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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, 2003
[ ]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
Commission File Number 0-19118
ABRAXAS PETROLEUM CORPORATION
-----------------------------
(Exact name of Registrant as specified in its charter)
Nevada 74-2584033
- -------------------------------------------------------------------------------
(State or Other Jurisdiction of (I.R.S. Employer Identification Number)
Incorporation or Organization)
500 N. Loop 1604 East, Suite 100
San Antonio, Texas 78232
(Address of principal executive offices)
Registrant's telephone number,
including area code (210) 490-4788
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Common Stock, par value $.01 per share
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No__
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ X ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act) [ ] Yes [X] No
The aggregate market value of the voting stock (which consists solely of
shares of common stock) held by nonaffiliates of the registrant as June 30,
2003, based upon the closing per share price of $1.08, was approximately
$30,917,000 on such date.
The number of shares of the issuer's common stock, par value $.01 per
share, outstanding as of March 9, 2004 was 36,267,337 shares of which 29,068,400
shares were held by non-affiliates.
Documents Incorporated by Reference: Portions of the registrant's Proxy
Statement relating to the 2004 Annual Meeting of Shareholders to be held on May
21, 2004 have been incorporated by reference herein (Part III).
ABRAXAS PETROLEUM CORPORATION
FORM 10-K
TABLE OF CONTENTS
PART I
Page
Item 1. Business............................................................5
General............................................................5
Markets and Customers..............................................6
Risk Factors.......................................................7
Regulation of Crude Oil and Natural Gas Activities................13
Canadian Royalty Matters..........................................15
Environmental Matters ...........................................17
Title to Properties...............................................19
Employees.........................................................19
Item 2. Properties.........................................................19
Primary Operating Areas...........................................19
Exploratory and Developmental Acreage.............................20
Productive Wells..................................................21
Reserves Information..............................................21
Crude Oil, Natural Gas Liquids and Natural Gas
Production and Sales Price .....................................23
Drilling Activities...............................................24
Office Facilities.................................................24
Other Properties..................................................25
Item 3. Legal Proceedings.................................................25
Item 4. Submission of Matters to a Vote of Security Holders...............25
Item 4A. Executive Officers of Abraxas.....................................25
PART II
Item 5. Market for Registrant's Common Equity
and Related Stockholder Matters.................................27
Market Information................................................27
Holders...........................................................27
Dividends.........................................................27
Recent Sales of Unregistered Securities...........................27
Item 6. Selected Financial Data...........................................28
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.............................28
General........................................................28
Results of Operations..........................................31
Liquidity and Capital Resources................................35
Critical Accounting Policies...................................41
New Accounting Pronouncements..................................44
Item 7A. Quantitative and Qualitative Disclosures about Market Risk........46
Item 8. Financial Statements and Supplementary Data.......................47
3
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure.....................................48
Item 9A. Controls and Procedures..........................................48
PART III
Item 10. Directors and Executive Officers of the Registrant ..............48
Item 11. Executive Compensation............................................49
Item 12. Security Ownership of Certain Beneficial Owners and Management....49
Item 13. Certain Relationships and Related Transactions....................49
Item 14. Principal Accountant Fees and Services ...........................49
PART IV
Item 15. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K........................................49
SIGNATURES.......................................................54
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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 when
we describe what we "believe," "expect" or "anticipate" will occur or what we
"intend" to do, and other similar statements), you must remember 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 "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 ability to raise capital;
o our limited liquidity;
o economic and business conditions;
o price and availability of alternative fuels;
o political and economic conditions in oil producing countries,
especially those in the Middle East;
o our success in development, exploitation and exploration
activities;
o planned capital expenditures;
o prices for crude oil and natural gas;
o declines in our production of crude oil and natural gas;
o our acquisition and divestiture activities;
o results of our hedging activities; and
o other factors discussed elsewhere in this document.
PART I
Item 1. Business
General
Abraxas Petroleum Corporation is an independent energy company engaged
primarily in the acquisition, development, exploitation and production of crude
oil and natural gas. Our principal means of growth has been through the
acquisition and subsequent development and exploitation of producing properties.
As a result of our historical acquisition activities, we believe that we have a
substantial inventory of low risk exploitation and development opportunities,
the successful completion of which is critical to the maintenance and growth of
our current production levels.
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
natural gas liquids and MBbls is used to designate one thousand barrels of crude
oil or natural gas liquids.
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Our principal areas of operation are Texas and western Canada. At December
31, 2003, we owned interests in 263,730 gross acres (183,354 net acres), and
operated properties accounting for approximately 88% of our PV-10, affording us
substantial control over the timing and incurrence of operating and capital
expenditures. At December 31, 2003 estimated total proved reserves were 121.1
Bcfe with an aggregate PV-10 of $216.8 million. During 2003, we continued
exploitation activities on our U.S. and Canadian properties. We participated in
the drilling of 24 gross (11.8 net) wells with 23 gross (11.3 net) being
successful. The Company invested $18.3 million in capital spending on these
activities during 2003. At the end of 2003, as a result of these activities, our
average daily production was approximately 24 MMcfe per day which represented a
26% increase from the daily production rate at the beginning of the year
(excluding production from the Canadian properties sold in January 2003).
In January 2003, we completed the following restructuring transactions:
o The closing of the sale of the capital stock of our wholly-owned
subsidiaries Canadian Abraxas Petroleum Limited, referred to herein
as Canadian Abraxas, and Grey Wolf Exploration Inc., referred to
herein as Old Grey Wolf, to a Canadian royalty trust for
approximately $138 million.
o The closing of a new senior credit agreement consisting of a term
loan facility of $4.2 million and a revolving credit facility of up
to $50 million with an initial borrowing base of $49.9 million, of
which $42.5 million was used to fund the exchange offer described
below and the remaining availability funded the continued
development of our existing crude oil and natural gas properties.
o The closing of an exchange offer, pursuant to which Abraxas paid
$264 in cash and issued $610 principal amount of new 11 1/2 %
Secured Notes due 2007, Series A, referred to herein as New Notes,
and 31.36 shares of Abraxas common stock for each $1,000 in
principal amount of the outstanding 11 1/2 % Senior Secured Notes
due 2004, Series A, and 11 1/2 % Senior Notes due 2004, Series D,
issued by Abraxas and Canadian Abraxas, which were tendered and
accepted in the exchange offer. An aggregate of approximately
$179.9 million in principal amount of the notes were tendered in
the exchange offer and the remaining $11.1 million of notes not
tendered were redeemed.
o The repayment of Abraxas' 12? % Senior Secured Notes due 2003,
principal amount of $63.5 million, plus accrued interest.
o The repayment of Old Grey Wolf's senior secured credit facility
with Mirant Canada Energy Capital Ltd. (Mirant Canada Facility) in
the amount of approximately $46.3 million.
As a result of these transactions, we reduced the principal amount of our total
outstanding long-term debt from approximately $300 million at December 31, 2002
to approximately $156.4 million at January 23, 2003 ($184.6 million at December
31, 2003) and reduced our annual cash interest payment from approximately $34
million to approximately $4 million, assuming that, as required under the senior
credit agreement, Abraxas continues to issue additional notes in lieu of cash
interest payments on the New Notes.
On February 23, 2004, we entered into an amendment to our existing senior
credit agreement providing for two revolving credit facilities and a new
non-revolving credit facility. Subject to earlier termination on the occurrence
of events of default or other events, the stated maturity date for these credit
facilities is February 1, 2007. We have included a detailed summary of our
amended senior credit agreement in "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Liquidity and Capital Resources
- - Long-Term Indebtedness - Senior Credit Agreement".
Markets and Customers
The revenue generated by our operations is highly dependent upon the prices
of, and demand for, crude oil and natural gas. Historically, the markets for
crude oil and natural gas have been volatile and are likely to continue to be
volatile in the future. The prices we receive for our crude oil and natural gas
production and the level of such production are subject to wide fluctuations and
depend on numerous factors beyond our control including seasonality, the
6
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 crude oil and natural gas 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 - Crude oil and natural gas prices and their volatility
could adversely effect our revenues, cash flows and profitability" and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Critical Accounting Policies" for more information relating to the
effects on us of decreases in crude oil and natural gas prices.
In order to manage our exposure to price risks in the marketing of our
crude oil and natural gas, from time to time we have entered into fixed price
delivery contracts, financial swaps and crude oil and natural gas futures
contracts as hedging devices. To ensure a fixed price for future production, we
may sell a futures contract and thereafter either (i) make physical delivery of
crude oil or natural gas to comply with such contract or (ii) buy a matching
futures contract to unwind our futures position and sell our production to a
customer. These contracts may expose us to the risk of financial loss in certain
circumstances, including instances where production is less than expected, our
customers fail to purchase or deliver the contracted quantities of crude oil or
natural gas, or a sudden, unexpected event materially impacts crude oil or
natural gas prices. These contracts may also restrict our ability to benefit
from unexpected increases in crude oil and natural gas prices. You should read
the discussion under "Management's Discussion and Analysis of Financial
Condition And Results of Operations -- Liquidity and Capital Resources," and
"Quantitative and Qualitative Disclosures about Market Risk; Commodity Price
Risk" for more information regarding our historical hedging activities.
Substantially all of our crude oil and natural gas is sold at current
market prices under short-term arrangements, as is customary in the industry.
During the year ended December 31, 2003 three purchasers accounted for
approximately 80% of our United States crude oil and natural gas sales and three
customers accounted for approximately 91% of our crude oil and natural gas sales
in Canada. We believe that there are numerous other companies available to
purchase our crude oil and natural gas and that the loss of one or more of these
purchasers would not materially affect our ability to sell crude oil and natural
gas. The prices we realize for the sale of our crude oil and natural gas are
subject to our hedging activities. You should read the discussion under
"Management's Discussion and Analysis of Financial Condition And Results of
Operations -- Liquidity and Capital Resources" and "Quantitative and Qualitative
Disclosures about Market Risk; Commodity Price Risk" for more information
regarding our historical hedging activities.
