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
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(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.
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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).
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ABRAXAS PETROLEUM CORPORATION
FORM 10-K
TABLE OF CONTENTS
PART I
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
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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
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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
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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.
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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
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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
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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;
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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
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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
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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
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
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
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
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
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
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:
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)
--------------- --------------- --------------- ------------------
Texas 23,866 19,218 14,521 11,161
18
Wyoming 3,240 3,240 51,634 48,105
N. Dakota - - 80 24
--------------- --------------- --------------- ------------------
Total 27,106 22,458 66,235 59,290
=============== =============== =============== ==================
(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:
Productive Wells (1)
As of December 31, 2004
---------------------------------------------------------------------
State/Country Crude Oil Natural Gas
------------------ -------------------------------- ----------------------------------
Gross(2) Net(3) Gross(2) Net(3)
--------------- -------------- --------------- ----------------
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
=============== ============== =============== ================
(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.
Estimated Proved Reserves
----------------------------------------------------------
Proved Proved Total
Developed Undeveloped Proved
-------------- --------------- ------------------
As of January 1, 2005
Crude oil (MBbls) 1,878 1,223 3,101
NGLs (MBbls) - - -
Natural gas (MMcf) 36,241 38,877 75,118
19
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
- ------------------
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
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:
2002 2003 2004
--------------- -------------- ---------------
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
- ------------------
(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:
2002 2003 2004
----------------------------- ----------------------------- -------------------------
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
------------ ---------- ------------ ---------- ---------- --------
Exploratory(3)
Productive(4)
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
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
============ ========== ============ ========== ========== ========
- ------------------
(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
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
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
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
Year Ended December 31,
--------------------------------------------------------------------------------
2000 2001 2002 2003 2004
---- ---- ---- ---- ----
(Dollars in thousands except per share data)
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)
(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
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.
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
---------- ---------- ----------- ---------- ---------- ---------- ---------- -----------
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
26
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.
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
---------- ---------- ----------- ---------- ---------- ---------- ---------- -----------
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
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:
Time Period Notional Quantities Price
- ---------------------------------- -------------------------------------------- ----------------------
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
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
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
Years Ended December 31,
---------------------------------------------------------------
(dollars in thousands, except per unit data)
2002 2003 2004
------------------- ------------------- -------------------
Operating revenue:
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
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
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 is due to the increase in the price of our common stock in
2004.
DD&A Expense. Depreciation, depletion and amortization expense
decreased from $7.6 million in 2003 to $7.2 million in 2004. The decrease in
DD&A was primarily due to decreased production volumes in 2004. Our DD&A expense
on a per Mcfe basis for 2004 was $1.25 per Mcfe as compared to $1.24 per Mcfe in
2003.
Interest Expense. Interest expense increased from $16.3 million to
$17.9 million for 2004 compared to 2003. The increase in interest expense was
due to increased debt levels in 2004, prior to the refinancing completed in
October 2004. The increase in debt was primarily due to the payment of interest
by the issuance of new notes related to the 11 1/2% notes due 2007.
Financing Cost. Financing cost in 2004 was $1.7 million compared to
$4.4 million in 2003. Financing cost represent costs related to refinancing
activities, which do not qualify for amortization over the life of the debt.
Financing costs in 2003 were related to the restructuring transaction, which
occurred in January 2003. The 2004 costs relate to the refinancing activities
during 2004.
Income from discontinued operations. Income from discontinued
operations was $3.3 million in 2004 compared to $70.0 million in 2003. This
represents income from our Canadian subsidiary, which was sold in February 2005.
Income in 2003 included a gain on the sale of foreign subsidiaries in January
2003 of $68.9 million. Excluding this gain, income in 2003 would have been $1.1
million. The increase in income in 2004, exclusive of the gain, was due to
increased production and higher commodity prices in 2004 as compared to 2003.
Comparison of Year Ended December 31, 2003 to Year Ended December 31, 2002
Operating Revenue. During the year ended December 31, 2003, operating
revenue from crude oil, natural gas and natural gas liquids sales increased by
$8.9 million from $20.8 million in 2002 to $29.7 million in 2003. The increase
in revenue was primarily due to increased commodity prices realized during 2003.
The increase in natural gas and crude oil revenue resulting from increased
prices was somewhat offset by decreased production volumes. Higher commodity
prices contributed $11.5 million to natural gas and crude oil revenue while
reduced production volumes had a $2.6 million negative impact on revenue.
Natural gas liquids volumes increased from 9.0 MBbls in 2002 to 9.4
MBbls in 2003. Crude oil sales volumes declined from 255.0 MBbls in 2002 to
220.1 MBbls during 2003. Crude oil production decreased due primarily to natural
field declines. Natural gas sales volumes decreased from 5.5 Bcf in 2002 to 4.8
Bcf in 2003. This decrease in production volumes was primarily due to natural
field declines and property sales in 2002. Limited drilling activity in 2002 and
2003 due to capital expenditure limitations also contributed to the decline in
production volumes.
30
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.
Average sales prices in 2002 net of hedging costs were:
o $24.34 per Bbl of crude oil,
o $14.43 per Bbl of natural gas liquids, and
o $ 2.65 per Mcf of natural gas.
Lease Operating Expense. Lease operating expense, or LOE, increased
from $7.6 million in 2002 to $8.3 million in 2003. The increase in LOE is
primarily due to higher production taxes associated with higher commodity prices
in 2003 as compared to 2002. Our LOE on a per Mcfe basis for the year ended
December 31, 2003 was $1.35 per Mcfe compared to $1.08 for 2002, primarily due
to the decrease in production volumes as well as the overall increase in
expense.
G&A Expense. General and administrative, or G&A, expense remained
constant at $4.0 million in 2002 and 2003. Our G&A expense on a per Mcfe basis
increased from $0.57 in 2002 to $0.65 in 2003. The increase in the per Mcfe cost
was due primarily to lower production volumes in 2003 as compared to 2002.
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 $1.1 million to stock based compensation
expense in 2003 related to these repricings. During 2002, we did not recognize
any stock-based compensation due to the decline in the price of our common
stock.
DD&A Expense. Depreciation, depletion and amortization expense
decreased by $1.6 million from $9.2 million in 2002 to $7.6 million in 2003. The
decrease in DD&A was primarily due to the ceiling limitation write-downs in the
second quarter of 2002, and decreased production volumes during 2003. Our DD&A
expense on a per Mcfe basis for 2003 was $1.24 per Mcfe as compared to $1.30 per
Mcfe in 2002.
Interest Expense. Interest expense decreased from $24.7 million to
$16.3 million for 2003 compared to 2002. The decrease in interest expense was
due to the reduction in debt in 2003. Total debt was reduced as a result of the
transactions which occurred on January 23, 2003. Total debt was $201.9 million
as of December 31, 2002 compared to $184.6 million at December 31, 2003.
Income from discontinued operations. Income from discontinued
operations was $70.0 million in 2003 compared to a loss of $63.4 million in
2002. This represents income from our Canadian subsidiary, which was sold in
February 2005. The loss in 2002 was primarily due to a ceiling limitation
writedown in that year of approximately $87.8 million offset by a deferred tax
benefit of $29.7 million. The income in 2003 was primarily due to a gain on the
sale of Canadian subsidiaries in January 2003 of $68.9 million.
Ceiling Limitation Write-down. We record the carrying value of our
natural gas and crude oil properties using the full cost method of accounting.
For more information on the full cost method of accounting, you should read the
description under "Critical Accounting Policies-- Full Cost Method of Accounting
for Natural gas and crude oil Activities". At June 30, 2002, our net capitalized
costs of natural gas and crude oil properties exceeded the present value of our
estimated proved reserves by $28.2 million. These amounts were calculated
considering June 30, 2002 prices of $26.12 per Bbl for crude oil and $2.16 per
31
Mcf for natural gas as adjusted to reflect the expected realized prices for each
of the full cost pools. At December 31, 2003 and 2004 our net capitalized cost
of natural gas and crude oil properties did not exceed the present value of our
estimated reserves, plus the cost of properties not being amortized and the
lower of cost of fair value of unproved properties being included in cost being
amortized, less related income taxes, due to increased commodity prices, as
such, no write-down was recorded in 2003 or 2004. We cannot assure you that we
will not experience additional ceiling limitation write-downs in the future.
The risk that we will be required to write-down the carrying value of
our natural gas and crude oil assets increases when natural gas and crude oil
prices are depressed or volatile. In addition, write-downs may occur if we have
substantial downward revisions in our estimated proved reserves or if purchasers
or governmental action cause an abrogation of, or if we voluntarily cancel,
long-term contracts for our natural gas. We cannot assure you that we will not
experience additional write-downs in the future. If commodity prices decline or
if any of our proved reserves are revised downward, a further write-down of the
carrying value of our natural gas and crude oil properties may be required.
Liquidity and Capital Resources
General. The natural gas and crude oil industry is a highly capital
intensive and cyclical business. Our capital requirements are driven principally
by our obligations to service debt and to fund the following costs:
o the development of existing properties, including drilling and
completion costs of wells;
o acquisition of interests in additional natural gas and crude oil
properties; and
o production and transportation facilities.
The amount of capital expenditures we are able to make has a direct impact on
our ability to increase cash flow from operations and, thereby, will directly
affect our ability to service our debt obligations and to continue to grow the
business through the development of existing properties and the acquisition of
new properties.
Our sources of capital going forward will primarily be cash from
operating activities, funding under our new revolving credit facility, cash on
hand, and if an appropriate opportunity presents itself, proceeds from the sale
of properties. However, under the terms of the notes, proceeds of optional sales
of our assets that are not timely reinvested in new natural gas and crude oil
assets will be required to be used to reduce indebtedness and proceeds of
mandatory sales must be used to repay or redeem indebtedness.
Working Capital (Deficit). The following discussion represents working
capital from continuing operations. At December 31, 2004 our current liabilities
of approximately $11.9 million exceeded our current assets of $8.0 million
resulting in a working capital deficit of $3.9 million. This compares to a
working capital deficit of $2.0 million as of December 31, 2003. Current
liabilities as of December 31, 2004 consisted of trade payables of $5.6 million,
revenues due third parties $2.4 million, accrued interest of $2.2 million and
other accrued liabilities of $ 1.6 million.
Capital Expenditures. Capital expenditures related to our continuing
operations in 2002, 2003 and 2004 were $5.1 million, $9.2 million and $9.3
million, respectively. The table below sets forth the components of these
capital expenditures for the three years ended December 31, 2004.
Year Ended December 31,
2002 2003 2004
------------------ ----------------- ---------------
(dollars in thousands)
Expenditure category:
Development $ 4,944 $ 9,158 $ 9,088
Facilities and other 126 36 181
------------------ ----------------- ----------------
Total $ 5,070 $ 9,194 $ 9,269
================== ================= ================
32
During 2002, 2003 and 2004, capital expenditures were primarily for the
development of existing properties. We anticipate making capital expenditures
for 2005 of approximately $22.0 million, which we expect will include
development activities related to approximately 16 projects. Our capital
expenditures could also include expenditures for acquisition of producing
properties if such opportunities arise, but we currently have no agreements,
arrangements or undertakings regarding any material acquisitions. We have no
material long-term capital commitments and are consequently able to adjust the
level of our expenditures as circumstances dictate. Additionally, the level of
capital expenditures will vary during future periods depending on market
conditions and other related economic factors. Should the prices of natural gas
and crude oil decline from current levels, our cash flows will decrease which
may result in a reduction of the capital expenditures budget. If we decrease our
capital expenditures budget, we may not be able to offset natural gas and crude
oil production volumes decreases caused by natural field declines and sales of
producing properties, if any.
Sources of Capital. The net funds provided by and/or used in each of
the operating, investing and financing activities, related to continuing
operations, are summarized in the following table and discussed in further
detail below:
2002 2003 2004
-------------- ------------- ------------
(dollars in thousands)
Net cash provided by operating activities $ 2,148 $ 11,479 $ 27,000
Net cash provided by (used in) investing activities 4,655 (9,194) (9,269)
Net cash used in financing activities (9,692) (88,652) (65,684)
-------------- ------------- ------------
Total $ (2,889) $ (86,367) $ (47,953)
============== ============= ============
Operating activities for the year ended December 31, 2004 provided us
with $27.0 million of cash. Expenditures in 2004 of approximately $9.3 were
primarily for the development of natural gas and crude oil properties. Financing
activities used $65.7 million during 2004, primarily for payments on long-term
debt and deferred financing fees.
Operating activities for the year ended December 31, 2003 provided us
with $11.5 million of cash. Investing activities used $9.2 million during 2003.
Financing activities used $88.7 million during 2003. Most of these funds were
used to reduce our long-term debt and were generated by the sale of our Canadian
subsidiaries and the exchange offer completed in January 2003. The sale of our
Canadian subsidiaries contributed $85.8 million in 2003 reduced by $9.2 million
in exploitation and development expenditures. Expenditures in 2003 were
primarily for the development of natural gas and crude oil properties.
Operating activities for the year ended December 31, 2002 provided us
$2.1 million of cash. Investing activities provided $4.7 million during 2002.
Our investing activities included the sale of properties which provided $9.8
million, and the use of $5.1 million primarily for the development of producing
properties. Financing activities used $9.7 million during 2002, relating
primarily to payments on long-term debt.
Future Capital Resources. We currently have four principal sources of
liquidity going forward: (i) cash from operating activities, (ii) funding under
our new revolving credit facility, (iii) cash on hand, and (iv) if an
appropriate opportunity presents itself, the sale of producing properties. While
we are no longer subject to the $10 million limitation on capital expenditures
under our 11 1/2% secured notes due 2007, covenants under the indenture for the
new notes and the new revolving credit facility restrict our use of cash from
operating activities, cash on hand and any proceeds from asset sales. Under the
terms of the notes, proceeds of optional sales of our assets that are not timely
reinvested in new natural gas and crude oil assets will be required to be used
to reduce indebtedness and proceeds of mandatory sales must be used to redeem
indebtedness. The terms of the notes and the new revolving credit facility also
substantially restrict our ability to:
o incur additional indebtedness;
o grant liens;
33
o pay dividends or make certain other restricted payments;
o merge or consolidate with any other person; or
o sell, assign, transfer, lease, convey or otherwise dispose of
all or substantially all of our assets.
Our cash flow from operations depends heavily on the prevailing prices
of natural gas and crude oil and our production volumes of natural gas and crude
oil. Significant downturns in commodity prices, such as that experienced in the
last nine months of 2001 and the first quarter of 2002, can reduce our cash flow
from operating activities. Although we have hedged a portion of our natural gas
and crude oil production and will continue this practice as required pursuant to
the new revolving credit facility, future natural gas and crude oil price
declines would have a material adverse effect on our overall results, and
therefore, our liquidity. Low natural gas and crude oil prices could also
negatively affect our ability to raise capital on terms favorable to us.
