-----BEGIN PRIVACY-ENHANCED MESSAGE-----
Proc-Type: 2001,MIC-CLEAR
Originator-Name: webmaster@www.sec.gov
Originator-Key-Asymmetric:
MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen
TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB
MIC-Info: RSA-MD5,RSA,
N4HnKmg8Nx8EYP15yXZRKUCBC85Zncp9xyyjX5JRI0KVM8b+NQmQ/6k4ONIMnpPZ
XAEAuY0ta4J8sUBnYzqCAw==
<SEC-DOCUMENT>0000867665-05-000030.txt : 20050329
<SEC-HEADER>0000867665-05-000030.hdr.sgml : 20050329
<ACCEPTANCE-DATETIME>20050329163938
ACCESSION NUMBER: 0000867665-05-000030
CONFORMED SUBMISSION TYPE: 10-K
PUBLIC DOCUMENT COUNT: 8
CONFORMED PERIOD OF REPORT: 20041231
FILED AS OF DATE: 20050329
DATE AS OF CHANGE: 20050329
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: ABRAXAS PETROLEUM CORP
CENTRAL INDEX KEY: 0000867665
STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311]
IRS NUMBER: 742584033
STATE OF INCORPORATION: NV
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-K
SEC ACT: 1934 Act
SEC FILE NUMBER: 001-16071
FILM NUMBER: 05710124
BUSINESS ADDRESS:
STREET 1: 500 N LOOP 1604 E STE 100
CITY: SAN ANTONIO
STATE: TX
ZIP: 78232
BUSINESS PHONE: 2104904788
MAIL ADDRESS:
STREET 1: 500 N LOOP 1604 EAST STE 100
CITY: SAN ANTONIO
STATE: TX
ZIP: 78232
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K
<SEQUENCE>1
<FILENAME>apb10k2004.txt
<TEXT>
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2004
[ ]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission File Number 0-19118
ABRAXAS PETROLEUM CORPORATION
------------------------------
(Exact name of Registrant as specified in its charter)
Nevada 74-2584033
- --------------------------------------------------------------------------------
(State or Other Jurisdiction of (I.R.S. Employer Identification Number)
Incorporation or Organization)
500 N. Loop 1604 East, Suite 100
San Antonio, Texas 78232
(Address of principal executive offices)
Registrant's telephone number,
including area code (210) 490-4788
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Common Stock, par value $.01 per share
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None
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 such
filing requirements for the past 90 days. Yes X No__
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ X ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act) [ ] Yes [X] No
The aggregate market value of the voting stock (which consists solely of
shares of common stock) held by non-affiliates of the registrant as of June 30,
2004, based upon the closing per share price of $1.66 was approximately
$53,719,000 on such date.
The number of shares of the registrant's common stock, par value $0.01 per
share, outstanding as of March 18, 2005 was 36,813,758 shares of which
32,715,439 shares were held by non-affiliates.
1
<PAGE>
Documents Incorporated by Reference: Portions of the registrant's Proxy
Statement relating to the 2005 Annual Meeting of Shareholders to be held on June
1, 2005 have been incorporated by reference herein (Part III).
2
<PAGE>
<TABLE>
<CAPTION>
ABRAXAS PETROLEUM CORPORATION
FORM 10-K
TABLE OF CONTENTS
PART I
<S> <C>
Page
Item 1. Business.......................................................................................5
General.......................................................................................6
Markets and Customers.........................................................................7
Risk Factors..................................................................................8
Regulation of Natural Gas and Crude Oil Activities..........................................14
Environmental Matters ......................................................................16
Title to Properties..........................................................................17
Employees....................................................................................17
Item 2. Properties....................................................................................18
Primary Operating Areas......................................................................18
Exploratory and Developmental Acreage........................................................18
Productive Wells.............................................................................19
Reserves Information.........................................................................19
Crude Oil, Natural Gas Liquids and Natural Gas Production and Sales Prices ..................21
Drilling Activities..........................................................................21
Office Facilities............................................................................22
Other Properties.............................................................................22
Item 3. Legal Proceedings............................................................................23
Item 4. Submission of Matters to a Vote of Security Holders..........................................23
Item 4A. Executive Officers of Abraxas................................................................23
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities...............................................................24
Market Information...........................................................................24
Holders......................................................................................24
Dividends....................................................................................24
Recent Sales of Unregistered Securities......................................................24
Item 6. Selected Financial Data......................................................................25
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations........26
General......................................................................................26
Results of Operations........................................................................28
Liquidity and Capital Resources..............................................................32
Critical Accounting Policies.................................................................41
New Accounting Pronouncements................................................................43
Item 7A. Quantitative and Qualitative Disclosures about Market Risk...................................43
Item 8. Financial Statements and Supplementary Data..................................................44
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure.......................................................44
3
<PAGE>
Item 9A. Controls and Procedures.....................................................................45
Item 9B. Other Information............................................................................45
PART III
Item 10. Directors and Executive Officers of the Registrant .........................................45
Item 11. Executive Compensation.......................................................................45
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters.................................................................45
Item 13. Certain Relationships and Related Transactions...............................................45
Item 14. Principal Accounting Fees and Services .....................................................46
PART IV
Item 15. Exhibits, Financial Statement Schedules......................................................46
SIGNATURES..................................................................................50
</TABLE>
4
<PAGE>
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 "Summary" "Risk Factors", "Business",
and "Management's Discussion and Analysis of Financial Condition and Results of
Operations" but may be found in other locations as well. These forward-looking
statements generally relate to our plans and objectives for future operations
and are based upon our management's reasonable estimates of future results or
trends. The factors that may affect our expectations regarding our operations
include, among others, the following:
o our high debt level;
o our success in development, exploitation and exploration activities;
o our ability to make planned capital expenditures;
o declines in our production of natural gas and crude oil;
o prices for natural gas and crude oil;
o our ability to raise equity capital or incur additional indebtedness;
o political and economic conditions in oil producing countries,
especially those in the Middle East;
o prices and availability of alternative fuels;
o our restrictive debt covenants;
o our acquisition and divestiture activities;
o results of our hedging activities; and
o other factors discussed elsewhere in this report.
PART I
Item 1. Business
As part of a series of restructuring transactions approved in 2004, we
adopted a plan to dispose of our operations and interest in Grey Wolf
Exploration Inc.("Grey Wolf"), a wholly-owned Canadian subsidiary of Abraxas
Petroleum Corporation. In February 2005 Grey Wolf closed on an initial public
offering ("IPO") resulting in our substantial divestiture of our capital stock
in Grey Wolf. As a result of the disposal of Grey Wolf the results of operations
of Grey Wolf are reflected in our Financial Statements and in this document as
"Discontinued Operations" and our remaining operations are referred to in our
Financial Statements and in this document as "Continuing Operations" or
"Continued Operations". Unless otherwise noted, all disclosures are for
continuing operations. See Notes 2 and 3 to the financial statements in Item 8.
In this report, PV-10 means estimated future net revenue discounted at a
rate of 10% per annum, before income taxes and with no price or cost escalation
or de-escalation in accordance with guidelines promulgated by the Securities and
Exchange Commission. A Mcf is one thousand cubic feet of natural gas. MMcf is
used to designate one million cubic feet of natural gas and Bcf refers to one
billion cubic feet of natural gas. Mcfe means thousands of cubic feet of natural
gas equivalents, using a conversion ratio of one barrel of crude oil to six Mcf
of natural gas. MMcfe means millions of cubic feet of natural gas equivalents
and Bcfe means billions of cubic feet of natural gas equivalents. MMBtu means
million British Thermal Units. The term Bbl means one barrel of crude oil or
5
<PAGE>
natural gas liquids and MBbls is used to designate one thousand barrels of crude
oil or natural gas liquids.
General
We are an independent energy company primarily engaged in the development
and production of natural gas and crude oil. Historically, we have grown through
the acquisition and subsequent development and exploitation of producing
properties, principally through the redevelopment of old fields utilizing new
technologies such as modern log analysis and reservoir modeling techniques as
well as 3-D seismic surveys and horizontal drilling. As a result of these
activities, we believe that we have a substantial inventory of low risk
development opportunities, which provide a basis for significant production and
reserve increases. In addition, we intend to expand upon our exploitation and
development activities with complementary low risk exploration projects in our
core areas of operation.
Our core areas of operation are in south and west Texas and east central
Wyoming. Our current producing properties are typically characterized by
long-lived reserves, established production profiles and an emphasis on natural
gas At December 31, 2004, we owned interests in 93,341 gross acres (81,748 net
acres) applicable to our continuing operations, and operated properties
accounting for approximately 95% of our PV-10, affording us substantial control
over the timing and incurrence of operating and capital expenditures. At
December 31, 2004 estimated total proved reserves were 93.7 Bcfe with an
aggregate PV-10 of $149.0 million. We participated in the drilling of 4 gross (4
net) wells with 3 gross (3 net) wells being successful. We invested $9.3 million
in capital spending on these activities during 2004.
We believe that our high quality asset base, high degree of operational
control and large inventory of drilling projects positions us for future growth.
Our properties are concentrated in locations that facilitate substantial
economies of scale in drilling and production operations and efficient reservoir
management practices. In addition, we have 47 proved undeveloped locations and
have identified over 100 drilling and recompletion opportunities on our existing
acreage, the successful development of which we believe could significantly
increase our daily production and proved reserves.
In January 2003, we completed a series of transactions, which we sometimes
refer to as the January 2003 financial restructuring, including the sale of most
of our Canadian producing properties and the issuance by Abraxas of 11 1/2%
secured notes due 2007. The terms of those notes limited our ability to make
capital expenditures exceeding $10 million per year, which caused us to put a
priority on those projects which allowed us to maintain our leasehold positions
and comply with drilling requirements on non-operated properties, rather than on
those opportunities which we believed had the greatest potential for increasing
our production and reserves.
On October 28, 2004, in order to provide us with greater flexibility in
conducting our business, including increasing capital spending and exploiting
our additional drilling opportunities, we refinanced all of our then existing
indebtedness by redeeming our 11 1/2% secured notes due 2007 and terminating our
previous credit facility with the net proceeds from:
o the private issuance of $125.0 million aggregate principal amount of
the Floating Rate Senior Secured Notes due 2009, Series A;
o the proceeds of our $25.0 million second lien increasing rate bridge
loan; and
o the payment to us by Grey Wolf of $35.0 million from the proceeds of
Grey Wolf's $35.0 million term loan.
