined as
the ratio of consolidated EBITDA to consolidated interest expense) as of the last day of
each quarter of not less than 2.50 to 1.00.
Under the terms of the Partnership Credit Facility, the Partnership may make
cash distributions if, after giving effect to such distributions, the Partnership is not in
default under the Partnership Credit Facility and there is no borrowing base deficiency and
provided that no such distribution shall be made using the proceeds of any advance unless
the amount of the unused portion of the amount then available under the Partnership Credit
Facility is greater than or equal to 10% of the lesser of the Partnership’s borrowing
base (which is currently $140.0 million) or the total commitment amount of the
Partnership Credit Facility (which is currently $300.0 million) at such
time.
In addition to the foregoing and other customary covenants, the Partnership
Credit Facility contains a number of covenants that, among other things, will restrict the
Partnership’s ability to:
|
•
|
incur or guarantee additional indebtedness;
|
|
•
|
transfer or sell assets;
|
|
•
|
create liens on assets;
|
|
•
|
engage in transactions with affiliates;
|
|
•
|
make any change in the principal nature of its business;
and
|
|
•
|
permit a change of control.
|
The Partnership 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 including the Subordinated Credit
Agreement described below, bankruptcy and material judgments and liabilities.
Subordinated Credit Agreement
On January 31, 2008, the Partnership entered into a subordinated credit
agreement which we refer to as the Subordinated Credit Agreement. The Subordinated Credit
Agreement has a maximum commitment of $50 million, all of which was borrowed at closing.
Outstanding amounts under the Subordinated Credit Agreement bear interest at the reference
rate announced from time to time by Société Générale or, if the
Partnership elects, at the London Interbank Offered Rate plus, in each case, the amount set
forth below:
Date
|
Eurodollar Rate (LIBOR) Advances
|
Base Rate Advances
|
01/31/08 – 04/30/08
|
5.0%
|
4.0%
|
05/01/08 – 01/31/08
|
5.5%
|
4.5%
|
After 07/31/08
|
6.5%
|
5.5%
|
|
|
|
Subject to earlier termination rights and events of default, the
Subordinated Credit Agreement’s stated maturity date is January 31, 2009. Interest is
payable quarterly on reference rate advances and not less than quarterly on Eurodollar
advances. The Partnership is permitted to terminate the Subordinated Credit Agreement, and
under certain circumstances, may be required, from time to time, to make prepayments under
the Subordinated Credit Agreement.
Each of the GP and Abraxas Operating has guaranteed the Partnership’s
obligations under the Subordinated Credit Agreement on a subordinated secured basis.
Obligations under the Subordinated Credit Agreement are secured by subordinated security
interests, subject to certain permitted encumbrances, in property and assets of the
Partnership, GP, and Abraxas Operating comprising at least 90% of the PV-10 of their proved
reserves and the related oil and gas properties, other than the GP’s general partner
units in the Partnership.
Under the Subordinated Credit Agreement, the Partnership is subject to
customary covenants, including certain financial covenants and reporting requirements. The
Subordinated Credit Agreement requires the Partnership to maintain a minimum current ratio
as of the last day of each quarter of 1.0 to 1.0 and an interest coverage ratio (defined as
the ratio of consolidated EBITDA to consolidated interest expense) as of the last day of
each quarter of not less than 2.50 to 1.00.
In addition to the foregoing and other customary covenants, the Subordinated
Credit Agreement contains a number of covenants that, among other things, will restrict the
Partnership’s ability to:
|
•
|
incur or guarantee additional indebtedness;
|
|
•
|
transfer or sell assets;
|
|
•
|
create liens on assets;
|
|
•
|
engage in transactions with affiliates;
|
|
•
|
make any change in the principal nature of its business;
and
|
|
•
|
permit a change of control.
|
The Subordinated Credit Agreement 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 the Credit Facility, bankruptcy
and material judgments and liabilities.
Note
5. Earnings (Loss) Per Share
|
The following table sets forth the computation of basic and
diluted earnings per share:
|
|
|
Three Months Ended March 31,
|
|
|
|
2008
|
|
2007
|
|
Numerator
|
|
(in thousands except per
share data)
|
|
Net loss available to common stockholders
|
|
$
|
(8,991
|
)
|
$
|
(988
|
)
|
Denominator:
|
|
|
|
|
|
|
|
Denominator for basic earnings per share –
weighted-average shares
|
|
|
48,871,974
|
|
|
42,681,278
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
Stock options and warrants
|
|
|
—
|
|
|
—
|
|
Denominator for diluted earnings per share - adjusted
weighted-average shares and assumed Conversions
|
|
|
48,871,974
|
|
|
42,681,278
|
|
Net earnings per common share – basic
|
|
$
|
(0.18
|
)
|
$
|
(0.02
|
)
|
Net earnings per common share – diluted
|
|
$
|
(0.18
|
)
|
$
|
(0.02
|
)
|
For the three months ended March 31, 2008 none of the shares issuable in
connection with stock options or warrants are included in diluted shares. Inclusion of
these shares would be antidilutive due to losses incurred in the period. Had there not been
a loss in this period, dilutive shares would have been 399,408_shares for the three months
ended March 31, 2008.
Note
6.
Hedging Program and Derivatives
The Partnership enters into agreements to hedge the risk of future oil and gas price
fluctuations. Such agreements are primarily in the form of NYMEX-based fixed price
commodity swaps, which limit the impact of price fluctuations with respect to the
Partnership’s sale of oil and gas. The Partnership does not enter into speculative
hedges.
Statement of Financial Accounting Standards, (‘‘SFAS’’) No. 133,
‘‘Accounting for Derivative Instruments and Hedging Activities,’’
as amended and interpreted, establishes accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other contracts, and for
hedging activities. The Partnership elected not to designate its derivative instruments for
hedge accounting as prescribed by SFAS 133. Accordingly, all derivatives will be recorded
on the balance sheet at fair value with changes in fair value being recognized in
earnings.
Under the terms of the Partnership Credit Facility, Abraxas Energy Partners
was required to enter into hedging arrangements for specified volumes, which equated to
approximately 85% of the estimated oil and gas production through December 31, 2011 from
its net proved developed producing reserves.
The following table sets forth the Partnership’s current hedge
position:
Period Covered
|
Hedged Product
|
Hedged Volume
(Production per day)
|
Weighted Average
Fixed Price
|
Year 2008
|
Natural Gas
|
11,840 Mmbtu
|
$8.44
|
Year 2008
|
Crude Oil
|
1,105 Bbl
|
$84.84
|
Year 2009
|
Natural Gas
|
10,595 Mmbtu
|
$8.45
|
Year 2009
|
Crude Oil
|
1,000 Bbl
|
$83.80
|
Year 2010
|
Natural Gas
|
9,130 Mmbtu
|
$8.22
|
Year 2010
|
Crude Oil
|
895 Bbl
|
$83.26
|
Year 2011
|
Natural Gas
|
8,010 Mmbtu
|
$8.10
|
Year 2011
|
Crude Oil
|
810 Bbl
|
$86.45
|
Note
7. Financial Instruments
SFAS 157
—Effective January 1,
2008, the Company adopted Financial Accounting Standards Board (“FASB”)
Statement No. 157,
Fair Value Measurements
(“SFAS 157”), which defines fair value, establishes a
framework for measuring fair value, establishes a fair value hierarchy based on the quality
of inputs used to measure fair value and enhances disclosure requirements for fair value
measurements. The implementation of SFAS 157 did not cause a change in the method of
calculating fair value of assets or liabilities, with the exception of incorporating a
measure of the Company’s own nonperformance risk or that of its counterparties as
appropriate, which was not material. The primary impact from adoption was additional
disclosures.