Our cash flow from operations will also depend upon the volume of
natural gas and crude oil that we produce. Unless we otherwise expand reserves,
our production volumes will decline as reserves are produced. Due to sales of
properties in 2002 and January 2003, and restrictions on capital expenditures
under the terms of our old notes, we now have significantly reduced reserves and
production as compared with pre-2003 levels. In the future, if an appropriate
opportunity presents itself, we may sell additional properties, which could
further reduce our production volumes. To offset the loss in production volumes
resulting from natural field declines and sales of producing properties, we must
conduct successful, exploitation and development activities, acquire additional
producing properties or identify additional behind-pipe zones or secondary
recovery reserves. While we have had some success in primarily pursuing these
activities since January 1, 2003, we have not been able to fully replace the
production volumes lost from natural field declines and property sales. We
believe our numerous drilling opportunities will allow us to increase our
production volumes; however, our drilling activities are subject to numerous
risks, including the risk that no commercially productive natural gas or crude
oil reservoirs will be found. The risk of not finding commercially productive
reservoirs will be compounded by the fact that 49% of our total estimated proved
reserves at December 31, 2004 were undeveloped. If the volume of natural gas and
crude oil we produce decreases, our cash flow from operations will decrease.
Our total indebtedness and cash interest expense as a result of issuing
the new notes and entering into the new revolving credit facility require us to
increase our production and cash flow from operations in order to meet our debt
service requirements, as well as to fund the development of our numerous
drilling opportunities. The ability to satisfy these new obligations will depend
upon our drilling success as well as prevailing commodity prices.
Contractual Obligations. We are committed to making cash payments in
the future on the following types of agreements:
o Long-term debt
o Operating leases for office facilities
We have no off-balance sheet debt or unrecorded obligations and we have not
guaranteed the debt of any other party. Below is a schedule of the future
payments that we are obligated to make based on agreements in place as of
December 31, 2004.
Contractual Obligations Payments due in:
(dollars in thousands)
--------------------------- --------------------------------------------------------------------------
Total Less than More than 5
one year 1-3 years 3-5 years years
- ----------------------------- --------------- ------------- ------------- ------------- ---------------
Long-Term Debt (1) $ 126,425 $ - $ - $ 1,425 $ 125,000
Operating Leases (2) 338 254 84 - -
34
(1) These amounts represent the balances outstanding under Floating Rate Senior
Secured Notes due 2009 and the new credit facility. These repayments assume
that interest will be will be paid on an as due and that we will not draw
down additional funds thereunder.
(2) These amounts represent office lease obligations, expiring in 2006.
Contingencies. 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 natural gas and crude oil 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 has paid its portion of the final judgment,
approximately $1 million, for which Abraxas had previously established a
reserve.
Other obligations. We make and will continue to make substantial
capital expenditures for the acquisition, exploitation development and
production of crude oil and natural gas. In the past, we have funded our
operations and capital expenditures primarily through cash flow from operations,
sales of properties, sales of production payments and borrowings under our bank
credit facilities and other sources. Given our high degree of operating control,
the timing and incurrence of operating and capital expenditures is largely
within our discretion.
Long-Term Indebtedness. The financial restructuring completed in
October 2004 resulted in the redemption of our 11 1/2% secured notes due 2007
and terminating our previous senior credit facility with the proceeds from:
o the issuance of $125 million aggregate principal amount of
floating rate senior secured notes due 2009;
o the proceeds from our $25 million bridge loan; and
o the payment to us by Grey Wolf of $35 million from the proceeds
of Grey Wolf's $35 million term loan.
In connection with the Grey Wolf IPO completed in February 2005, 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 shares offered by Abraxas were used to reduce the amount outstanding
under its bridge loan to approximately $5.4 million.
On March 24, 2005, the Company was 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 the
Company's revolving credit facility to, effectively, zero.
The following table sets forth our long-term indebtedness as of December 31,
2003 and 2004
35
Long Term Indebtedness
December 31,
--------------------------------
2003 2004
----------------- --------------
(in thousands)
11 1/2% secured notes due 2007 .................................... $ 137,258 $ -
Senior credit agreement .......................................... 47,391 -
Floating rate senior secured notes due 2009........................ - 125,000
Senior secured revolving credit facility........................... - 1,425
----------------- ---------------
184,649 126,425
Less current maturities ........................................... - -
----------------- ---------------
$ 184,649 $ 126,425
================= ===============
Floating Rate Senior Secured Notes due 2009. In connection with the
October 2004 financial restructuring, Abraxas issued $125 million in principal
aggregate amount of Floating Rate Senior Secured Notes due 2009. The new notes
will mature on December 1, 2009 and began accruing interest from the date of
issuance, October 28, 2004 at a per annum floating rate of six-month LIBOR plus
7.50%. The initial interest rate on the new notes is 9.72% per annum. The
interest will be reset semi-annually on each June 1 and December 1, commencing
on June 1, 2005. Interest is payable semi-annually in arrears on June 1 and
December 1 of each year, commencing on June 1, 2005.
The new notes rank equally among themselves and with all of our
unsubordinated and unsecured indebtedness, including our new credit facility and
senior in right of payment to our existing and future subordinated indebtedness,
including the bridge loan.
Each of our subsidiaries, Eastside Coal Company, Inc., Sandia Oil & Gas
Corporation, Sandia Operating Corp., Wamsutter Holdings, Inc. and Western
Associated Energy Corporation (collectively, the "Subsidiary Guarantors"), has
unconditionally guaranteed, jointly and severally, the payment of the principal,
premium and interest including any additional interest) on, the new notes on a
senior secured basis. In addition, any other subsidiary or affiliate of ours,
that in the future guarantees any other indebtedness with us, or our restricted
subsidiaries, will also be required to guarantee the new notes.
The new notes and the Subsidiary Guarantors' guarantees thereof,
together with our new credit facility and the Subsidiary Guarantors' guarantees
thereof, are secured by shared first priority perfected security interests,
subject to certain permitted encumbrances, in all of our and each of our
restricted subsidiaries' material property and assets, including substantially
all of our and their natural gas and crude oil properties and all of the capital
stock (or in the case of an unrestricted subsidiary that is a controlled foreign
corporation, up to 65% of the outstanding capital stock) of any entity, owned by
us and our restricted subsidiaries (collectively, the "Collateral").
After April 28, 2007, we may redeem all or a portion of the new notes
at the redemption prices set forth in the indenture with U.S. Bank National
Association under which the new notes were issued, plus accrued and unpaid
interest to the date of redemption. Prior to that date, we may redeem up to 35%
of the aggregate original principal amount of the new notes using the net
proceeds of one or more equity offerings, in each case at the redemption price
equal to the product of (i) the principal amount of the new notes being so
redeemed and (ii) a redemption price factor of 1.00 plus the per annum interest
rate on the new notes (expressed as a decimal) on the applicable redemption date
plus accrued and unpaid interest to the applicable redemption date, provided
certain conditions are also met.
If we experience specific kinds of change of control events, each
holder of new notes may require us to repurchase all or any portion of such
holder's new notes at a purchase price equal to 101% of the principal amount of
the new notes, plus accrued and unpaid interest to the date of repurchase.
The indenture governing the new notes contains covenants that, among
other things, limit our ability to:
o incur or guarantee additional indebtedness and issue certain
types of preferred stock or redeemable stock;
36
o transfer or sell assets;
o create liens on assets;
o pay dividends or make other distributions on capital stock or
make other restricted payments, including repurchasing,
redeeming or retiring capital stock or subordinated debt or
making certain investments or acquisitions;
o engage in transactions with affiliates;
o guarantee other indebtedness;
o permit restrictions on the ability of our subsidiaries to
distribute or lend money to us;
o cause a restricted subsidiary to issue or sell its capital
stock; and
o consolidate, merge or transfer all or substantially all of the
consolidated assets of our and our restricted subsidiaries.
The indenture also contains customary events of default, including
nonpayment of principal or interest, violations of covenants, cross default and
cross acceleration to certain other indebtedness, including our new credit
facility and bridge loan, bankruptcy, and material judgments and liabilities.
Senior Secured Revolving Credit Facility. On October 28, 2004, we
entered into an agreement for a new revolving credit facility having a maximum
commitment of $15 million, which includes a $2.5 million subfacility for letters
of credit. Availability under the new revolving credit facility is subject to a
borrowing base consistent with normal and customary natural gas and crude oil
lending transactions.
Outstanding amounts under the new revolving 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
stated maturity date under the new revolving credit facility is October 28,
2008.
We are permitted to terminate the new revolving credit facility, and
under certain circumstances, may be required, from time to time, to permanently
reduce the lenders' aggregate commitment under the new revolving credit
facility. Such termination and each such reduction is subject to a premium equal
to the percentage listed below multiplied by the lenders' aggregate commitment
under the new revolving credit facility, or, in the case of partial reduction,
the amount of such reduction.
Year % Premium
-------------- --------------------
1 1.5
2 1.0
3 0.5
4 0.0
Each of our current subsidiaries has guaranteed, and each of our future
restricted subsidiaries will guarantee, our obligations under the new revolving
credit facility on a senior secured basis. In addition, any other subsidiary or
affiliate of ours, that in the future guarantees any of our other indebtedness
or of its restricted subsidiaries will be required to guarantee our obligations
under the new revolving credit facility. Obligations under the new revolving
credit facility are secured, together with the new notes, by a shared first
priority perfected security interest, subject to certain permitted encumbrances,
in all of our and each of our restricted subsidiaries' material property and
assets, including substantially all of our and their natural gas and crude oil
properties and all of the capital stock (or in the case of an unrestricted
subsidiary that is a controlled foreign corporation, up to 65% of the
outstanding capital stock) in any entity, owned by us and our restricted
subsidiaries.
37
Under the new revolving credit facility, we are subject to customary
covenants, including certain financial covenants and reporting requirements. The
new revolving credit facility requires us to maintain a minimum net cash
interest coverage and also requires us to enter into hedging agreements on not
less than 25% or more than 75% of our projected natural gas and crude oil
production.
In addition to the foregoing and other customary covenants, the new
revolving credit facility contains a number of covenants that, among other
things, restrict Abraxas' ability to:
o incur or guarantee additional indebtedness and issue certain
types of preferred stock or redeemable stock;
o transfer or sell assets;
o create liens on assets;
o pay dividends or make other distributions on capital stock or
make other restricted payments, including repurchasing,
redeeming or retiring capital stock or subordinated debt or
making certain investments or acquisitions;
o engage in transactions with affiliates;
o guarantee other indebtedness;
o make any change in the principal nature of our business;
o prepay, redeem, purchase or otherwise acquire any of our or our
restricted subsidiaries' indebtedness;
o permit a change of control;
o directly or indirectly make or acquire any investment;
o cause a restricted subsidiary to issue or sell our capital
stock; and
o consolidate, merge or transfer all or substantially all of the
consolidated assets of Abraxas and our restricted subsidiaries.
The new revolving credit facility also contains customary events of
default, including nonpayment of principal or interest, violations of covenants,
cross default and cross acceleration to certain other indebtedness, bankruptcy
and material judgments and liabilities, and is subject to an Intercreditor,
Security and Collateral Agency Agreement, which specifies the rights of the
parties thereto to the proceeds from the Collateral.
Abraxas' New $25 Million Second Lien Increasing Rate Bridge Loan. On
October 28, 2004, Abraxas borrowed $25 million under its new bridge loan.
Interest on the bridge loan currently accrues at a rate of 12.0% per
annum until October 28, 2005, and is payable monthly in cash. Interest on the
bridge loan will thereafter accrue at a rate of 15.0% per annum, and will be
payable in-kind. Subject to earlier termination rights and events of default,
the stated maturity date under the bridge loan is October 28, 2010.
The bridge loan is classified as liabilities related to assets held for
sale in this document, and was substantially repaid subsequent to December 31,
2004.
Intercreditor Agreement. The holders of the new notes, together with
the lenders under our new credit facility and bridge loan, are subject to an
Intercreditor, Security and Collateral Agency Agreement, which specifies the
rights of the parties thereto to the proceeds from the Collateral. The
38
Intercreditor Agreement, among other things, (i) creates security interests in
the Collateral in favor of a collateral agent for the benefit of the holders of
the new notes, the new credit facility lenders and the bridge loan lenders and
(ii) governs the priority of payments among such parties upon notice of an event
of default under the Indenture, the new credit facility or the bridge loan.
So long as no such event of default exists, the collateral agent will
not collect payments under the new credit facility documents, the indenture
governing the new notes and other new note documents or the bridge loan
documents (collectively, the "Secured Documents"), and all payments will be made
directly to the respective creditor under the applicable Secured Document. Upon
notice of such an event of default and for so long as an event of default
exists, payments to each new credit facility lender, holder of the new notes and
bridge loan lender from us and our current subsidiaries, other than Grey Wolf,
and proceeds from any disposition of any collateral, will, subject to limited
exceptions, be collected by the collateral agent for deposit into a collateral
account and then distributed as provided in the following paragraph, provided,
that, any payment made with proceeds from the sale or other disposition of Grey
Wolf stock will be applied exclusively to pay amounts with respect to the bridge
loan, and no such proceeds will be deposited into the collateral account or will
be subject to the payment priority described in the following paragraph.
Upon notice of any such event of default and so long as an event of
default exists, funds in the collateral account will be distributed by the
collateral agent generally in the following order of priority:
first, to reimburse the collateral agent for expenses incurred in
protecting and realizing upon the value of the Collateral;
second, to reimburse the new credit facility administrative agent, the
trustee and the bridge loan administrative agent, on a pro rata basis, for
expenses incurred in protecting and realizing upon the value of the Collateral
while any of these parties was acting on behalf of the Control Party (as defined
below);
third, to reimburse the new credit facility administrative agent, the
trustee and the bridge loan administrative agent, on a pro rata basis, for
expenses incurred in protecting and realizing upon the value of the Collateral
while any of these parties was not acting on behalf of the Control Party;
fourth, to pay all accrued and unpaid interest (and then any unpaid
commitment fees) under the new credit facility;
fifth, if, the collateral coverage value of three times the outstanding
obligations under the new credit facility would be met after giving effect to
any payment under this clause "fifth," to pay all accrued and unpaid interest on
the new notes;
sixth, to pay all outstanding principal of (and then any other unpaid
amounts, including, without limitation, any fees, expenses, premiums and
reimbursement obligations) the new credit facility;
seventh, to pay all accrued and unpaid interest on the new notes (if
not paid under clause "fifth");
eighth, to pay all outstanding principal of (and then any other unpaid
amounts, including, without limitation, any premium with respect to) the new
notes;
ninth, to pay the bridge loan lenders all accrued and unpaid interest
under the bridge loan;
tenth, to pay all outstanding principal of (and then any other unpaid
amounts, including, without limitation, any premium with respect to) the bridge
loan; and
eleventh, to pay each new credit facility lender, holder of the new
notes, bridge loan lender and other secured party, on a pro rata basis, all
other amounts outstanding under the new credit facility, the new notes and the
bridge loan.
To the extent there exists any excess monies or property in the
collateral account after all obligations ours and our subsidiaries', other than
Grey Wolf, under the new credit facility, the indenture and the new notes and
39
the bridge loan are paid in full, the collateral agent will be required to
return such excess to us.