Interest on the bridge loan currently accrues at a rate of 12% per annum
until October 28, 2005, and will be payable monthly in cash. Interest on the
Bridge Loan will thereafter accrue at a rate of 15% per annum, and will be
payable in-kind. Subject to earlier termination rights and events of default,
the bridge loan's stated maturity date is October 28, 2010. We originally
borrowed the full $25 million under the bridge loan, but paid down the bridge
loan to approximately $5.4 million in February 2005 with the proceeds from the
sale of secondary shares offered by us in connection with the Grey Wolf IPO,
described below.
6
<PAGE>
Until the Grey Wolf term loan was re-paid in full with the proceeds of the
Grey Wolf IPO completed in February 2005, as described below, interest on the
term loan accrued at the prime rate announced by the term loan's administrative
agent plus 6.25%. Such interest was payable quarterly in cash with the first
interest payment having been made on January 1, 2005. Subject to earlier
termination rights and events of default, the Grey Wolf term loan would have
matured on October 29, 2009.
As a part of the October 2004 refinancing, we also entered into a new $15.0
million senior secured revolving credit facility, under which we currently have
availability of approximately $13.0 million. Our new credit facility has a
maximum commitment of $15 million, which includes a $2.5 million subfacility for
letters of credit. Availability under the new credit facility is subject to a
borrowing base consistent with normal and customary natural gas and crude oil
lending transactions. Outstanding amounts under the new credit facility bear
interest at the prime rate announced by Wells Fargo Bank, National Association
plus 1.00%. Subject to earlier termination rights and events of default, the new
credit facility's stated maturity date is October 28, 2008.
In February 2005, we completed an exchange offer pursuant to which all the
Floating Rate Senior Secured Notes due 2009, Series A were exchanged for
Floating Rate Senior Secured Notes due 2009, Series B. These new notes continue
to accrue interest from the date of issuance at a per annum floating rate of
6-month LIBOR plus 7.50%. The initial interest rate on these new notes is 9.72%
per annum. The interest rate will reset semi-annually on each June 1 and
December 1, commencing on June 1, 2005. Interest is payable in cash
semi-annually in arrears on June 1 and December 1 of each year, commencing on
June 1, 2005.
Also as part of the restructuring plan in 2004 we approved a plan to
dispose of our operations and interest in Grey Wolf. In February 2005, Grey Wolf
closed on an initial public offering ("IPO") resulting in our substantial
divestiture of our capital stock in Grey Wolf. Net proceeds of approximately $37
million from the offering by Grey Wolf of treasury shares were used to repay
Grey Wolf's term loan in its entirety and eliminate its working capital deficit.
Net proceeds of approximately $20 million from the secondary share offered by
Abraxas were used to reduce the amount outstanding under its bridge loan to
approximately $5.4 million.
On March 24, 2005, we were advised of the underwriter's intent to exercise
3.5 million of the over allotment shares. Closing for this exercise is scheduled
for March 31,2005 and will provide approximately $7.5 million that Abraxas will
utilize to payoff the remaining balance of its Bridge Loan. The remaining
proceeds of approximately $2 million will be used to pay down our revolving
credit facility to, effectively, zero.
Markets and Customers
The revenue generated by our operations is highly dependent upon the prices
of, and demand for, natural gas and crude oil. Historically, the markets for
natural gas and crude oil have been volatile and are likely to continue to be
volatile in the future. The prices we receive for our natural gas and crude oil
production are subject to wide fluctuations and depend on numerous factors
beyond our control including seasonality, the condition of the United States
economy (particularly the manufacturing sector), foreign imports, political
conditions in other crude oil-producing and natural gas-producing countries, the
actions of the Organization of Petroleum Exporting Countries and domestic
regulation, legislation and policies. Decreases in the prices of natural gas and
crude oil have had, and could have in the future, an adverse effect on the
carrying value of our proved reserves and our revenue, profitability and cash
flow from operations. You should read the discussion under "Risk Factors - Risks
Relating to Our Industry -- Market conditions for natural gas and crude oil and
particularly volatility of prices for natural gas and crude oil could adversely
affect our revenues, cash flows, profitability and Growth" and "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Critical Accounting Policies" for more information relating to the effects of
decreases in natural gas and crude oil prices on us.
Substantially all of our natural gas and crude oil is sold at current
market prices under short-term arrangements, as is customary in the industry.
During the year ended December 31, 2004 two purchasers accounted for
approximately 64% of our natural gas and crude oil sales. We believe that there
7
<PAGE>
are numerous other companies available to purchase our natural gas and crude oil
and that the loss of one or more of these purchasers would not materially affect
our ability to sell natural gas and crude oil.
Risk Factors
Risks Related to Our Business
We have a highly leveraged capital structure, which limits our operating
and financial flexibility.
We have a highly leveraged capital structure. We currently have total
indebtedness, including the notes, of approximately $126 million, all of which
is secured indebtedness.
Our highly leveraged capital structure will have several important
effects on our future operations, including:
o A substantial amount of our cash flow from operations will be
required to service our indebtedness (including cash interest
payments on the notes), which will reduce the funds that would
otherwise be available for operations, capital expenditures and
expansion opportunities, including developing our properties;
o The covenants contained in our new revolving credit facility and
bridge loan require us to meet certain financial tests and comply
with certain other restrictions, including limitations on capital
expenditures. These restrictions, together with those in the
indenture governing the new notes, may limit our ability to
undertake certain activities and respond to changes in our
business and our industry;
o Our debt level may impair our ability to obtain additional
capital, through equity offerings or debt financings, for working
capital, capital expenditures, or refinancing of indebtdness;
o Our debt level makes us more vulnerable to economic downturns and
adverse developments in our industry (especially declines in
natural gas and crude oil prices) and the economy in general; and
o The notes and the new revolving credit facility are subject to
variable interest rates which makes us vulnerable to interest rate
increases.
We may not be able to fund the substantial capital expenditures that will
be required for us to increase our reserves and our production.
We are required to make substantial capital expenditures to develop our
existing reserves and to discover new reserves. Historically, we have financed
our capital expenditures primarily with cash flow from operations, borrowings
under credit facilities and sales of producing properties, and we expect to
continue to do so in the future; however, we cannot assure you that we will have
sufficient capital resources in the future to finance our capital expenditures.
Volatility in natural gas and crude oil prices, the timing of our
drilling program and our drilling results will affect our cash flow from
operations. Lower prices and/or lower production will also decrease revenues and
cash flow, thus reducing the amount of financial resources available to meet our
capital requirements, including reducing the amount available to pursue our
drilling opportunities. If our cash flow from operations does not increase as a
result of our planned capital expenditures, a greater percentage of our cash
flow from operations will be required for debt service (including cash interest
payments on the notes) and our planned capital expenditures would, by necessity,
be decreased.
The borrowing base under the new revolving credit facility will be
determined from time to time by our lenders , consistent with their customary
natural gas and crude oil lending practices. Reductions in estimates of our
natural gas and crude oil reserves could result in a reduction in our borrowing
base, which would reduce the amount of financial resources available under the
new revolving credit facility to meet our capital requirements. Such a reduction
8
<PAGE>
could be the result of lower commodity prices or production, inability to drill
or unfavorable drilling results, changes in natural gas and crude oil reserve
engineering, the lenders' inability to agree to an adequate borrowing base or
adverse changes in the lenders' practices regarding estimation of reserves.
If cash flow from operations or our borrowing base decrease for any
reason, our ability to undertake exploitation and development activities could
be adversely affected. As a result, our ability to replace production may be
limited. In addition, if the borrowing base under our new revolving credit
facility is reduced, we would be required to reduce our borrowings under the new
revolving credit facility so that such borrowings do not exceed the borrowing
base. This could further reduce the cash available to us for capital spending
and, if we did not have sufficient capital to reduce our borrowing level, could
cause us to default under the new revolving credit facility, the notes and the
bridge loan.
We have sold producing properties to provide us with liquidity and
capital resources in the past and may do so in the future. After any such sale,
we would expect to utilize the proceeds to drill new wells. If we cannot replace
the production lost from properties sold with production from new properties,
our cash flow from operations will likely decrease which, in turn, would
decrease the amount of cash available for debt service and additional capital
spending.
We may be unable to acquire or develop additional reserves, in which case
our results of operations and financial condition would be adversely
affected.
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 exploitation activities or,
through engineering studies, identify additional behind-pipe zones or secondary
recovery reserves. We cannot assure you that our exploration, exploitation and
development activities will result in increases in our proved reserves. While we
have had some success in pursuing these activities, we have not been able to
fully replace the production volumes lost from natural field declines and
property sales. As our proved reserves, and consequently our production,
decline, our cash flow from operations and the amount that we are able to borrow
under the new revolving credit facility will also decline. In addition,
approximately 49% of our total estimated proved reserves at December 31, 2004
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.
Prior to the January 2003 financial restructuring, we implemented a
number of measures to conserve our cash resources, including postponement of
drilling projects. While these measures helped conserve our cash resources, they
also limited our ability to replenish our depleting reserves. While the 11 1/2%
secured notes due 2007 were outstanding, we also postponed drilling projects as
a result of the capital spending limitations that existed in those notes. As a
result, our current producing properties have continued to deplete, and we have
not been able to drill new wells at a rate that we would have desired in the
absence of these limitations. The terms of the new revolving credit facility and
the bridge loan place limits on our capital expenditures, which could limit our
ability to replenish our reserves and increase production.
Restrictive debt covenants could limit our growth and our ability to
finance our operations, fund our capital needs, respond to changing
conditions and engage in other business activities that may be in our best
interests.
The new revolving credit facility, bridge loan and the indenture
governing the notes contain a number of significant covenants that, among other
things, limit our ability to:
o Incur or guarantee additional indebtedness and issue certain
types of preferred stock or redeemable stock;
o transfer or sell assets;
o create liens on assets;
9
<PAGE>
o pay dividends or make other distributions on capital stock or
make other restricted payments, including repurchasing, redeeming
or retiring capital stock or subordinated debt or making certain
investments or acquisitions;
o engage in transactions with affiliates;
o guarantee other indebtedness;
o make any change in the principal nature of our business;
o prepay, redeem, purchase or otherwise acquire any of our or our
restricted subsidiaries' indebtedness;
o permit a change of control;
o directly or indirectly make or acquire any investment;
o cause a restricted subsidiary to issue or sell our capital stock;
and
o consolidate, merge or transfer all or substantially all of the
consolidated assets of Abraxas and our restricted subsidiaries.
In addition, the new revolving credit facility and bridge loan require
us to maintain compliance with specified financial ratios and satisfy certain
financial condition tests. Our ability to comply with these ratios and financial
condition tests may be affected by events beyond our control, and we cannot
assure you that we will meet these ratios and financial condition tests. These
financial ratio restrictions and financial condition tests could limit our
ability to obtain future financings, make needed capital expenditures, withstand
a future downturn in our business or the economy in general or otherwise conduct
necessary or desirable corporate activities.