Risk Factors
Risks Related to Our Company
Our reduced operating cash flow resulting from the sale of Canadian Abraxas
and Old Grey Wolf may put significant strain on our liquidity and cash position.
Our reduced operating cash flow and resulting limited liquidity has caused us,
and the limitations imposed by our senior credit agreement and the New Notes
will cause us, to reduce capital expenditures, including exploitation and
development projects. These reductions will limit our ability to replenish our
depleting reserves, which could negatively impact our cash flow from operations
and results of operations in the future. In addition, under the terms of the New
Notes, we are required, to the extent permitted, to pay down debt under our
senior credit agreement and, if permitted, the New Notes, with our cash flow
which is not required to pay our capital expenditures or make cash interest and
tax payments.
The effects of our reduced operating cash flow will be exacerbated by our
high level of debt, which will affect our operations in several important ways,
including:
o A portion of our cash flow from operations could be required to
make principal and interest payments on our outstanding
indebtedness and may not be available for other purposes, including
developing our properties;
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o The covenants contained in the indenture governing the New Notes
and in the senior credit agreement will limit our ability to borrow
additional funds or to dispose of assets or use the proceeds of any
asset sales and may affect our flexibility in planning for, and
reacting to, changes in our business; and
o Our debt level may impair our ability to obtain additional
financing in the future for working capital, capital expenditures,
acquisitions, interest payments, scheduled principal payments,
general corporate purposes or other purposes.
Our limited liquidity and restrictions on uses of cash dictated by both our
senior credit agreement and the New Notes, combined with our high debt levels,
may hinder our ability to satisfy the substantial capital requirements related
to our operations. The success of our future operations will require us to make
substantial capital expenditures for the exploitation, development and
production of crude oil and natural gas.
Under the terms of the senior credit agreement and the New Notes, Abraxas
is subject to cash and expenditures covenants including limitations on capital
expenditures. These limitations will have the effect of limiting our ability to
develop our crude oil and natural gas properties because much of our cash flow
may be used for debt service. As a result, our ability to replace production may
be limited. You should read the discussion under "Our ability to replace
production with new reserves is highly dependent on acquisitions or successful
development and exploration activities" for more information regarding the risks
associated with limitations on our ability to develop our crude oil and natural
gas properties.
Hedging transactions may limit our potential gains. Under the terms of the
senior credit agreement, we are required to maintain commodity price hedging
positions on not less than 40% and not more than 75% of our estimated production
for a rolling six-month period. As of December 31, 2003 we had floors in place
as follows:
Time Period Notional Quantities Price
- -----------------------------------------------------------------------------
March 1, 2003 - February 29, 5,000 MMBtu of natural gas Floor of $4.50
2004 production per day
March 1, 2004 - April 30, 2004 2,000 MMBtu of natural gas Floor of $4.00
production per day
March 1, 2004 - April 30, 2004 500 Bbls of crude oil Floor of $22.00
production per day
May 2004 2,000 MMbtu of natural gas Floor of $4.00
production per day
May 2004 500 Bbls of crude oil Floor of $22.00
production per day
June 2004 800 Bbls of crude oil Floor of $22.00
production per day
July 2004 2,000 MMbtu of natural gas Floor of $4.00
production per day
July 2004 500 Bbls of crude oil Floor of $22.00
production per day
Subsequent to year-end, we have entered into additional agreements similar
to those scheduled above (floors) in volume amounts sufficient to reach the 40%
threshold required by our senior credit agreement. We anticipate continuing to
purchase similar floors in the future to satisfy our requirements under the
senior credit agreement.
We cannot assure you that our hedging transactions will reduce risk or
minimize the effect of any decline in crude oil or natural gas prices. Any
substantial or extended decline in crude oil or natural gas prices would have a
material adverse effect on our business and financial results. Hedging
activities may limit the risk of declines in prices, but such arrangements may
also limit, and have in the past limited, additional revenues from price
increases. In addition, such transactions may expose us to risks of financial
loss under certain circumstances, such as:
o production being less than expected; or
8
o price differences between delivery points for our production and
those in our hedging agreements increasing.
In 2001, 2002 and 2003, we experienced hedging losses of $12.1 million,
$3.2 million and $842,000, respectively.
Our ability to replace production with new reserves is highly dependent on
acquisitions or successful development and exploitation activities. The rate of
production from crude oil and natural gas properties declines as reserves are
depleted. Our proved reserves will decline as reserves are produced unless we
acquire additional properties containing proved reserves, conduct successful
exploration, exploitation and development activities or, through engineering
studies, identify additional behind-pipe zones or secondary recovery reserves.
Our future crude oil and natural gas production is therefore highly dependent
upon our level of success in acquiring or finding additional 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. We have implemented a number of measures to conserve our cash
resources, including postponement of exploration and development projects.
However, while these measures will conserve our cash resources in the near term,
they will also limit our ability to replenish our depleting reserves, which
could negatively impact our cash flow from operations in the future. The terms
of our senior credit agreement and the new notes limit our capital expenditures
which will further limit our ability to replenish our reserves and replace
production. Further, in addition to the effects of our limited liquidity, our
operations may be curtailed, delayed or cancelled by other factors, such as
title problems, weather, compliance with governmental regulations, mechanical
problems or shortages or delays in the delivery of equipment. We cannot assure
you that our exploration and development activities will result in increases in
reserves.
Use of our net operating loss carryforwards may be limited. At December 31,
2003, Abraxas had, subject to the limitation discussed below, $100.6 million of
net operating loss carryforwards for U.S. tax purposes. These loss carryforwards
will expire from 2003 through 2022 if not utilized. In connection with the
January 2003 transactions described in Note 2, in Notes to Consolidated
Financial Statements, Item 8, certain of the loss carryforwards were utilized.
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.
Additionally, uncertainties exist as to the future utilization of the operating
loss carryforwards under the criteria set forth under FASB Statement No. 109.
Therefore, Abraxas has established a valuation allowance of $99.1 million and
$76.1 million for deferred tax assets at December 31, 2002 and 2003,
respectively.
Crude oil and natural gas prices and their volatility 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 crude oil and natural gas. 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. In
addition, we may have ceiling limitation write-downs if prices decline. For
example, during the second quarter of 2002, we had a ceiling limitation write
down of approximately $116.0 million. Lower prices may also reduce the amount of
crude oil and natural gas that we can produce economically.
We cannot predict future crude oil and natural gas prices. Factors that can
cause price fluctuations include:
o changes in supply and demand for crude oil and natural gas;
o weather conditions;
o the price and availability of alternative fuels;
o political and economic conditions in oil producing countries,
especially those in the Middle East; and
9
o overall economic conditions.
In addition to decreasing our revenue and cash flow from operations, low or
declining crude oil and natural gas prices could have additional material
adverse effects on us, such as:
o reducing the overall volumes of crude oil and natural gas that we
can produce economically;
o causing a ceiling limitation write-down;
o increasing our dependence on external sources of capital to meet
our liquidity requirements;
o reducing our borrowing base under our senior credit agreement; and
o impairing our ability to obtain needed equity capital.
Lower crude oil and natural gas prices increase the risk of ceiling
limitation write-downs. We use the full cost method to account for our crude oil
and natural gas operations. Accordingly, we capitalize the cost to acquire,
explore for and develop crude oil and natural gas properties. Under full cost
accounting rules, the net capitalized cost of crude oil and natural gas
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, as
adjusted for asset retirement obligations. If net capitalized costs of crude oil
and natural gas properties, as adjusted for asset retirement obligations, 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
crude oil and natural gas properties increases when crude oil and natural gas
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 crude
oil and natural gas prices may have increased the ceiling applicable to the
subsequent period.
We have incurred ceiling limitation writedowns in the past. At June 30,
2002, for example, we recorded a ceiling limitation writedown of $116 million.
We cannot assure you that we will not experience additional ceiling limitation
write-downs in the future.
Estimates of our proved reserves and future net revenue are uncertain and
inherently imprecise. This annual report contains estimates of our proved crude
oil and natural gas reserves and the estimated future net revenue from such
reserves. 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, crude oil and natural gas prices, revenues,
taxes, development expenditures, operating expenses and quantities of
recoverable crude oil and natural gas 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 exploration and development, prevailing crude oil and
natural gas 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 report is the current market value of our estimated
crude oil and natural gas 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 crude oil and natural gas
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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 crude oil and natural gas 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 crude oil and natural gas reserves, future net
revenue from proved reserves and the PV-10 thereof for the crude oil and natural
gas properties described in this annual report are based on the assumption that
future crude oil and natural gas prices remain the same as crude oil and natural
gas prices at December 31, 2003. The sales prices as of such date used for
purposes of such estimates were $31.03 per Bbl of crude oil, $27.19 per Bbl of
NGLs and $5.05 per Mcf of natural gas. This compares with $29.69 per Bbl of
crude oil, $18.89 per Bbl of NGLs and $3.79 per Mcf of natural gas as of
December 31, 2002. These estimates also assume that we will make future capital
expenditures of approximately $50.4 million in the aggregate, 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 herein.
We have experienced recurring net losses. The following table shows the
losses we had in 1998, 1999, 2001 and 2002:
Years Ended December 31,
1998 1999 2001 2002
---- ---- ---- ----
Net loss $(84.0) $(36.7) $(19.7) $ (118.5)
While we had net income in 2000 of $8.4 million, if the significant gain on
the sale of an interest in a partnership were excluded, we would have
experienced a net loss for the year of ($25.5) million. Similarly, while we had
net income of $55.9 million in 2003, if the gain on the sale of our Canadian
subsidiaries were excluded, we would have experienced a net loss for the year of
($13.0) million. We cannot assure you that we will become profitable in the
future.
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 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 and
Canadian regulation of crude oil and natural gas 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 crude oil and natural gas.