The collateral agent will act in accordance with the Intercreditor
Agreement and as directed by the "Control Party". Prior to the occurrence of any
such event of default, the "Control Party" will be the holders of the new notes
and the new credit facility lenders, acting as a single class, by vote of the
holders of a majority of the aggregate principal amount of outstanding
obligations under the new notes and the new credit facility. Upon notice of any
such event of default, the bridge loan lenders will be the Control Party for 240
days following such notice. If a stay under the Bankruptcy Code occurs during
such 240-day period, that period will be extended by the number of days during
which that stay was effective. If the new credit facility lenders and holders of
the new notes have not been paid in full by the end of such specified period,
they will become the Control Party, acting as a single class, by vote of the
holders of a majority of the aggregate principal amount of outstanding
obligations under the new notes and the new credit facility.
The Intercreditor Agreement provides that the lien on the assets
constituting part of the Collateral that is sold or otherwise disposed of in
accordance with the terms of each Secured Document may be released if (i) no
default or event of default exists under any of the Secured Documents, (ii) we
have delivered an officers' certificate to each of the collateral agent, the
trustee, the new credit facility administrative agent and the bridge loan
administrative agent, certifying that the proposed sale or other disposition of
assets is either permitted or required by, and is in accordance with the
provisions of, the applicable Secured Documents and (iii) the collateral agent
has acknowledged such certificate.
The Intercreditor Agreement provides for the termination of security
interests on the date that all obligations under the Secured Documents are paid
in full.
The Grey Wolf term loan was paid in full in February 2005 with the
proceeds of the Grey Wolf IPO. This loan is included in Liabilities related to
assets held for sale in the accompanying financial statements.
Hedging Activities
Our results of operations are significantly affected by fluctuations in
commodity prices and we seek to reduce our exposure to price volatility by
hedging our production through swaps, options and other commodity derivative
instruments. Under our new revolving credit facility, we are required to
maintain hedge positions on not less than 25% or more than 75% of our projected
oil and gas production for a six month rolling period. See "--Quantitative and
Qualitative Disclosures about Market Risk--Hedging Sensitivity" for further
information.
Net Operating Loss Carryforwards
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.
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.
40
Related Party Transactions
Accounts receivable - Other in the consolidated balance sheets includes
approximately $35,558 and $ 0 as of December 31, 2003 and 2004, respectively,
representing amounts due from officers relating to advances made to employees.
Abraxas has adopted a policy that transactions between Abraxas and its
officers, directors, principal stockholders, or affiliates of any of them, will
be on terms no less favorable to Abraxas than can be obtained on an arm's length
basis in transactions with third parties and must be approved by the vote of at
least a majority of the disinterested directors.
Critical Accounting Policies
The preparation of financial statements in conformity with generally
accepted accounting principles requires that management apply accounting
policies and make estimates and assumptions that affect results of operations
and the reported amounts of assets and liabilities in the financial statements.
The following represents those policies that management believes are
particularly important to the financial statements and that require the use of
estimates and assumptions to describe matters that are inherently uncertain.
Full Cost Method of Accounting for Natural gas and crude oil
Activities. SEC Regulation S-X defines the financial accounting and reporting
standards for companies engaged in natural gas and crude oil activities. Two
methods are prescribed: the successful efforts method and the full cost method.
We have chosen to follow the full cost method under which all costs associated
with property acquisition, exploitation and development are capitalized. We also
capitalize internal costs that can be directly identified with our acquisition,
exploitation and development activities and do not include any costs related to
production, general corporate overhead or similar activities. Under the
successful efforts method, geological and geophysical costs and costs of
carrying and retaining undeveloped properties are charged to expense as
incurred. Costs of drilling exploratory wells that do not result in proved
reserves are charged to expense. Depreciation, depletion, amortization and
impairment of natural gas and crude oil properties are generally calculated on a
well by well or lease or field basis versus the "full cost" pool basis.
Additionally, gain or loss is generally recognized on all sales of natural gas
and crude oil properties under the successful efforts method. As a result our
financial statements will differ from companies that apply the successful
efforts method since we will generally reflect a higher level of capitalized
costs as well as a higher depreciation, depletion and amortization rate on our
natural gas and crude oil properties.
At the time it was adopted, management believed that the full cost
method would be preferable, as earnings tend to be less volatile than under the
successful efforts method. However, the full cost method makes us susceptible to
significant non-cash charges during times of volatile commodity prices because
the full cost pool may be impaired when prices are low. These charges are not
recoverable when prices return to higher levels. We have experienced this
situation several times over the years, most recently in 2002. Our natural gas
and crude oil reserves have a relatively long life. However, temporary drops in
commodity prices can have a material impact on our business including impact
from the full cost method of accounting.
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%, plus the lower of cost or fair market value of unproved
properties and the cost of properties not being amortized, less income taxes. 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 reported
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 depressed or volatile. In addition, write-downs may occur if we
experience substantial downward adjustments to our estimated proved reserves or
if purchasers cancel long-term contracts for our natural gas production. 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.
41
For the year ended December 31, 2002, we recorded a write-down of
approximately $28.2 million related to continuing operations. The write-down in
2002 was due to low commodity prices. We cannot assure you that we will not
experience additional write-downs in the future.
Estimates of Proved Natural Gas and Crude Oil Reserves. Estimates of
our proved reserves included in this report are prepared in accordance with GAAP
and SEC guidelines. The accuracy of a reserve estimate is a function of:
o the quality and quantity of available data;
o the interpretation of that data;
o the accuracy of various mandated economic assumptions;
o and the judgment of the persons preparing the estimate.
Our proved reserve information included in this report was based on
evaluations prepared by independent petroleum engineers. Estimates prepared by
other third parties may be higher or lower than those included herein. Because
these estimates depend on many assumptions, all of which may substantially
differ from future actual results, reserve estimates will be different from the
quantities of oil and gas that are ultimately recovered. In addition, results of
drilling, testing and production after the date of an estimate may justify
material revisions to the estimate.
You should not assume that the present value of future net cash flows
is the current market value of our estimated proved reserves. In accordance with
SEC requirements, we based the estimated discounted future net cash flows from
proved reserves on prices and costs on the date of the estimate. Actual future
prices and costs may be materially higher or lower than the prices and costs as
of the date of the estimate.
The estimates of proved reserves materially impact DD&A expense. If the
estimates of proved reserves decline, the rate at which we record DD&A expense
will increase, reducing future net income. Such a decline may result from lower
market prices, which may make it uneconomic to drill for and produce higher cost
fields.
Asset Retirement Obligations The estimated costs of restoration and
removal of facilities are accrued. The fair value of a liability for an asset's
retirement obligation is recorded in the period in which it is incurred and the
corresponding cost capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its then present value each
period, and the capitalized cost is depreciated over the useful life of the
related asset. For all periods presented, we have included estimated future
costs of abandonment and dismantlement in our full cost amortization base and
amortize these costs as a component of our depletion expense.
Hedge Accounting. From time to time, we use commodity price hedges to
limit our exposure to fluctuations in natural gas and crude oil prices. Results
of those hedging transactions are reflected in natural gas and crude oil sales.
Statement of Financial Accounting Standards, ("SFAS") No. 133,
"Accounting for Derivative Instruments and Hedging Activities," was effective
for us on January 1, 2001. SFAS 133, as amended and interpreted, establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities.
In 2003 we elected out of hedge accounting as prescribed by SFAS 133.
Accordingly all derivatives, whether designated in hedging relationships or not,
are required to be recorded at fair value on our balance sheet. Changes in fair
value of contracts are recognized in earnings in the current period.
Due to the volatility of natural gas and crude oil prices and, to a lesser
extent, interest rates, our financial condition and results of operations can be
significantly impacted by changes in the market value of our derivative
instruments. As of December 31, 2003 and 2004 the net market value of our
derivatives was an asset of $21,136 and $528,165 respectively.
42
New Accounting Pronouncements
In November 2004 , the FASB issued SFAS No. 151, entitled " Inventory
Costs - an amendment of ARB 43, chapter. The purpose of this statement is to
clarify the accounting for abnormal amounts of idle facilities expense, freight,
handling cost and wasted material. This statement is effective for inventory
costs incurred during fiscal years beginning after June 15, 2005. We are
evaluating the effect of this statement on our operations and do not expect it
to impact our financial statements.
In December 2004 the FASB issued "Summary of Statement No. 123 (revised
2004), Share-Based Payment. This statement addresses the accounting for
share-based payment transactions in which an enterprise receives employee
services in exchange for: (1) equity instruments of the enterprise or (2)
liabilities that are based on the fair value of the enterprise's equity
instruments or that may be settled by the issuance of such equity instruments.
The proposed statement would eliminate the ability to account for share-based
compensation transactions using APB Opinion No. 25, "Accounting for Stock Issued
to Employees" and generally would require instead that such transactions be
accounted for using a fair value-based method. As proposed, this statement is be
effective as of the beginning of the first interim or annual reporting period
that begins after June 15, 2005. We are currently evaluating what effect this
statement will have on our financial position or results of operations.
In December 2004 the FASB issued FASB No. 153, entitled " Exchanges of
Nonmonetary Assets - an amendment of ABP Opinion No. 29". The guidance in ABP
Opinion No. 29 is based on the principle that exchanges of nonmonetary assets
should be measured based on the fair value of the assets exchanged. The guidance
in that Opinion, however, included certain exceptions to that principle. This
statement amends Opinion 29 to eliminate the exception for nonmonetary of
similar productive assets and replaces it with a general exception for exchanges
of nonmonetary assets that do not have commercial substance. A nonmonetary
exchange has commercial substance if the future cash flows of the entity are
expected to change significantly as a result of the exchange. The statement is
effective for nonmonetary exchanges occurring in fiscal periods beginning after
June 15, 2005. We do not anticipate this statement impacting our financial
statements.
In September 2004, the Securities and Exchange Commission issued "Staff
Accounting Bulletin No. 106" (SAB No. 106). SAB No. 106 applies to companies
using the full cost method of accounting for oil and gas properties and
equipment costs. SAB No. 106 affects the way in which companies calculate their
full cost ceiling limitation (including asset retirement cost related to proved
developed properties in the calculation of the ceiling) and the way companies
calculate depletion on oil and gas properties (only asset retirement cost for
new recompletions and new wells will be included in future development costs in
calculating depletion rates). The Company does not anticipate that adoption of
SAB No 106 will have a significant inpact on its financial position or results
of operations.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Commodity Price Risk
As an independent natural gas and crude oil producer, our revenue, cash
flow from operations, other income and equity earnings and profitability,
reserve values, access to capital and future rate of growth are substantially
dependent upon the prevailing prices of crude oil, natural gas and natural gas
liquids. Declines in commodity prices will materially adversely affect our
financial condition, liquidity, ability to obtain financing and operating
results. Lower commodity prices may reduce the amount of natural gas and crude
oil that we can produce economically. Prevailing prices for such commodities are
subject to wide fluctuation in response to relatively minor changes in supply
and demand and a variety of additional factors beyond our control, such as
global political and economic conditions. Historically, prices received for
natural gas and crude oil production have been volatile and unpredictable, and
such volatility is expected to continue. Most of our production is sold at
market prices. Generally, if the commodity indexes fall, the price that we
receive for our production will also decline. Therefore, the amount of revenue
that we realize is partially determined by factors beyond our control. Assuming
the production levels we attained during the year ended December 31, 2004, a 10%
43
decline in crude oil, natural gas and natural gas liquids prices would have
reduced our operating revenue and cash flow by approximately $3.3 million for
the year.
Hedging Sensitivity
On January 1, 2001, we adopted SFAS 133 as amended by SFAS 137 and SFAS
138. Under SFAS 133, all derivative instruments are recorded on the balance
sheet at fair value. In 2003 we elected not to designate derivative instruments
as hedges. Accordingly the instruments are recorded on the balance sheet at fair
value with changes in the market value of the derivatives being recorded in
current oil and gas revenue.
Under the terms of 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 for a rolling six month period.
All hedge transactions are subject to our risk management policy, which
has been approved by the Board of Directors.
As of December 31, 2004, we had the following hedges in place:
Time Period Notional Quantities Price
--------------------------- ------------------------------------------ ----------------------
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
February 2005 7,100 MMbtu of production per day Floor of $4.50
400 Bbls of crude oil production per day Floor of $25.00
March 2005 7,100 MMbtu of production per day Floor of $4.50
400 Bbls of crude oil production per day Floor of $25.00
April 2005 7,100 MMbtu of production per day Floor of $4.50
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
Interest rate risk
At December 31, 2004, as a result of the financial restructuring that
occurred in October 2004, we had $125.0 million in outstanding indebtedness
under the floating rate senior secured notes due 2009. The notes bear interest
at a per annum rate of six-month LIBOR plus 7.5%. The rate is redetermined on
June 1 and December 1 of each year, beginning June 1, 2005. The current rate on
the new notes is 9.72%. For every percentage point that the LIBOR rate rises,
our interest expense would increase by approximately $1.3 million on an annual
basis. At December 31, 2004 we had $1.4 million of outstanding indebtedness
under our new revolving credit facility. Interest on this facility accrues at
the prime rate announced by Wells Fargo Bank plus 1.00%. For every percentage
point increase in the announced prime rate, our interest expense would increase
by approximately $14,000 on an annual basis.
Item 8. Financial Statements
For the financial statements and supplementary data required by this Item
8, see the Index to Consolidated Financial Statements.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None
Item 9A. Controls and Procedures
As of the end of the period covered by this report, our Chief Executive
Officer and Chief Financial Officer carried out an evaluation of the
effectiveness of our "disclosure controls and procedures" (as defined in the
Securities Exchange Act of 1934 Rules 13a-15(e)and 15d-15(e)) and concluded that
the disclosure controls and procedures were adequate and designed to ensure that
material information relating to Abraxas and our consolidated subsidiaries which
44
is required to be included in our periodic Securities and Exchange Commission
filings would be made known to them by others within those entities. There were
no changes in our internal controls that could materially affect, or are
reasonably likely to materially affect our financial reporting.
Item 9B. Other Information
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
There is incorporated in this Item 10 by reference that portion of our
definitive proxy statement for the 2005 Annual Meeting of Stockholders which
appears therein under the captions "Election of Directors". See also the
information in Item 4a of Part I of this Report.
Audit Committee and Audit Committee Financial Expert
The Audit Committee of our board of directors consists of C. Scott
Bartlett, Jr., Frank M. Burke, James C. Phelps and Joseph A. Wagda. The board of
directors has determined that each of the members of the Audit Committee is
independent as determined in accordance with the listing standards of the
American Stock Exchange and Item 7(d) (3) (iv) of Schedule 14A of the Exchange
Act. In addition, the board of directors has determined that C. Scott Bartlett,
Jr., as defined by SEC rules, is an audit committee financial expert.
Section 16(a) Compliance
Section 16(a) of the Exchange Act requires Abraxas directors and
executive officers and persons who own more than 10% of a registered class of
Abraxas equity securities to file with the Securities and Exchange Commission
and the AMEX initial reports of ownership and reports of changes in ownership of
Abraxas common stock. Officers, directors and greater than 10% stockholders are
required by SEC regulations to furnish us with copies of all such forms they
file. Based solely on a review of the copies of such reports furnished to us and
written representations that no other reports were required, We believe that all
our directors and executive officers during 2004 complied on a timely basis with
all applicable filing requirements under Section 16(a) of the Exchange Act.