A breach of any of these covenants or our inability to comply with the
required financial ratios or financial condition tests could result in a default
under the new revolving credit facility and bridge loan and the notes. A
default, if not cured or waived, could result in all of our indebtedness,
including the notes, becoming immediately due and payable. If that should occur,
we may not be able to pay all such debt or to borrow sufficient funds to
refinance it. Even if new financing were then available, it may not be on terms
that are acceptable to us. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Long-Term Indebtedness."
The marketability of our production depends largely upon the availability,
proximity and capacity of natural gas gathering systems, pipelines and
processing facilities.
The marketability of our production depends in part upon processing and
transportation facilities. Transportation space on such gathering systems and
pipelines is occasionally limited and at times unavailable due to repairs or
improvements being made to such facilities or due to such space being utilized
by other companies with priority transportation agreements. Our access to
transportation options can also be affected by U.S. Federal and state regulation
of natural gas and crude oil production and transportation, general economic
conditions and changes in supply and demand. These factors and the availability
of markets are beyond our control. If market factors dramatically change, the
financial impact on us could be substantial and adversely affect our ability to
produce and market natural gas and crude oil.
Hedging transactions have in the past and may in the future impact our cash
flow from operations.
We enter into hedging arrangements from time to time to reduce our
exposure to fluctuations in natural gas and crude oil prices and to achieve more
predictable cash flow. In 2002 and 2003, we experienced hedging costs of $1.5
million and $842,000, respectively; resulting from the price ceilings we
established being exceeded by the index prices. For the year ended December 31,
2004 we recognized a gain from hedging activities of approximately $118,000.
Currently, we believe our hedging arrangements, which are in the form of price
10
<PAGE>
floors, do not expose us to significant financial risk. Although our hedging
activities may limit our exposure to declines in natural gas and crude oil
prices, such activities may also limit and have in the past limited, additional
revenues from increases in natural gas and crude oil prices.
We cannot assure you that the hedging transactions we have entered into, or
will enter into, will adequately protect us from financial loss due to
circumstances such as:
o highly volatile natural gas and crude oil prices;
o our production being less than expected; or
o a counterparty to one of our hedging transactions defaulting on
our contractual obligations.
We have experienced recurring significant operating losses.
We recorded net losses from continuing operations for 2002 and 2003 of
$55.2 million and $14.1 million, respectively.
Lower natural gas and crude oil prices increase the risk of ceiling
limitation write-downs.
We use the full cost method to account for our natural gas and crude
oil operations. Accordingly, we capitalize the cost to acquire, explore for and
develop natural gas and crude oil properties. Under full cost accounting rules,
the net capitalized cost of natural gas and crude oil properties may not exceed
a "ceiling limit" which is based upon the present value of estimated future net
cash flows from proved reserves, discounted at 10%. If net capitalized costs of
natural gas and crude oil properties exceed the ceiling limit, we must charge
the amount of the excess to earnings. This is called a "ceiling limitation
write-down." This charge does not impact cash flow from operating activities,
but does reduce our stockholders' equity and earnings. The risk that we will be
required to write-down the carrying value of natural gas and crude oil
properties increases when natural gas and crude oil prices are low. In addition,
write-downs may occur if we experience substantial downward adjustments to our
estimated proved reserves. An expense recorded in one period may not be reversed
in a subsequent period even though higher natural gas and crude oil prices may
have increased the ceiling applicable to the subsequent period.
We have incurred ceiling limitation write-downs in the past. At June
30, 2002, for example, we recorded a ceiling limitation write-down of $28.2
million. We cannot assure you that we will not experience additional ceiling
limitation write-downs in the future.
Use of our net operating loss carryforwards may be limited.
At December 31, 2004, we had, subject to the limitation discussed
below, $184.0 million of net operating loss carryforwards for U.S. tax purposes.
These loss carryforwards will expire through 2022 if not utilized. In addition,
as to a portion of the U.S. net operating loss carryforwards, the amount of such
carryforwards that we can use annually is limited under U.S. tax law. Moreover,
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 $73.2 million and $73.0
million for deferred tax assets at December 31, 2003 and 2004, respectively.
We depend on our Chairman, President and CEO and the loss of his services
could have an adverse effect on our operations.
We depend to a large extent on Robert L. G. Watson, our Chairman of the
Board, President and Chief Executive Officer, for our management and business
and financial contacts. Mr. Watson may terminate his employment agreement with
us at any time on 30 days notice, but, if he terminates without cause, he would
not be entitled to the severance benefits provided under the terms of that
agreement. Mr. Watson is not precluded from working for, with or on behalf of a
competitor upon termination of his employment with us. If Mr. Watson were no
longer able or willing to act as our Chairman, the loss of his services could
have an adverse effect on our operations. In addition, in connection with the
Grey Wolf IPO, Abraxas, Grey Wolf and Mr. Watson agreed that Mr. Watson would
continue to serve as Chief Executive Officer and President for Abraxas and as
the Chief Executive Officer for Grey Wolf, with Mr. Watson devoting two-thirds
11
<PAGE>
of his time to his positions and duties with Abraxas and one-third of his time
to his position and duties with Grey Wolf.
Risks Related to Our Industry
We may not find any commercially productive natural gas or crude oil
reservoirs.
We cannot assure you that the new wells we drill will be productive or
that we will recover all or any portion of our capital investment. Drilling for
natural gas and crude oil may be unprofitable. Dry holes and wells that are
productive but do not produce sufficient net revenues after drilling, operating
and other costs are unprofitable. The inherent risk of not finding commercially
productive reservoirs will be compounded by the fact that 49% of our total
estimated proved reserves at December 31, 2004 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. In addition, our properties may be susceptible to drainage from
production by other operations on adjacent properties. If the volume of natural
gas and crude oil we produce decreases, our cash flow from operations will
decrease.
We operate in a highly competitive industry which may adversely affect our
operations, including our ability to secure drilling equipment to service
our core areas.
We operate in a highly competitive environment. The principal resources
necessary for the exploration and production of natural gas and crude oil are
leasehold prospects under which natural gas and crude oil reserves may be
discovered, drilling rigs and related equipment to explore for such reserves and
knowledgeable personnel to conduct all phases of natural gas and crude oil
operations. We must compete for such resources with both major natural gas and
crude oil companies and independent operators. Many of these competitors have
financial and other resources substantially greater than ours. In the past, we
have had difficulty securing drilling equipment in certain of our core areas.
Although we believe our current operating and financial resources are adequate
to preclude any significant disruption of our operations in the immediate
future, we cannot assure you that such materials and resources will be available
to us.
Market conditions for natural gas and crude oil, and particularly
volatility of prices for natural gas and crude oil, could adversely affect
our revenue, cash flows, profitability and growth. .
Our revenue, cash flows, profitability and future rate of growth depend
substantially upon prevailing prices for natural gas and crude oil. Natural gas
prices affect us more than crude oil prices because most of our production and
reserves are natural gas. Prices also affect the amount of cash flow available
for capital expenditures and our ability to borrow money or raise additional
capital. Lower prices may also make it uneconomical for us to increase or even
continue current production levels of natural gas and crude oil.
Prices for natural gas and crude oil are subject to large fluctuations
in response to relatively minor changes in the supply and demand for natural gas
and crude oil, market uncertainty and a variety of other factors beyond our
control, including:
o changes in foreign and domestic supply and demand for natural gas
and crude oil;
o political stability and economic conditions in oil producing
countries, particularly in the Middle East; o general economic
conditions.
o Domestic and foreign governmental regulation; and
o The price and availability of alternative fuel sources.
In addition to decreasing our revenue and cash flow from operations,
low or declining natural gas and crude oil prices could have additional material
adverse effects on us, such as:
12
<PAGE>
o reducing the overall volume of natural gas and crude oil that we
can produce economically
o reducing our borrowing base under the new credit facility; and
o thereby adversely affecting our revenue, profitability and cash
flow and our ability to perform our obligations with respect to
the notes; and
o impairing our borrowing capacity and our ability to obtain equity
capital.
Estimates of our proved reserves and future net revenue are uncertain and
inherently imprecise.
The process of estimating natural gas and crude oil reserves is complex
involving decisions and assumptions in the evaluating available geological,
geophysical, engineering and economic data. Accordingly, these estimates are
imprecise. Actual future production, natural gas and crude oil prices, revenues,
taxes, development expenditures, operating expenses and quantities of
recoverable natural gas and crude oil reserves most likely will vary from those
estimated. Any significant variance could materially affect the estimated
quantities and present value of reserves set forth in this report. In addition,
we may adjust estimates of proved reserves to reflect production history,
results of exploitation and development, prevailing natural gas and crude oil
prices and other factors, many of which are beyond our control.
The estimates of our reserves are based upon various assumptions about
future production levels, prices and costs that may not prove to be correct over
time. In particular, estimates of natural gas and crude oil reserves, future net
revenue from proved reserves and the PV-10 thereof for the natural gas and crude
oil gas properties described in this report are based on the assumption that
future natural gas and crude oil prices remain the same as crude oil and natural
gas prices at December 31, 2004. The sales prices as of such date used for
purposes of such estimates were $41.01 per Bbl of crude oil and $4.94 per Mcf of
natural gas. This compares with $31.03 per Bbl of crude oil and $5.05 per Mcf of
natural gas as of December 31, 2003. These estimates also assume that we will
make future capital expenditures of approximately $45.0 million in the aggregate
through 2019, the majority expected to be incurred from 2005 to 2008, which are
necessary to develop and realize the value of proved undeveloped reserves on our
properties. Any significant variance in actual results from these assumptions
could also materially affect the estimated quantity and value of reserves set
forth in this report.
The present value of future net revenues referred to in this report may
not be the current market value of our estimated natural gas and crude oil
reserves. In accordance with SEC requirements, the estimated discounted future
net cash flows from proved reserves are generally based on prices and costs as
of the end of the period of the estimate. Actual future prices and costs may be
materially higher or lower than the prices and costs as of the end of the year
of the estimate. Any changes in consumption by natural gas purchasers or in
governmental regulations or taxation will also affect actual future net cash
flows. The timing of both the production and the expenses from the development
and production of natural gas and crude oil properties will affect the timing of
actual future net cash flows from proved reserves and their present value. In
addition, the 10% discount factor, which is required by the SEC to be used in
calculating discounted future net cash flows for reporting purposes, is not
necessarily the most accurate discount factor. The effective interest rate at
various times and the risks associated with us or the natural gas and crude oil
industry in general will affect the accuracy of the 10% discount factor.
Our operations are subject to numerous risks of natural gas and crude oil
drilling and production activities.