Our Canadian operations are subject to the risks of currency fluctuations
and in some instances economic and political developments. We conduct operations
in Canada. The expenses of such operations are payable in Canadian dollars while
most of the revenue from crude oil and natural gas sales is based upon U.S.
dollar price indices. As a result, Canadian operations are subject to the risk
of fluctuations in the relative values of the Canadian and U.S. dollars. We are
also required to recognize foreign currency translation gains or losses related
to any debt issued by our Canadian subsidiary because the debt is denominated in
U.S. dollars and the functional currency of such subsidiary is the Canadian
dollar. Our foreign operations may also be adversely affected by local political
and economic developments, royalty and tax increases and other foreign laws or
policies, as well as U.S. policies affecting trade, taxation and investment in
other countries.
We depend on our key personnel. 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. The unavailability of Mr.
Watson could have a materially adverse effect on our business. Mr. Watson has a
three-year employment contract with Abraxas commencing on December 21, 1999,
11
which automatically renews thereafter for successive one-year periods unless
Abraxas gives 120 days notice prior to the expiration of the original term or
any extension thereof of its intention not to renew the employment agreement.
Our success is also dependent upon our ability to employ and retain skilled
technical personnel. While we have not experienced difficulties in employing or
retaining such personnel, our failure to do so in the future could adversely
affect our business.
Risks Related to Our Industry
Our operations are subject to numerous risks of crude oil and natural gas
drilling and production activities. Our crude oil and natural gas drilling and
production activities are subject to numerous risks, many of which are beyond
our control. These risks include the following:
o that no commercially productive crude oil or natural gas reservoirs
will be found;
o that crude oil and natural gas drilling and production activities
may be shortened, delayed or canceled; and
o that our ability to develop, produce and market our reserves may be
limited by:
o title problems,
o weather conditions,
o compliance with governmental requirements, and
o mechanical difficulties or shortages or delays in the delivery of
drilling rigs and other equipment.
In the past, we have had difficulty securing drilling equipment in certain
of our core areas. We cannot assure you that the new wells we drill will be
productive or that we will recover all or any portion of our investment.
Drilling for crude oil and natural gas 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. In addition, our properties may be
susceptible to hydrocarbon draining from production by other operations on
adjacent properties.
Our industry also experiences numerous operating risks. These operating
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 or discharges of toxic gases. If any of
these 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 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.
We operate in a highly competitive industry which may adversely affect our
operations. We operate in a highly competitive environment. Competition is
particularly intense with respect to the acquisition of desirable undeveloped
crude oil and natural gas properties. The principal competitive factors in the
acquisition of such undeveloped crude oil and natural gas properties include the
staff and data necessary to identify, investigate and purchase such properties,
and the financial resources necessary to acquire and develop such properties. We
compete with major and independent crude oil and natural gas companies for
properties and the equipment and labor required to develop and operate such
properties. Many of these competitors have financial and other resources
substantially greater than ours.
The principal resources necessary for the exploration and production of
crude oil and natural gas are leasehold prospects under which crude oil and
natural gas reserves may be discovered, drilling rigs and related equipment to
explore for such reserves and knowledgeable personnel to conduct all phases of
crude oil and natural gas operations. We must compete for such resources with
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both major crude oil and natural gas companies and independent operators.
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.
We face significant competition for obtaining additional natural gas
supplies for gathering and processing operations, for marketing NGLs, residue
gas, helium, condensate and sulfur, and for transporting natural gas and
liquids. Our principal competitors include major integrated oil companies and
their marketing affiliates and national and local gas gatherers, brokers,
marketers and distributors of varying sizes, financial resources and experience.
Certain competitors, such as major crude oil and natural gas companies, have
capital resources and control supplies of natural gas substantially greater than
ours. Smaller local distributors may enjoy a marketing advantage in their
immediate service areas.
Our crude oil and natural gas operations are subject to various U.S.
federal, state and local and Canadian federal and provincial governmental
regulations that materially affect our operations. Matters regulated include
discharge 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
crude oil and natural gas, these agencies have restricted the rates of flow of
crude oil and natural gas wells below actual production capacity. Federal,
state, provincial and local laws regulate production, handling, storage,
transportation and disposal of crude oil and natural gas, by-products from crude
oil and natural gas and other substances and materials produced or used in
connection with crude oil and natural gas 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 Crude Oil and Natural Gas 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, provincial 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 in the United States were subject to
significant federal regulation. At the present time, however, all sales of our
crude oil, natural gas, condensate and NGLs produced in the United States under
private contracts may be sold at market prices. Congress could, however, reenact
price controls in the future. If controls that limit prices to below market
rates are instituted, our revenue would be adversely affected.
Crude oil and natural gas exported from Canada is subject to regulation by
the National Energy Board ("NEB") and the government of Canada. Exporters are
free to negotiate prices and other terms with purchasers, provided that export
contracts in excess of two years must continue to meet certain criteria
prescribed by the NEB and the government of Canada. Crude oil and natural gas
exports for a term of less than two years must be made pursuant to an NEB order,
or, in the case of exports for a longer duration, pursuant to an NEB license and
Governor in Council approval.
The provincial governments of Alberta, British Columbia and Saskatchewan
also regulate the volume of natural gas that may be removed from these provinces
for consumption elsewhere based on such factors as reserve availability,
transportation arrangements and marketing considerations.
The North American Free Trade Agreement
On January 1, 1994, the North American Free Trade Agreement ("NAFTA") among
the governments of the United States, Canada and Mexico became effective. In the
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context of energy resources, Canada remains free to determine whether exports to
the U.S. or Mexico will be allowed provided that any export restrictions do not:
(i) reduce the proportion of energy resources exported relative to the total
supply of the energy resource (based upon the proportion prevailing in the most
recent 36 month period); (ii) impose an export price higher than the domestic
price; or (iii) disrupt normal channels of supply. All three countries are
prohibited from imposing minimum export or import price requirements.
NAFTA contemplates the reduction of Mexican restrictive trade practices in
the energy sector and prohibits discriminatory border restrictions and export
taxes. The agreement also contemplates clearer disciplines on regulators to
ensure fair implementation of any regulatory changes and to minimize disruption
of contractual arrangements, which is important for Canadian natural gas
exports. The Texas Railroad Commission has recently become the lead agency for
Texas for coordinating permits governing Texas to Mexico cross border pipeline
projects. The availability of selling natural gas into Mexico may substantially
impact the interstate natural gas market on all producers in the coming years.
United States 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 (the "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
of natural gas. For example, the 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 the 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 the 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, including interstate pipelines, under existing long term
contractual arrangements. 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.
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In summary, all of the 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, the 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 crude oil and natural
gas industry historically has been very heavily regulated; thus there is no
assurance that the less stringent regulatory approach recently pursued by the
FERC and Congress will continue indefinitely into the future.
State and Other Regulation
All of the jurisdictions where we own producing crude oil and natural gas
properties have statutory provisions regulating the exploration for and
production of crude oil and natural gas. 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 crude oil and natural gas
properties. In this regard, some states and provinces allow the forced pooling
or integration of tracts to facilitate exploration while other states and
provinces rely on voluntary pooling of lands and leases. In addition, state and
provincial conservation laws establish maximum rates of production from crude
oil and natural gas 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 and provincial 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. 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.
For those operations on U.S. 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 crude oil and natural gas 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.
Canadian Royalty Matters
In addition to Canadian federal regulation, each province has legislation
and regulations that govern land tenure, royalties, production rates,
environmental protection and other matters. The royalty regime is a significant
factor in the profitability of crude oil and natural gas production. Royalties
payable on production from lands other than Crown lands are determined by
negotiations between the mineral owner and the lessee. Crown royalties are
determined by governmental regulation and are generally calculated as a
percentage of the value of the gross production, and the rate of royalties
payable generally depends in part on prescribed reference prices, well
productivity, geographical location, field discovery date and the type and
15
quality of the petroleum product produced.
From time to time the governments of Alberta and British Columbia, the
provinces where almost all of New Grey Wolf's production is located, have
established incentive programs which have included royalty rate reductions,
royalty holidays and tax credits for the purpose of encouraging crude oil and
natural gas exploration or enhanced planning projects. All of New Grey Wolf's
production is from oil and gas rights which have been granted by the Provinces.
The Province of Alberta requires the payment from lessees of oil and gas
rights of annual rental payments as well as royalty payments. Regulations made
pursuant to the Mines and Minerals Act (Alberta) provide various incentives for
exploring and developing crude oil reserves in Alberta. Crude oil produced from
horizontal extensions commenced at least five years after the well was
originally spudded may qualify for a royalty reduction. An 8,000 cubic meters
exemption is available to production from a well that has not produced for a
12-month period prior to January 31, 1993 or 24 consecutive months following
such date. In addition, crude oil production from eligible new field and new
pool wildcat wells and deeper pool test wells spudded or deepened after
September 30, 1992, is entitled to a 12-month royalty exemption (to a maximum of
CDN $1 million). Crude oil produced from low productivity wells, enhanced
recovery schemes (such as injection wells) and experimental projects is also
subject to royalty reductions.
The Alberta government classifies conventional crude oil into three
categories, being Old Oil, New Oil and Third Tier Oil. Each have a base royalty
rate of 10%. The rate caps on the categories are 25% for oil from crude oil
pools discovered after September 30, 1992, being the Third Tier Oil, 30% for oil
from pools or pool extensions discovered after April 1, 1974, from wells drilled
or deepened after October 31, 1991 or from reactivated wells and which are not
Third Tier Oil, and 35% for Old Oil.
Effective January 1, 1994, the calculation and payment of natural gas
royalties became subject to a simplified process. The royalty reserved to the
Crown, subject to various incentives, is between 15% or 30%, in the case of new
natural gas, and between 15% and 35%, in the case of old natural gas, depending
upon a prescribed or corporate average reference price. Natural gas produced
from qualifying intervals in eligible natural gas wells spudded or deepened to a
depth below 2,500 meters is also subject to a royalty exemption, the amount of
which depends on the depth of the well.