Item 11. Executive Compensation
There is incorporated in this Item 11 by reference that portion of our
definitive proxy statement for the 2005 Annual Meeting of Stockholders which
appears therein under the caption "Executive Compensation", except for those
parts under the captions "Compensation Committee Report on Executive
Compensation," "Performance Graph", "Audit Committee Report" and "Report on
Repricing of Options."
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
There is incorporated in this Item 12 by reference that portion of our
definitive proxy statement for the 2005 Annual Meeting of Stockholders which
appears therein under the caption "Securities Holdings of Principal
Stockholders, Directors and Officers."
Item 13. Certain Relationships and Related Transactions
There is incorporated in this Item 13 by reference that portion of our
definitive proxy statement for the 2005 Annual Meeting of Stockholders which
appears therein under the caption "Certain Transactions."
45
Item 14. Principal Accounting Fees and Services
There is incorporated in this Item 14 by reference that portion of our
definitive proxy statement for the 2005 Annual Meeting of Stockholders which
appears therein under the caption "Principal Auditor Fees and Services."
PART IV
Item 15. Exhibits, Financial Statement Schedules
(a)1. Consolidated Financial Statements Page
Report of BDO Seidman LLP, Independent Registered Public Accounting Firm...................F-2
Report of Deloitte & Touche LLP, an Independent Registered Public Accounting Firm...........F-3
Consolidated Balance Sheets,
December 31, 2003 and 2004................................................................F-4
Consolidated Statements of Operations,
Years Ended December 31, 2002, 2003 and 2004..............................................F-6
Consolidated Statements of Stockholders' Deficit
Years Ended December 31, 2002, 2003 and 2004 ............................................F-7
Consolidated Statements of Cash Flows
Years Ended December 31, 2002, 2003 and 2004..............................................F-9
Consolidated Statements of Other Comprehensive Income (Loss)
Years Ended December 31, 2002, 2003 and 2004.............................................F-11
Notes to Consolidated Financial Statements.................................................F-12
(a) 2. Financial Statement Schedules
All schedules have been omitted because they are not applicable, not
required under the instructions or the information requested is set forth in the
consolidated financial statements or related notes thereto.
(a)3.Exhibits
The following Exhibits have previously been filed by the Registrant or
are included following the Index to Exhibits.
Exhibit Number. Description
3.1 Articles of Incorporation of Abraxas. (Filed as Exhibit 3.1 to our
Registration Statement on Form S-4, No. 33-36565 (the "S-4 Registration
Statement")).
3.2 Articles of Amendment to the Articles of Incorporation of Abraxas dated
October 22, 1990. (Filed as Exhibit 3.3 to the S-4 Registration
Statement).
3.3 Articles of Amendment to the Articles of Incorporation of Abraxas dated
December 18, 1990. (Filed as Exhibit 3.4 to the S-4 Registration
Statement).
46
3.4 Articles of Amendment to the Articles of Incorporation of Abraxas dated
June 8, 1995. (Filed as Exhibit 3.4 to our Registration Statement on
Form S-3, No. 333-00398 (the "S-3 Registration Statement")).
3.5 Articles of Amendment to the Articles of Incorporation of Abraxas dated
as of August 12, 2000 (Filed as Exhibit 3.5 to our Annual Report of
Form 10-K filed April 2, 2001).
3.6 Amended and Restated Bylaws of Abraxas. (Filed as Exhibit 3.6 to
Abraxas' Annual Report on Form 10-K filed April 5, 2002).
4.1 Specimen Common Stock Certificate of Abraxas. (Filed as Exhibit 4.1 to
the S-4 Registration Statement).
4.2 Specimen Preferred Stock Certificate of Abraxas. (Filed as Exhibit 4.2
to our Annual Report on Form 10-K filed on March 31, 1995).
4.3 Indenture dated October 28, 2004, by and among Abraxas, as Issuer; the
Subsidiary Guarantors party thereto and U.S. Bank National Association,
as Trustee, relating to Abraxas' Floating Rate Senior Secured Notes Due
2009. (filed as Exhibit 4.1 to Abraxas' Current Report on Form 8-K
filed on November 3, 2004).
4.4 Form of Rule 144A Global Note for Floating Rate Senior Secured Notes
due 2009. (Filed as Exhibit A-1 to Exhibit 4.1 to Abraxas' Current
Report on Form 8-K filed on November 3, 2004).
4.5 Form of Regulation S Global Note for Floating Rate Senior Secured Notes
due 2009. (Filed as Exhibit A-2 to Exhibit 4.1 to Abraxas' Current
Report on Form 8-K filed on November 3, 2004).
4.6 Form of Accredited Investor Certificated Note for Floating Rate Senior
Secured Notes due 2009. (Filed as Exhibit A-3 to Exhibit 4.1 to
Abraxas' Current Report on Form 8-K filed on November 3, 2004).
*10.1 Abraxas Petroleum Corporation 401(k) Profit Sharing Plan. (Filed as
Exhibit 10.4 to Abraxas'Registration Statement on Form S-4, No.
333-18673, (the "1996 Exchange Offer Registration Statement")).
*10.2 Abraxas Petroleum Corporation Director Stock Option Plan. (Filed as
Exhibit 10.5 to the 1996 Exchange Offer Registration Statement).
*10.3 Abraxas Petroleum Corporation Restricted Share Plan for Directors.
(Filed as Exhibit 10.20 to Abraxas' Annual Report on Form 10-K filed on
April 12, 1994).
*10.4 Abraxas Petroleum Corporation Amended and Restated 1994 Long Term
Incentive Plan.
*10.5 Abraxas Petroleum Corporation Incentive Performance Bonus Plan. (Filed
as Exhibit 10.24 to Abraxas' Annual Report on Form 10-K filed on April
12, 1994).
10.6 Form of Indemnity Agreement between Abraxas and each of its directors
and officers. (Filed as Exhibit 10.30 to the 1993 S-1).
10.7 Farmout Agreement between Grey Wolf Exploration Limited and PrimeWest
Energy, Inc. (Filed as Exhibit 10.2 to Abraxas' Current Report on Form
8-K/A filed on December 9, 2002).
47
10.8 Purchase Agreement dated as of October 21, 2004 by and among Abraxas
Petroleum Corporation, the Subsidiary Guarantors signatory thereto and
Guggenheim Capital Markets, LLC. (Filed as Exhibit 10.1 to Abraxas'
Current Report on Form 8-K filed November 3, 2004).
10.9 Loan Agreement dated as of October 28, 2004 by and among Abraxas
Petroleum Corporation, the Subsidiary Guarantors party thereto, Wells
Fargo Foothill, Inc., as Arranger and Administrative Agent and the
Lenders signatory thereto. (Filed as Exhibit 10.2 to Abraxas' Current
Report on Form 8-K filed November 3, 2004).
10.10 Loan Agreement dated as of October 28, 2004 by and among Abraxas
Petroleum Corporation, the Subsidiary Guarantors party thereto,
Guggenheim Corporate Funding, LLC, as Arranger and Administrative Agent
and the Lenders signatory thereto. (Filed as Exhibit 10.3 to Abraxas'
Current Report on Form 8-K filed November 3, 2004).
*10.11 Employment Agreement between Abraxas and Robert L. G. Watson. (Filed as
Exhibit 10.19 to the 2000 S-1 Registration Statement).
*10.12 Employment Agreement between Abraxas and Chris E. Williford. (Filed as
Exhibit 10.20 to the 2000 S-1 Registration Statement).
*10.13 Employment Agreement between Abraxas and Robert W. Carington, Jr.
(Filed as Exhibit 10.22 to the 2000 S-1 registration Statement).
*10.14 Employment Agreement between Abraxas and Stephen T. Wendel. (Filed as
Exhibit 10.26 to the S-3 Registration Statement).
*10.15 Employment Agreement between Abraxas and William H. Wallace. (Filed as
Exhibit 10.27 to the S-3 Registration Statement).
*10.16 Employment Agreement between Abraxas and Lee T. Billingsley. (Filed as
Exhibit 10.28 to the S-3 Registration Statement).
10.17 Loan Agreement dated October 28, 2004 by and among Grey Wolf
Exploration Inc., Guggenheim Corporate Funding, LLC as Arranger and
Administrative Agent and the Lenders signatory thereto. (Filed as
Exhibit 10.4 to Abraxas' Current Report on Form 8-K filed November 3,
2004).
10.18 Intercreditor, Security and Collateral Agency Agreement dated as of
October 28, 2004 by and among Abraxas Petroleum Corporation, the
Subsidiary Guarantors party thereto, Wells Fargo Foothill, Inc.,
Guggenheim Corporate Funding, LLC and U.S. Bank National Association.
(Filed as Exhibit 10.5 to Abraxas' Current Report on Form 8-K filed
November 3, 2004).
10.19 Warrant issued to Guggenheim Corporate Funding, LLC dated October 28,
2004. (Filed as Exhibit 10.6 to Abraxas' Current Report on Form 8-K
filed November 3, 2004).
10.20 Exchange and Registration Rights Agreement dated October 28, 2004, by
and among Abraxas Petroleum Corporation, the Subsidiary Guarantors
signatory thereto, and Guggenheim Capital Markets, LLC. (Filed as
Exhibit 10.1 to Abraxas' Quarterly Report on Form 10-Q filed November
12, 2004).
21.1 Subsidiaries of Abraxas. (Filed as Exhibit 21.1 to Abraxas, Grey Wolf
Exploration Inc., Sandia Oil & Gas Corporation, Sandia Operating Corp.,
Wamsutter Holdings, Inc., Western Associated Energy Corporation and
Eastside Coal Company, Inc.'s Registration Statement on Form S-1, No.
333-103027).
23.1 Consent of BDO Seidman, LLP (filed herewith)
48
23.2 Consent of Deloitte & Touche LLP (filed herewith).
23.3 Consent of DeGolyer and MacNaughton. (filed herewith).
31.1 Certification - Chief Executive Officer (filed herewith)
31.2 Certification - Chief Financial Officer (filed herewith)
32.1 Certification by Chief Executive Officer pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002 (filed herewith).
32.2 Certification by Chief Financial Officer pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002 (filed herewith).
* Management Compensatory Plan or Agreement.
49
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
ABRAXAS PETROLEUM CORPORATION
By:/s/ Robert L.G. Watson By: /s/ Chris E. Williford
--------------------------------- -------------------------------
President and Principal Exec. Vice President and
Executive Officer Principal Financial and
Accounting Officer
DATED: March 29, 2005
Pursuant to the requirements of the Securities and Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the date indicated.
Signature Name and Title Date
--------- -------------- ----
/s/ Robert L.G. Watson Chairman of the Board,
- ------------------------ President (Principal Executive
Robert L.G. Watson Officer) and Director March 29, 2005
/s/ Chris E. Williford Exec. Vice President and
- ------------------------ Treasurer (Principal Financial
Chris E. Williford and Accounting Officer) March 29, 2005
/s/ Craig S. Bartlett, Jr. Director March 29, 2005
- --------------------------
Craig S. Bartlett, Jr.
/s/ Franklin A. Burke Director March 29, 2005
- ----------------------
Franklin A. Burke
/s/ Harold D. Carter Director March 29, 2005
- ----------------------
Harold D. Carter
/s/ Ralph F. Cox Director March 29, 2005
- ----------------------
Ralph F. Cox
/s/ Barry J. Galt Director March 29, 2005
- ------------------
Barry J. Galt
/s/ Dennis E. Logue Director March 29, 2005
- ----------------------
Dennis E Logue
/s/ James C. Phelps Director March 29, 2005
- ----------------------
James C. Phelps
/s/ Joseph A. Wagda Director March 29, 2005
- ----------------------
Joseph A. Wagda
50
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Abraxas Petroleum Corporation and Subsidiaries
Report of Independent Registered Public Accounting Firm for the
year ended December 31, 2003 and 2004...................................F-2
Report of Independent Registered Public Accounting Firm for the year
ended December 31, 2002.................................................F-3
Consolidated Balance Sheets at December 31, 2003 and 2004...................F-4
Consolidated Statements of Operations for the years ended
December 31, 2002, 2003 and 2004........................................F-6
Consolidated Statements of Stockholders' Deficit for the years ended
December 31, 2002, 2003 and 2004........................................F-7
Consolidated Statements of Cash Flows for the years ended
December 31, 2002, 2003 and 2004........................................F-8
Consolidated Statements of Other Comprehensive Income (loss)
for the years ended December 31, 2002, 2003 and 2004....................F-10
Notes to Consolidated Financial Statements .................................F-11
All other schedules are omitted because they are not required, are not
applicable or the information required is included in the Consolidated Financial
Statements or the notes thereto.
F-1
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Abraxas Petroleum Corporation
We have audited the accompanying consolidated balance sheets of Abraxas
Petroleum Corporation as of December 31, 2003 and 2004 and the related
consolidated statements of operations, stockholders' deficit, cash flows, and
other comprehensive income (loss) for the years ended December 31, 2003 and
2004. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. The Company is not required to
have, nor were we engaged to perform, an audit of its internal control over
financial reporting. Our audits included consideration of internal control over
financial reporting as a basis for designing audit procedures that are
appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Company's internal control over financial
reporting. Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Abraxas Petroleum
Corporation at December 31, 2003 and 2004, and the results of its operations and
its cash flows for the years ended December 31, 2003 and 2004, in conformity
with accounting principles generally accepted in the United States of America.
/s/ BDO Seidman, LLP
Dallas, Texas
February 28, 2005, except for Note 2 , as to which the date is March 24, 2005
F-2
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
Abraxas Petroleum Corporation
We have audited the accompanying consolidated statement of operations,
stockholders' deficit, cash flows, and other comprehensive income (loss) of
Abraxas Petroleum Corporation (the "Company") for the year ended December 31,
2002. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audit.