Our natural gas and crude oil drilling and production activities are
subject to numerous risks, many of which are beyond our control. These risks
include the risk of fire, explosions, blow-outs, pipe failure, abnormally
pressured formations and environmental hazards. Environmental hazards include
oil spills, natural gas leaks, ruptures and discharges of toxic gases. In
addition, title problems, weather conditions and mechanical difficulties or
shortages or delays in delivery of drilling rigs and other equipment could
negatively affect our operations. If any of these or other similar industry
operating risks occur, we could have substantial losses. Substantial losses also
may result from injury or loss of life, severe damage to or destruction of
property, clean-up responsibilities, regulatory investigation and penalties and
suspension of operations. In accordance with industry practice, we maintain
13
<PAGE>
insurance against some, but not all, of the risks described above. We cannot
assure you that our insurance will be adequate to cover losses or liabilities.
Also, we cannot predict the continued availability of insurance at premium
levels that justify its purchase.
Our natural gas and crude oil operations are subject to various Federal,
state and local regulations that materially affect our operations.
Matters regulated include permits for drilling operations, drilling and
abandonment bonds, reports concerning operations, the spacing of wells and
unitization and pooling of properties and taxation. At various times, regulatory
agencies have imposed price controls and limitations on production. In order to
conserve supplies of natural gas and crude oil, these agencies have restricted
the rates of flow of natural gas and crude oil wells below actual production
capacity. Federal, state and local laws regulate production, handling, storage,
transportation and disposal of natural gas and crude oil, by-products from
natural gas and crude oil and other substances and materials produced or used in
connection with natural gas and crude oil operations. To date, our expenditures
related to complying with these laws and for remediation of existing
environmental contamination have not been significant. We believe that we are in
substantial compliance with all applicable laws and regulations. However, the
requirements of such laws and regulations are frequently changed. We cannot
predict the ultimate cost of compliance with these requirements or their effect
on our operations.
Regulation of Natural Gas and Crude Oil Activities
The exploration, production and transportation of all types of
hydrocarbons are subject to significant governmental regulations. Our operations
are affected from time to time in varying degrees by political developments and
federal, state and local laws and regulations. In particular, crude oil and
natural gas production operations and economics are, or in the past have been,
affected by industry specific price controls, taxes, conservation, safety,
environmental, and other laws relating to the petroleum industry, by changes in
such laws and by constantly changing administrative regulations.
Price Regulations
In the past, maximum selling prices for certain categories of crude
oil, natural gas, condensate and NGLs were subject to significant federal
regulation. At the present time, however, all sales of our crude oil, natural
gas, condensate and NGLs produced under private contracts may be sold at market
prices. Congress could, however, re-enact price controls in the future. If
controls that limit prices to below market rates are instituted, our revenue
would be adversely affected.
Natural Gas Regulation
Historically, the natural gas industry as a whole has been more heavily
regulated than the crude oil or other liquid hydrocarbons market. Most
regulations focused on transportation practices. Currently, the Federal Energy
Regulatory Commission ("FERC), requires each interstate pipeline to, among other
things, "unbundle" its traditional bundled sales services and create and make
available on an open and nondiscriminatory basis numerous constituent services
(such as gathering services, storage services, firm and interruptible
transportation services, and standby sales and natural gas balancing services),
and to adopt a new ratemaking methodology to determine appropriate rates for
those services. To the extent the pipeline company or its sales affiliate
markets natural gas as a merchant, it does so pursuant to private contracts in
direct competition with all of the sellers, such as us; however, pipeline
companies and their affiliates are not required to remain "merchants" of natural
gas, and most of the interstate pipeline companies have become "transporters
only," although many have affiliated marketers.
Transportation pipeline availability and shipping cost are major
factors affecting the production and sale of natural gas. Our physical sales of
natural gas are affected by the actual availability, terms and cost of pipeline
transportation. The price and terms for access onto the pipeline transportation
systems remain subject to extensive Federal regulation. Although FERC does not
directly regulate our production and marketing activities, it does affect how
buyers and sellers gain access to and use of the necessary transportation
facilities and how we and our competitors sell natural gas in the marketplace.
FERC continues to review and modify its regulations regarding the transportation
14
<PAGE>
of natural gas. For example, FERC has recently begun a broad review of its
natural gas transportation regulations, including how its regulations operate in
conjunction with state proposals for natural gas marketing restructuring and in
the increasingly competitive marketplace for all post-wellhead services related
to natural gas.
In recent years FERC also has pursued a number of important policy
initiatives which could significantly affect the marketing of natural gas in the
United States. Most of these initiatives are intended to enhance competition in
natural gas markets. FERC rules encouraging "spin downs," or the breakout of
unregulated gathering activities from regulated transportation services, may
have the adverse effect of increasing the cost of doing business on some in the
industry, including us, as a result of the geographic monopolization of certain
facilities by their new, unregulated owners. As to all of FERC initiatives, the
ongoing, or, in some instances, preliminary and evolving nature makes it
impossible at this time to predict their ultimate impact on our business.
However, we do not believe that any FERC initiatives will affect us any
differently than other natural gas producers and marketers with which we
compete.
FERC decisions involving onshore facilities are more liberal in their
reliance upon traditional tests for determining what facilities are "gathering"
and therefore exempt from federal regulatory control. In many instances, what
was in the past classified as "transmission" may now be classified as
"gathering." We ship certain of our natural gas through gathering facilities
owned by others. Although FERC decisions create the potential for increasing the
cost of shipping our natural gas on third party gathering facilities, our
shipping activities have not been materially affected by these decisions.
In summary, all of FERC activities related to the transportation of
natural gas result in improved opportunities to market our physical production
to a variety of buyers and market places, while at the same time increasing
access to pipeline transportation and delivery services. Additional proposals
and proceedings that might affect the natural gas industry in the United States
are considered from time to time by Congress, FERC, state regulatory bodies and
the courts. We cannot predict when or if any such proposals might become
effective or their effect, if any, on our operations. The natural gas and crude
oil industry historically has been very heavily regulated; thus there is no
assurance that the less stringent regulatory approach recently pursued by FERC
and Congress will continue indefinitely into the future.
State and Other Regulation
All of the jurisdictions in which we own producing natural gas and
crude oil properties have statutory provisions regulating the exploration for
and production of natural gas and crude oil. These include provisions requiring
permits for the drilling of wells and maintaining bonding requirements in order
to drill or operate wells and provisions relating to the location of wells, the
method of drilling and casing wells, the surface use and restoration of
properties upon which wells are drilled and the plugging and abandoning of
wells. Our operations are also subject to various conservation laws and
regulations. These include the regulation of the size of drilling and spacing
units or proration units on an acreage basis and the density of wells which may
be drilled and the unitization or pooling of natural gas and crude oil
properties. In this regard, some states allow the forced pooling or integration
of tracts to facilitate exploration while other states rely on voluntary pooling
of lands and leases. In addition, state conservation laws establish maximum
rates of production from natural gas and crude oil wells, generally prohibit the
venting or flaring of natural gas and impose certain requirements regarding the
ratability of production. Some states, such as Texas and Oklahoma, have, in
recent years, reviewed and substantially revised methods previously used to make
monthly determinations of allowable rates of production from fields and
individual wells. The effect of all of these conservation regulations is to
limit the speed, timing and amounts of crude oil and natural gas we can produce
from our wells, and to limit the number of wells or the location at which we can
drill.
State regulation of gathering facilities generally includes various
safety, environmental, and in some circumstances, non-discriminatory take or
service requirements, but does not generally entail rate regulation. In the
United States, natural gas gathering has received greater regulatory scrutiny at
both the state and federal levels in the wake of the interstate pipeline
restructuring under FERC. Order 636. For example, the Texas Railroad Commission
enacted a Natural Gas Transportation Standards and Code of Conduct to provide
regulatory support for the State's more active review of rates, services and
practices associated with the gathering and transportation of natural gas by an
entity that provides such services to others for a fee, in order to prohibit
such entities from unduly discriminating in favor of their affiliates.
15
<PAGE>
For those operations on Federal or Indian oil and gas leases, such
operations must comply with numerous regulatory restrictions, including various
non-discrimination statutes, and certain of such operations must be conducted
pursuant to certain on-site security regulations and other permits issued by
various federal agencies. In addition, in the United States, the Minerals
Management Service ("MMS") prescribes or severely limits the types of costs that
are deductible transportation costs for purposes of royalty valuation of
production sold off the lease. In particular, MMS prohibits deduction of costs
associated with marketer fees, cash out and other pipeline imbalance penalties,
or long-term storage fees. Further, the MMS has been engaged in a process of
promulgating new rules and procedures for determining the value of crude oil
produced from federal lands for purposes of calculating royalties owed to the
government. The natural gas and crude oil industry as a whole has resisted the
proposed rules under an assumption that royalty burdens will substantially
increase. We cannot predict what, if any, effect any new rule will have on our
operations.
Environmental Matters
Our operations are subject to numerous federal, state and local laws
and regulations controlling the generation, use, storage, and discharge of
materials into the environment or otherwise relating to the protection of the
environment. These laws and regulations may require the acquisition of a permit
or other authorization before construction or drilling commences; restrict the
types, quantities, and concentrations of various substances that can be released
into the environment in connection with drilling, production, and natural gas
processing activities; suspend, limit or prohibit construction, drilling and
other activities in certain lands lying within wilderness, wetlands, and other
protected areas; require remedial measures to mitigate pollution from historical
and on-going operations such as use of pits and plugging of abandoned wells;
restrict injection of liquids into subsurface strata that may contaminate
groundwater; and impose substantial liabilities for pollution resulting from our
operations. Environmental permits required for our operations may be subject to
revocation, modification, and renewal by issuing authorities. Governmental
authorities have the power to enforce compliance with their regulations and
permits, and violations are subject to injunction, civil fines, and even
criminal penalties. Our management believes that we are in substantial
compliance with current environmental laws and regulations, and that we will not
be required to make material capital expenditures to comply with existing laws.
Nevertheless, changes in existing environmental laws and regulations or
interpretations thereof could have a significant impact on us as well as the
natural gas and crude oil industry in general, and thus we are unable to predict
the ultimate cost and effects of future changes in environmental laws and
regulations.