The Company elected to implement SFAS 157 with the one-year deferral
permitted by FASB Staff Position No. FAS 157-2,
Effective Date of
FASB Statement
No
. 157
(“FSP 157-2”), issued February 2008, which defers the effective
date of SFAS 157 for one year for certain nonfinancial assets and nonfinancial liabilities
measured at fair value, except those that are recognized or disclosed at fair value in the
financial statements on a recurring basis. As it relates to the Company, the deferral
applies to certain nonfinancial assets and liabilities as may be acquired in a business
combination and thereby measured at fair value; impaired oil and gas property assessments;
and the initial recognition of asset retirement obligations for which fair value is
used.
Fair Value Hierarchy
—SFAS 157
establishes a three-level valuation hierarchy for disclosure of fair value measurements.
The valuation hierarchy categorizes assets and liabilities measured at fair value into one
of three different levels depending on the observability of the inputs employed in the
measurement. The three levels are defined as follows:
|
•
|
Level 1 – inputs to the valuation methodology are
quoted prices (unadjusted) for identical assets or liabilities in active
markets.
|
|
•
|
Level 2- inputs to the valuation methodology include quoted
prices for similar assets and liabilities in active markets, and inputs
that are observable for the asset or liability, either directly or
indirectly, for substantially the full term of the financial
instrument.
|
|
•
|
Level 3 -
inputs to the valuation
methodology are unobservable and significant to the fair value
measurement.
|
A financial instrument’s categorization within the valuation hierarchy
is based upon the lowest level of input that is significant to the fair value measurement.
The Company’s assessment of the significance of a particular input to the fair value
measurement in its entirety requires judgment and considers factors specific to the asset
or liability. The following table presents information about the Company’s assets and
liabilities measured at fair value on a recurring basis as of March 31, 2008, and indicates
the fair value hierarchy of the valuation techniques utilized by the Company to determine
such fair value (in thousands):
|
|
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs (Level 3)
|
|
Balance as of
March 31,
2008
|
|
Assets
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative contracts
|
|
$
|
—
|
|
$
|
—
|
|
$
|
29,619
|
|
$
|
29,619
|
|
Total Liabilities
|
|
$
|
—
|
|
$
|
—
|
|
$
|
29,619
|
|
$
|
29,619
|
|
Commodity derivative instruments consist of fixed price swaps for crude oil
and natural gas. The Company’s costless collars are valued based on the
counterparty’s marked-to-market statements, Such values have been derived using
models that considers various inputs including current market and contractual prices for
the underlying instruments, quoted forward prices for natural gas and crude oil, volatility
factors and interest rates, such as a LIBOR curve for a similar length of time as the
derivative contract term. The Company has not attempted to obtain sufficient corroborating
market evidence to support classifying these derivative contracts as Level 2 accordingly
they are classified as Level 3.
Note
8. 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 March 31, 2008, 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.
ABRAXAS PETROLEUM CORPORATION
PART
I
Item
2. Management’s Discussion and Analysis of Financial Condition and Results of
Operations
The following is a discussion of our financial condition, results of
operations, liquidity and capital resources. This discussion should be read in conjunction
with our consolidated financial statements and the notes thereto, included in our Annual
Report on Form 10-K filed for the year ended December 31, 2007. The terms
“Abraxas” or “Abraxas Petroleum” refer to Abraxas Petroleum
Corporation and its subsidiaries other than Abraxas Energy Partners, L.P., which we refer
to as “Abraxas Energy Partners” or the “Partnership”, and its
subsidiary, Abraxas Operating, LLC, which we refer to as “Abraxas Operating”
and the terms “we”, “us”, “our” or the
“Company” refer to Abraxas Petroleum Corporation and all of its consolidated
subsidiaries including Abraxas Energy Partners and Abraxas Operating. The operations of
Abraxas Petroleum and the Partnership are consolidated for financial reporting purposes
with the interest of the 52.8% minority owners presented as minority interest. Abraxas owns
the remaining 47.2% of the partnership interests.
Critical Accounting Policies
There have been
no changes from the Critical Accounting Policies described in our Annual Report on Form
10-K for the year ended December 31, 2007.
General
We are independent energy company primarily engaged in the development and
production of natural gas and crude oil. Our principal means of growth has been through the
acquisition and subsequent development and exploitation of producing properties. As a
result of these activities, we believe that we have a number of development opportunities
on our properties. In addition, we intend to expand upon our development activities with
complementary exploration projects in our core areas of operation. Success in our
development and exploration activities is critical to the maintenance and growth of our
current production levels and associated reserves.
Factors Affecting Our Financial
Results
While we have attained positive net income in four of the five years ended
December 31, 2007, we sustained a loss in the first quarter of 2008 and we cannot assure
you that we can achieve positive operating income and net income in the future. Our
financial results depend upon many factors, which significantly affect our results of
operations including the following:
|
•
|
the sales prices of natural gas and crude oil;
|
|
•
|
the level of total sales volumes of natural gas and crude
oil;
|
|
•
|
the availability of, and our ability to raise additional
capital resources and provide liquidity to meet cash flow needs;
|
|
•
|
the level of and interest rates on borrowings;
and
|
|
•
|
the level of success of exploitation, exploration and
development activity.
|
Commodity Prices and Hedging
Activities
.
The results of our operations are highly dependent upon the prices received
for our natural gas and crude oil production. The prices we receive for our production are
dependent upon spot market prices, price differentials and the effectiveness of our hedging
arrangements. Substantially all of our sales of natural gas and crude oil are made in the
spot market, or pursuant to contracts based on spot market prices, and not pursuant to
long-term, fixed-price contracts. Accordingly, the prices received for our natural gas and
crude oil production are dependent upon numerous factors beyond our control. Significant
declines in prices for natural gas and crude oil could have a material adverse effect on
our financial condition, results of operations, cash flows and quantities of reserves
recoverable on an economic basis. Recently, the prices of natural gas and crude oil
have been volatile. During the first quarter of 2008, prices for natural gas and crude oil
were sustained at record or near-record levels. New York Mercantile Exchange (NYMEX) spot
prices for West Texas Intermediate (WTI) crude oil
averaged $97.81 per barrel for the quarter ended March 31, 2008. WTI crude
oil ended the quarter at $101.59 per barrel. NYMEX Henry Hub spot prices for natural gas
averaged $8.64 per million British thermal units (MMBtu) during first quarter of 2008 and
ended the quarter at $10.10.
The realized prices that we receive for our production differ from NYMEX
futures and spot market prices, principally due to:
|
•
|
basis differentials which are dependent on actual delivery
location,
|
|
•
|
adjustments for BTU content; and
|
|
•
|
gathering, processing and transportation costs.
|
During the first quarter of 2008, differentials averaged $4.18 per BOE of
crude oil and $1.32 per Mcf of natural gas. We expect to realize greater differentials
during the remainder of 2008 because of the increased percentage of our production from the
Rocky Mountain and Mid-Continent regions which experience higher differentials than our
Texas properties. Under the terms of the Partnership Credit Facility, Abraxas Energy
Partners was required to enter into hedging arrangements for specified volumes, which
equated to approximately 85% of the estimated oil and gas production through December 31,
2011 from its net estimated proved developed producing reserves. The Partnership intends to
enter into hedging arrangements in the future to reduce the impact of price volatility on
its cash flow. By removing a significant portion of price volatility on its future oil and
gas production, the Partnership believes it will mitigate, but not eliminate, the potential
effects of changing commodity gas prices on its cash flow from operations for those
periods.