We conducted our audit in accordance with standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the results of operations and cash flows of the Company for
the year ended December 31, 2002, in conformity with accounting principles
generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
San Antonio, Texas
March 10, 2003 (July 18, 2003 as to Note 17, March 28, 2005 as to the
reclassification of the 2002 consolidated financial statements for discontinued
operations referred to in Note 2)
F-3
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31
--------------------------------------
2003 2004
------------------ -------------------
(Dollars in thousands)
Current assets:
Cash ................................................... $ - $ 1,284
Accounts receivable:
Joint owners ....................................... 1,271 471
Oil and gas production sales ....................... 5,190 4,724
Other .............................................. 959 66
------------------ -------------------
7,420 5,261
Equipment inventory .................................... 782 735
Other current assets ................................... 418 752
------------------ -------------------
8,620 8,032
Assets held for sale.................................... 37,092 52,600
------------------ -------------------
Total current assets................................ 45,712 60,632
Property and equipment:
Oil and gas properties, full cost method of accounting:
Proved ............................................. 288,559 297,647
Other property and equipment ......................... 2,749 2,930
------------------ -------------------
Total .......................................... 291,308 300,577
Less accumulated depreciation, depletion, and
amortization ....................................... 215,287 222,500
------------------ -------------------
Total property and equipment - net ................. 76,021 78,077
Deferred financing fees net ............................... 4,410 7,618
Deferred tax asset......................................... - 6,060
Other assets .............................................. 294 298
------------------ -------------------
Total assets ........................................... $ 126,437 $ 152,685
================== ===================
See accompanying notes to consolidated financial statements
F-4
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS (CONTINUED)
LIABILITIES AND STOCKHOLDERS' DEFICIT
December 31
--------------------------------------
2003 2004
------------------ -------------------
(Dollars in thousands)
Current liabilities:
Accounts payable .......................................... $ 5,019 $ 5,622
Joint interest oil and gas production payable ............. 2,056 2,443
Accrued interest .......................................... 2,340 2,170
Other accrued expenses .................................... 1,228 1,654
------------------ -------------------
10,643 11,889
Liabilities related to assets held for sale................ 2,572 66,947
------------------ -------------------
Total current liabilities................................ 13,215 78,836
Long-term debt ............................................... 184,649 126,425
Future site restoration ..................................... 776 888
Stockholders' equity (deficit):
Common stock, par value $.01 per share - authorized 200,000,000 shares;
issued 36,024,308 and 36,597,045
at December 31, 2003 and 2004 respectively............ 360 366
Additional paid-in capital ................................ 141,835 146,185
Receivables from stock sale................................ (97) -
Accumulated deficit ...................................... (213,701) (202,534)
Treasury stock, at cost, 165,883 and 105,989 shares at
December 31, 2003 and 2004 respectively.................. (964) (549)
Accumulated other comprehensive income..................... 364 3,068
------------------ -------------------
Total stockholders' deficit................................... (72,203) (53,464)
------------------ -------------------
Total liabilities and stockholders' deficit................ $ 126,437 $ 152,685
================== ===================
See accompanying notes to consolidated financial statements
F-5
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31
----------------------------------------------------------
2002 2003 2004
------------------- --------------------- ------------------
(In thousands except per share data)
Revenues:
Oil and gas production revenues ......................... $ 20,835 $ 29,710 $ 33,073
Rig revenues ............................................ 635 663 771
Other .................................................. 71 7 10
----------------- --------------------- ------------------
21,541 30,380 33,854
Operating costs and expenses:
Lease operating and production taxes .................... 7,639 8,342 8,567
Depreciation, depletion, and amortization ............... 9,194 7,608 7,213
Proved property impairment .............................. 28,178 - -
Rig operations .......................................... 567 609 671
General and administrative .............................. 4,045 3,995 5,126
Stock-based compensation................................. - 1,106 1,305
----------------- --------------------- ----------------
49,623 21,660 22,882
----------------- --------------------- ----------------
Operating income (loss)..................................... (28,082) 8,720 10,972
Other (income) expense:
Interest income ......................................... (92) (30) (10)
Amortization of deferred financing fees ................. 1,325 1,630 1,848
Interest expense ........................................ 24,689 16,323 17,867
Financing costs.......................................... 967 4,406 1,657
Gain on debt redemption.................................. - - (12,561)
Other ................................................... 201 100 387
----------------- --------------------- ----------------
27,090 22,429 9,188
----------------- --------------------- ----------------
Income (loss) from continuing operations before cumulative
effect of accounting change ............................. (55,172) (13,709) 1,784
Cumulative effect of accounting change...................... - 395 -
------------------ --------------------- ---------------
Net income (loss) from continuing operations before
income tax............................................ (55,172) (14,104) 1,784
------------------ --------------------- ---------------
Deferred income tax benefit.............................. - - (6,060)
------------------ --------------------- ---------------
Income (loss) from continuing operations................. (55,172) (14,104) 7,844
Net income (loss) from discontinued operations........... (63,355) 70,024 3,323
------------------ --------------------- ---------------
Net income (loss) $ (118,527) $ 55,920 $ 11,167
=================- ===================== ===============
Basic earnings (loss)per common share:
Net earnings (loss) from continuing operations........ $ (1.84) $ (0.39) $ 0.22
Discontinued operations (loss)........................ (2.11) 1.98 0.09
Cumulative effect of accounting change................ - (0.01) -
------------------ --------------------- ---------------
Net income (loss) per common share - basic .............. $ (3.95) $ 1.58 $ 0.31
=================- ===================== ===============
Diluted earnings (loss) per common share:
Net earnings (loss) from continuing operations........ $ (1.84) $ (0.39) $ 0.20
Discontinued operations (loss)........................ (2.11) 1.98 0.09
Cumulative effect of accounting change................ - (0.01) -
------------------ --------------------- ---------------
Net income (loss) per common share - diluted............ $ (3.95) $ 1.58 $ 0.29
=================- ===================== ===============
See accompanying notes to consolidated financial statements
F-6
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' DEFICIT
(In thousands except number of shares)
Accumulated
Common Stock Treasury Stock Additional Other Receivable
-------------------------------------- Paid-In Accumulated Comprehensive From
Shares Amount Shares Amount Capital Deficit Income (Loss) Stock Sale Total
----------- ---------------------------------------------------------------------------------------
Balance at December 31, 2001 30,145,280 $ 301 165,883 (964) $ 136,830 $ (151,094) (13,561) $(97) (28,585)
Net loss................. - - - - - (118,527) - - (118,527)
Hedge income......... - - - - - - 566 - 566
Foreign currency
translation
adjustment ........ - - - - - - 4,292 - 4,292
----------- ---------------------------------------------------------------------------------------
Balance at December 31, 2002 30,145,280 301 165,883 (964) 136,839 (269,621) (8,730) (97) 142,254)
Net income.............. - - - - - 55,920 - - 55,920
Foreign currency
translation
adjustment ........ - - - - - - 9,067 - 9,067
Stock-base d compensation
expense................ - - - - 1,106 - - - 1,106
Stock options exercised . 129,352 1 - - 84 - - - 85
Stock issued for
acquisition of Wind
River Resources........ 106,977 1 - - 91 - - - 92
Stock issued in
connection with
exchange offer......... 5,642,699 57 - - 3,724 - - - 3,781
----------- ---------------------------------------------------------------------------------------
Balance at December 31, 2003 36,024,308 360 165,883 (964) 141,835 (213,701) 364 (97) (72,203)
Net income.............. - - - - 11,167 - - 11,167
Foreign currency
translation
adjustment ........ - - - - - 2,704 2,704
Proceeds from receivable - - - - - - 97 97
Stock issued for
compensation........... 58,808 1 (59,894) 415 (87) - - - 329
Stock-based compensation
expense................ - - - 1,305 - - - 1,305
Stock options and
warrants exercised .... 513,929 - - 3,132 - - - 3,137
----------- ---------------------------------------------------------------------------------------
Balance at December 31, 2004 36,597,045 $360 105,989 $ (549) $ 146,185 $ (202,534) $ 3,068 $ - $(53,464)
=========== =======================================================================================
See accompanying notes to consolidated financial statements.
F-7
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31
-----------------------------------------------------------------------------
2002 2003 2004
-----------------------------------------------------------------------------
(In thousands)
Operating Activities
Net income (loss) .................................. $ (118,527) $ 55,920 $ 11,167
Income (loss) from discontinued operations.......... (63,355) 70,024 3,323
------------------ ----------------------- -------------------------
Income (loss) from continuing operations............ (55,172) (14,104) 7,844
Adjustments to reconcile net income (loss) to net
cash provided by (used in) operating activities:
Depreciation, depletion, and
amortization ............................... 9,194 7,608 7,213
Non-cash interest and financing cost........... - 16,422 5,967
Accretion of future site restoration........... - 379 108
Deferred tax benefit........................... - - (6,060)
Proved property impairment .................... 28,178 - -
Amortization of deferred financing fees........ 1,325 1,630 1,848
Stock-based compensation ...................... - 1,106 1,305
Changes in operating assets and liabilities:
Accounts receivable ........................ 18,088 (7,850) 7,816
Equipment inventory ........................ 201 78 47
Other ..................................... 381 295 (338)
Accounts payable ........................... (3) 2,161 990
Accrued expenses ........................... (44) 3,754 260
------------------ ----------------------- -------------------------
Net cash provided by continuing operations......... 2,148 11,479 27,000
Net cash provided by (used in) discontinued
operations.................................. (10,984) 16,125 3,265
------------------ ----------------------- -------------------------
Net cash provided by (used in) operations........... (8,836) 27,604 30,265
------------------ ----------------------- -------------------------
Investing Activities
Capital expenditures, including purchases
and development of properties ................... (5,070) (9,194) (9,269)
Proceeds from sale of oil and gas
properties....................................... 9,725 - -
------------------ ----------------------- -------------------------
Net cash (used in) provided by continuing operations
4,655 (9,194) (9,269)
Net cash used in discontinued operations............ (9,691) 76,655 (12,069)
------------------ ----------------------- -------------------------
Net cash (used in) provided by investing activities. (5,036) 67,461 (21,338)
Financing Activities
Proceeds from issuance of common stock............ - - 3,465
Proceeds from long-term borrowings ............... - 43,051 147,955
Payments on long-term borrowings ................. (8,176) (131,283) (212,146)
Deferred financing fees .......................... (1,516) (597) (5,056)
Other............................................. - 177 98
------------------ ----------------------- -------------------------
Net cash used in continuing operations............ (9,692) (88,652) (65,684)
Net cash provided by (used in) discontinued
operations..................................... 20,528 (6,970) 58,041
------------------ ----------------------- -------------------------
Net cash (used in) provided by financing
activities..................................... 10,836 (95,622) (7,643)
------------------ ----------------------- -------------------------
Increase (decrease) in cash ...................... (3,036) (4,389) 1,284
Cash at beginning of year ........................ 3,593 557 -
------------------ ----------------------- -------------------------
Cash at end of year............................... $ 557 $ - $ 1,284
================== ======================= =========================
F-8
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOW (CONTINUED)
Years Ended December 31.
-------------------------------------------------------------
2002 2003 2004
------------------ ---------------- -----------------
Supplemental disclosures of cash flow information:
Interest paid .......................... $ 24,597 $ 3,637 $ 7,608
================== ================ =================
See accompanying notes to consolidated financial statements.
F-9
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME (LOSS)
Years Ended December 31,
---------------------------------------------------------
2002 2003 2004
------------------- ------------------ ------------------
(In thousands)
Net income (loss)............................................ $ (118,527) $ 55,920 $ 11,167
Other Comprehensive income (loss):
Hedging derivatives (net of tax) - See Note 4 - -
Reclassification adjustment for settled hedge contracts,
net of taxes................................................ 2,556 - -
Change in fair market value of outstanding hedge positions
net of taxes ............................................... (1,990) -
------------------- ------------------ ------------------
566 - -
Foreign currency translation adjustment
Reclassification of foreign currency translation adjustment
relating to the sale of foreign subsidiaries.............. 4,292 4,632 -
Effect of change in exchange rate........................... - 4,435 2,704
------------------- ------------------ ------------------
Other comprehensive income (loss)................................ 4,858 9,067 -
------------------- ------------------ ------------------
Comprehensive income (loss)...................................... $ (113,669) $ 64,987 $ 13,871
=================== ================== ==================
See accompanying notes to consolidated financial statements.
F-10
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Significant Accounting Policies
Nature of Operations
Abraxas Petroleum Corporation (the "Company" or "Abraxas") is an
independent energy company primarily engaged in the exploitation of and the
acquisition, development, and production of crude oil and natural gas primarily
along the Texas Gulf Coast, in the Permian Basin of western Texas and in
Wyoming. The consolidated financial statements include the accounts of the
Company and its wholly owned subsidiaries. All intercompany accounts and
transactions have been eliminated in consolidation.
As part of the series of transactions related to the Company's 2004
restructuring of operations, see Note 2, the Company approved a plan in 2004 to
dispose of its operations and interest in Grey Wolf Exploration Inc. ("Grey
Wolf") a wholly-owned Canadian subsidiary of Abraxas. In February 2005 Grey Wolf
closed an initial public offering, resulting in our substantial divestiture of
our capital stock and operations in Grey Wolf. As a result of the disposal of
Grey Wolf, the results of operations of Grey Wolf are reflected in our Financial
Statements as discontinued operations. See note 2.
Use of Estimates
The preparation of consolidated financial statements in conformity with
accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the consolidated financial statements and the
reported amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates. Management believes that it is
reasonably possible that estimates of proved crude oil and natural gas revenues
could significantly change in the future.
Concentration of Credit Risk
Financial instruments, which potentially expose the Company to credit risk
consist principally of trade receivables and crude oil and natural gas price
hedges. Accounts receivable are generally from companies with significant oil
and gas marketing activities. The Company performs ongoing credit evaluations
and, generally, requires no collateral from its customers.
The Company maintains its cash and cash equivalents in excess of Federally
insured limits in prominent financial institutioins considered by the Company to
be of high credit quality.
Cash and Equivalents
Cash and cash equivalents includes cash on hand, demand deposits and
short-term investments with original maturities of three months or less.
Accounts Receivable
Accounts receivable are reported net of an allowance for doubtful accounts
of approximately $11,000 at December 31, 2003 and 2004. The allowance for
doubtful accounts is determined based on the Company's historical losses, as
well as a review of certain accounts. Accounts are charged off when collection
efforts have failed and the account is deemed uncollectible.
F-11
Equipment Inventory
Equipment inventory principally consists of casing, tubing, and compression
equipment and is carried at cost.
Oil and Gas Properties
The Company follows the full cost method of accounting for crude oil and
natural gas properties. Under this method, all direct costs and certain indirect
costs associated with acquisition of properties and successful as well as
unsuccessful exploration and development activities are capitalized.
Depreciation, depletion, and amortization of capitalized crude oil and natural
gas properties and estimated future development costs, excluding unproved
properties, are based on the unit-of-production method based on proved reserves.
Net capitalized costs of crude oil and natural gas properties, as adjusted for
asset retirement obligations, less related deferred taxes, are limited to the
lower of unamortized cost or the cost ceiling, defined as the sum of the present
value of estimated future net revenues from proved reserves based on unescalated
prices discounted at 10 percent, plus the cost of properties not being
amortized, if any, plus the lower of cost or estimated fair value of unproved
properties included in the costs being amortized, if any, less related income
taxes. Excess costs are charged to proved property impairment expense. No gain
or loss is recognized upon sale or disposition of crude oil and natural gas
properties, except in unusual circumstances.
Unproved properties represent costs associated with properties on which the
Company is performing exploration activities or intends to commence such
activities. These costs are reviewed periodically for possible impairments or
reduction in value based on geological and geophysical data. If a reduction in
value has occurred, costs being amortized are increased. The Company believes
that the unproved properties will be substantially evaluated in six to
thirty-six months and it will begin to amortize these costs at such time.
Other Property and Equipment
Other property and equipment are recorded on the basis of cost.
Depreciation of other property and equipment is provided over the estimated
useful lives using the straight-line method. Major renewals and betterments are
recorded as additions to the property and equipment accounts. Repairs that do
not improve or extend the useful lives of assets are expensed.