In Alberta, a producer of crude oil or natural gas is entitled to credit
against the royalties payable to the Crown by virtue of the Alberta Royalty Tax
Credit ("ARTC") program. The ARTC program is based on a price-sensitive formula,
and the ARTC rate currently varies between 75% for prices for crude oil at or
below CDN $100 per cubic meter (CDN $15.90 per Bbl) and 35% for prices above CDN
$210 per cubic meter (CDN $33.38 per Bbl). The ARTC rate is currently applied to
a maximum of CDN $2.0 million of Alberta Crown royalties payable for each
producer or associated group of producers. Crown royalties on production from
producing properties acquired from corporations claiming maximum entitlement to
ARTC will generally not be eligible for ARTC. The rate is established quarterly
based on average "par price", as determined by the Alberta Department of Energy
for the previous quarterly period.
Producers of crude oil and natural gas in British Columbia are also
required to pay annual rental payments in respect of Crown leases and royalties
and freehold production taxes in respect of crude oil and natural gas produced
from Crown and freehold lands respectively. British Columbia also classifies
conventional crude oil into the three categories of Old Oil, New Oil and Third
Tier Oil. The amount payable as a royalty in respect of crude oil depends on the
vintage of the crude oil (whether it was produced from a pool discovered before
or after October 31, 1975) or a pool in which no well was completed on June 1,
1998), the quantity of crude oil produced in a month and the value of the crude
oil. Crude oil produced from a discovery well may be exempt from the payment of
a royalty for the first 36 months of production to a maximum production of
72,024 Bbls. The royalty payable on natural gas is determined by a sliding scale
based on a classification of the gas based on whether it is conservation gas
(gas associated with marketed oil production) and by drilling and land lease
date and on a reference price which is the greater of the amount obtained by the
producer and at prescribed minimum price. Conservation gas has a minimum royalty
of 8%. The royalty rate ranges from between 9% and 27% for wells drilled on
lands issued after May 31, 1998 and before January 1, 2003 and completed within
5 years of the date the lands were issued and between 12% and 27% for wells
spudded after May 31, 1998 on lands where rights had been issued as of May 31,
1998.
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Environmental Matters
Our operations are subject to numerous federal, state, provincial 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
crude oil and natural gas 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
crude oil and natural gas 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 crude oil and natural gas. Although we utilized standard industry operating
and disposal practices at the time, hydrocarbons or other wastes may 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 crude oil and natural gas 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 there from, and are usually causes of action based on negligence,
trespass, nuisance, strict liability and fraud.
17
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.
Our Canadian operations are also subject to environmental regulation
pursuant to local, provincial and federal legislation which generally require
operations to be conducted in a safe and environmentally responsible manner.
Canadian environmental legislation provides for restrictions and prohibitions
relating to the discharge of air, soil and water pollutants and other substances
produced in association with certain crude oil and natural gas industry
operations, and environmental protection requirements, including certain
conditions of approval and laws relating to storage, handling, transportation
and disposal of materials or substances which may have an adverse effect on the
environment. Environmental legislation can affect the location of wells and
facilities and the extent to which exploration and development is permitted. In
addition, legislation requires that well and facilities sites be abandoned and
reclaimed to the satisfaction of provincial authorities. A breach of such
legislation may result in the imposition of fines or issuance of clean-up
orders.
Certain federal environmental laws that may affect us include the Canadian
Environmental Assessment Act which ensures that the environmental effects of
projects receive careful consideration prior to licenses or permits being
issued, to ensure that projects that are to be carried out in Canada or on
federal lands do not cause significant adverse environmental effects outside the
jurisdictions in which they are carried out, and to ensure that there is an
opportunity for public participation in the environmental assessment process;
the Canadian Environmental Protection Act ("CEPA") which is the most
comprehensive federal environmental statute in Canada, and which controls toxic
substances (broadly defined), includes standards relating to the discharge of
air, soil and water pollutants, provides for broad enforcement powers and
remedies and imposes significant penalties for violations; the National Energy
Board Act which can impose certain environmental protection conditions on
approvals issued under the Act; the Fisheries Act which prohibits the depositing
of a deleterious substance of any type in water frequented by fish or in any
place under any condition where such deleterious substance may enter any such
water and provides for significant penalties; the Navigable Waters Protection
Act which requires any work which is built in, on, over, under, through or
across any navigable water to be approved by the Minister of Transportation, and
which attracts severe penalties and remedies for non-compliance, including
removal of the work.
In Alberta, environmental compliance has been governed by the Alberta
Environmental Protection and Enhancement Act ("AEPEA") since September 1, 1993.
In addition to consolidating a variety of environmental statutes, the AEPEA also
imposes certain new environmental responsibilities on crude oil and natural gas
operators in Alberta. The AEPEA sets out environmental standards and compliance
for releases, clean-up and reporting. The Act provides for a broad range of
liabilities, enforcement actions and penalties.
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 reclaimation 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.
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Title to Properties
As is customary in the crude oil and natural gas industry, we make only a
cursory review of title to undeveloped crude oil and natural gas 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 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 crude oil and natural gas properties, some of which are
subject to immaterial encumbrances, easements and restrictions. The crude oil
and natural gas 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, 2004, we had 46 full-time employees in the United States,
including 3 executive officers, 3 non-executive officers, 1 petroleum engineer,
1 geologist, 5 managers, 1 landman, 11 administrative and support personnel and
21 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.
As of March 9, 2004, New Grey Wolf had 11 full-time employees, including 4
executive officers, 1 non-executive officer, 2 geologists and, 4 technical and
clerical personnel in Canada.
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 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 U.S. operations are concentrated in South and West Texas with over 99%
of the PV-10 of our U.S. crude oil and natural gas properties at December 31,
2003 located in those two regions. We operate 94% of our wells in Texas. During
2003, we drilled a total of six new wells (3.73 net) in Texas with a 100%
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 43 wells with average production of 239 net Bbls of crude
oil and NGLs and 6,210 net Mcf of natural gas per day for the year ended
December 31, 2003. As of December 31, 2003 we had estimated net proved reserves
in South Texas of 28.6 Bcfe (82% natural gas) with a PV-10 of $57.7 million, 70%
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 Abraxas' then existing Ward County
Montoya acreage by paying Abraxas $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 Abraxas was responsible for its pro rata share of
drilling and development cost. The farmout agreement terminated in early January
2004 and accordingly, EOG is obligated to reassign all unearned acreage to
Abraxas.
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In total in West Texas we own an average 74% working interest in 158 wells
with average daily production of 338 net Bbls of crude oil and NGLs and 6,887
net Mcf of natural gas per day for the year ended December 31, 2003. As of
December 31, 2003, we had estimated net proved reserves in West Texas of 71.1
Bcfe (80% natural gas) with a PV-10 of $103.6 million, 60% of which was
attributable to proved developed reserves.
Wyoming
We currently hold over 60,000 contiguous acres in the Powder River Basin in
east central Wyoming. The Company has drilled and operates 5 wells in Converse
and Niobrara counties that were completed in the Turner and Niobrara formations.
We own a 100% working interest in these wells that produced an average of 31 net
barrels of crude oil per day in 2003. As of December 31, 2003 we had estimated
net proved producing reserves in Wyoming of 68,669 barrels of crude oil with a
PV-10 of $280,843.
Western Canada
We own properties in western Canada, consisting primarily of natural gas
reserves and undeveloped acreage in the provinces of Alberta and British
Columbia. Our Alberta properties are in two concentrated areas; the Caroline
field, 60 miles northwest of Calgary and the Peace River Arch area in
northwestern Alberta. We entered into a farmout agreement with PrimeWest in
connection with the sale of Canadian Abraxas and Old Grey Wolf in January of
2003 to jointly develop these areas in the future. Our other Canadian operations
are located in the Ladyfern area of northeast British Columbia. During 2003, we
drilled a total of 18 new wells (8.1 net) with a 95% success rate.
As of December 31, 2003 New Grey Wolf had estimated net proved reserves of
21.0 Bcfe (77% natural gas) with a PV-10 of $55.2 million of which 76% was
attributable to proved developed reserves. For the year ended December 31, 2003,
the Canadian properties produced an average of approximately 111 net Bbls of
crude oil and NGLs per day and 2,328 net Mcf of natural gas per day.
Exploratory and Developmental Acreage
Our principal crude oil and natural gas properties consist of non-producing
and producing crude oil and natural gas leases, including reserves of crude oil
and natural gas in place. The following table indicates our interest in
developed and undeveloped acreage as of December 31, 2003:
Developed and Undeveloped Acreage
----------------------------------------------------------------
As of December 31, 2003
----------------------------------------------------------------
Developed Acreage (1) Undeveloped Acreage (2)
--------------------------------- ------------------------------
Gross Acres (3) Net Acres (4) Gross Acres (3) Net Acres (4)
--------------- --------------- --------------- --------------
Canada 18,238 9,075 155,246 93,866
Texas 23,671 18,978 5,864 4,692
Wyoming 3,200 3,200 57,431 53,519
N. Dakota - - 80 24
--------------- ------------------------------ --------------
Total 45,109 31,253 218,621 152,101
=============== ============================== ==============
- ---------------
(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 crude oil and natural gas, 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
expressed separately for crude oil and natural gas, as of December 31, 2003:
20
Productive Wells (1)
-------------------------------------------------
As of December 31, 2003
---------------- -------------------------------------------------
State/Country Crude Oil Natural Gas
---------------- ------------------------- -----------------------
Gross(2) Net(3) Gross(2) Net(3)
------------- ----------- ----------- -----------
Canada 29.0 5.1 205.0 17.0
Texas 140.5 112.6 60.5 44.7
Wyoming 5.0 5.0 18.0 -
N. Dakota 1.0 - - -
------------- ----------- ----------- -----------
Total 175.5 122.7 283.5 61.7
============= =========== =========== ===========
- ------------
(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 crude oil and natural gas reserves of the U.S. operations only have
been estimated as of January 1, 2004, January 1, 2003, and January 1, 2002, by
DeGolyer and MacNaughton, of Dallas, Texas. The reserves of the Canadian
operations as of January 1, 2004 and January 1, 2003 have been estimated by
DeGolyer and MacNaughton, and the reserves as of January 1, 2002 were estimated
by McDaniel and Associates Consultants Ltd. of Calgary, Alberta. The January 1,
2003 reserves attributable to the Canadian properties which were sold in
connection with the sale of Canadian Abraxas and Old Grey Wolf were estimated
internally. The January 1, 2004 reserves related to an override which was
retained by New Grey Wolf were estimated internally. Crude oil and natural gas
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 crude
oil and natural gas and the timing and amount of future net revenues to be
received there from. 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,
2002, January 1, 2003 and January 1, 2004:
21
Estimated Proved Reserves
--------------------------------------
Proved Proved Total
Developed Undeveloped Proved
------------ -------------- ----------
As of January 1, 2002 (1)
Crude oil (MBbls) 1,980 1,170 3,150
NGLs (MBbls) 3,067 585 3,652
Natural gas (MMcf) 111,243 77,514 188,757
As of January 1, 2003 (2)
Crude oil (MBbls) 1,782 1,317 3,099
NGLs (MBbls) 1,222 284 1,506
Natural gas (MMcf) 90,374 48,458 138,832
As of January 1, 2004
Crude oil (MBbls) 2,051 1,578 3,629
NGLs (MBbls) 263 242 505
Natural gas (MMcf) 52,398 43,885 96,284
- ------------------
(1)Reserves as of January 1, 2002 include 138 MBbls of crude oil, 2,257
MBbls of NGLs and 80,289MMcf of natural gas that were sold in connection
with the sale of Canadian Abraxas and Old Grey Wolf in January 2003.