The following table sets forth the Partnership’s hedge position at
March 31, 2008:
Period Covered
|
Hedged Product
|
Hedged Volume
(Production per day)
|
Weighted Average
Fixed Price
|
Year 2008
|
Natural Gas
|
11,840 Mmbtu
|
$8.44
|
Year 2008
|
Crude Oil
|
1,105 Bbl
|
$84.84
|
Year 2009
|
Natural Gas
|
10,595 Mmbtu
|
$8.45
|
Year 2009
|
Crude Oil
|
1,000 Bbl
|
$83.80
|
Year 2010
|
Natural Gas
|
9,130 Mmbtu
|
$8.22
|
Year 2010
|
Crude Oil
|
895 Bbl
|
$83.26
|
Year 2011
|
Natural Gas
|
8,010 Mmbtu
|
$8.10
|
Year 2011
|
Crude Oil
|
810 Bbl
|
$86.45
|
At March 31, 2008, the aggregate fair market value of our hedges was
approximately $(29.6) million.
Production Volumes.
Because our proved
reserves will decline as natural gas and crude oil are produced, unless we find, acquire or
develop additional properties containing proved reserves or conduct successful exploration
and development activities, our reserves and production will decrease. Approximately 90% of
the estimated ultimate recovery of Abraxas’ and 91% of the Partnership’s, or
91% of our consolidated proved developed producing reserves as of December 31, 2007 had
been produced. Based on the reserve information set forth in our reserve report of
December 31, 2007, Abraxas’ average annual estimated decline rate for its net
proved developed producing reserves is 9% during the first five years, 6% in the next five
years, and approximately 5% thereafter. Based on the reserve information set forth in our
reserve report of December 31, 2007, the Partnership’s average annual estimated
decline rate for its net proved developed producing reserves is 12% during the first five
years, 9% in the next five years and approximately 9% thereafter. These rates of decline
are estimates and actual production declines could be materially higher. While Abraxas has
had some success in finding, acquiring and developing additional revenues, Abraxas has not
been able to fully replace the production volumes lost from natural field declines and
prior property sales. For example, in 2006, Abraxas replaced only 7% of the reserves it
produced. In 2007, however, we replaced 219% of the reserves we produced. 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 and development projects.
We had capital expenditures of $137.9 million during the first quarter of
2008, including $131.3 million for the St. Mary property acquisition that closed in
January, 2008, and have a capital budget for 2008 of approximately $55 million of which $35
million is applicable to Abraxas and $20 million applicable to the
Partnership. The final amount of our capital expenditures for 2008 will
depend on our success rate, production levels, the availability of capital and commodity
prices.
Availability of Capital
.
As described more fully under “Liquidity and Capital Resources”
below, Abraxas’ sources of capital going forward will primarily be cash from
operating activities, funding under the Credit Facility, cash on hand, distributions from
the Partnership and if an appropriate opportunity presents itself, proceeds from the sale
of properties. Abraxas Energy Partners’ principal sources of capital will be cash
from operating activities, borrowings under the Partnership Credit Facility, and sales of
debt or equity securities if available to it. At March 31, 2008, Abraxas had approximately
$6.5 million of availability under the Credit Facility. Upon the closing of the acquisition
of properties described in Recent Transactions, the Partnership borrowed $115.6 million
under the Partnership Credit Facility and $50 million under the Subordinate Credit
Agreement. Upon the completion of this transaction, the Partnership had $24.4 million
available under the Partnership Credit Facility.
Exploration and Development Activity.
We
believe that our high quality asset base, high degree of operational control and 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 December 31, 2007 we
operated 95% of the properties accounting for approximately 95% of our PV-10, giving us
substantial control over the timing and incurrence of operating and capital
expenses.
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
and exploration activities or, through engineering studies, identify additional behind-pipe
zones or secondary recovery reserves. We cannot assure you that our exploration and
development activities will result in increases in our proved reserves. In 2006, for
example, Abraxas replaced only 7% of the reserves it produced. In 2007, however, we
replaced 219% of our reserves. If our proved reserves decline in the future, our production
will also decline and, consequently, our cash flow from operations, distributions of
available cash from the Partnership to Abraxas and the amount that Abraxas is able to
borrow under its credit facility and that the Partnership will be able to borrow under its
credit facility will also decline. In addition, approximately 69% of Abraxas’ and 56%
of the Partnership’s estimated proved reserves at December 31, 2007 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.
We may be unable to acquire or develop additional reserves, in which case our results of
operations and financial condition could be adversely affected.
Borrowings and Interest
.
Abraxas Energy Partners currently has indebtedness of approximately $115.6
under the Amended Partnership Credit Facility and $50 million under its Subordinated Credit
Agreement. The Partnership has $24.4 million available under its Amended Partnership Credit
Facility. Abraxas has availability of $6.5 million under its $50 million Credit Facility.
There is currently no outstanding balance under this facility. If interest expense
increases as a result of higher interest rates or increased borrowings, more cash flow from
operations would be used to meet debt service requirements. As a result, we would need to
increase our cash flow from operations in order to fund the development of our numerous
drilling opportunities which, in turn, will be dependent upon the level of our production
volumes and commodity prices.
Recent
Transactions
On January 31, 2008, Abraxas Operating consummated the acquisition of
certain oil and gas properties located in various states from St. Mary and certain other
sellers for $126.0 million. The properties are primarily located in the Rocky Mountain and
Mid-Continent regions of the United States, and, at December 31, 2007, included
approximately 57.5 Bcfe (9.6 MMBOE) of estimated proved reserves.
The Partnership borrowed approximately $115.6 million under the Partnership
Credit Facility and $50 million under the Subordinated Credit Agreement in order to
complete this acquisition and repay its previously outstanding indebtedness of $45.9
million. For a complete description of these credit facilities, please see “ –
Liquidity and Capital Resources–Long-Term Indebtedness”.
Simultaneously, Abraxas announced that it had completed the acquisition of
certain oil and gas properties from St. Mary with estimated proved reserves of at December
31, 2007 of approximately 3.1 Bcfe (0.5 MMBOE) for a purchase price of approximately $5.6
million. Abraxas paid the purchase price from its internal funds. The right to purchase
these properties had previously been assigned to Abraxas by the Partnership.
Results of Operations
The following table sets forth certain of our operating data for the periods
presented.
|
|
Three Months Ended
March 31,
|
|
|
|
2008
|
|
2007
|
|
|
|
(in thousands)
|
|
Operating Revenue: (1) (2)
|
|
|
|
|
|
|
|
Crude oil sales
|
|
$
|
10,858
|
|
$
|
2,741
|
|
Natural gas sales
|
|
|
11,005
|
|
|
8,791
|
|
Realized hedge loss
|
|
|
(883
|
)
|
|
(81
|
)
|
Unrealized hedge loss
|
|
|
(26,075
|
)
|
|
(129
|
)
|
Rig operations
|
|
|
306
|
|
|
328
|
|
Other
|
|
|
1
|
|
|
1
|
|
|
|
$
|
(4,788
|
)
|
$
|
11,651
|
|
|
|
|
|
|
|
|
|
Operating Income (loss)
|
|
$
|
(17,093
|
)
|
$
|
3,547
|
|
|
|
|
|
|
|
|
|
Crude oil production (MBbl)
|
|
|
116.0
|
|
|
50.2
|
|
Natural gas production (MMcf)
|
|
|
1,504
|
|
|
1,451
|
|
Average crude oil sales price ($/Bbl)
|
|
$
|
93.63
|
|
$
|
54.63
|
|
Average natural gas sales price ($/Mcf)
|
|
$
|
7.32
|
|
$
|
6.06
|
|
|
(1)
|
Revenue and average sales prices are before the impact of
hedging activities.
|
|
(2)
|
Includes results of operations for properties acquired from
St. Mary Land & Exploration for February and March 2008.
|
Comparison of Three Months Ended March 31, 2008 to Three Months Ended
March 31, 2007
Operating Revenue
.