Hedging
The Company periodically enters into agreements to hedge the risk of future
crude oil and natural gas price fluctuations. Such agreements are primarily in
the form of price floors, which limit the impact of price reductions with
respect to the Company's sale of crude oil and natural gas. The Company does not
enter into speculative hedges. Gains and losses on such hedging activities are
recognized in oil and gas production revenues when hedged production is sold.
The net cash flows related to any recognized gains or losses associated with
these hedges are reported as cash flows from operations. If the hedge is
terminated prior to expected maturity, gains or losses are deferred and included
in income in the same period as the physical production required by the contract
is delivered.
Statement of Financial Accounting Standards, ("SFAS") No. 133, "Accounting
for Derivative Instruments and Hedging Activities," was effective for the
Company on January 1, 2001. SFAS 133, as amended and interpreted, establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities.
In 2003, the Company elected out of hedge accounting as prescribed by SFAS 133.
Accordingly all derivatives will be recorded on the balance sheet at fair value
with changes in fair value being recognized in earnings.
Stock-Based Compensation
The Company accounts for stock-based compensation using the intrinsic value
method prescribed in Accounting Principles Board Opinion ("APB") No. 25,
"Accounting for Stock Issued to Employees," (APB No. 25) and related
interpretations. Accordingly, compensation cost for stock options is measured as
the excess, if any, of the quoted market price of the Company's stock at the
date of the grant over the amount an employee must pay to acquire the stock.
F-12
Effective July 1, 2000, the Financial Accounting Standards Board ("FASB")
issued FIN 44, "Accounting for Certain Transactions Involving Stock
Compensation," an interpretation of APB No. 25. Under the interpretation,
certain modifications to fixed stock option awards which were made subsequent to
December 15, 1998, and were not exercised prior to July 1, 2000, require that
the awards be accounted for as variable until they are exercised, forfeited, or
expired. In March 1999, the Company amended the exercise price to $2.06 on all
options with an existing exercise price greater than $2.06. In January 2003, in
connection with the restructuring (see note 2), the Company amended the exercise
price to $0.66 on certain options with an existing exercise price greater than
$0.66. The Company recognized stock-based compensation expense of approximately
$1.1 and $1.3 million during 2003 and 2004 respectively. There was no stock
based compensation expense for the year ended December 31, 2002.
Pro forma information regarding net income (loss) and earnings (loss) per
share is required by SFAS 123, "Accounting for Stock-Based Compensation (SFAS
123)", which also requires that the information be determined as if the Company
has accounted for its employee stock options granted subsequent to December 31,
1995 under the fair value method prescribed by SFAS No. 123. The fair value for
these options was estimated at the date of grant using a Black-Scholes option
pricing model with the following weighted-average assumptions for 2002, 2003 and
2004, risk-free interest rates of 1.5% each year; dividend yields of -0-%;
volatility factors of the expected market price of the Company's common stock of
..35, and a weighted-average expected life of the option of ten years.
The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions including the expected stock price
volatility. Because the Company's employee stock options have characteristics
significantly different from those of traded options, and because changes in the
subjective input assumptions can materially affect the fair value estimate, in
management's opinion, the existing models do not necessarily provide a reliable
single measure of the fair value of its employee stock options.
For purposes of pro forma disclosures, the estimated fair value of the
options is amortized to expense over the options' vesting period. The Company's
pro forma information follows:
Year Ended December 31
-----------------------------------------------------------------
2002 2003 2004
------------------ ----------------- ----------------
Net income (loss) as reported (including
discontinued operations $ (118,527) $ 55,920 $ 11,167
Add: Stock-based employee compensation expense
included in reported net income, net of related
tax effects - 1,106 1,305
Deduct: Total stock-based employee compensation
expense determined under fair value based
method for all awards, net of related tax
effects (670) (228) (112)
------------------ ----------------- ----------------
Pro forma net income (loss) $ (119,197) $ 56,798 $ 12,360
================== ================= ================
Earnings (loss) per share:
Basic - as reported $ (3.95) $ 1.58 $ 0.31
================== ================= ================
Basic - pro forma $ (3.98) $ 1.61 $ 0.34
================== ================= ================
Diluted - as reported $ (3.95) $ 1.58 $ 0.29
================== ================= ================
Diluted - pro forma $ (3.98) $ 1.61 $ 0.32
================== ================= ================
Foreign Currency Translation
The functional currency for Grey Wolf is the Canadian dollar ($CDN). The
Company translates the functional currency into U.S. dollars ($US) based on the
current exchange rate at the end of the period for the balance sheet and a
weighted average rate for the period on the statement of operations. Translation
adjustments are reflected as accumulated other comprehensive income (loss) in
the consolidated financial statement of stockholders' deficit. The amount
reflected in the accompanying financial statements relates to discontinued
operations.
F-13
Fair Value of Financial Instruments
The Company includes fair value information in the notes to consolidated
financial statements when the fair value of its financial instruments is
materially different from the book value. The Company assumes the book value of
those financial instruments that are classified as current approximates fair
value because of the short maturity of these instruments. For noncurrent
financial instruments, the Company uses quoted market prices or, to the extent
that there are no available quoted market prices, market prices for similar
instruments.
Restoration, Removal and Environmental Liabilities
The Company is subject to extensive Federal, state and local environmental
laws and regulations. These laws regulate the discharge of materials into the
environment and may require the Company to remove or mitigate the environmental
effects of the disposal or release of petroleum substances at various sites.
Environmental expenditures are expensed or capitalized depending on their future
economic benefit. Expenditures that relate to an existing condition caused by
past operations and that have no future economic benefit are expensed.
Liabilities for expenditures of a noncapital nature are recorded when
environmental assessments and/or remediation is probable, and the costs can be
reasonably estimated. Such liabilities are generally undiscounted unless the
timing of cash payments for the liability or component are fixed or reliably
determinable.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations" (SFAS 143). SFAS 143 addresses accounting and reporting
for obligations associated with the retirement of tangible long-lived assets and
the associated asset retirement costs. SFAS 143 is effective for us January 1,
2003. SFAS 143 requires that the fair value of a liability for an asset's
retirement obligation be recorded in the period in which it is incurred and the
corresponding cost capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its then present value each
period, and the capitalized cost is depreciated over the useful life of the
related asset. For all periods presented, we have included estimated future
costs of abandonment and dismantlement in our full cost amortization base and
amortize these costs as a component of our depletion expense in the accompanying
consolidated financial statements.
The following table summarizes the Company's asset retirement obligation
transactions related to continuing operations during the following years:
2003 2004
----------------- --------------------
Beginning asset retirement obligation............. $ - $ 776
Additions related to new properties............... 973 132
Deletions related to property disposals........... (576) (128)
Accretion expense................................. 379 108
----------------- --------------------
Ending asset retirement obligation................ $ 776 $ 888
================= ====================
Revenue Recognition and Major Customers
The Company recognizes crude oil and natural gas revenue from its interest
in producing wells as crude oil and natural gas is sold from those wells, net of
royalties. Revenue from the processing of natural gas is recognized in the
period the service is performed. The Company utilizes the sales method to
account for gas production volume imbalances. Under this method, income is
recorded based on the Company's net revenue interest in production taken for
delivery. The Company had no material gas imbalances at December 31, 2004.
During 2002, 2003 and 2004 sales to two customers accounted for
approximately 77%, 80% and 64% of crude oil and natural gas revenues.
Deferred Financing Fees
Deferred financing fees are being amortized on a level yield basis over the
term of the related debt arrangements.
F-14
Assets and Liabilities Held for Sale
The Company holds assets and liabilities related to discontinued operations
as held for sale, in accordance with Statement of Financial Standards No. 144
"Accounting for Impairment of Disposal of Long-Lived Assets" (SFAS 144). The
Company records its assets at the lower of its carrying amount or fair market
value less cost to sell and does not depreciate or amortize the assets while
classified as held for sale.
Income Taxes
The Company records deferred income taxes using the liability method. Under
this method, deferred tax assets and liabilities are determined based on
differences between financial reporting and tax bases of assets and liabilities
and are measured using the enacted tax rates and laws that will be in effect
when the differences are expected to reverse. Valuation allowances are
established when necessary to reduce deferred tax assets to the amounts expected
to be realized.
New Accounting Pronouncements
In September 2004, the Securities and Exchange Commission issued "Staff
Accounting Bulletin No. 106" (SAB No. 106). SAB No. 106 applies to companies
using the full cost method of accounting for oil and gas properties and
equipment costs. SAB No. 106 affects the way in which companies calculate their
full cost ceiling limitation (including asset retirement cost related to proved
developed properties in the calculation of the ceiling) and the way companies
calculate depletion on oil and gas properties (only asset retirement cost for
new recompletions and new wells will be included in future development costs in
calculating depletion rates). The Company does not anticipate that adoption of
SAB No 106 will have a significant impact on its financial position or results
of operations.
In November 2004, the FASB issued SFAS No. 151, entitled " Inventory Costs-
an amendment of ARB 43, chapter. The purpose of this statement is to clarify the
accounting for abnormal amounts of idle facilities expense, freight, handling
cost and wasted material. This statement is effective for inventory costs
incurred during fiscal years beginning after June 15, 2005. The Company is
evaluating the effect of this statement on it's operations and does not expect
it to impact it's financial statements.
In December 2004 the FASB issued "Summary of Statement No. 123 (revised
2004), Share-Based Payment. This statement addresses the accounting for
share-based payment transactions in which an enterprise receives employee
services in exchange for: (1) equity instruments of the enterprise or (2)
liabilities that are based on the fair value of the enterprise's equity
instruments or that may be settled by the issuance of such equity instruments.
The proposed statement would eliminate the ability to account for share-based
compensation transactions using APB Opinion No. 25, "Accounting for Stock Issued
to Employees" and generally would require instead that such transactions be
accounted for using a fair value-based method. As proposed, this statement is be
effective as of the beginning of the first interim or annual reporting period
that begins after June 15, 2005. The Company is currently evaluating what effect
this statement will have on the Company's financial position or results of
operations.
In December 2004 the FASB issued FASB No. 153, entitled " Exchanges of
Nonmonetary Assets - an amendment of ABP Opinion No. 29". The guidance in ABP
Opinion No. 29 is based on the principle that exchanges of nonmonetary assets
should be measured based on the fair value of the assets exchanged. The guidance
in that Opinion, however, included certain exceptions to that principle. This
statement amends Opinion 29 to eliminate the exception for nonmonetary of
similar productive assets and replaces it with a general exception for exchanges
of nonmonetary assets that do not have commercial substance. A nonmonetary
exchange has commercial substance if the future cash flows of the entity are
expected to change significantly as a result of the exchange. The statement is
effective for nonmonetary exchanges occurring in fiscal periods beginning after
June 15, 2005. The Company does not anticipate this statement impacting its
financial statements.
2. Discontinued Operations and Subsequent Events
As part of the restructuring operations in 2004 - see Note 3, the Company
approved a plan to dispose of its operations and interest in Grey Wolf. On
February 28, 2005, Abraxas substantially divested its investment in Grey Wolf.
Pursuant to an Underwriting Agreement, the underwriters purchased 17,800,000
common shares of Grey Wolf capital stock from Grey Wolf (the "Treasury Shares"),
and 9,100,000 shares of Grey Wolf common stock owned by Abraxas (the "Secondary
Shares") from Abraxas at a purchase price of CDN $2.80 per share.
F-15
Abraxas also granted to the underwriters an over-allotment option to
purchase from Abraxas, at the underwriters' election, up to an additional
3,902,360 shares of Grey Wolf common stock held by Abraxas (the "Option
Shares"). The over-allotment option may be exercised in whole or in part at any
one time prior to thirty calendar days after the closing date for the IPO. Grey
Wolf utilized the proceeds from the sale of the Treasury Shares to re-pay and
terminate its $35 million term loan and re-pay $1 million in inter-company debt
to Abraxas. Abraxas utilized the $1 million received from Grey Wolf and the
proceeds received from the sale of the Secondary Shares to re-pay outstanding
debt under its $25 million bridge loan. After consummation of the offering,
Abraxas' remaining debt under the bridge loan was $5.4 million - see Note 3. As
part of the approved 2004 disposal plan, the Company's will divest the remaining
3,902,360 shares of Grey Wolf common stock, utilizing the proceeds to retire the
balance of the bridge loan.
On March 24, 2005, the Company was 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 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 the Company's
revolving credit facility to, effectively, zero.
The operations of Grey Wolf, previously reported as a business segment, are
reported as discontinued operations for all periods presented in the
accompanying financial statements and the operating results are reflected
separately from the results of continuing operations. Interest attributable to
discontinued operations represents interest on debt attributable to the Canadian
subsidiary, no general allocation of Abraxas interest was attributed to Grey
Wolf in prior periods. Summarized discontinued operations operating results and
net gain (loss) for the years ended December 31, 2002, 2003 and 2004 were:
Years ended December 31,
------------------------------------------------------------
2002 2003 2004
---------------- ----------------- ------------------
(in thousands)
Total revenue........................................ $ 32,779 $ 8,639 $ 15,082
Income (loss) from operations before income tax...... (93,052) 70,401 3,323
Income tax expense (benefit)......................... (29,697) 377 -
---------------- ----------------- ------------------
Income (loss) from discontinued operations........... $ (63,355) $ 70,024(1) $ 3,323
================ ================= ==================
(1) In 2003, as part of a series of transactions related to a financial
restructuring including an exchange offer, redemption of certain notes
payable and a credit agreement, the Company sold its wholly owned
Canadian subsidiaries. The 2003 statement of operations includes a gain
on the sale of the Canadian subsidiaries in January 2003 of $68.9
million.
Assets and liabilities of discontinued operations were as follows:
December 31,
----------------------------------
2003 2004
-------------- --------------
(in thousands)
Assets:
Cash...................................................................... $ 493 $ 693
Accounts receivable....................................................... 903 2,556
Net property.............................................................. 35,542 45,426
Deferred financing fees................................................... - 3,577
Other..................................................................... 154 348
-------------- --------------
$ 37,092 $ 52,600
============== ==============
Liabilities:
Accounts payable and accrued expenses..................................... $ 1,971 $ 5,262
Long-term debt (1)........................................................ - 60,000
Other..................................................................... 601 1,685
-------------- --------------
$ 2,572 $ 66,947
============== ==============
(1) Includes Abraxas Bridge Loan of $25 million and $35 million related to
Grey Wolf term loan.
F-16
3. Restructuring Transactions
On October 28, 2004, in order to provide the Company with greater
flexibility in conducting its business, including increasing capital spending
and exploiting its additional drilling opportunities, Abraxas refinanced all of
its then existing indebtedness by redeeming its 11 1/2% secured notes due 2007
and terminating its 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 its new $25.0 million second lien increasing rate
bridge loan; and
o the payment to Abraxas by Grey Wolf of $35.0 million from the
proceeds of Grey Wolf's new $35.0 million term loan.
As a part of the refinancing, the Company also entered into a new $15.0
million revolving credit facility, which currently has availability of
approximately $13.0 million.
In connection with the redemption of the previous secured notes, the
Company recognized a $12.6 million gain on extinguishment in 2004.