In the United States, the Comprehensive Environmental Response,
Compensation and Liability Act ("CERCLA"), also known as "Superfund," and
comparable state statutes impose strict, joint, and several liability on certain
classes of persons who are considered to have contributed to the release of a
"hazardous substance" into the environment. These persons include the owner or
operator of a disposal site or sites where a release occurred and companies that
generated, disposed or arranged for the disposal of the hazardous substances
released at the site. Under CERCLA such persons or companies may be
retroactively liable for the costs of cleaning up the hazardous substances that
have been released into the environment and for damages to natural resources,
and it is common for neighboring land owners and other third parties to file
claims for personal injury, property damage, and recovery of response costs
allegedly caused by the hazardous substances released into the environment. The
Resource Conservation and Recovery Act ("RCRA") and comparable state statutes
govern the disposal of "solid waste" and "hazardous waste" and authorize
imposition of substantial civil and criminal penalties for failing to prevent
surface and subsurface pollution, as well as to control the generation,
transportation, treatment, storage and disposal of hazardous waste generated by
natural gas and crude oil operations. Although CERCLA currently contains a
"petroleum exclusion" from the definition of "hazardous substance," state laws
affecting our operations impose cleanup liability relating to petroleum and
petroleum related products, including crude oil cleanups. In addition, although
RCRA regulations currently classify certain oilfield wastes which are uniquely
associated with field operations as "non-hazardous," such exploration,
development and production wastes could be reclassified by regulation as
hazardous wastes thereby administratively making such wastes subject to more
stringent handling and disposal requirements.
We currently own or lease, and have in the past owned or leased,
numerous properties that for many years have been used for the exploration and
production of natural gas and crude oil. Although we utilized standard industry
operating and disposal practices at the time, hydrocarbons or other wastes may
16
<PAGE>
have been disposed of or released on or under the properties we owned or leased
or on or under other locations where such wastes have been taken for disposal.
In addition, many of these properties have been operated by third parties whose
treatment and disposal or release of hydrocarbons or other wastes was not under
our control. These properties and the wastes disposed thereon may be subject to
CERCLA, RCRA, and analogous state laws. Our operations are also impacted by
regulations governing the disposal of naturally occurring radioactive materials
("NORM"). We must comply with the Clean Air Act and comparable state statutes
which prohibit the emissions of air contaminants, although a majority of our
activities are exempted under a standard exemption. Moreover, owners, lessees
and operators of natural gas and crude oil properties are also subject to
increasing civil liability brought by surface owners and adjoining property
owners. Such claims are predicated on the damage to or contamination of land
resources occasioned by drilling and production operations and the products
derived therefrom, and are usually causes of action based on negligence,
trespass, nuisance, strict liability and fraud.
United States federal regulations also require certain owners and
operators of facilities that store or otherwise handle crude oil, such as us, to
prepare and implement spill prevention, control and countermeasure plans and
spill response plans relating to possible discharge of crude oil into surface
waters. The federal Oil Pollution Act ("OPA") contains numerous requirements
relating to prevention of, reporting of, and response to crude oil spills into
waters of the United States. For facilities that may affect state waters, OPA
requires an operator to demonstrate $10 million in financial responsibility.
State laws mandate crude oil cleanup programs with respect to contaminated soil.
We are not currently involved in any administrative, judicial or legal
proceedings arising under domestic or foreign federal, state, or local
environmental protection laws and regulations, or under federal or state common
law, which would have a material adverse effect on our financial position or
results of operations. Moreover, we maintain insurance against costs of clean-up
operations, but we are not fully insured against all such risks. A serious
incident of pollution may result in the suspension or cessation of operations in
the affected area.
We believe that we have obtained and are in compliance with all
material environmental permits, authorizations and approvals.
All of our oil and gas wells will require proper plugging and
abandonment when they are no longer producing. We post bonds with most
regulatory agencies to ensure compliance with our plugging responsibility.
Plugging and abandonment operations and associated reclamation of the surface
production site are important components of our environmental management system.
We plan accordingly for the ultimate disposition of properties that are no
longer producing.
Title to Properties
As is customary in the natural gas and crude oil industry, we make only
a cursory review of title to undeveloped natural gas and crude oil leases at the
time we acquire them. However, before drilling commences, we require a thorough
title search to be conducted, and any material defects in title are remedied
prior to the time actual drilling of a well begins. To the extent title opinions
or other investigations reflect title defects, we, rather than the seller/lessor
of the undeveloped property, are typically obligated to cure any title defect at
our expense. If we were unable to remedy or cure any title defect of a nature
such that it would not be prudent to commence drilling operations on the
property, we could suffer a loss of our entire investment in the property. We
believe that we have good title to our natural gas and crude oil properties,
some of which are subject to immaterial encumbrances, easements and
restrictions. The natural gas and crude oil properties we own are also typically
subject to royalty and other similar non-cost bearing interests customary in the
industry. We do not believe that any of these encumbrances or burdens will
materially affect our ownership or use of our properties.
Employees
As of March 9, 2005, we had 47 full-time employees in the United
States, including 3 executive officers, 3 non-executive officers, 1 petroleum
engineer, 1 geologist, 5 managers, 1 landman, 10 administrative and support
personnel and 23 field personnel. Additionally, we retain contract pumpers on a
month-to-month basis. We retain independent geological and engineering
consultants from time to time on a limited basis and expect to continue to do so
in the future.
17
<PAGE>
Available Information
Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current
Reports on Form 8-K and other reports and amendments filed with the Securities
and Exchange Commission are available free of charge on our web site at
www.abraxaspetroleum.com in the Investor Relations section as soon as
practicable after such reports are filed.
Item 2. Properties
Primary Operating Areas
Texas
Our operations are concentrated in South and West Texas with over 99%
of the PV-10 of our natural gas and crude oil properties at December 31, 2004
located in those two regions. We operate 94% of our wells in Texas. During 2004,
we drilled a total of 3 new wells (3 net) in Texas with a 66% success rate.
Operations in South Texas are concentrated along the Edwards trend in
Live Oak and DeWitt Counties, the Frio/Vicksburg trend in San Patricio County
and the Wilcox trend in Goliad County. In total in South Texas, we own an
average 93% working interest in 45 wells with average production of 217 net Bbls
of crude oil and 4,924 net Mcf of natural gas per day for the year ended
December 31, 2004. As of December 31, 2004 we had estimated net proved reserves
in South Texas of 27.8 Bcfe (82% natural gas) with a PV-10 of $59.2 million, 61%
of which was attributable to proved developed reserves.
Our West Texas operations are concentrated along the deep
Devonian/Montoya/Ellenberger formations and shallow Cherry Canyon sandstones in
Ward County and in the Sharon Ridge Clearfork Field in Scurry County. In
September 2000, we entered into a farmout agreement with EOG Resources Inc.
whereby EOG earned a 75% working interest in our then existing Ward County
Montoya acreage by paying us $2.5 million and paying 100% of the cost of the
first five wells, the last of which came on line in December 2002. Two wells
were drilled in 2003 in which we were responsible for our pro rata share of
drilling and development cost. The farmout agreement terminated in early January
2004 and accordingly, EOG has reassigned all unearned acreage to Abraxas.
In total in West Texas we own an average 74% working interest in 166
wells with average daily production of 375 net Bbls of crude oil and NGLs and
7,139 net Mcf of natural gas per day for the year ended December 31, 2004. As of
December 31, 2004, we had estimated net proved reserves in West Texas of 65.1
Bcfe (81% natural gas) with a PV-10 of $88.9 million, 45% of which was
attributable to proved developed reserves.
Wyoming
We currently hold 54,874 contiguous acres in the Powder River Basin in
east central Wyoming. We have drilled and operate 6 wells in Converse and
Niobrara counties that were completed in the Turner, Muddy and Niobrara
formations. We own a 100% working interest in these wells that produced an
average of 36 net barrels of crude oil per day in 2004. As of December 31, 2004
we had estimated net proved producing reserves in Wyoming of 137,345 barrels of
crude oil with a PV-10 of $992,217.
Exploratory and Developmental Acreage
Our principal natural gas and crude oil properties consist of
non-producing and producing natural gas and crude oil leases, including reserves
of natural gas and crude oil in place. The following table indicates our
interest in developed and undeveloped acreage applicable to continuing
operations as of December 31, 2004:
<TABLE>
<CAPTION>
Developed and Undeveloped Acreage
As of December 31, 2004
-----------------------------------------------------------------------
Developed Acreage (1) Undeveloped Acreage (2)
--------------------------------- -----------------------------------
Gross Acres (3) Net Acres (4) Gross Acres (3) Net Acres (4)
--------------- --------------- --------------- ------------------
<S> <C> <C> <C> <C>
Texas 23,866 19,218 14,521 11,161
18
<PAGE>
Wyoming 3,240 3,240 51,634 48,105
N. Dakota - - 80 24
--------------- --------------- --------------- ------------------
Total 27,106 22,458 66,235 59,290
=============== =============== =============== ==================
</TABLE>
(1) Developed acreage consists of acres spaced or assignable to productive
wells.
(2) Undeveloped acreage is considered to be those leased acres on which
wells have not been drilled or completed to a point that would permit
the production of commercial quantities of natural gas and crude oil,
regardless of whether or not such acreage contains proved reserves.
(3) Gross acres refers to the number of acres in which we own a working
interest.
(4) Net acres represents the number of acres attributable to an owner's
proportionate working interest and/or royalty interest in a lease
(e.g., a 50% working interest in a lease covering 320 acres is
equivalent to 160 net acres).
Productive Wells
The following table sets forth our total gross and net productive wells
applicable to continuing operations, expressed separately for natural gas and
crude oil, as of December 31, 2004:
<TABLE>
<CAPTION>
Productive Wells (1)
As of December 31, 2004
---------------------------------------------------------------------
State/Country Crude Oil Natural Gas
------------------ -------------------------------- ----------------------------------
Gross(2) Net(3) Gross(2) Net(3)
--------------- -------------- --------------- ----------------
<S> <C> <C> <C> <C>
Texas 145.0 116.6 66.0 48.8
Wyoming 6.0 6.0 18.0 -
N. Dakota - - 1.0 -
--------------- -------------- --------------- ----------------
Total 151.0 122.6 85.0 48.8
=============== ============== =============== ================
</TABLE>
(1) Productive wells are producing wells and wells capable of production.
(2) A gross well is a well in which we own an interest. The number of gross
wells is the total number of wells in which we own an interest.
(3) A net well is deemed to exist when the sum of fractional ownership
working interests in gross wells equals one. The number of net wells is
the sum of our fractional working interest owned in gross wells.
Reserves Information
The natural gas and crude oil reserves have been estimated as of
January 1, 2005, January 1, 2004, and January 1, 2003, by DeGolyer and
MacNaughton, of Dallas, Texas. Natural gas and crude oil reserves, and the
estimates of the present value of future net revenues there-from, were
determined based on then current prices and costs. Reserve calculations involve
the estimate of future net recoverable reserves of natural gas and crude oil and
the timing and amount of future net revenues to be received therefrom. Such
estimates are not precise and are based on assumptions regarding a variety of
factors, many of which are variable and uncertain.