During the three months ended March 31, 2008, operating revenue from natural
gas and crude oil sales increased to $21.9 million from $11.3 million for the first quarter
of 2007. The increase in revenue was primarily due to increased production volumes as well
as higher realized prices during the first quarter of 2008 as compared to the same period
of 2007. Higher realized prices contributed $4.0 million to revenue for the quarter while
increased production volumes contributed $6.6 million.
Average sales prices net of hedging cost for the quarter ended March 31,
2008 were:
|
§
|
$93.63 per Bbl of crude oil,
|
|
§
|
$ 7.32 per Mcf of natural gas
|
Average sales prices net of hedging cost for the quarter ended March 31,
2007 were:
|
§
|
$54.63 per Bbl of crude oil,
|
|
§
|
$ 6.06 per Mcf of natural gas
|
Crude oil sales volumes increased from 50.2 MBbls during the quarter ended
March 31, 2007 to 116.0 MBbls for the same period of 2008. The increase in crude oil sales
volumes was primarily due to production from properties acquired in the St. Mary
acquisition that closed on January 31, 2008. Production for the months of February and
March from these properties added 64.7 MBbls of crude oil. Natural gas production volumes
increased from 1,451 MMcf for the three months ended March 31, 2007 to 1,504 MMcf for the
same period of 2008. The properties acquired in the St. Mary acquisition contributed 352.9
MMcf of natural gas production during the quarter, which was partially offset by natural
field declines.
Lease Operating Expenses
.
Lease operating expenses (“LOE”) for the three months ended
March 31, 2008 increased to $5.2 million compared to $3.0 million in 2007. LOE related to
the properties acquired in the St. Mary property acquisition added $2.3 million to LOE
during the quarter. LOE on a per BOE basis for the three months ended March 31, 2008 was
$14.19 per BOE compared to $10.14 for the same period of 2007. The
increase
in per BOE cost was attributable to the increase in the number of crude oil wells as a
result of the St. Mary acquisition, which are more expensive to operate than natural gas
wells, as well as well as the overall increase in costs.
General and Administrative (“G&A”)
Expenses.
G&A expenses, excluding stock-based
compensation, increased to $1.6 million for the quarter ended March 31, 2008 compared to
$1.1 million during for the quarter ended March 31, 2007. The increase in G&A was
primarily due to higher personnel expenses associated with additional staff added to manage
the properties acquired from St. Mary. G&A expense on a per BOE basis was $4.24 for the
first quarter of 2008 compared to $3.92 for the same period of 2007. The increase in
G&A expense on a per BOE basis was primarily due to increased cost in the first quarter
of 2008 compared to the same period in 2007.
Stock-based Compensation.
We currently
utilize a standard option pricing model (i.e., Black-Scholes) to measure the fair value of
stock options granted to employees. Options granted to employees are valued at the date of
grant and expense is recognized over the options vesting period. For the quarters ended
March 31, 2008 and 2007, stock based compensation was approximately $246,000 and $172,000
respectively. The increase in 2008 as compared to 2007 is due to the grant on options and
restricted stock in the third quarter of 2007 as well as grants to new employees hired as a
result of the St. Mary acquisition.
Depreciation, Depletion and Amortization
Expenses
. Depreciation, depletion and amortization
(“DD&A”) expense increased to $5.1 million for the three months ended March
31, 2008 from $3.7 million for same period of 2007. The increase in DD&A is primarily
the result of increased production as well as an increase in out depletion base as a result
of the St. Mary acquisition. Our DD&A on a per BOE basis for the three months ended
March 31, 2008 was $13.89 per BOE compared to $12.51 per BOE in 2007. The increase in the
per BOE DD&A was due to a higher depletion base for the period.
Interest Expense.
Interest expense
decreased to $2.5 million for the first three months of 2008 from $4.2 million for the same
period of 2007. The decrease in interest expense was primarily due lower levels of
long-term debt during the first quarter of 2008 as compared to 2007 as well as lower
interest rates. Long-term debt increased on January 31, 2008 as a result of the St. Mary
acquisition. The interest rate on our senior notes, which were redeemed in May 2007, was
12.5% for the three months ended March 31, 2007. The interest rates on the Partnerships
amended credit facility averaged approximately 7.0% and the Partnerships subordinated
credit facility averaged approximately 8.1% for the quarter ended March 31,
2008.
Minority interest.
Minority interest represents
the share of the net income (loss) of Abraxas Energy Partners for the period owned by the
partners other than Abraxas Petroleum. For the quarter ended March 31, 2008, the minority
interest in the net loss of the Partnership was approximately $10.7 million
Recently
Issued Accounting Pronouncements
Fair Value Measurements (SFAS
No. 157) —
In September 2006, the Financial Accounting
Standards Board (“FASB”) issued Statement of Financial Accounting Standards
(“SFAS”) No. 157, which provides a single definition of fair value,
together with a framework for measuring it, and requires additional disclosure about the
use of fair value to measure assets and liabilities. SFAS No. 157 also emphasizes that
fair value is a market-based measurement, and sets out a fair value hierarchy with the
highest priority being quoted prices in active markets. Fair value measurements are
disclosed by level within that hierarchy. SFAS No. 157 is effective for financial
statements issued for fiscal years beginning after November 15, 2007. The FASB agreed
to defer the effective date of Statement 157 for one year for nonfinancial assets and
nonfinancial liabilities that are recognized or disclosed at fair value in the financial
statements on a nonrecurring basis. There is no deferral for financial assets and financial
liabilities. We are evaluating the impact of SFAS No. 157 on our consolidated
financial statements and do not expect the impact of implementation to be
material.
The Fair Value Option for Financial Assets and Financial Liabilities —
Including an Amendment of FASB Statement No. 115 (SFAS No. 159)
—
In February 2007, the FASB issued SFAS No. 159, which
provides companies with an option to measure, at specified election dates, many financial
instruments and certain other items at fair value that are not currently measured at fair
value. A company that adopts SFAS No. 159 will report unrealized gains and losses on
items, for which the fair value option has been elected, in earnings at each subsequent
reporting date. This statement also establishes presentation and disclosure requirements
designed to facilitate comparisons between entities that choose different measurement
attributes for similar types of assets and liabilities. This statement is effective for
fiscal years beginning after November 15, 2007. We do not expect the implementation of
SFAS No. 159 to have a material impact on our consolidated financial
statements.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about
Derivative Instruments and Hedging Activities,” which amends SFAS No. 133,
“Accounting for Derivative Instruments and Hedging Activities.” Enhanced
disclosures to improve financial reporting transparency are required and include disclosure
about the location and amounts of derivative instruments in the financial statements, how
derivative instruments are accounted for and how derivatives affect an entity’s
financial position, financial performance and cash flows. A tabular format including the
fair value of derivative instruments and their gains and losses, disclosure about credit
risk-related derivative features and cross-referencing within the footnotes are also new
requirements. SFAS No. 161 is effective for financial statements issued for fiscal
years and interim periods beginning after November 15, 2008, with early application
and comparative disclosures encouraged, but not required. We have not yet adopted SFAS
No. 161. We do not believe that SFAS No. 161 will have a material impact on our
financial position, results of operations or cash flows.