Also in connection with the restructuring of operations in late 2004, the
Company approved a plan to dispose of its operations and interest in Grey Wolf.
In connection with the Grey Wolf IPO completed in February 2005, 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
shares offered by Abraxas were used to reduce the amount outstanding under its
bridge loan to approximately $5.4 million.
On March 24, 2005, the Company was advised of the underwriter's intent to
exercise 3.5 million of the over allotment shares. See Note 2.
Floating Rate Senior Secured Notes due 2009. In connection with the October
2004 financial restructuring, Abraxas issued $125 million in principal aggregate
amount of Floating Rate Senior Secured Notes due 2009. The new notes will mature
on December 1, 2009 and began accruing interest from the date of issuance,
October 28, 2004 at a per annum floating rate of six-month LIBOR plus 7.50%. The
initial interest rate on the new notes is 9.72% per annum. The interest will be
reset semi-annually on each June 1 and December 1, commencing on June 1, 2005.
Interest is payable semi-annually in arrears on June 1 and December 1 of each
year, commencing on June 1, 2005.
Abraxas' New $15 Million Senior Secured Revolving Credit Facility. On
October 28, 2004, Abraxas entered into an agreement for a new revolving credit
facility having a maximum commitment of $15 million, which includes a $2.5
million subfacility for letters of credit. Availability under the new revolving
credit facility is subject to a borrowing base consistent with normal and
customary natural gas and crude oil lending transactions.
Outstanding amounts under the new revolving 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 stated
maturity date under the new revolving credit facility is October 28, 2008.
Abraxas' New $25 Million Second Lien Increasing Rate Bridge Loan. On
October 28, 2004, Abraxas borrowed $25 million under its new bridge loan.
The balance of the Bridge Loan ($25 million) and the Grey Wolf Term loan
($35 million) as of December 31, 2004 are included in liabilities related to
assets held for sale.
4. Long-Term Debt
As described in Note 3, the 11 1/2% Secured Notes and the Senior Credit
Agreement were refinanced in October 2004.
The following is a brief description of the Company's debt as of December 31,
2003 and 2004, respectively:
F-17
December 31
--------------------------------
2003 2004
--------------------------------
(in thousands)
11.5% Secured Notes due 2007 ...................................... $ 137,258 $ -
Senior Credit Agreement ........................................... 47,391 -
Floating rate senior secured notes due 2009........................ - 125,000
Senior secured revolving credit facility........................... - 1,425
--------------------------------
184,649 126,425
Less current maturities ........................................... - -
--------------------------------
$ 184,649 $ 126,425
================================
Floating Rate Senior Secured Notes due 2009. In connection with the October
2004 financial restructuring, Abraxas issued $125 million in principal aggregate
amount of Floating Rate Senior Secured Notes due 2009. The notes were issued
under an indenture with U.S. Bank National Association.
Abraxas' New $15 Million Senior Secured Revolving Credit Facility. On
October 28, 2004, Abraxas entered into an agreement for a new revolving credit
facility having a maximum commitment of $15 million, which includes a $2.5
million subfacility for letters of credit. Availability under the new revolving
credit facility is subject to a borrowing base consistent with normal and
customary natural gas and crude oil lending transactions.
Outstanding amounts under the new revolving 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 stated
maturity date under the new revolving credit facility is October 28, 2008.
Abraxas' New $25 Million Second Lien Increasing Rate Bridge Loan. On
October 28, 2004, Abraxas borrowed $25 million under its new $25 million bridge
loan.
Interest on the bridge loan currently accrues at a rate of 12.0% per annum
until October 28, 2005, and is payable monthly in cash. Interest on the bridge
loan will thereafter accrue at a rate of 15.0% per annum, and will be payable
in-kind. Subject to earlier termination rights and events of default, the stated
maturity date under the bridge loan is October 28, 2010.
The bridge loan balance of $25 million is included in liabilities related
to assets held for sale. See note 2.
The new revolving credit facility, bridge loan and indenture governing the
notes contain certain restrictions and covenants that, among other things, limit
the Company's ability to incur additional indebtedness, transfer or sell assets,
guarantee debt, and other items. Additionally, the Company must comply with
certain financial covenants and satisfy financial condition tests. The Company
was in compliance with the covenants at December 31, 2004.
The following table represents the maturities of our long-term debt:
Year ending December 31, Amount
2005 -
2006 -
2007 -
2008 $1,425
2009 $ 125,000
-------------
$ 126,425
=============
5. Property and Equipment
The major components of property and equipment, at cost, are as
follows:
Estimated December 31
----------------------------------
Useful Life 2003 2004
----------------- ---------------- -----------------
Years (In thousands)
Crude oil and natural gas properties ........... - $ 288,559 $ 297,647
F-18
Equipment and other ............................ 7 2,749 2,930
---------------- -----------------
$ $ 291,308 $ $ 300,577
================ =================
6. Stockholders' Equity
Common Stock
In 1994, the Board of Directors adopted a Stockholders' Rights Plan and
declared a dividend of one Common Stock Purchase Right ("Rights") for each share
of common stock. The Rights are not initially exercisable. Subject to the Board
of Directors' option to extend the period, the Rights will become exercisable
and will detach from the common stock ten days after any person has become a
beneficial owner of 20% or more of the common stock of the Company or has made a
tender offer or Exchange Offer (other than certain qualifying offers) for 20% or
more of the common stock of the Company.
Once the Rights become exercisable, each Right entitles the holder, other
than the acquiring person, to purchase for $40 a number of shares of the
Company's common stock having a market value of two times the purchase price.
The Company may redeem the Rights at any time for $.01 per Right prior to a
specified period of time after a tender or Exchange Offer. The Rights expired in
November 2004.
Treasury Stock
In March 1996, the Board of Directors authorized the purchase in the open
market of up to 500,000 shares of the Company's outstanding common stock, the
aggregate purchase price not to exceed $3,500,000. During the year ended
December 31, 2000, 38,800 shares with an aggregate cost of $78,000 were
purchased. The Company has not purchased any shares of its common stock for
treasury stock in subsequent years.
7. Stock Option Plans and Warrants
Stock Options
The Company grants options to its officers, directors, and other employees
under various stock option and incentive plans.
The Company's 1994 Long-Term Incentive Plan has authorized the grant of
options to management, employees and directors for up to approximately 6.1
million shares of the Company's common stock. All options granted have ten year
terms and vest and become fully exercisable over three to four years of
continued service at 25% to 33% on each anniversary date. At December 31, 2004
approximately 2.6 million options remain available for grant.
A summary of the Company's stock option activity, and related information
for the three years ended December 31, follows:
2002 2003 2004
----------------------------- ----------------------------- -----------------------------
Options Weighted-Average Options Weighted-Average Options Weighted-Average
(000s) Exercise Price (000s) Exercise Price (000s) Exercise Price
---------- ------------------ ---------- ------------------ --------- ------------------
Outstanding-beginning of
year ................... 4,942 $ 3.28 3,305 $ 1.85 3,364 $ 0.90
Granted ................... 521 0.68 360 0.68 - -
Exercised ................. - - (129) 0.66 (414) 0.69
Forfeited/Expired ......... (2,158) 4.84 (172) 1.61 (57) 0.77
---------- ---------- ---------
Outstanding-end of year ... 3,305 $ 1.85 3,364 $ 0.90 2,893 $ 0.93
========== ========== =========
Exercisable at end of year 2,136 $ 1.91 2,331 $ 0.95 2,327 $ 0.97
========== ========== =========
Weighted-average fair
value of options
granted during the year $ 0.63 $ 0.38 $ 0.00
F-19
The following table represents the range of option prices and the
weighted average remaining life of outstanding options as of December 31, 2004:
Options outstanding Exercisable
----------------------------------------------- --------------------------------------
Weighted Weighted
average average
Number remaining exercise Number Weighted average
Exercise price outstanding life price exercisable exercise price
--------------------- ------------------ --------------- ------------ ---------------- ---------------------
$ 0.50 - 0.97 2,294,719 5.1 $ 0.69 1,818,472 $ 0.70
$ 1.01 - 1.63 257,500 6.8 1.22 176,875 1.31
$ 2.06 - 2.21 311,358 2.3 2.07 309,269 2.07
$ 4.83 30,001 6.2 4.83 22,501 4.83
In January 2003, in connection with the financial restructuring,
approximately 1.9 million options with a strike price greater that $0.66 were
re-priced to $0.66.
Stock Awards
In addition to stock options granted under the plan described above, the
1994 Long-Term Incentive Plan also provides for the right to receive
compensation in cash, awards of common stock, or a combination thereof. There
were no awards in 2002, 2003 or 2004.
The Company also has adopted the Restricted Share Plan for Directors which
provides for awards of common stock to non-employee directors of the Company who
did not, within the year immediately preceding the determination of the
director's eligibility, receive any award under any other plan of the Company.
There were no direct awards of common stock in 2002, 2003 or 2004.
Stock Warrants
In 2000, the Company issued 950,000 warrants in conjunction with a
consulting agreement. Each is exercisable for one share of common stock at an
exercise price of $3.50 per share. These warrants had a four-year term beginning
July 1, 2000. and expired on June 30, 2004.
In October 2004, the Company issued 1.1 million warrants in conjunction
with the refinancing. Each is exercisable for one share of common stock at an
exercise price of $0.01 per share. These warrants have a ten year term.
At December 31, 2004, the Company has approximately 4.0 million shares
reserved for future issuance for conversion of its stock options, warrants, and
incentive plans for the Company's directors, employees and consultants.
8. Income Taxes
Deferred income taxes reflect the net tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts used for income tax purposes. Significant components of
the Company's deferred tax liabilities and assets are as follows:
December 31
---------------------------
2003 2004
------------- -------------
(In thousands)
Deferred tax liabilities:
U.S. full cost pool ..................................................... $ 4,835 $ 7,310
------------- -------------
Total deferred tax liabilities ............................................ 4,835 7,310
Deferred tax assets:
Capital loss carryforward................................................ 12,895 11,913
F-20
Original issue discount on certain debt obligations...................... 22,453 -
Depletion ............................................................... 4,856 3,232
Net operating losses ("NOL")............................................ 35,218 64,408
Investment in foreign subsidiaries....................................... - 2,426
Other ................................................................... 2,575 4,432
------------- -------------
Total deferred tax assets ................................................. 77,997 86,366
Valuation allowance for deferred tax assets ............................... (73,162) (72,996)
------------- -------------
Net deferred tax assets ................................................... 4,835 13,370
------------- -------------
Net deferred tax liabilities (assets) ..................................... $ - $ (6,060)
============= =============
Significant components of the provision (benefit) for income taxes are
as follows:
2002 2003 2004
-----------------------------------------
(in thousands)
Current:
Federal.......................................................... $ - $ - $ -
Foreign ......................................................... - - -
-----------------------------------------
$ - $ - $ -
=========================================
Deferred:
Federal ......................................................... $ - $ - $ 6,060
Foreign ......................................................... 29,697 377 -
-----------------------------------------
29,697 377 6,060
Attributable to discontinued operations.......................... (29,697) (377) -
-----------------------------------------
Attributable to continuing operations............................ $ - $ - $ 6,060
=========================================
At December 31, 2004 the Company had, subject to the limitation discussed
below, $184 million of net operating loss carryforwards for U.S. tax purposes.
These loss carryforwards will expire from 2004 through 2022 if not utilized.
In addition to the Section 382 limitations, uncertainties exist as to the
future utilization of the operating loss carryforwards under the criteria set
forth under FASB Statement No. 109. Therefore, the Company has established a
valuation allowance of $73.2 million and $73.0 million for deferred tax assets
at December 31, 2003 and 2004, respectively.
The reconciliation of income tax computed at the U.S. federal statutory tax
rates to income tax expense is:
December 31
---------------------------------------------------------------------
2002 2003 2004
-------------------------------------------- ------------------------
(in thousands)
Tax (expense) benefit at U.S. statutory
rates (35%) ............................ $ 51,878 $ (19,842) $ (1,875)
(Increase) decrease in deferred tax asset
valuation allowance .................... (59,456) 22,993 8,123
Write-down of non-tax basis assets...... (7,009) - -
Higher effective rate of foreign 7,349 (2,835) (140)
operations............................
Percentage depletion ................... 683 - -
Investment in foreign subsidiaries .... 35,604 - -
Other .................................. 648 (693) (48)
--------------------- ----------------------- ------------------------
$ 29,697 $ (377) $ 6,060
Attributable to discontinued operations (29,697) 377 -
--------------------- ----------------------- ------------------------
Attributable to continuing operations.. $ - $ - $ 6,060
===================== ======================= ========================
9. Related Party Transactions
Accounts receivable - Other includes approximately $35,558 and $0 as of
December 31, 2003 and 2004, respectively, representing amounts due from officers
relating to advances made to employees.
F-210
10. Commitments and Contingencies
Operating Leases
During the years ended December 31, 2002, 2003 and 2004 the Company
incurred rent expense related to leasing office facilities of approximately
$236,000, $246,650 and $256,355 respectively. Future minimum rental payments are
as follows at December 31, 2004.
2005............................................. $ 254,004
2006............................................. 83,908
Thereafter....................................... -
------------------
$ 337,912
==================
Litigation and Contingencies
In 2001, the Company 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 the
Company and the Partnership related to the responsibility for year 2000 ad
valorem taxes on crude oil and natural gas properties sold by the Company and
the Partnership. In February 2002, a summary judgment was granted to the
plaintiff in this matter and a final judgment in the amount of $1.3 million was
entered. The Company and the Partnership 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).
The Company has decided not to pursue further appeals and subsequent to December
31, 2004, paid its portion of the final judgment, approximately $1 million, for
which the Company had previously established a reserve.
Additionally, from time to time, the Company is involved in litigation
relating to claims arising out of its operations in the normal course of
business. At December 31, 2004 the Company was not engaged in any legal
proceedings that are expected, individually or in the aggregate, to have a
material adverse effect on the Company.
11. Earnings per Share
Basic earnings (loss) per share excludes any dilutive effects of options,
warrants and convertible securities and is computed by dividing income (loss)
available to common stockholders by the weighted average number of common shares
outstanding for the period. Diluted earnings (loss) per share are computed
similar to basic, however diluted earnings per share reflects the assumed
conversion of all potentially dilutive securities.