The following table sets forth certain information regarding estimates
of our crude oil, natural gas liquids and natural gas reserves as of January 1,
2003, January 1, 2004 and January 1, 2005 relating to continuing operations.
<TABLE>
<CAPTION>
Estimated Proved Reserves
----------------------------------------------------------
Proved Proved Total
Developed Undeveloped Proved
-------------- --------------- ------------------
As of January 1, 2005
<S> <C> <C> <C>
Crude oil (MBbls) 1,878 1,223 3,101
NGLs (MBbls) - - -
Natural gas (MMcf) 36,241 38,877 75,118
19
<PAGE>
As of January 1, 2004
Crude oil (MBbls) 1,791 1,264 3,054
NGLs (MBbls) 95 170 265
Natural gas (MMcf) 39,371 40,831 80,202
As of January 1, 2003
Crude oil (MBbls) 1,646 1,317 2,963
NGLs (MBbls) 105 168 273
Natural gas (MMcf) 34,776 43,420 78,196
- ------------------
</TABLE>
The process of estimating crude oil and natural gas reserves is complex
and involves decisions and assumptions in the evaluation of available
geological, geophysical, engineering and economic data. Therefore, these
estimates are imprecise.
Actual future production, natural gas and crude oil prices, revenues,
taxes, development expenditures, operating expenses and quantities of
recoverable natural gas and crude oil reserves most likely will vary from those
estimated. Any significant variance could materially affect the estimated
quantities and present value of reserves set forth in this annual report. In
addition, we may adjust estimates of proved reserves to reflect production
history, results of exploitation and development, prevailing natural gas and
crude oil prices and other factors, many of which are beyond our control.
You should not assume that the present value of future net revenues
referred to in this annual statement is the current market value of our
estimated natural gas and crude oil reserves. In accordance with SEC
requirements, the estimated discounted future net cash flows from proved
reserves are generally based on prices and costs as of the end of the year of
the estimate, or alternatively, if prices subsequent to that date have
increased, a price near the periodic filing date of the Company's financial
statements. Because we use the full cost method to account for our natural gas
and crude oil operations, we are susceptible to significant non-cash charges
during times of volatile commodity prices because the full cost pool may be
impaired when prices are low. At June 30, 2002, we incurred a ceiling test
writedown of approximately $28.2 million. A ceiling test writedown does not
impact cash flow from operating activities but does reduce our stockholders'
equity and reported earnings. We cannot assure you that we will not experience
additional ceiling limitation write-downs in the future. For more information
regarding the full cost method of accounting, you should read the information
under "Management's Discussion and Analysis of Financial Condition and Results
of Operation - Critical Accounting Policies."
Actual future prices and costs may be materially higher or lower than
the prices and costs as of the end of the year of the estimate. Any changes in
consumption by natural gas purchasers or in governmental regulations or taxation
will also affect actual future net cash flows. The timing of both the production
and the expenses from the development and production of natural gas and crude
oil properties will affect the timing of actual future net cash flows from
proved reserves and their present value. In addition, the 10% discount factor,
which is required by the SEC to be used in calculating discounted future net
cash flows for reporting purposes, is not necessarily the most accurate discount
factor. The effective interest rate at various times and the risks associated
with us or the natural gas and crude oil industry in general will affect the
accuracy of the 10% discount factor.
The estimates of our reserves are based upon various assumptions about
future production levels, prices and costs that may not prove to be correct over
time. In particular, estimates of natural gas and crude oil reserves, future net
revenue from proved reserves and the PV-10 thereof for the natural gas and crude
oil properties described in this report are based on the assumption that future
natural gas and crude oil prices remain the same as natural gas and crude oil
prices at December 31, 2004. The average sales prices as of such date used for
purposes of such estimates were $41.01 per Bbl of crude oil and $4.94 per Mcf of
natural gas. It is also assumed that we will make future capital expenditures of
approximately $45.0 million in the aggregate, most of which is in the years 2005
through 2008, which are necessary to develop and realize the value of proved
20
<PAGE>
undeveloped reserves on our properties. Any significant variance in actual
results from these assumptions could also materially affect the estimated
quantity and value of reserves set forth herein.
We file reports of our estimated natural gas and crude oil reserves
with the Department of Energy and the Bureau of the Census. The reserves
reported to these agencies are required to be reported on a gross operated basis
and therefore are not comparable to the reserve data reported herein.
Crude Oil, Natural Gas Liquids, and Natural Gas Production and Sales Prices
The following table presents our net crude oil, net natural gas liquids
and net natural gas production, the average sales price per Bbl of crude oil and
natural gas liquids and per Mcf of natural gas produced and the average cost of
production per Mcfe of production sold, for the three years ended December 31,
2004 related to continuing operations:
<TABLE>
<CAPTION>
2002 2003 2004
--------------- -------------- ---------------
<S> <C> <C> <C>
Crude oil production (Bbls) 255,041 220,135 220,409
Natural gas production (Mcf) 5,471,589 4,780,739 4,403,030
Natural gas liquids production (Bbls) 8,970 9,439 8,875
Total production (Mmcfe) 7,056 6,158 5,779
Average sales price per Bbl of crude oil $ 24.34 $ 30.43 $ 40.12
Average sales price per Mcf of natural
gas (1) $ 2.65 $ 4.77 $ 5.45
Average sales price per Bbl of natural
gas liquids $ 14.43 $ 20.46 $ 26.32
Average sales price per Mcfe $ 2.95 $ 4.82 $ 5.72
Average cost of production per Mcfe
produced (2) $ 1.08 $ 1.35 $ 1.48
- ------------------
</TABLE>
(1) Average sales prices are net of hedging activity.
(2) Natural gas and crude oil were combined by converting crude oil and
natural gas liquids to a Mcf equivalent on the basis of 1 Bbl of crude
oil and natural gas liquid equals 6 Mcf of natural gas. Production
costs include direct operating costs, ad valorem taxes and gross
production taxes.
Drilling Activities
The following table sets forth our gross and net working interests in
exploratory and development wells drilled, related to continuing operations
during the three years ended December 31, 2004:
<TABLE>
<CAPTION>
2002 2003 2004
----------------------------- ----------------------------- -------------------------
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
------------ ---------- ------------ ---------- ---------- --------
Exploratory(3)
Productive(4)
<S> <C> <C> <C> <C>
Crude oil - - 1.0 1.0 2.0 2.0
Natural gas - - - - - -
Dry holes(5) - - - - - -
------------ ---------- ------------ ---------- ---------- --------
Total - - 1.0 1.0 2.0 2.0
============ ========== ============ ========== ========== ========
21
<PAGE>
Development(6)
Productive (4)
Crude oil - - - - - -
Natural gas 2.0 0.12 5.0 5.0 1.0 1.0
Dry holes (5) - - - - 1.0 1.0
------------ ---------- ------------ ---------- ---------- --------
Total 2.0 0.12 5.0 5.0 2.0 2.0
============ ========== ============ ========== ========== ========
- ------------------
</TABLE>
(1) A gross well is a well in which we own an interest.
(2) The number of net wells represents the total percentage of working
interests held in all wells (e.g., total working interest of 50% is
equivalent to 0.5 net well. A total working interest of 100% is
equivalent to 1.0 net well).
(3) An exploratory well is a well drilled to find and produce natural gas
or crude oil in an unproved area, to find a new reservoir in a field
previously found to be producing natural gas or crude oil in another
reservoir, or to extend a known reservoir.
(4) A productive well is an exploratory or a development well that is not a
dry hole.
(5) A dry hole is an exploratory or development well found to be incapable
of producing either natural gas or crude oil in sufficient quantities
to justify completion as a natural gas or crude oil well.
(6) A development well is a well drilled within the proved area of a
natural gas or crude oil reservoir to the depth of stratigraphic
horizon (rock layer or formation) noted to be productive for the
purpose of extracting proved natural gas or crude oil reserves.
As of March 18, 2005 we had 6 wells in process of drilling and/or
completing.
Office Facilities
Our executive and administrative offices are located at 500 North Loop
1604 East, Suite 100, San Antonio, Texas 78232, consisting of approximately
12,650 square feet leased until April 2006 at an aggregate base rate of $20,787
per month. We also have an office in Midland, Texas consisting of 570 square
feet leased through February 2006 at an aggregate base rate of $380 per month.
Other Properties
We own 10 acres of land, an office building, workshop, warehouse and
house in Sinton, Texas, 2.8 acres of land, an office building in Scurry County,
Texas, 600 acres of fee land in Scurry County, Texas and 160 acres of land in
Coke County, Texas. All of these properties are used for the storage of tubulars
and production equipment. We also own 23 vehicles which are used in the field by
employees. We own 2 workover rigs, which are used for servicing our wells.
Item 3. Legal Proceedings
In 2001, Abraxas and a limited partnership, of which Wamsutter
Holdings, Inc. is the general partner (the "Partnership"), were named in a
lawsuit filed in U.S. District Court in the District of Wyoming. The claim
asserted breach of contract, fraud and negligent misrepresentation by Abraxas
and the Partnership related to the responsibility for year 2000 ad valorem taxes
on crude oil and natural gas properties sold by Abraxas and the Partnership. In
February 2002, a summary judgment was granted to the plaintiff in this matter
and a final judgment in the amount of $1.3 million was entered. Abraxas and the
Partnership appealed the District Court's judgment and on November 3, 2004, the
U.S. Court of Appeals for the 10th Circuit affirmed the District Court's
decision. On December 14, 2004, the U.S. Court of Appeals for the 10th Circuit
entered a mandate for the District Court to enforce the judgment. As of December
27, 2004, the final judgment amount was approximately $1.55 million (which
includes accrued and unpaid interest since February 2002). Abraxas has decided
not to pursue further appeals and subsequent to December 31, 2004 has paid its
portion of the final judgment, approximately $1 million, for which Abraxas had
previously established a reserve.
22
<PAGE>
Additionally, from time to time, Abraxas is involved in litigation
relating to claims arising out of its operations in the normal course of
business. At December 31, 2004, Abraxas was not engaged in any legal proceedings
that are expected, individually or in the aggregate, to have a material adverse
effect on Abraxas.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted to a vote of our security holders during the
fourth quarter of the fiscal year ended December 31, 2004.
Item 4A. Executive Officers of Abraxas
Certain information is set forth below concerning our executive
officers, each of whom has been selected to serve until the 2005 annual meeting
of shareholders and until his successor is duly elected and qualified.