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling
Interest in Consolidated Financial Statements, an amendment of Accounting Research Bulletin
(ARB) No. 51.” SFAS No. 160 clarifies that a noncontrolling interest
(previously commonly referred to as a minority interest) in a subsidiary is an ownership
interest in the consolidated entity and should be reported as equity in the consolidated
financial statements. The presentation of the consolidated income statement has been
changed by SFAS No. 160, and consolidated net income attributable to both the parent
and the noncontrolling interest is now required to be reported separately. Previously, net
income attributable to the noncontrolling interest was typically reported as an expense or
other deduction in arriving at consolidated net income and was often combined with other
financial statement amounts. In addition, the ownership interests in subsidiaries held by
parties other than the parent must be clearly identified, labeled, and presented in the
equity in the consolidated financial statements separately from the parent’s equity.
Subsequent changes in a parent’s ownership interest while the parent retains its
controlling financial interest in its subsidiary should be accounted for consistently, and
when a subsidiary is deconsolidated, any retained noncontrolling equity interest in the
former subsidiary must be initially measured at fair value. Expanded disclosures, including
a reconciliation of equity balances of the parent and noncontrolling interest, are also
required. SFAS No. 160 is effective for fiscal years, and interim periods within those
fiscal years, beginning on or after December 15, 2008 and earlier adoption is
prohibited. Prospective application is required. At this time, we do not have any material
noncontrolling interests in consolidated subsidiaries. Therefore, we do not believe that
the adoption of SFAS No. 160 will have a material impact on our financial position,
results of operations or cash flows.
In December 2007, the FASB issued SFAS No. 141(R), “Business
Combinations.” SFAS No. 141(R) was issued in an effort to continue the movement
toward the greater use of fair values in financial reporting and increased transparency
through expanded disclosures. It changes how business acquisitions are accounted for and
will impact financial statements at the acquisition date and in subsequent periods. Certain
of these changes will introduce more volatility into earnings. The acquirer must now record
all assets and liabilities of the acquired business at fair value, and related transaction
and restructuring costs will be expensed rather than the previous method of being
capitalized as part of the acquisition. SFAS No. 141(R) also impacts the annual
goodwill impairment test associated with acquisitions, including those that close before
the effective date of SFAS No. 141(R). The definitions of a “business” and
a “business combination” have been expanded, resulting in more transactions
qualifying as business combinations. SFAS No. 141(R) is effective for fiscal years,
and interim periods within those fiscal years, beginning on or after December 31, 2008
and earlier adoption is prohibited. We cannot predict the impact that the adoption of SFAS
No. 141(R) will have on our financial position, results of operations or cash flows
with respect to any acquisitions completed after December 31, 2008.
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:
|
•
|
the development of existing properties, including drilling
and completion costs of wells;
|
|
•
|
acquisition of interests in additional natural gas and crude
oil properties; and
|
|
•
|
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.
Abraxas’ sources of capital going forward will primarily be cash from
operating activities, funding under its credit facility, cash on hand, and if an
appropriate opportunity presents itself, proceeds from the sale of
properties. We may also seek equity capital although we may not be able to
complete any equity financings on terms acceptable to us, if at all. The
Partnership’s principal sources of capital will be cash from operating activities,
borrowings under the Partnership Credit Facility and sales of debt or equity securities if
available to it.
Working Capital (Deficit)
. At March 31,
2008, our current liabilities of approximately $73.6 million exceeded our current assets of
$21.6 million resulting in a working capital deficit of $52.0 million. This compares to a
working capital of approximately $11.3 million at December 31, 2007. Current liabilities at
March 31, 2008 consisted of current portion of long-term debt consisting of $50.0 million
outstanding under the Partnership’s Subordinated Credit Agreement, the current
portion of hedge liability of $12.1 million, trade payables of $5.3 million, revenues due
third parties of $3.0 million, accrued interest of $1.6 million and other accrued
liabilities of $1.7 million. The Partnership intends to repay its subordinated Credit
Facility with proceeds from its initial public offering (“IPO”) later this
year. In the event that the IPO has not been completed in this time frame, or is not
successful, the Partnership will enter into discussions with the lending institutions to
either extend or refinance the $50.0 million in debt under its Subordinated Credit
Agreement, due January 31, 2009 There can be no assurance that the Partnership will be
successful in such negotiations.
Capital expenditures
.
Capital expenditures during the first three months of 2008 were $137.9
million compared to $3.9 million during the same period of 2007. The table below sets forth
the components of these capital expenditures on a historical basis for the three months
ended March 31, 2008 and 2007.
|
|
Three Months Ended
March 31,
|
|
|
|
2008
|
|
2007
|
|
|
|
(in thousands)
|
|
Expenditure category:
|
|
|
|
|
|
|
|
Acquisitions
|
|
$
|
131,333
|
|
$
|
—
|
|
Development
|
|
|
6,340
|
|
|
3,896
|
|
Facilities and other
|
|
|
186
|
|
|
4
|
|
Total
|
|
$
|
137,859
|
|
$
|
3,900
|
|
During the three months ended March 31, 2008 capital expenditures were
primarily for the acquisition of properties from St. Mary as well as the development of our
existing properties. For the first quarter of 2007, capital expenditures were primarily for
the development of existing properties. We anticipate making capital expenditures of $55
million in 2008, excluding the cost of the St. Mary acquisition. The Partnership
anticipates making capital expenditures for 2008 of $20 million which will be used
primarily for the development of its current properties. These anticipated expenditures are
subject to adequate cash flow from operations, availability under our Credit Facility and
the Partnership’s Credit Facility and, in Abraxas’ case, distributions of
available cash from the Partnership. If these sources of funding 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. 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 the acquisition of producing properties if such opportunities
arise. Additionally, the level of capital expenditures will vary during future periods
depending on market conditions and other related economic factors. Should the prices of
natural gas and crude oil decline and if our costs of operations continue to increase as a
result of the scarcity of drilling rigs or if our production volumes decrease, our cash
flows will decrease which may result in a reduction of the capital expenditures budget. If
we decrease our capital expenditures budget, we may not be able to offset natural gas and
crude oil production volumes decreases caused by natural field declines and sales of
producing properties, if any.
Sources of Capital
. The net funds
provided by and/or used in each of the operating, investing and financing activities
relating to continuing operations are summarized in the following table and discussed in
further detail below:
|
|
Three Months Ended
March 31,
|
|
|
|
2008
|
|
2007
|
|
|
|
(in thousands)
|
|
Net cash provided by operating activities
|
|
$
|
9,696
|
|
$
|
4,760
|
|
Net cash used in investing activities
|
|
|
(137,859
|
)
|
|
(3,900
|
)
|
Net cash provided by (used in) financing
activities
|
|
|
115,818
|
|
|
(293
|
)
|
Total
|
|
$
|
(12,365
|
)
|
$
|
567
|
|
Operating activities during the three months ended March 31, 2008 provided
us $9.7 million of cash compared to providing $4.8 million in the same period in 2007. Net
income plus non-cash expense items during 2008 and 2007 and net changes in operating assets
and liabilities accounted for most of these funds. Financing activities provided $115.8 for
the first three months of 2008 compared to using $293,000 for the same period of 2007.
Funds provided in 2008 were primarily proceeds from the Partnership’s credit facility
and subordinated facility in connection with the St. Mary property acquisition. Funds used
in 2007 were the result of a net reduction in the outstanding balance of our revolving line
of credit. Investing activities used $137.9 million during the three months ended March 31,
2008 compared to using $3.9 million for the quarter ended March 31, 2007. Expenditures
during the quarter ended March 31, 2008 were primarily for the acquisition of properties
from St. Mary Land and Exploration as well as the development of our existing properties.