(2)Reserves as of January 1, 2003 include 67 MBbls of crude oil, 1,079
MBbls of NGLs, and 47,066 MMcf of natural gas that were sold in
connection with the sale of Canadian Abraxas and Old Grey Wolf in
January 2003.
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, crude oil and natural gas prices, revenues,
taxes, development expenditures, operating expenses and quantities of
recoverable crude oil and natural gas 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 exploration and development, prevailing crude oil and
natural gas 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 crude oil and natural gas 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 crude oil and
natural gas 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 $116.0 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."
22
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 crude oil and natural
gas 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 crude oil and natural gas 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 crude oil and natural gas reserves, future net
revenue from proved reserves and the PV-10 thereof for the crude oil and natural
gas properties described in this report are based on the assumption that future
crude oil and natural gas prices remain the same as crude oil and natural gas
prices at December 31, 2003. The average sales prices as of such date used for
purposes of such estimates were $31.03 per Bbl of crude oil, $27.19 per Bbl of
NGLs and $5.05 per Mcf of natural gas. It is also assumed that we will make
future capital expenditures of approximately $50.4 million in the aggregate,
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 herein.
We file reports of our estimated crude oil and natural gas 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 BOE of production sold, for the three years ended December 31,
2003.
2001 (1) 2002 (1) 2003 (1)
----------------- ---------------- -----------------
Crude oil production (Bbls) 454,063 292,264 251,567
Natural gas production (Mcf) 17,495,598 15,452,721 6,189,359
Natural gas liquids production
(Bbls) 277,969 242,032 37,258
MMcfe 21,888 18,658 7,922
Average sales price per Bbl of
crude oil $ 24.63 $ 24.34 $ 30.32
Average sales price per Mcf of
natural gas (2) $ 3.20 $ 2.55 $ 4.78
Average sales price per Bbl of
natural gas liquids $ 21.51 $ 17.94 $ 24.47
Average sales price per Mcfe $ 3.35 $ 2.72 $ 4.81
Average cost of production per
Mcfe produced (3) $ 0.85 $ 0.82 $ 1.21
- ------------------
(1)Includes production for 2001, 2002 and the first 23 days of 2003 for
Canadian properties sold in January 2003.
(2) Average sales prices are net of hedging activity.
(3)Crude oil and natural gas 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.
23
Drilling Activities
Thefollowing table sets forth our gross and net working interests in
exploratory and development wells drilled during the three years ended December
31, 2003:
2001 2002 2003
----------------------------- ----------------------------- -------------------------------
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
------------ ---------- ------------ ---------- ---------- --------
Exploratory(3)
Productive(4)
Crude oil - - 1.0 1.0 1.0 1.0
Natural gas 2.0 1.0 3.0 0.5 - -
Dry holes(5) 1.0 .5 3.0 1.5 1.0 0.5
------------ ---------- ------------ ---------- ---------- --------
Total 3.0 1.5 7.0 3.0 2.0 1.5
============ ========== ============ ========== ========== ========
Development(6)
Productive (4)
Crude oil 2.0 2.0 - - 2.0 2.0
Natural gas 13.0 11.0 14.0 11.8 20.0 8.3
Dry holes (5) - - 1.0 1.0 - -
------------ ---------- ------------ ---------- ---------- --------
Total 15.0 13.0 15.0 12.8 22.0 10.3
============ ========== ============ ========== ========== ========
- ------------------
(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 crude oil or
natural gas in an unproved area, to find a new reservoir in a field
previously found to be producing crude oil or natural gas 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 crude oil or natural gas in sufficient quantities to
justify completion as a crude oil or natural gas well.
(6) A development well is a well drilled within the proved area of a crude oil
or natural gas reservoir to the depth of stratigraphic horizon (rock layer
or formation) noted to be productive for the purpose of extracting proved
crude oil or natural gas reserves.
As of March 9, 2004 we had five wells in process of drilling and
completing, two in the U.S. and three in Canada.
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 March 2006 at an aggregate base rate of $20,900 per
month. We also have an office in Midland, Texas consisting of 570 square feet
leased through October 2004 at an aggregate base rate of $380 per month.
New Grey Wolf leases 7,350 square feet of office space in Calgary, Alberta,
leased through December 2008 at an aggregate base rate of $13,400 US$ per month.
24
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 three properties are used for the storage of tubulars and
production equipment. We also own 25 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 Abraxas Wamsutter L.P. were named as defendants in a
lawsuit filed in U.S. District Court in the District of Wyoming. The claim
asserts breach of contract, fraud and negligent misrepresentation by Abraxas and
Abraxas Wamsutter, L.P. related to the responsibility for year 2000 ad valorem
taxes on crude oil and natural gas properties sold by Abraxas and Abraxas
Wamsutter, L.P. 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 has filed an appeal. We believe these charges are without
merit. We have established a reserve in the amount of $845,000, which represents
our estimated share of the judgment.
In 2003, Abraxas and Leam Drilling Systems each filed suit against the
other relating to certain drilling services that Leam contracted to provide
Abraxas. Abraxas believes that the services were provided in a grossly negligent
manner and that Leam committed fraud. Leam has asserted that Abraxas failed to
pay approximately $639,000 for services rendered. The cases are pending in Bexar
County and Ward County, Texas.
Additionally, from time to time, we are involved in litigation relating to
claims arising out of its operations in the normal course of business. At
December 31, 2003, we were not engaged in any legal proceedings that are
expected, individually or in the aggregate, to have a material adverse effect on
our operations.
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, 2003.
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 2004 annual meeting of
shareholders and until his successor is duly elected and qualified.
Robert L. G. Watson, age 53, 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. In November 1996, Mr. Watson was elected Chairman of the Board,
President and as a director of Canadian Abraxas. Prior to joining Abraxas, Mr.
Watson was employed in various petroleum engineering positions with Tesoro
Petroleum Corporation, a crude oil and natural gas 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 52, 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 November 1996, Mr. Williford was
elected Vice President and Assistant Secretary of Canadian Abraxas. 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 crude oil and natural gas exploration and production company,
from July 1989 to December 1992 and President of Clark Resources Corp., a crude
25
oil and natural gas 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 42, was elected Executive Vice President and a
director of the Company in July 1998. In December 1999, Mr. Carington resigned
as a director of Abraxas. Prior to joining the Company, 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.
26
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
Market Information
Abraxas 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 Abraxas' common
stock on the American Stock Exchange.
Period High Low
2002
First Quarter $ 1.70 $ 0.89
Second Quarter 1.41 0.52
Third Quarter 0.98 0.42
Fourth Quarter 0.80 0.52
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 (Through March 9, 2004) $ 3.64 $ 1.29
Holders
As of March 9, 2004, we had 36,267,337 shares of common stock outstanding
and had approximately 1,597 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 the New Notes 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
On January 23, 2003, we issued approximately $109.7 million in principal
amount of New Notes and 5,642,699 shares of Abraxas common stock in connection
with the exchange offer. These securities were issued pursuant to the exemption
from the registration requirements of the Securities Act of 1933, as amended,
under Regulation D. The securities were offered and sold only to accredited
investors and to no more than 35 non-accredited investors each of whom Abraxas
believed had such knowledge and experience in financial and business matters
that he or she was capable of evaluation of the merits and risks on the
investment in the New Notes and shares of Abraxas common stock.
On July 29, 2003 Abraxas acquired all of the shares of the capital stock of
Wind River Resources Corporation which owned an airplane. The sole shareholder
of Wind River was the Company's President. The consideration for the purchase
was 106,977 shares of Abraxas common stock and $35,000 in cash. These securities
were issued pursuant to the exemption from the registration requirements of the
Securities Act of 1933, as amended, under Section 4(2).
27
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.
Year Ended December 31,
--------------------------------------------------------------------------------
1999* 2000* 2001* 2002* 2003*
----- ----- ----- ----- -----
(Dollars in thousands except per share data)
Total revenue $ 66,770 $ 76,600 $ 77,243 $ 54,320 $ 39,019
Net income (loss) $ (36,680) (3) $ 8,449 (2)$ (19,718) (4) $ (118,527) (1)$ 55,920 (5)
Net income (loss) per common share -
diluted $ (5.41) $ 0.26 $ (0.76) $ (3.95) $ 1.55
Weighted average shares outstanding -
diluted (in thousands) 6,784 22,616 25,789 29,979 36,076
Total assets $ 322,284 $ 335,560 $ 303,616 $ 181,425 $ 126,437
Long-term debt, excluding current
maturities $ 273,421 $ 266,441 $ 285,184 $ 236,943 $ 184,649
Total stockholders' equity (deficit) $ (9,505) $ (6,503) $ (28,585) $ (142,254) $ (72,203)
(1) Includes ceiling limitation write-down of $116.0 million.