Robert L. G. Watson, age 54, has served as Chairman of the Board,
President, Chief Executive Officer and a director of Abraxas since 1977. Since
May 1996, Mr. Watson has also served as Chairman of the Board and a director of
Grey Wolf. Prior to joining Abraxas, Mr. Watson was employed in various
petroleum engineering positions with Tesoro Petroleum Corporation, a natural gas
and crude oil exploration and production company, from 1972 through 1977, and
DeGolyer and McNaughton, an independent petroleum engineering firm, from 1970 to
1972. Mr. Watson received a Bachelor of Science degree in Mechanical Engineering
from Southern Methodist University in 1972 and a Master of Business
Administration degree from the University of Texas at San Antonio in 1974.
Chris E. Williford, age 53, was elected Vice President, Treasurer and
Chief Financial Officer of Abraxas in January 1993, and as Executive Vice
President and a director of Abraxas in May 1993. In December 1999, Mr. Williford
resigned as a director of Abraxas. Prior to joining Abraxas, Mr. Williford was
Chief Financial Officer of American Natural Energy Corporation, a natural gas
and crude oil exploration and production company, from July 1989 to December
1992 and President of Clark Resources Corp., a natural gas and crude oil
exploration and production company, from January 1987 to May 1989. Mr. Williford
received a Bachelor of Science degree in Business Administration from Pittsburgh
State University in 1973.
Robert W. Carington, Jr., age 43, was elected Executive Vice President
and a director of Abraxas in July 1998. In December 1999, Mr. Carington resigned
as a director of Abraxas. Prior to joining Abraxas, Mr. Carington was a Managing
Director with Jefferies & Company, Inc. Prior to joining Jefferies & Company,
Inc. in January 1993, Mr. Carington was a Vice President at Howard, Weil,
Labouisse, Friedrichs, Inc. Prior to joining Howard, Weil, Labouisse,
Friedrichs, Inc., Mr. Carington was a petroleum engineer with Unocal Corporation
from 1983 to 1990. Mr. Carington received a degree of Bachelor of Science in
Mechanical Engineering from Rice University in 1983 and a Masters of Business
Administration from the University of Houston in 1990.
23
<PAGE>
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities
Market Information
Our common stock began trading on the American Stock Exchange on August
18, 2000, under the symbol "ABP." The following table sets forth certain
information as to the high and low bid quotations quoted for our common stock on
the American Stock Exchange.
Period High Low
2003
First Quarter $ 0.95 $ 0.55
Second Quarter 1.30 0.61
Third Quarter 1.11 0.82
Fourth Quarter 1.32 0.88
2004
First Quarter $ 3.64 $ 1.29
Second Quarter 2.89 1.50
Third Quarter 2.37 1.09
Fourth Quarter 2.99 1.91
2005 First Quarter (Through March 18, 2005) $ 2.92 $ 1.97
Holders
As of March 18, 2005, we had 36,813,758 shares of common stock
outstanding and had approximately 1600 stockholders of record.
Dividends
We have not paid any cash dividends on our common stock and it is not
presently determinable when, if ever, we will pay cash dividends in the future.
In addition, the indenture governing our Floating Rate Senior Secured Notes due
2009 and our senior credit agreement prohibits the payment of cash dividends and
stock dividends on our common stock. You should read the discussion under
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Liquidity and Capital Resources" for more information regarding the
restrictions on our ability to pay dividends.
Recent Sales of Unregistered Securities
As part of the October 2004 refinancing, we privately issued $125.0
million aggregate principal amount of Floating Rate Senior Secured Notes due
2009, Series A. On October 28, 2004, we sold the new notes to Guggenheim Capital
Markets, LLC, which subsequently resold the new notes under Rule 144A, Rule
501(a) and Regulation S of the Securities Act of 1933, as amended.
In connection with the October 2004 refinancing, Guggenheim Capital
Markets, LLC received warrants to purchase up to 1,000,000 shares of our common
stock at a purchase price of $0.01 per share pursuant to a Warrant entered into
on October 28, 2004 (the "GCM Warrant"). The GCM Warrant was issued to
Guggenheim pursuant to a private placement by us as an issuer under Section 4(2)
of the Securities Act of 1933. From and after October 28, 2004 and until 5:00
P.M., New York time, on October 28, 2014, the holder of the GCM Warrant may from
time to time exercise it, on any business day, for all or any part of the number
of shares of our common stock purchasable thereunder. In order to exercise the
GCM Warrant, in whole or in part, the holder must (i) deliver to us (x) a
written notice of the holder's election to exercise the GCM Warrant, which
notice shall be irrevocable and specify the number of shares of our common stock
to be purchased and (y) the GCM Warrant, and (ii) pay to us the warrant price.
The GCM Warrant permits payment upon exercise of the GCM Warrant to be made, at
24
<PAGE>
the option of the holder, by: (i) delivery of a certified or official bank check
in the amount of the warrant price; (ii) instructing us to withhold a number of
shares of warrant stock then issuable upon exercise of the GCM Warrant with an
aggregate fair value equal to the warrant price; or (iii) surrendering to us
shares of our common stock previously acquired by the holder with an aggregate
fair value equal to the warrant price. The GCM Warrant contains customary
restrictions on transfer and anti-dilution provisions, including dilution caused
by stock dividends, subdivisions, combinations, reorganizations,
reclassifications, mergers, consolidations or disposition of assets. Pursuant to
the GCM Warrant, we also agreed, in specified circumstances, to file a
registration statement to cover the warrant stock underlying the GCM warrant.
Durham Capital Corporation, also received a warrant to purchase up to
100,000 shares of our common stock at a purchase price of $0.01 per share (the
"Durham Warrant"), pursuant to a private placement by us as an issuer under
Section 4(2) of the Securities Act for advising us in connection with the
October 2004 refinancing. The Durham Warrant was exercised in November 2004.
We did not repurchase any of our registered equity securities in the
fourth quarter of 2004.
Item 6. Selected Financial Data
The following selected financial data is derived from our Consolidated
Financial Statements. The data should be read in conjunction with our
Consolidated Financial Statements and Notes thereto, and other financial
information included herein. See "Financial Statements" in Item 8.
51
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------------------------------------------
2000 2001 2002 2003 2004
---- ---- ---- ---- ----
(Dollars in thousands except per share data)
<S> <C> <C> <C> <C> <C>
Total revenue - continuing operations $ 32,886 $ 35,775 $ 21,541 $ 30,380 $ 33,854
Net income (loss) $ 8,449 (2) $ (19,718) (3) $ (118,527) (1) $ 55,920 (4) $ 11,167 (6)
Net income (loss) - discontinued
operations (3,985) (4,870) (63,355) 70,024 (4) 3,323
Net income (loss) - continuing
operations 12,434 (14,848) (55,172) (14,104) 7,844
Net income (loss) per common share -
diluted $ 0.26 $ (0.76) $ (3.95) $ 1.58 $ 0.29
Weighted average shares outstanding -
diluted (in thousands) 22,616 25,789 29,979 35,364 (5) 38,895
Total assets $ 335,560 $ 303,616 $ 181,425 $ 126,437 $ 152,685
Long-term debt, excluding current
maturities $ 207,081 $ 209,611 $ 201,850 $ 184,649 $ 126,425
Total stockholders' equity (deficit) $ (6,503) $ (28,585) $ (142,254) $ (72,203) $ (53,464)
</TABLE>
(1) Includes ceiling limitation write-down of $116.0 million ($28.2 million
related to continuing operations).
(2) Includes gain on sale of partnership interest of $34 million in 2000 and
the reclassification of an extraordinary gain on debt extinguishment in
2000 to other income.
(3) Includes ceiling test write-down of $2.6 million in 2001, based on
subsequent (March 22, 2002) realized prices, related to discontinued
operations.
(4) Includes gain on sale of foreign subsidiaries of $ 68.9 million in 2003.
(5) For the year ended December 31, 2003, 711,928 shares were excluded from the
calculation of diluted earnings per share since their inclusion would have
been antidilutive.
(6) Includes gain on debt extinguishment of $12.6 million and a deferred tax
benefit of $6.1 million.
25
<PAGE>
Item 7. Management's Discussion And Analysis Of Financial Condition And Results
Of Operations
Prior to February 2005, Grey Wolf Exploration Inc. was a wholly-owned
Canadian subsidiary of Abraxas. In February 2005, Grey Wolf , closed on an
initial public offering resulting in the substantial divestiture of our capital
stock in Grey Wolf. As a result of the Grey Wolf IPO, and the significant
divestiture of our interest in Grey Wolf, the results of operations of Grey Wolf
are reflected in our Financial Statements and in this document as "Discontinued
Operations" and our remaining operations are referred to in our Financial
Statements and in this document as "Continuing Operations" or "Continued
Operations". Unless otherwise noted, all disclosures are for continuing
operations.
The following is a discussion of our consolidated financial condition,
results of continuing operations, liquidity and capital resources. This
discussion should be read in conjunction with our Consolidated Financial
Statements and the Notes thereto. See "Financial Statements" in Item 8.
General
We are an independent energy company primarily engaged in the
development, and production of natural gas and crude oil. Historically we have
grown through the acquisition and subsequent development and exploitation of
producing properties, principally through the redevelopment of old fields
utilizing new technologies such as modern log analysis and reservoir modeling
techniques as well as 3-D seismic surveys and horizontal drilling. As a result
of these activities, we believe that we have a substantial inventory of low risk
development opportunities, which provide a basis for significant production and
reserve increases. In addition, we intend to expand upon our exploitation and
development activities with complementary low risk exploration projects in our
core areas of operation.
We have incurred net losses in two of the last five years, and there
can be no assurance that operating income and net earnings will be achieved in
future periods. Our financial results depend upon many factors which
significantly affect our results of operations including the following:
o the sales prices of natural gas, natural gas liquids and crude
oil ;
o the level of total sales volumes of natural gas, natural gas
liquids and crude oil;
o the availability of, and our ability to raise additional capital
resources and provide liquidity to meet cash flow needs;
o the level of and interest rates on borrowings; and
o the level and success of exploitation and development activity.
Commodity Prices and Hedging Activities. Our results of operations are
significantly affected by fluctuations in commodity prices. Price volatility in
the natural gas market has remained prevalent in the last few years. In January
2001, the market price of natural gas was at its highest level in our operating
history and the price of crude oil was also at a high level. However, over the
course of 2001 and the beginning of the first quarter of 2002, prices again
became depressed, primarily due to the economic downturn. Beginning in March
2002, commodity prices began to increase and continued higher through December
2004. Prices remained strong during 2004 and have continued to remain strong
during the beginning of 2005.
The table below illustrates how natural gas prices fluctuated during
2003 and 2004. The table below contains the last three day average of NYMEX
traded contracts price and the prices we realized during each quarter for 2003
and 2004, including the impact of our hedging activities.