For the first quarter of 2007, capital expenditures were primarily for the development of
existing properties.
Future Capital Resources
. Abraxas’
sources of capital going forward will primarily be cash from operating activities, funding
under the Credit Facility, cash on hand, distributions from the Partnership and if an
appropriate opportunity presents itself, proceeds from the sale of properties. Abraxas
Energy Partners’ principal sources of capital will be cash from operating activities,
borrowings under the Partnership Credit Facility, and sales of debt or equity securities if
available to it. 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
a significant portion of our consolidated natural gas and crude oil production is hedged,
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.
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. For example, in 2006, Abraxas replaced only
7% of the reserves it produced. In 2007 we replaced 219% of the reserves we produced. In
the future, if an appropriate opportunity presents itself, we may sell producing
properties, which could further reduce our production volumes. To offset the loss in
production volumes resulting from natural field declines and sales of producing properties,
we must conduct successful, exploration 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. If our proved reserves decline in the future, our production will also decline
and, consequently, our cash flow from operations, distributions from the Partnership and
the amount that we are able to borrow under our credit facilities will also decline. The
risk of not finding commercially productive reservoirs will be compounded by the fact that
69% of Abraxas Petroleum’s and 50% of the Partnership’s total estimated proved
reserves at December 31, 2007 were undeveloped. During the first quarter of 2008, we
expended approximately $6.3 million for wells in Texas. We continue to perform general well
maintenance and work-overs utilizing our own work-over rigs.
Contractual Obligations
We are committed to making cash payments in the future on the following
types of agreements:
|
•
|
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 March 31, 2008:
Contractual Obligations
(dollars in thousands)
|
|
Payments due in twelve month periods
ended:
|
|
|
Total
|
|
March 31,
2009
|
|
March 31,
2010-2011
|
|
March 31,
2012-2013
|
|
Thereafter
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt (1)
|
|
$
|
165,600
|
|
$
|
50,000
|
|
$
|
—
|
|
$
|
115,600
|
|
$
|
—
|
|
Interest on long-term debt (2)
|
|
|
21,988
|
|
|
9,325
|
|
|
11,764
|
|
|
899
|
|
|
—
|
|
Operating Leases (3)
|
|
|
268
|
|
|
268
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
|
$
|
187,856
|
|
$
|
59,593
|
|
$
|
11,764
|
|
$
|
116,499
|
|
$
|
—
|
|
|
(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
|
We maintain a reserve for cost associated with the retirement of tangible
long-lived assets. At March 31, 2008, our reserve for these obligations totaled $10.0
million for which no contractual commitment exists.
Off-Balance Sheet Arrangements
. At March
31, 2008, we had no existing off-balance sheet arrangements, as defined under SEC
regulations, that have or are reasonably likely to have a current or future effect on our
financial condition, revenues or expenses, results of operations, liquidity, capital
expenditures or capital resources that are material to investors.
Contingencies.
From time to time, we are
involved in litigation relating to claims arising out of our operations in the normal
course of business. At March 31, 2008, we were not engaged in any legal proceedings that
were expected, individually or in the aggregate, to have a material adverse effect on the
Company.
Other obligations.
We make and will
continue to make substantial capital expenditures for the acquisition, development,
exploration and production of crude oil and natural gas. In the past, we have funded our
operations and capital expenditures primarily through cash flow from operations, sales of
properties, sales of production payments and borrowings under our bank credit facilities
and other sources. Given our high degree of operating control, the timing and incurrence of
operating and capital expenditures is largely within our discretion.
Long-Term Indebtedness
Long-term debt consisted of the following:
|
|
March 31,
2008
|
|
December
31,
2007
|
|
|
|
(in thousands)
|
|
Partnership credit facility
|
|
$
|
115,600
|
|
$
|
45,900
|
|
Partnership subordinated credit agreement
|
|
|
50,000
|
|
|
—
|
|
Senior secured credit facility
|
|
|
—
|
|
|
—
|
|
|
|
|
165,600
|
|
|
45,900
|
|
Less current maturities
|
|
|
(50,000
|
)
|
|
—
|
|
|
|
$
|
115,600
|
|
$
|
45,900
|
|
Senior Secured Credit Facility.
On June
27, 2007, Abraxas entered into a new senior secured revolving credit facility, which we
refer to as the Credit Facility. The Credit Facility has a maximum commitment of $50
million. Availability under the Credit Facility is subject to a borrowing base. The
borrowing base under the Credit Facility, which is currently $6.5 million, is determined
semi-annually by the lenders based upon our reserve reports, one of which must be prepared
by our independent petroleum engineers and one of which may be prepared internally. The
amount of the borrowing base is calculated by the lenders based upon their valuation of our
proved reserves utilizing these reserve reports and their own internal decisions. In
addition, the lenders, in their sole discretion, may make one additional borrowing base
redetermination during any six-month period between scheduled redeterminations and we may
also request one redetermination during any six-month period between scheduled
redeterminations. The lenders may also make a redetermination in connection with any sales
of producing properties with a market value of 5% or more of our current borrowing base.
Our borrowing base at March 31, 2008 of $6.5 million was determined based upon our reserves
at December 31,
2006
after giving effect to the contribution of properties to the Partnership in May 2007. Our
borrowing base can never exceed the $50.0 million maximum commitment amount. Outstanding
amounts under the Credit Facility will bear interest at (a) the greater of reference
rate announced from time to time by Société Générale, and (b)
the Federal Funds Rate plus ½ of 1%, plus in each case, (c) 0.5% - 1.5% depending on
utilization of the borrowing base, or, if Abraxas elects, at the London Interbank Offered
Rate plus 1.5% - 2.5%, depending on the utilization of the borrowing base. Subject to
earlier termination rights and events of default, the Credit Facility’s stated
maturity date will be June 27, 2011. Interest will be payable quarterly on reference rate
advances and not less than quarterly on Eurodollar advances.
Abraxas is permitted to terminate the Credit Facility, and may, from time to
time, permanently reduce the lenders’ aggregate commitment under the Credit Facility
in compliance with certain notice and dollar increment requirements.
Each of Abraxas’ subsidiaries other than the Partnership, Abraxas
General Partner, LLC and Abraxas Energy Investments, LLC has guaranteed Abraxas’
obligations under the Credit Facility on a senior secured basis. Obligations under the
Credit Facility are secured by a first priority perfected security interest, subject to
certain permitted encumbrances, in all of Abraxas’ and the subsidiary
guarantors’ material property and assets.
Under the Credit Facility, Abraxas is subject to customary covenants,
including certain financial covenants and reporting requirements. The Credit Facility
requires Abraxas to maintain a minimum current ratio as of the last day of each quarter of
not less than 1.00 to 1.00 and an interest coverage ratio (generally defined as the ratio
of consolidated EBITDA to consolidated interest expense as of the last day of such quarter)
of not less than 2.50 to 1.00.
In addition to the foregoing and other customary covenants, the Credit
Facility contains a number of covenants that, among other things, will restrict
Abraxas’ ability to:
|
•
|
incur or guarantee additional indebtedness;
|
|
•
|
transfer or sell assets;
|
|
•
|
create liens on assets;
|
|
•
|
engage in transactions with affiliates other than on an
“arms-length” basis;
|
|
•
|
make any change in the principal nature of its business;
and
|
|
•
|
permit a change of control.
|
The 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.
Amended and Restated Partnership Credit Facility.