(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 limitation write-down of $19.1 million.
(4) Includes ceiling test write-down of $2.6 million in 2001, based on
subsequent (March 22, 2002) realized prices, related to our Canadian
operations.
(5) Includes gain on sale of foreign subsidiaries of $ 68.9 million in 2003.
*Data includes Canadian Abraxas and Old Grey Wolf for 1999-2002 and for the
first 23 days of 2003 which were sold in January 2003.
Item 7. Management's Discussion And Analysis Of Financial Condition And Results
Of Operations
The following is a discussion of our consolidated financial condition,
results of operations, liquidity and capital resources. This discussion should
be read in conjunction with our Consolidated Financial Statements and the Notes
thereto. See "Financial Statements" in Item 8.
General
We are an independent energy company engaged primarily in the acquisition,
exploration, exploitation and production of crude oil and natural gas. Our
principal means of growth has been through the acquisition and subsequent
development and exploitation of producing properties. As a result of our
historical acquisition activities, we believe that we have a substantial
inventory of low risk exploitation and development opportunities, the successful
completion of which is critical to the maintenance and growth of our current
production levels.
We have incurred net losses in three 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, particularly the
following factors which most significantly affect our results of operations:
o the sales prices of crude oil, natural gas liquids and natural gas;
o the level of total sales volumes of crude oil, natural gas liquids
and natural gas;
28
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
2003. Prices have remained strong during the first part of 2004.
The table below illustrates how natural gas prices fluctuated over the
course of 2002 and 2003. The table below contains the last three day average of
NYMEX traded contracts price and the prices we realized during each quarter for
2002 and 2003, including the impact of our hedging activities.
Natural Gas Prices by Quarter
(in $ per Mcf)
----------------------------------------------------------------------------------------------------
Quarter Ended
----------------------------------------------------------------------------------------------------
March 31, June 30, Sept. 30, Dec. 31, March 31, June 30, Sept. 30, Dec. 31,
2002 2002 2002 2002 2003 2003 2003 2003
------------ ----------- ----------- ------------ ----------- ------------- ----------- ------------
Index $ 2.38 $ 3.36 $ 3.28 $ 3.99 $ 6.61 $ 5.51 $ 5.10 $ 4.60
Realized $ 2.21 $ 2.44 $ 2.08 $ 3.47 $ 5.13 $ 5.11 $ 4.50 $ 4.30
The NYMEX natural gas price on March 9, 2004 was $5.44 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 2002 and
2003.
Crude Oil Prices by Quarter
(in $ per Bbl)
-------------------------------------------------------------------------------------------------------
Quarter Ended
-------------------------------------------------------------------------------------------------------
March 31, June 30, Sept. 30, Dec. 31, March 31, June 30, Sept. 30, Dec. 31,
2002 2002 2002 2002 2003 2003 2003 2003
----------- ----------- ------------ -------------- ------------- ----------- ------------ ------------
Index $ 19.48 $ 26.40 $ 27.50 $ 28.29 $ 33.71 $ 29.87 $ 30.85 $ 29.64
Realized $ 16.64 $ 23.47 $ 23.47 $ 24.83 $ 33.22 $ 28.53 $ 29.52 $ 29.73
The NYMEX crude oil price on March 9, 2004 was $ 36.28 per Bbl.
We seek to reduce our exposure to price volatility by hedging our
production through swaps, options and other commodity derivative instruments. In
2001 and 2002, we experienced hedging losses of $12.1 million and $3.2 million,
respectively. In October 2002, all of these hedge agreements expired. We made
total payments over the term of these arrangements to various counterparties in
the amount of $35.1 million.
Under the terms of our senior credit agreement, we are required to maintain
hedging positions with respect to not less than 40% nor more than 75% of our
crude oil and natural gas production, on an equivalent basis, for a rolling six
month period. As of December 31, 2003, we had the following hedges in place:
Time Period Notional Quantities Price
- --------------------------------- ----------------------------- ---------------
March 1, 2003 - February 29, 5,000 MMBtu of natural gas Floor of $4.50
2004 production per day
29
March 1, 2004 - April 30, 2004 2,000 MMBtu of natural gas Floor of $4.00
production per day
March 1, 2004 - April 30, 2004 500 Bbls of crude oil Floor of $22.00
production per day
May 2004 2,000 Mmbtu of natural gas Floor of $4.00
production per day
June 2004 500 Bbls of crude oil Floor of $22.00
production per day
June 2004 800 Bbls of crude oil Floor of $22.00
production per day
July 2004 2,000 Mmbtu of natural gas Floor of $4.00
production per day
July 2004 500 Bbls of crude oil Floor of $22.00
production per day
Subsequent to year-end we have entered into additional agreements similar
to those scheduled above (floors) in volume amounts sufficient to reach the 40%
threshold required by our senior credit agreement. The Company anticipates
continuing to purchase similar floors in the future to satisfy our requirements
under the senior credit agreement.
Production Volumes. Because our proved reserves will decline as crude oil,
natural gas and natural gas liquids are produced, unless we acquire additional
properties containing proved reserves or conduct successful exploration and
development activities, our reserves and production will decrease. Our ability
to acquire or find additional reserves in the near future will be dependent, in
part, upon the amount of available funds for acquisition, exploitation and
development projects. For more information on the volumes of crude oil, natural
gas liquids and natural gas we have produced during 2001, 2002 and 2003, please
refer to the information under the caption "Results of Operations" below.
We have budgeted $10 million for drilling expenditures in 2004. Under the
terms of our senior credit agreement and our New Notes, we are subject to
limitations on capital expenditures. As a result, we will be limited in our
ability to replace existing production with new production and might suffer a
decrease in the volume of crude oil and natural gas we produce. If crude oil 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. For more information, see
"Liquidity and Capital Resources - Current Liquidity Requirements" and "Future
Capital Resources."
Availability of Capital. As described more fully under "Liquidity and
Capital Resources" below, our sources of capital are primarily cash on hand,
cash from operating activities, funding under our senior credit agreement and
the sale of properties. At March 9, 2004, we had approximately $14.0 million of
availability under our senior credit agreement. We may also attempt to raise
additional capital through the issuance of debt or equity securities although we
cannot assure you that we will be successful in any such efforts.
Borrowings and Interest. As a result of the financial restructuring we
completed in January 2003, we reduced our indebtedness from approximately $300.4
million at December 31, 2002 to approximately $184.6 million at December 31,
2003. In addition, we decreased our cash interest expense from $34.2 million
during 2002 to $4.3 million during 2003. By decreasing the amount of our
indebtedness and required cash interest payments, we reduced the amount of our
cash flow from operations needed to pay interest on our indebtedness so that
more of our capital resources could be utilized for drilling activities and
paying other expenses.
Exploitation and Development Activity During 2003, we continued
exploitation activities on our U.S. properties. We participated in the drilling
of 24 gross (11.8 net) wells with 23 gross (11.3 net) being successful. The
Company invested $18.3 million in capital spending on these activities during
2003. At the end of 2003, as a result of these activities, our average daily
production was approximately 24 MMcfepd, a 26% increase from the daily
production rate at the beginning of the year (excluding production from the
Canadian properties sold in January 2003).
Outlook for 2004. As a result of final 2003 financial results and current
market conditions, Abraxas has updated its operating and financial guidance for
year 2004 as follows:
30
Production:
BCFE (approximately 80% gas........................ 8-9
Price Differentials (Pre Hedge):
$ Per Bbl.......................................... 0.86
$ Per Mcf.......................................... 0.64
Lifting Coas, $ Per Mce............................... 1.29
G&A, $ Per Mcfe....................................... 0.60
Capital Expenditures ($ Millions)..................... 10.00
Results of Operations
Selected Operating Data. The following table sets forth certain of our
operating data for the periods presented.
Years Ended December 31,
---------------------------------------------------------------
(dollars in thousands, except per unit data)
2001 (1) 2002 (1) 2003 (1)
------------------- ------------------- -------------------
Operating revenue:
Crude oil sales............................. $ 11,184 $ 7,114 $ 7,627
NGLs sales ................................. 5,979 4,343 911
Natural gas sales........................... 56,038 39,405 29,567
Gas processing revenue...................... 2,438 2,420 133
Rig and other............................... 1,604 1,038 781
------------------- ------------------- -------------------
Total operating revenues ................... $ 77,243 $ 54,320 $ 39,019
=================== =================== ===================
Operating income (loss)..................... $ 19,125 $ (110,903) $ 11,542
Crude oil production (MBbls)................ 454.1 292.3 251.6
NGLs production (MBbls)..................... 278.0 242.0 37.3
Natural gas production (MMcf)............... 17,495.6 15,452.7 6,189.4
Average crude oil sales price (per Bbl) $ 24.63 $ 24.34 $ 30.32
Average NGLs sales price (per Bbl) $ 21.51 $ 17.94 $ 24.47
Average natural gas sales price (per Mcf) $ 3.20 $ 2.55 $ 4.78
Revenue and average sales prices are net of hedging activities.
(1) Data for 2001, 2002 and the first 23 days of 2003 includes Canadian
Abraxas and Old Grey Wolf which were sold in January 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 decreased by
$12.8 million from $50.9 million in 2002 to $38.1 million in 2003. The decrease
in revenue was primarily due to decreased production volumes, primarily due to
the sale of our Canadian subsidiaries in January 2003, which was partially
offset by higher commodity prices realized during the period. Higher commodity
prices contributed $16.5 million to crude oil and natural gas revenue while
reduced production volumes had a $29.3 million negative impact on revenue. The
Canadian properties which were sold in January 2003 contributed $29.3 million to
revenues from crude oil and natural gas for the year ended December 31, 2002,
compared to $3.1 million in 2003 through the date of sale (January 23, 2003).