The following table sets forth the computation of basic and diluted
earnings per share:
2002 2003 2004
--------------------------------------------------------
Numerator:
Net income (loss) before effect of discontinued
operations and accounting change .............. $ (55,172,000) $ (14,104,000) $ 7,844,000
Discontinued operations........................... (63,355,000) 70,024,000 3,323,000
Cumulative effect of accounting change........... - (395,000) -
--------------------------------------------------------
$(118,527,000) 55,920,000 11,167,000
Denominator:
Denominator for basic earnings per share -
weighted-average shares ........................ 29,979,397 35,364,363 36,221,887
Effect of dilutive securities:
Stock options and warrants..................... - - 2,672,778
--------------------------------------------------------
F-22
Dilutive potential common shares Denominator for
diluted earnings per share - adjusted
weighted-average shares and assumed
exercise of options and warrants................ 29,979,397 35,364,363 38,894,665
========================================================
Basic earnings (loss) per share:
Net income (loss) before effect of discontinued
operations and accounting change.................. $ (1.84) $ (0.39) $ 0.22
Discontinued operations (2.11) 1.98 0.09
Cumulative effect of accounting change.......... - (0.01) -
--------------------------------------------------------
Net income (loss) per common share................ $ (3.95) $ 1.58 $ 0.31
========================================================
Diluted earnings (loss) per share:
Net income (loss) before effect of discontinued
operations and accounting change.................e $ (1.84) $ (0.39) $ 0.20
Discontinued operations........................... (2.11) 1.98 0.09
Cumulative effect of accounting change.......... - (0.01) -
--------------------------------------------------------
Net income (loss) per common share - diluted. $ (3.95) $ 1.58 $ 0.29
========================================================
For the year ended December 31, 2002, and 2003 5.9 million and 711,000
shares were excluded from the calculation of diluted earnings per share since
their inclusion would have been anti-dilutive.
12. Quarterly Results of Operations (Unaudited)
Selected results of operations for each of the fiscal quarters during the
years ended December 31, 2003 and 2004 are as follows:
1st 2nd 3rd 4th
Quarter Quarter Quarter Quarter
---------------- ---------------- --------------- ----------------
(In thousands, except per share data)
Year Ended December 31, 2003
Net revenue - as previously reported.. $ 13,111 $ 8,430 $ 8,430 $ 9,048
Net revenue - discontinued operations. (4,312) (1,212) (1,254) (1,861)
---------------- ---------------- --------------- ----------------
Net revenue - continuing operations... 8,799 7,218 7,176 7,187
Operating income (loss) - as
previously reported................. 5,646 1,927 2,694 1,275
Operating income (loss) -
discontinued operations............. (2,243) (288) (279) (12)
---------------- ---------------- --------------- ----------------
Operating income (loss) - continuing
operations.......................... 3,403 1,639 2,415 1,263
Net income (loss)..................... 62,702 (2,346) (2,702) (1,734)
Net income (loss) per common share -
basic............................... $ 1.83 $ (0.07) $ (0.08) $ (0.05)
Net income (loss) per common share -
diluted............................. $ 1.82 $ (0.07) $ (0.08) $ (0.05)
Year Ended December 31, 2004
Net revenue - as previously reported.. $ 10,935 $ 12,267 $ 11,783 $ 13,951
Net revenue - discontinued operations. (2,975) (3,763) (3,546) (4,798)
---------------- ---------------- --------------- ----------------
Net revenue - continuing operations... 7,960 8,504 8,237 9,153
Operating income (loss) as previously
reported............................ 983 5,707 3,202 6,342
Operating income (loss) -
discontinued operations............. (407) (860) (1,365) (2,140)
---------------- ---------------- --------------- ----------------
Operating income (loss) continuing
operations.......................... 576 4,847 1,837 3,712
Net income (loss)..................... (5,557) 372 (1,643) 17,995
Net income (loss) per common share -
basic............................... $ (0.15) $ 0.01 $ (0.05) $ 0.50
Net income (loss) per common share -
diluted............................. $ (0.15) $ 0.01 $ (0.05) $ 0.47
F-23
13. Benefit Plans
The Company has a defined contribution plan (401(k)) covering all eligible
employees of the Company. The Company matched employee contributions in 2004.
The Company did not contribute to the plan in 2002 or 2003. The employee
contribution limitations are determined by formulas, which limit the upper
one-third of the plan members from contributing amounts that would cause the
plan to be top-heavy. The employee contribution is limited to the lesser of 20%
of the employee's annual compensation or $12,000 in 2003 and $13,000 in 2004.
The contribution limit for 2004 was $16,000 for employees 50 years of age or
older.
14. Hedging Program and Derivatives
On January 1, 2001, the Company adopted SFAS 133 "Accounting for Derivative
Instruments and Hedging Activities" SFAS 133 as amended by SFAS 137 "Accounting
for Derivative Instruments and Hedging Activities - Deferral of the Effective
Date of FASB 133" and SFAS 138 "Accounting for Certain Derivative Instruments
and Certain Hedging Activities. In 2003 the Company elected out of hedge
accounting as prescribed by SFAS 133. Accordingly, instruments are recorded on
the balance sheet at their fair value with adjustments to the carrying value of
the instruments bring recognized in oil and gas income in the current period.
Under the terms of the Company's revolving credit facility, the Company
is required to maintain hedging agreements with respect to not less than 25% nor
more than 75% of it crude oil and natural gas production for a rolling six month
period. As of December 31, 2004 the Company's hedging positions were as follows:
Time Period Notional Quantities Price
- ---------------------------------- -------------------------------------------- ----------------------
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
February 2005 7,100 MMbtu of production per day Floor of $4.50
400 Bbls of crude oil production per day Floor of $25.00
March 2005 7,100 MMbtu of production per day Floor of $4.50
400 Bbls of crude oil production per day Floor of $25.00
April 2005 7,100 MMbtu of production per day Floor of $4.50
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
All hedge transactions are subject to the Company's risk management policy,
approved by the Board of Directors. The Company formally documents all
relationships between hedging instruments and hedged items, as well as its risk
management objectives and strategy for undertaking the hedge. This process
includes specific identification of the hedging instrument and the hedged
transaction, the nature of the risk being hedged and how the hedging
instrument's effectiveness will be assessed. Both at the inception of the hedge
and on an ongoing basis, the Company assesses whether the derivatives that are
used in hedging transactions are effective in offsetting changes in cash flows
of hedged items.
15. Proved Property Impairment
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, or alternatively, if prices subsequent to that date have
increased, a price near the periodic filing date of the Company's financial
statements. During the second quarter of 2002, the Company had a ceiling
limitation write-down of approximately $28.2 million related to continuing
operations. At December 31, 2003 and 2004, the net capitalized cost of crude oil
and natural gas properties, plus the cost of properties not being amortized and
the lower of cost of fair value of unproved properties being included in cost
being amortized, less related income taxes did not exceed the present value of
our estimated reserves, as such, no write-down was recorded.
F-24
16. Supplemental Oil and Gas Disclosures (Unaudited)
The accompanying table presents information concerning the Company's crude
oil and natural gas producing activities from continuing operations as required
by Statement of Financial Accounting Standards No. 69, "Disclosures about Oil
and Gas Producing Activities." Capitalized costs relating to oil and gas
producing activities from continuing operations are as follows:
Years Ended December 31,
2003 2004
---------------- ---------------
(In thousands)
Proved crude oil and
natural gas properties ... $ 288,559 $ 297,647
Unproved properties ........ - -
---------------- ---------------
Total..................... 288,559 297,647
Accumulated depreciation,
depletion, and
amortization, and
impairment ............... (212,609) (219,726)
---------------- ---------------
Net capitalized costs .. $ 75,950 $ 77,921
================ ===============
Cost incurred in oil and gas property acquisitions and development
activities related to continuing operations are as follows:
Years Ended December 31,
-------------------------------------------
2002 2003 2004
-------------- -------------- -------------
(In Thousands)
-------------------------------------------
Property acquisition costs:
Proved ...................... $ - $ - $ -
Unproved .................... - - -
-------------- -------------- -------------
$ - $ - $ -
============== ============== =============
Property development and
exploration costs ........... $ 4,944 $ 9,158 $ 9,088
============== ============== =============
The results of operations for oil and gas producing activities from
continuing operations for the three years ending December 31, 2002, 2003 and
2004, respectively are as follows:
Years Ended December 31,
-------------------------------------------
2002 2003 2004
-------------- ------------- -------------
(In thousands)
Revenues ................... $ 20,835 $ 29,710 $ 33,073
Production costs ........... (7,639) (8,342) (8,567)
Depreciation, depletion,
and amortization ......... (8,879) (7,428) (7,117)
Proved property impairment . (28,178) - -
General and administrative . (1,011) (998) (1,281)
-------------- ------------- -------------
Results of operations from oil
and gas producing activities
(excluding corporate overhead
and interest costs) .......... $ (24,872) $ 12,942 $ 16,108
============== ============= =============
Depletion rate per barrel
of oil equivalent, before
impact of impairment ..... $ 7.55 $ 7.24 $ 7.39
============== ============= =============
F-25
Estimated Quantities of Proved Oil and Gas Reserves
The following table presents the Company's estimate of its net proved crude
oil and natural gas reserves as of December 31, 2002, 2003, and 2004 related to
continuing operations. The Company's management emphasizes that reserve
estimates are inherently imprecise and that estimates of new discoveries are
more imprecise than those of producing oil and gas properties. Accordingly, the
estimates are expected to change as future information becomes available. The
estimates have been prepared by independent petroleum reserve engineers.
Liquid Natural
Hydrocarbons Gas
------------------ --------------
(Barrels) (Mcf)
(In thousands)
Proved developed and undeveloped reserves:
Balance at December 31, 2001...................... 4,407 108,468
Revisions of previous estimates ................ (64) (14,986)
Production ..................................... (264) (5,733)
Sale of minerals in place ...................... (843) (9,553)
------------------ --------------
Balance at December 31, 2002 ..................... 3,236 78,196
Revisions of previous estimates ................ 268 6,759
Extensions and discoveries ..................... 44 28
Production ..................................... (229) (4,781)
------------------ --------------
Balance at December 31, 2003...................... 3,319 80,202
Revisions of previous estimates ................ (60) (754)
Extensions and discoveries ..................... 70 73
Production ..................................... (229) (4,403)
------------------ --------------
Balance at December 31, 2004...................... 3,101 75,118
================== ==============
Liquid Natural
Hydrocarbons Gas
------------------ --------------
(Barrels) (Mcf)
Proved developed reserves:
December 31, 2002 ................................ 1,754 34,776
================== ==============
December 31, 2003................................. 1,887 39,371
================== ==============
December 31, 2004................................. 1,878 36,241
================== ==============
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves
The following disclosures concerning the standardized measure of future
cash flows from proved crude oil and natural gas are presented in accordance
with SFAS No. 69. The standardized measure does not purport to represent the
fair market value of the Company's proved crude oil and natural gas reserves. An
estimate of fair market value would also take into account, among other factors,
the recovery of reserves not classified as proved, anticipated future changes in
prices and costs, and a discount factor more representative of the time value of
money and the risks inherent in reserve estimates.
Under the standardized measure, future cash inflows were estimated by
applying period-end prices at December 31, 2004 adjusted for fixed and
determinable escalations, to the estimated future production of year-end proved
reserves. Future cash inflows were reduced by estimated future production and
development costs based on year-end costs to determine pre-tax cash inflows.
Future income taxes were computed by applying the statutory tax rate to the
excess of pre-tax cash inflows over the tax basis of the properties. Operating
loss carryforwards, tax credits, and permanent differences to the extent
F-26
estimated to be available in the future were also considered in the future
income tax calculations, thereby reducing the expected tax expense.
Future net cash inflows after income taxes were discounted using a 10%
annual discount rate to arrive at the Standardized Measure.
Set forth below is the Standardized Measure relating to proved oil and gas
reserves relating to continuing operations for the three years ending December
31, 2002, 2003 and 2004.
Years Ended December 31,
------------------------------------------------------
2002 2003 2004
------------------------------------------------------
(in Thousands)
Future cash inflows ... $ 389,061 $ 512,797 $ 498,165
Future production and
development costs ... (158,507) (179,036) (194,187)
Future income tax
expense ............. - - -
------------------------------------------------------
Future net cash flows . 230,554 333,761 303,978
Discount .............. (120,238) (172,177) (154,943)
------------------------------------------------------
Standardized Measure
of discounted future
net cash relating to
proved reserves ..... $ 110,316 $ 161,584 $ 149,035
======================================================
F-27
F-29 Changes in Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
The following is an analysis of the changes in the Standardized Measure
related to continuing operations:
Year Ended December 31
----------------------------------------------------------
2002 2003 2004
------------------- ------------------- ------------------
(In thousands)
Standardized Measure, beginning
of year ................................. $ 77,187 $ 110,316 $ 161,584
Sales and transfers of oil and gas
produced, net of production costs ....... (13,196) (21,368) (24,506)
Net changes in prices and development
and production costs from prior year .... 56,447 42,398 (2,814)
Extensions, discoveries, and improved
recovery, less related costs ............ - 471 810
Purchase of minerals in place.............. - 313 -
Sales of minerals in place ................ (9,089) - -
Revision of previous quantity estimates ... (9,581) 9,351 (1,818)
Other ..................................... 829 9,071 (380)
Accretion of discount ..................... 7,719 11,032 16,159
------------------- ------------------- ------------------
Standardized Measure, end of year ....... $ 110,316 $ 161,584 $ 149,035
=================== =================== ==================
F-28
17. Restatement - Year Ended December 31, 2002
In January 2003, the Company sold its wholly-owned Canadian subsidiaries as
part of a series of transactions related to a financial restructuring.
Subsequent to the original issuance of its consolidated financial statements for
the year ended December 31, 2002, the Company's management determined that the
wholly-owned Canadian subsidiaries should not have been presented as
discontinued operations. As a result, in July 2003 the consolidated statements
of operations and cash flows for the year ended December 31, 2002 were restated
to present results of operations and cash flows as components of continuing
operations.
As discussed in Note 2, during 2004 the business segment containing the
Grey Wolf operations was discontinued.
A summary of the significant effects of the restatement and subsequent
discontinued operations is as follows:
For the Year Ended December 31, 2002
------------------------------------------------
As As Restated As Reported
Originally
Reported Herein
-------------- ------------- --------------
(in thousands)
Revenues:
Oil and gas production revenue................ $21,601 $ 50,862 $ 20,835
Gas processing revenue....................... - 2,420 -
Rig revenue.................................. 635 635 635
Other........................................ 71 403 71
-------------- ------------- --------------
22,307 54,320 21,541
Operating costs and expenses:
Lease operating and production taxes......... 7,910 15,240 7,639
Depreciation, depletion and amortization..... 9,654 26,539 9,194
Proved property impairment................... 32,850 115,993 28,178
Rig operations............................... 567 567 567
General and administrative................... 5,082 6,884 4,045
Stock-based compensation..................... - - -
-------------- ------------- --------------
56,063 165,223 49,623
-------------- ------------- --------------
Operating loss.................................. (33,756) (110,903) (28,082)
Other (income) expense:
Interest income.............................. (92) (92) (92)
Amortization of deferred financing fees...... 1,325 2,095 1,325
Interest expense............................. 24,689 34,150 24,689
Financing costs.............................. 967 967 967
(Gain) loss on sale of equity investment..... - - -
Other........................................ 201 201 201
-------------- ------------- --------------
27,090 37,321 27,090
-------------- ------------- --------------
Income loss before income tax.................. (60,846) (148,224) (55,172)
Income tax expense (benefit):
Current...................................... - - -
Deferred..................................... - (29,697) -
Loss from discontinued operations............... (57,681) - (63,355)
-------------- ------------- --------------
Net loss........................................ $(118,527) $(118,527) $ (118,527)
============== ============= ==============
F-29