On May 25, 2007, the Partnership entered into a senior secured revolving
credit facility which was amended and restated on January 31, 2008, which we refer to as
the Partnership Credit Facility. The Partnership Credit Facility has a maximum commitment
of $300.0 million. Availability under the Partnership Credit Facility is subject to a
borrowing base. The borrowing base under the Partnership Credit Facility, which is
currently $140.0 million, is determined semi-annually by the lenders based upon the
Partnership’s reserve reports, one of which must be prepared by the
Partnership’s independent petroleum engineers and one of which may be prepared
internally. The amount of the borrowing base is calculated by the lenders based upon their
valuation of the Partnership’s proved reserves utilizing these reserve reports and
their own internal decisions. In addition, the lenders, in their sole discretion, may make
one additional borrowing base redetermination during any six-month period between scheduled
redeterminations. The lenders may also make a redetermination in connection with any sales
of producing properties with a market value of 5% or more of the Partnership’s
current borrowing base. The Partnership’s current borrowing base of $140.0 million
was determined based upon its reserves at June 30, 2007 and the reserves attributable to
the oil and gas properties acquired from St. Mary Land & Exploration Company on January
31, 2008. The borrowing base can never exceed the $300 million maximum commitment amount.
Outstanding amounts under the Partnership Credit Facility bear interest at the reference
rate announced from time to time by Société Générale plus .25%
- 1.00%, depending on the utilization of the borrowing base or, if the Partnership elects,
at the London Interbank Offered Rate plus 1.25% - 2.00%, depending on the utilization of
the borrowing base. Subject to earlier termination rights and events of default, the
Partnership Credit Facility’s stated maturity date is January 31, 2013. Interest is
payable quarterly on reference rate advances and not less than quarterly on Eurodollar
advances. The Partnership is permitted to terminate the Partnership Credit Facility, and
under certain circumstances, may be required, from time to time, to permanently reduce the
lenders’ aggregate commitment under the Partnership Credit Facility.
Each of the general partner of the Partnership, Abraxas General Partner,
LLC, which is a wholly-owned subsidiary of Abraxas and which we refer to as the GP, and
Abraxas Operating, LLC, which is a wholly-owned subsidiary of the Partnership and which we
refer to as Abraxas Operating , has guaranteed the Partnership’s obligations under
the Credit Facility on a senior secured basis. Obligations under the Partnership Credit
Facility are secured by a first priority perfected security interest, subject to certain
permitted encumbrances, in property and assets of the GP, the Partnership and Abraxas
Operating comprising at least 90% of the PV-10 of their proved reserves and the related oil
and gas properties, other than the GP’s general partner units in the
Partnership.
Under the Partnership Credit Facility, the Partnership is subject to
customary covenants, including certain financial covenants and reporting requirements. The
Partnership Credit Facility requires the Partnership to maintain a minimum current ratio as
of the last day of each quarter of 1.0 to 1.0 and an interest coverage ratio (defined as
the ratio of consolidated EBITDA to consolidated interest expense) as of the last day of
each quarter of not less than 2.50 to 1.00.
Under the terms of the Partnership Credit Facility, the Partnership may make
cash distributions if, after giving effect to such distributions, the Partnership is not in
default under the Partnership Credit Facility and there is no borrowing base deficiency and
provided that no such distribution shall be made using the proceeds of any advance unless
the amount of the unused portion of the amount then available under the Partnership Credit
Facility is greater than or equal to 10% of the lesser of the Partnership’s borrowing
base (which is currently $140.0 million) or the total commitment amount of the
Partnership Credit Facility (which is currently $300.0 million) at such
time.
In addition to the foregoing and other customary covenants, the Partnership
Credit Facility contains a number of covenants that, among other things, will restrict the
Partnership’s ability to:
|
•
|
incur or guarantee additional indebtedness;
|
|
•
|
transfer or sell assets;
|
|
•
|
create liens on assets;
|
|
•
|
engage in transactions with affiliates;
|
|
•
|
make any change in the principal nature of its business;
and
|
|
•
|
permit a change of control.
|
The Partnership 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 including the Subordinated Credit
Agreement described below, bankruptcy and material judgments and liabilities.
Subordinated Credit Agreement
On January 31, 2008, the Partnership entered into a subordinated credit
agreement which we refer to as the Subordinated Credit Agreement. The Subordinated Credit
Agreement has a maximum commitment of $50 million, all of which was borrowed at closing.
Outstanding amounts under the Subordinated Credit Agreement bear interest at the reference
rate announced from time to time by Société Générale or, if the
Partnership elects, at the London Interbank Offered Rate plus, in each case, the amount set
forth below:
Date
|
Eurodollar Rate (LIBOR) Advances
|
Base Rate Advances
|
01/31/08 – 04/30/08
|
5.0%
|
4.0%
|
05/01/08 – 01/31/08
|
5.5%
|
4.5%
|
After 07/31/08
|
6.5%
|
5.5%
|
|
|
|
Subject to earlier termination rights and events of default, the
Subordinated Credit Agreement’s stated maturity date is January 31, 2009. Interest is
payable quarterly on reference rate advances and not less than quarterly on Eurodollar
advances. The Partnership is permitted to terminate the Subordinated Credit Agreement, and
under certain circumstances, may be required, from time to time, to make prepayments under
the Subordinated Credit Agreement.
Each of the GP and Abraxas Operating has guaranteed the Partnership’s
obligations under the Subordinated Credit Agreement on a subordinated secured basis.
Obligations under the Subordinated Credit Agreement are secured by subordinated security
interests, subject to certain permitted encumbrances, in property
and
assets of the Partnership, GP, and Abraxas Operating comprising at least 90% of the PV-10
of their proved reserves and the related oil and gas properties, other than the GP’s
general partner units in the Partnership.
Under the Subordinated Credit Agreement, the Partnership is subject to
customary covenants, including certain financial covenants and reporting requirements. The
Subordinated Credit Agreement requires the Partnership to maintain a minimum current ratio
as of the last day of each quarter of 1.0 to 1.0 and an interest coverage ratio (defined as
the ratio of consolidated EBITDA to consolidated interest expense) as of the last day of
each quarter of not less than 2.50 to 1.00.
In addition to the foregoing and other customary covenants, the Subordinated
Credit Agreement contains a number of covenants that, among other things, will restrict the
Partnership’s ability to:
|
•
|
incur or guarantee additional indebtedness;
|
|
•
|
transfer or sell assets;
|
|
•
|
create liens on assets;
|
|
•
|
engage in transactions with affiliates;
|
|
•
|
make any change in the principal nature of its business;
and
|
|
•
|
permit a change of control.
|
The Subordinated Credit Agreement 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 the Credit Facility, bankruptcy
and material judgments and liabilities.
Hedging Activities
.
Under the terms of the Partnership Credit Facility, Abraxas Energy Partners
was required to enter into hedging arrangements for specified volumes, which equated to
approximately 85% of the estimated oil and gas production through December 31, 2011 from
its net proved developed producing reserves. The Partnership intends to enter into hedging
arrangements in the future to reduce the impact of price volatility on its cash flow. By
removing a significant portion of price volatility on its future oil and gas production,
the Partnership believes it will mitigate, but not eliminate, the potential effects of
changing commodity prices on its cash flow from operations for those periods.
Net Operating Loss
Carryforwards
.
At December 31, 2007, we had, subject to the limitation discussed below,
$178.1 million of net operating loss carryforwards for U.S. tax purposes. These loss
carryforwards will expire through 2027 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, we have
established a valuation allowance of $47.2 million for deferred tax assets at December 31,
2007.