Natural gas liquids volumes declined from 242.0 MBbls in 2002 to 37.3 MBbls
in 2003 The decline in natual gas liquids volumes was due almost entirely to the
sale of our Canadian subsidiaries in January 2003. These properties contributed
232.5 MBbls of natural gas liquids in 2002 compared to 11.7 MBbls during 2003.
Crude oil sales volumes declined from 292.3 MBbls in 2002 to 251.6 MBbls during
31
2003. The Canadian properties which were sold in January 2003 contributed 27.7
MBbls of crude oil production in 2002 compared to 2.4 MBbls in 2003 through the
date of the sale. Crude oil production volumes relating to the Canadian
properties which were retained and current drilling activities in Canada
resulted in an increase to 29.0 MBbls in 2003 compared to 9.5 MBbls in 2002.
Crude oil production from U.S. operations decreased due primarily to natural
field declines. Natural gas sales volumes decreased from 15.5 Bcf in 2002 to 6.2
Bcf in 2003. This decrease is primarily due to the sale of our Canadian
subsidiaries in January 2003. The Canadian properties sold contributed 9.8 Bcf
in 2002 compared to .558 MMcf in 2003 through the date of sale.
Average sales prices in 2003 net of hedging costs were:
o $30.32 per Bbl of crude oil,
o $24.47 per Bbl of natural gas liquids, and
o $ 4.78 per Mcf of natural gas.
Average sales prices in 2002 net of hedging costs were:
o $24.34 per Bbl of crude oil,
o $17.94 per Bbl of natural gas liquids, and
o $ 2.55 per Mcf of natural gas.
Lease Operating Expense. Lease operating expense, or LOE, decreased from
$15.2 million in 2002 to $9.6 million in 2003 The decrease in LOE is primarily
due the sale of Canadian Abraxas and Old Grey Wolf in January 2003. LOE related
to the properties owned by Canadian Abraxas and Old Grey Wolf was $7.3 million
for the year ended December 31, 2002. Excluding the properties sold, LOE
attributable to on going operations increased, 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 $1.21
per Mcfe compared to $0.82 for 2002, primarily due to the decrease in production
volumes.
G&A Expense. General and administrative, or G&A, expense decreased from
$6.9 million in 2002 to $5.4 million in 2003 The decrease in G&A expense was
primarily due to a reduction in personnel in connection with the sale of
Canadian Abraxas and Old Grey Wolf on January 23, 2003. Our G&A expense on a per
Mcfe basis increased from $0.37 in 2002 to $0.67 in 2003. The increase in the
per Mcfe cost was due primarily to lower production volumes in 2003 as compared
to 2002.
G&A - 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, or DD&A, expense
decreased by $15.7 million from $26.5 million in 2002 to $10.8 million in 2003.
The decrease in DD&A was primarily due to the sale of our Canadian subsidiaries
in January 2003 as well as ceiling limitation write-downs in the second quarter
of 2002. Our DD&A expense on a per Mcfe basis for 2003 was $1.33 per Mcfe as
compared to $1.42 per Mcfe in 2002.
Interest Expense. Interest expense decreased from $34.1 million to $17.0
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 $300.4 million
as of December 31, 2002 compared to $184.6 million at December 31, 2003.
32
Ceiling Limitation Write-down. We record the carrying value of our crude
oil and natural gas 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 Crude Oil and Natural Gas Activities". At June 30, 2002, our net capitalized
costs of crude oil and natural gas properties exceeded the present value of our
estimated proved reserves by $138.7 million ($28.2 million on the U.S.
properties and $110.5 million on the Canadian properties). These amounts were
calculated considering June 30, 2002 prices of $26.12 per Bbl for crude oil and
$2.16 per Mcf for natural gas as adjusted to reflect the expected realized
prices for each of the full cost pools. Subsequent to June 30, 2002, commodity
prices increased in Canada and we utilized these increased prices in calculating
the ceiling limitation write-down. The total write-down was approximately $116.0
million. At December 31, 2003 our net capitalized cost of crude oil and natural
gas properties did not exceed the present value of our estimated reserves, due
to increased commodity prices during 2003 and, as such, no write-down was
recorded in 2003. 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
crude oil and natural gas assets increases when crude oil and natural gas 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 resources are revised downward, a further write-down of the
carrying value of our crude oil and natural gas properties may be required.
Income taxes. Income tax expense increased from a benefit of $29.7 million
for the year ended December 31, 2002 to an expense of $377,000 for the year
ended December 31, 2003. The expense in 2003 was related to the operations of
the Canadian properties prior to their sale on January 23, 2003. There is no
current or deferred income tax expense for 2003 related to on-going operations
due to the valuation allowance which has been recorded against the deferred tax
asset.
Comparison of Year Ended December 31, 2002 to Year Ended December 31, 2001.
Operating Revenue. During the year ended December 31, 2002, operating
revenue from crude oil, natural gas and natural gas liquids sales decreased by
$22.3 million from $73.2 million in 2001 to $50.9 million in 2002. This decrease
was primarily attributable to a decrease in production volumes and lower
commodity prices in 2002 as compared to 2001. Crude oil and natural gas revenue
was impacted by $11.5 million from a decline in commodity prices and $10.8
million from reduced production. The decline in production was due to the
disposition of certain properties in south Texas and natural field declines.
Natural gas liquids volumes declined from 278.0 MBbls in 2001 to 242.0
MBbls in 2002. Crude oil sales volumes declined from 454.1 MBbls in 2001 to
292.3 MBbls during 2002. Natural gas sales volumes decreased from 17.5 Bcf in
2001 to 15.5 Bcf in 2002. Production declines were primarily attributable to our
disposition of assets during 2002 and natural field declines.
Average sales prices in 2002 net of hedging losses were:
o $ 24.34 per Bbl of crude oil,
o $ 17.94 per Bbl of natural gas liquids, and
o $ 2.55 per Mcf of natural gas.
Average sales prices in 2001 net of hedging losses were:
o $24.63 per Bbl of crude oil,
o $21.51 per Bbl of natural gas liquids, and
o $ 3.20 per Mcf of natural gas.
33
Lease Operating Expense. LOE expense decreased from $18.6 million in 2001
to $15.2 million in 2002. LOE on a per Mcfe basis for 2002 was $0.82 per Mcfe as
compared to $0.83 per Mcfe in 2001. The decrease in the per Mcfe cost is due to
a reduced operating cost offset by the decline in production volumes.
G&A Expense. G&A expense increased slightly from $6.4 million in 2001 to
$6.9 million in 2002. This increase was due primarily to increased legal
expenses related to ongoing litigation in 2002. Our G&A expense on a per Mcfe
basis increased from $0.30 in 2001 to $0.37 in 2002. The increase in the per
Mcfe cost was due primarily to lower production volumes in 2002 as compared to
2001.
G&A - 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. We charged approximately
$2.8 million to stock-based compensation expense in 2000 compared to crediting
approximately $2.8 million in 2001. This was due to the decline in the market
price of our Common stock during 2001. During 2002, we did not recognize any
stock-based compensation due to the decline in the price of our common stock.
DD&A Expense. DD&A expense decreased by $5.9 million from $32.4 million in
2001 to $26.5 million in 2002. The decline in DD&A is due to reductions in our
full cost pool resulting from ceiling test write-downs, as well as lower
production volumes. Our DD&A expense on a per Mcfe basis for 2002 was $1.42 per
Mcfe as compared to $1.74 per Mcfe in 2001.
Interest Expense. Interest expense increased from $31.5 million to $34.1
million for 2002 compared to 2001. The increase was the result of additional
sales pursuant to our production payment arrangement with Mirant Americas as
well as increased borrowings under Old Grey Wolf's credit facility in 2002. The
production payment was reacquired in June 2002 for approximately $6.8 million.
Ceiling Limitation Write-down. We record the carrying value of our crude
oil and natural gas 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 Crude Oil and Natural Gas Activities". As of December 31, 2001, the
Company's net capitalized costs of crude oil and natural gas properties exceeded
the present value of its estimated proved reserves by $71.3 million. These
amounts were calculated considering 2001 year-end prices of $19.84 per Bbl for
crude oil and $2.57 per Mcf for natural gas as adjusted to reflect the expected
realized prices for each of the full cost pools. The Company did not adjust its
capitalized costs for its U.S. properties because subsequent to December 31,
2001, crude oil and natural gas prices increased such that capitalized costs for
its U.S. properties did not exceed the present value of the estimated proved
crude oil and natural gas reserves for its U.S. properties as determined using
increased realized prices on March 22, 2002 of $24.16 per Bbl for crude oil and
$2.89 per Mcf for natural gas.
At June 30, 2002, our net capitalized costs of crude oil and natural gas
properties exceeded the present value of our estimated proved reserves by $138.7
million ($28.2 million on the U.S. properties and $110.5 million on the Canadian
properties). These amounts were calculated considering June 30, 2002 prices of
$26.12 per Bbl for crude oil and $2.16 per Mcf for natural gas as adjusted to
reflect the expected realized prices for each of the full cost pools. Subsequent
to June 30, 2002, commodity prices increased in Canada and we utilized these
increased prices in calculating the ceiling limitation write-down. The total
write-down was approximately $116.0 million. At December 31, 2002, our net
capitalized cost of crude oil and natural gas properties did not exceed the
present value of our estimated reserves, due to increased commodity prices
during the fourth quarter and, as such, no further write-down was recorded. 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
crude oil and natural gas assets increases when crude oil and natural gas 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
34
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 resources are revised downward, a further write-down of the
carrying value of our crude oil and natural gas properties may be required.
Income taxes. Income tax expense decreased from an expense of $2.4 million
for the year ended December 31, 2001 to a benefit of $29.7 million for the year
ended December 31, 2002. The decrease was primarily due to the tax benefit
relating to the ceiling limitation write-down related to our Canadian
properties.