<TABLE>
<CAPTION>
Natural Gas Prices by Quarter
(in $ per Mcf)
Quarter Ended
----------------------------------------------------------------------------------------------------------------
Mar. 31, June 30, Sept. 30, Dec. 31, Mar 31, June 30, Sept. 30 Dec. 31
2003 2003 2003 2003 2004 2004 2004 2004
---------- ---------- ----------- ---------- ---------- ---------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Index $6.61 $5.51 $5.10 $4.60 $5.69 $5.97 $5.85 $6.77
Realized $5.30 $5.05 $4.47 $4.29 $4.98 $5.52 $5.24 $6.14
</TABLE>
26
<PAGE>
The NYMEX natural gas price on March 18, 2005 was $7.27 per Mcf.
The table below contains the last three day average of NYMEX traded
contracts price and the prices we realized during each quarter for 2003 and
2004.
<TABLE>
<CAPTION>
Crude Oil Prices by Quarter
(in $ per Bbl)
Quarter Ended
----------------------------------------------------------------------------------------------------------------
Mar. 31, June 30, Sept. 30, Dec. 31, Mar 31, June 30, Sept. 30 Dec. 31
2003 2003 2003 2003 2004 2004 2004 2004
---------- ---------- ----------- ---------- ---------- ---------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Index $33.71 $29.87 $30.85 $29.64 $34.76 $38.48 $42.32 $49.46
Realized $33.36 $28.54 $29.55 $29.99 $34.18 $37.29 $42.43 $46.81
</TABLE>
The NYMEX crude oil price on March 18, 2005 was $56.72 per Bbl.
We seek to reduce our exposure to price volatility by hedging our
production through swaps, options and other commodity derivative instruments. In
2002 and 2003, we experienced hedging losses of $1.5 million and $842,000,
respectively. For the year ended December 31, 2004 we recognized a gain from
hedging activities of approximately $118,000.
Under the terms of our new revolving credit facility, we are required
to maintain hedging positions with respect to not less than 25% nor more than
75% of our natural gas and crude oil production, on an equivalent basis, for a
rolling six month period. As of December 31, 2004, we had the following hedges
in place:
<TABLE>
<CAPTION>
Time Period Notional Quantities Price
- ---------------------------------- -------------------------------------------- ----------------------
<S> <C> <C>
January 2005 7,100 MMbtu of production per day Floor of $4.50
400 Bbls of crude oil production per day Floor of $25.00
7,100 MMbtu of production per day Floor of $4.50
February 2005 400 Bbls of crude oil production per day Floor of $25.00
7,100 MMbtu of production per day Floor of $4.50
March 2005 400 Bbls of crude oil production per day Floor of $25.00
7,100 MMbtu of production per day Floor of $4.50
April 2005 400 Bbls of crude oil production per day Floor of $25.00
May - December 2005 9,500 MMbtu of production per day Floor of $5.00
</TABLE>
Production Volumes. Because our proved reserves will decline as natural
gas, natural gas liquids and crude oil are produced, unless we acquire
additional properties containing proved reserves or conduct successful
exploitation and development activities, our reserves and production will
decrease. Our ability to acquire or find additional reserves in the near future
will be dependent, in part, upon the amount of available funds for acquisition,
exploitation and development projects.
We had capital expenditures for 2004 of $9.3 million and anticipate
approximately $22.0 million, in 2005, which we expect will include the drilling
or recompletion of approximately 16 wells. Capital spending limitations that
existed under the terms of our prior senior credit agreement and our 11 1/2%
notes due 2007 were removed in connection with the refinancing that closed in
October 2004. As a result of the limitations, we were limited for most of 2004
in our ability to replace existing production with new production. If crude oil
27
<PAGE>
and natural gas prices return to depressed levels or if our production levels
continue to decrease, our revenues, cash flow from operations and financial
condition will be materially adversely affected.
Availability of Capital. As described more fully under "Liquidity and
Capital Resources" below, our sources of capital going forward will primarily be
cash from operating activities, funding under its new revolving credit facility,
cash on hand, and if an appropriate opportunity presents itself, proceeds from
the sale of properties. We currently have approximately $13.0 million of
availability under our new revolving credit facility.
Exploitation and Development Activity. We believe that our high quality
asset base, high degree of operational control and large inventory of drilling
projects position us for future growth. Our properties are concentrated in
locations that facilitate substantial economies of scale in drilling and
production operations and more efficient reservoir management practices. We
operate 94% of the properties accounting for approximately 95% of our PV-10,
giving us substantial control over the timing and incurrence of operating and
capital expenditures. In addition, we have 47 proved undeveloped locations and
have identified over 100 drilling and recompletion opportunities on our existing
acreage, the successful development of which we believe could significantly
increase our daily production and proved reserves.
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 exploitation activities or,
through engineering studies, identify additional behind-pipe zones or secondary
recovery reserves. We cannot assure you that our exploitation and development
activities will result in increases in our proved reserves. In addition,
approximately 49% of our total estimated proved reserves at December 31, 2004
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. For a more complete discussion of these
risks please see "Risk Factors--We may be unable to acquire or develop
additional reserves, in which case our results of operations and financial
condition would be adversely affected."
Borrowings and Interest. We currently have indebtedness of
approximately $127 million and availability of $13.0 million under the new
revolving credit facility. We paid interest under our 11 1/2% secured notes due
2007 by the issuance of additional notes, which caused our cash interest expense
to be $3.6 million during 2003 and $7.6 million during 2004. In connection with
the refinancing transactions completed in October 2004, interest on the new
notes will be paid in cash. This increase in cash interest expense will require
us to increase our production and cash flow from operations in order to meet our
debt service requirements, as well as to fund the development of our numerous
drilling opportunities.
Outlook for 2005. As a result of final 2004 financial results and
current market conditions, we have updated our operating and financial guidance
for year 2005 as follows:
Production:
BCFE (approximately 80% gas)....................... 6.5 - 7.5
Exit Rate (Mmcfe/d)................................... 19-21
Price Differentials (Pre Hedge):
$ Per Bbl.......................................... 0.55
$ Per Mcf.......................................... 0.75
Lifting Costs, $ Per Mcfe............................. 0.85
G&A, $ Per Mcfe....................................... 0.55
Capital Expenditures ($ Millions)..................... 22.0
Results of Operations
Selected Operating Data. The following table sets forth certain of our
operating data for the periods presented. All data has been restated to reflect
continuing operations.
28
<PAGE>
<TABLE>
<CAPTION>
Years Ended December 31,
---------------------------------------------------------------
(dollars in thousands, except per unit data)
2002 2003 2004
------------------- ------------------- -------------------
Operating revenue:
<S> <C> <C> <C>
Crude oil sales............................. $ 6,208 $ 6,699 $ 8,843
NGLs sales ................................. 130 193 234
Natural gas sales........................... 14,497 22,818 23,996
Rig and other............................... 706 670 781
------------------- ------------------- -------------------
Total operating revenues ................... $ 21,541 $ 30,380 $ 33,854
=================== =================== ===================
Operating income (loss)..................... $ (28,082) $ 8,720 $ 10,972
Crude oil production (MBbls)................ 255.0 220.1 220.4
NGLs production (MBbls)..................... 9.0 9.4 8.9
Natural gas production (MMcf)............... 5,471.6 4,780.7 4,403.0
Average crude oil sales price (per Bbl) $ 24.34 $ 30.43 $ 40.12
Average NGLs sales price (per Bbl) $ 14.43 $ 20.46 $ 26.32
Average natural gas sales price (per Mcf) $ 2.65 $ 4.77 $ 5.45
</TABLE>
Revenue and average sales prices are net of hedging activities.
Comparison of Year Ended December 31, 2004 to Year Ended December 31, 2003
Operating Revenue. During the year ended December 31, 2004, operating
revenue from crude oil, natural gas and natural gas liquids sales increased by
$3.4 million from $29.7 million in 2003 to $33.1 million in 2004. The increase
in revenue was primarily due to increased commodity prices realized in 2004 as
compared to 2003. The increase in revenue due to commodity prices was partially
offset by decreased production volumes. Higher commodity prices contributed $5.2
million to natural gas and crude oil revenue while reduced production volumes
had a $1.8 million negative impact on revenue.
Natural gas liquids volumes declined from 9.4 MBbls in 2003 to 8.9
MBbls in 2004. Crude oil sales volumes increased slightly from 220.1 MBbls in
2003 to 220.4 MBbls during 2004. The increase is primarily due to the production
from new wells in Wyoming and west Texas brought onto production in 2004,
offsetting natural field declines in other areas. Natural gas sales volumes
decreased from 4.8 Bcf in 2003 to 4.4 Bcf in 2004. This decrease is primarily
due to natural field declines. There were no significant wells brought on line
in 2004, primarily due to significant restrictions on capital expenditures for
most of the year.
Average sales prices in 2004 net of hedging costs were:
o $40.12 per Bbl of crude oil,
o $26.32 per Bbl of natural gas liquids, and
o $ 5.45 per Mcf of natural gas.
Average sales prices in 2003 net of hedging costs were:
o $30.43 per Bbl of crude oil,
o $20.46 per Bbl of natural gas liquids, and
o $ 4.77 per Mcf of natural gas.
Lease Operating Expense. Lease operating expense, or LOE, increased
slightly from $8.3 million in 2003 to $8.6 million in 2004. The increase in LOE
was primarily due to higher production taxes associated with higher commodity
prices in 2004 as compared to 2003. Our LOE on a per Mcfe basis for the year
29
<PAGE>
ended December 31, 2004 was $1.48 per Mcfe compared to $1.35 for 2003, primarily
due to the decrease in production volumes.
G&A Expense. G&A expense increased from $4.0 million in 2003 to $5.1
million in 2004. The increase in G&A expense was primarily due to performance
bonuses in 2004. Our G&A expense on a per Mcfe basis increased from $0.65 in
2003 to $0.89 in 2004. The increase in the per Mcfe cost was due to increased
expense and to lower production volumes in 2004 as compared to 2003.
Stock-based Compensation Expense. Effective July 1, 2000, the Financial
Accounting Standards Board ("FASB") issued FIN 44, "Accounting for Certain
Transactions Involving Stock Compensation", an interpretation of Accounting
Principles Board Opinion No. ("APB") 25. Under the interpretation, certain
modifications to fixed stock option awards, which were made subsequent to
December 15, 1998, and not exercised prior to July 1, 2000, require that the
awards be subject to variable accounting until they are exercised, forfeited, or
expired. In March 1999, we amended the exercise price to $2.06 on all options
with an existing exercise price greater than $2.06. In January 2003, we amended
the exercise price to $0.66 per share on certain options with an existing
exercise price greater than $0.66 per share which resulted in variable
accounting. We charged approximately $1.3 million to stock based compensation
expense in 2004 related to these repricings, compared to $1.1 million during
2003. The increase