In June 2006, the FASB issued FASB Interpretation No. 48,
“Accounting for Uncertainty in Income Taxes” (“FIN 48”). FIN 48 is
an interpretation of SFAS 109, “Accounting for Income Taxes”, and it seeks to
reduce the diversity in practice associated with certain aspects of measurement and
accounting for income taxes and requires expanded disclosure with respect to the
uncertainty in income taxes. FIN 48 is effective for fiscal years beginning after December
15, 2006. Accordingly, the Company adopted FIN 48 on January 1, 2007. The adoption of FIN
48 did not have any effect on the Company’s financial position or results of
operations as of January 1, 2007 or for the quarter ended March 31, 2007. The Company
recognizes interest and penalties related to uncertain tax positions in income tax expense.
As of March 31, 2008, the Company did not have any accrued interest or penalties related to
uncertain tax positions. The tax years from 1999 through 2006 remain open to
examination by the tax jurisdictions to which the Company is subject.
Item
3. Quantitative and Qualitative Disclosures about Market Risk
Commodity Price Risk
As an independent crude oil and natural gas producer, our revenue, cash flow
from operations, other income and profitability, reserve values, access to capital and
future rate of growth are substantially dependent upon the
prevailing prices of crude oil and natural gas. Declines in commodity prices
will materially adversely affect our financial condition, liquidity, ability to obtain
financing and operating results. Lower commodity prices may reduce the amount of crude oil
and natural gas that we can produce economically. Prevailing prices for such commodities
are subject to wide fluctuation in response to relatively minor changes in supply and
demand and a variety of additional factors beyond our control, such as global, political
and economic conditions. Historically, prices received for crude oil and natural gas
production have been volatile and unpredictable, and such volatility is expected to
continue. Most of our production is sold at market prices. Generally, if the commodity
indexes fall, the price that we receive for our production will also decline. Therefore,
the amount of revenue that we realize is partially determined by factors beyond our
control. Assuming the production levels we attained during the quarter ended March 31,
2008, a 10% decline in crude oil and natural gas prices would have reduced our operating
revenue, cash flow and net income by approximately $2.2 million for the quarter, however,
due to the hedges that the Partnership has in place, it is unlikely that a10% decline in
commodity prices from their current levels would significantly impact our operating
revenue, cash flow and net income.
Hedging Sensitivity
The Partnership accounts for its derivative instruments in accordance with
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. In 2003 we elected not to designate
derivative instruments as hedges. Accordingly the instruments are recorded on the balance
sheet at fair value with changes in the market value of the derivatives being recorded in
current oil and gas revenue.
Under the terms of the Partnership Credit Facility, Abraxas Energy Partners
was required to enter into hedging arrangements for specified volumes, which equated to
approximately 85% of the estimated oil and gas production through December 31, 2011 from
its net proved developed producing reserves. The Partnership intends to enter into hedging
arrangements in the future to reduce the impact of price volatility on its cash flow. By
removing a significant portion of price volatility on its future oil and gas production,
the Partnership believes it will mitigate, but not eliminate, the potential effects of
changing commodity gas prices on its cash flow from operations for those
periods.
Interest
rate risk
At March 31, 2008, we had $115.6 million in outstanding indebtedness under
the Partnership Credit Facility. Outstanding amounts under the Partnership Credit Facility
bear interest at (a) the greater of (1) the reference rate announced from time to time by
Société Générale, and (2) the Federal Funds Rate plus 0.5%,
plus in each case, (b) 0.25% to 1.25% depending on utilization of the borrowing base, or,
if the Partnership elects, at the London Interbank Offered Rate plus 1.25% to 2.25%,
depending on the utilization of the borrowing base. At March 31, 2008, the interest rate on
the facility was 5.1%. For every percentage point that the LIBOR rate rises, our interest
expense would increase by approximately $1.2 million on an annual basis. In addition we had
$50.0 million in outstanding indebtedness under the Partnerships Subordinated Credit
Facility. Outstanding amounts under the Subordinated Credit Agreement bear interest at the
reference rate announced from time to time by Société Générale
or, if the Partnership elects, at the London Interbank Offered Rate plus various amounts.
At March 31, 2008 the interest rate on the facility was 8.13%. For every percentage point
that the rate rises, our interest expense would increase by approximately $500,000 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.
There were no changes in our internal controls over financial reporting
during the three month period ended March 31, 2008 covered by this report that could
materially affect, or are reasonably likely to materially affect, our financial
reporting.
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 on Form 10-K for the year ended December 31,
2007, and in Note 6 in the Notes to Condensed Consolidated Financial Statements contained
in Part I of this report on Form 10-Q.
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, 2007,
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.
An increase in the
differential between NYMEX and the reference or regional index price used to price our oil
and gas would reduce our cash flow from operations.
Our oil and gas is
priced in the local markets where it is produced based on local or regional supply and
demand factors. The prices we receive for all of our oil and gas are lower than the
relevant benchmark prices, such as NYMEX. The difference between the benchmark price and
the price we receive is called a differential. Numerous factors may influence local
pricing, such as refinery capacity, pipeline capacity and specifications, upsets in the
midstream or downstream sectors of the industry, trade restrictions and governmental
regulations. Additionally, insufficient pipeline capacity, lack of demand in any given
operating area or other factors may cause the differential to increase in a particular area
compared with other producing areas. For example, production increases from competing
Canadian and Rocky Mountain producers, combined with limited refining and pipeline capacity
in the Rocky Mountain area, have gradually widened differentials in this area.
Our hedging
activities could result in financial losses or could reduce our cash flow.
To achieve more
predictable cash flow and reduce our exposure to adverse fluctuations in the prices of oil
and gas and to comply with the requirements under our credit facility, we have and expect
to continue to enter into hedging arrangements for a significant portion of our oil and gas
production that could result in both realized and unrealized hedging losses. We have
entered into NYMEX-based fixed price commodity swap arrangements on approximately 85% of
our estimated oil and gas production from our estimated pro forma net proved developed
producing reserves through December 31, 2011. The extent of our commodity price exposure is
related largely to the effectiveness and scope of our commodity price hedging activities.
For example, the prices utilized in our derivative instruments are NYMEX-based, which may
differ significantly from the actual prices we receive for oil and gas which are based on
the local markets where oil and gas are produced. The prices that we receive for our oil
and gas production are lower than the relevant benchmark prices that are used for
calculating commodity derivative positions. The difference between the benchmark price and
the price we receive is called a differential. As a result, our cash flow could be affected
if the basis differentials widen more than we anticipate. For more information see
‘‘—An increase in the differential between NYMEX and the reference or
regional index price used to price our oil and gas would reduce our cash flow from
operations’’. We currently do not have any basis differential hedging
arrangements in place. Our cash flow could also be affected based upon the levels of our
production. If production is higher than we estimate, we will have greater commodity price
exposure than we intended. If production is lower than the nominal amount that is subject
to our hedging arrangements, we may be forced to satisfy all or a portion of our hedging
arrangements without the benefit of the cash flow from our sale of the underlying physical
commodity, resulting in a substantial reduction in cash flows.
Item 2.
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Unregistered Sales of Equity Securities and Use of
Proceeds.
|
None Item
3.Defaults Upon Senior Securities.
Item
4.
Submission of Matters to a Vote of Security Holders.
None
Item 5.
|
Other Information.
|
|
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
|
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:
May 12,
2008
|
By:
/s/Robert L.G.
Watson
|
ROBERT L.G. WATSON,
President and Chief
Executive Officer
|
Date:
May, 12,
2008
|
By
:
/s/Chris E, Williford
|
CHRIS E. WILLIFORD,
Executive Vice President and
Principal Accounting Officer
Abraxas (AMEX:ABP)
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