Liquidity and Capital Resources
General. The crude oil and natural gas industry is a highly capital
intensive and cyclical business. Our capital requirements are driven principally
by our obligations to service debt and to fund the following costs:
o the development of existing properties, including drilling and
completion costs of wells;
o acquisition of interests in crude oil and natural gas properties;
and
o production and transportation facilities.
The amount of capital available to us will affect our ability to service our
existing debt obligations and to continue to grow the business through the
development of existing properties and the acquisition of new properties.
Our sources of capital are primarily cash on hand, cash from operating
activities, funding under the senior credit agreement and the sale of
properties. Our overall liquidity depends heavily on the prevailing prices of
crude oil and natural gas and our production volumes of crude oil and natural
gas. Significant 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 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
senior credit agreement, future crude oil and natural gas price declines would
have a material adverse effect on our overall results, and therefore, our
liquidity. Low crude oil and natural gas prices could also negatively affect our
ability to raise capital on terms favorable to us and could also reduce the
borrowing base under our senior credit agreement.
If the volume of crude oil and natural gas we produce decreases, our cash
flow from operations will decrease. Our production volumes will decline as
reserves are produced. In addition, due to sales of properties in 2002 and
January 2003, we now have reduced reserves and production levels. In the future,
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
exploration, 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 pursuing these activities,
historically, we have not been able to fully replace the production volumes lost
from natural field declines and property sales.
Working Capital. At December 31, 2003, our current liabilities of
approximately $12.6 million exceeded our current assets of $10.2 million
resulting in a working capital deficit of $2.4 million. This compares to a
working capital deficit of $65.7 million as of December 31, 2002. Current
liabilities as of December 31, 2003 consisted of trade payables of $6.8 million,
revenues due third parties $2.3 million, accrued interest related to our New
Notes of $2.3 million, of which $2.0 is non-cash and other accrued liabilities
of $ 1.2 million. We do not expect to make cash interest payments with respect
to the outstanding New Notes, and the issuance of additional New Notes in lieu
of cash interest payments thereon will not affect our working capital balance.
35
Capital Expenditures. Capital expenditures in 2001, 2002 and 2003 were
$57.1 million, $38.7 million and $18.3 million, respectively. The table below
sets forth the components of these capital expenditures for the three years
ended December 31, 2003.
Year Ended December 31,
-----------------------------------------
2001 2002 2003
---- ---- ----
(dollars in thousands)
Expenditure category:
Development $ 56,694 $ 38,560 $ 18,313
Facilities and other 362 154 36
------------- ------------ ------------
Total $ 57,056 $ 38,714 $ 18,349
============= ============= ============
- ------------------
During 2001, 2002 and 2003, capital expenditures were primarily for the
development of existing properties. We currently have a capital expenditure
budget of $10 million for 2004, of which $5.0 million is allocated to U.S.
projects and $5.0 million is allocated to Canadian drilling projects. We plan to
participate in the drilling or putting on production of 17 gross (13 net) wells,
of which 11 gross (11 net) wells will be operated by us. 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 crude oil
and natural gas 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 crude oil and natural
gas production volumes decreases caused by natural field declines and sales of
producing properties.
Sources of Capital. The net funds provided by and/or used in each of the
operating, investing and financing activities are summarized in the following
table and discussed in further detail below:
2001 2002 2003
---- ---- ----
(dollars in thousands)
Net cash (used in) provided by operating activities $ 16,263 $ (8,336) $ 23,850
Net cash (used in) provided by investing activities (30,797) (5,036) 67,461
Net cash provided by (used in) financing activities 20,685 10,836 (95,622)
-------------- ------------- ------------
Total $ 6,151 $ (2,536) $ (4,311)
============== ============= ============
Operating activities for the year ended December 31, 2003 provided us with
$23.9 million of cash. Investing activities provided us $67.5 million during
2003. Financing activities used $95.6 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 $18.3
million in exploration and development expenditures. Expenditures in 2003 were
primarily for the development of crude oil and natural gas properties.
Operating activities for the year ended December 31, 2002 used $8.4 million
of cash. Investing activities used $5.0 million during 2002. Our investing
activities included the sale of properties which provided $33.9 million, and the
use of $38.9 million primarily for the development of producing properties.
Financing activities provided us with $10.8 million during 2002, relating
primarily to advances on Old Grey Wolf's credit facility.
Operating activities for the year ended December 31, 2001 provided us $16.3
million of cash. Investing activities included the sale of properties which
36
provided $28.9 million, and the use of $57.1 million for the development of
producing properties and $2.7 million for the acquisition of the minority
interest in Grey Wolf. Financing activities provided $20.7 million during 2001,
including the provision of additional funding of $11.7 million under our
production payment arrangement with Mirant Americas, and the provision of $18.3
million under Old Grey Wolf's credit facility. Payments on long-term debt used
$9.3 million.
Future Capital Resources. We will have four principal sources of liquidity
going forward: (i) cash on hand, (ii) cash from operating activities, (iii)
funding under the senior credit agreement, and (iv) sales of producing
properties. Covenants under the indenture for the New Notes and the senior
credit agreement restrict our use of cash on hand, cash from operating
activities and any proceeds from asset sales. We may also attempt to raise
additional capital through the issuance of additional debt or equity securities,
although the terms of the new note indenture and the senior credit agreement
substantially restrict our ability to:
o incur additional indebtedness;
o incur liens;
o pay dividends or make certain other restricted payments;
o consummate certain asset sales;
o enter into certain transactions with affiliates;
o merge or consolidate with any other person; or
o sell, assign, transfer, lease, convey or otherwise dispose of all
or substantially all of our assets.
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, 2003.
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) $ 241,399 $ - $ 57,155 $ 184,244 $ -
Operating Leases (2) 1,373 416 796 161 -
(1) These amounts represent the balances outstanding under the senior credit
agreement and the New Notes. These repayments assume that interest will
be capitalized under the New Notes and that periodic interest on the
senior credit agreement will be paid on a monthly basis and that we will
not draw down additional funds thereunder.
(2) These amounts represent office lease obligations. Leases for office space
for Abraxas and New Grey Wolf expire in April 2006 and December 2008,
respectively.
Other obligations. We make and will continue to make substantial capital
expenditures for the acquisition, exploitation, development, exploration and
production of crude oil and natural gas. In the past, we have funded our
operations and capital expenditures primarily through cash flow from operations,
37
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 January
2003 resulted in the retirement of our first lien notes, second lien notes and
old notes, together with the Old Grey Wolf credit facility. The following table
sets forth our long-term indebtedness as of December 31, 2002, and 2003.
Long Term Indebtedness
December 31
--------------------------------
2002 2003
----------------- --------------
(in thousands)
11.5% Senior Notes due 2004 ("Old Notes") ......................... $ 801 $ -
12.875% Senior Secured Notes due 2003 ("First Lien Notes") ........ 63,500 -
11.5% Second Lien Notes due 2004 ("Second Lien Notes")............. 190,178 -
9.5% Senior Credit Facility ("Grey Wolf Facility") providing for
borrowings up to approximately US $96 million (CDN $150
million). Secured by the assets of Old Grey Wolf and
non-recourse to Abraxas....................................... 45,964 -
11.5% Secured Notes due 2007 ("New Notes")......................... - 137,258
Senior Credit Agreement ........................................... - 47,391 (1)
----------------- ---------------
300,443 184,649
Less current maturities ........................................... 63,500 -
----------------- ---------------
$ 236,943 $ 184,649
================= ===============
- ----------------
(1) At March 2, 2004, the outstanding principal balance on our senior credit
agreement was $50.7 million.
For financial reporting purposes, the New Notes are reflected at the
carrying value of the Second Lien Notes and Old Notes prior to the exchange of
$191.0 million, net of the cash offered in the exchange of $47.5 million and net
of the fair market value related to equity of $3.8 million offered in the
exchange transaction. The face amount of the New Notes was $120.5 million at
December 31, 2003 including $10.8 million in new notes issued for interest.
The New Notes accrue interest from the date of issuance, at a fixed annual
rate of 11 1/2%, payable in cash semi-annually on each May 1 and November 1,
commencing May 1, 2003. We will pay such unpaid interest in kind by the issuance
of additional New Notes with a principal amount equal to the amount of accrued
and unpaid cash interest on the New Notes plus an additional 1% accrued interest
for the applicable period. Upon an event of default, the New Notes accrue
interest at an annual rate of 16.5%.
The New Notes are secured by a second lien or charge on all of our current
and future assets, including, but not limited to, all of our crude oil and
natural gas properties. All of Abraxas' current subsidiaries, Sandia Oil & Gas,
Sandia Operating (a wholly-owned subsidiary of Sandia Oil & Gas), Wamsutter, New
Grey Wolf, Western Associated Energy and Eastside Coal, are guarantors of the
New Notes, and all of Abraxas' future subsidiaries will guarantee the New Notes.
If Abraxas cannot make payments on the New Notes when they are due, the
guarantors must make them instead.
The New Notes and related guarantees
o are subordinated to the indebtedness under the new senior secured
credit agreement;
o rank equally with all of Abraxas' current and future senior
indebtedness; and
o rank senior to all of Abraxas' current and future subordinated
indebtedness, in each case, if any.
38
The New Notes are subordinated to amounts outstanding under the new senior
secured credit agreement both in right of payment and with respect to lien
priority and are subject to an intercreditor agreement.
Abraxas may redeem the New Notes, at its option, in whole at any time or in
part from time to time, at redemption prices expressed as percentages of the
principal amount set forth below. If Abraxas redeems all or any New Notes, it
must also pay all interest accrued and unpaid to the applicable redemption date.
The redemption prices for the New Notes during the indicated time periods are as
follows:
Period Percentage
From January 24, 2004 to June 23, 2004............................97.1674%
From June 24, 2004 to January 23, 2005............................98.5837%
Thereafter.......................................................100.0000%
Under the indenture, we are subject to customary covenants which, among
other things, restrict our ability to:
o borrow money or issue preferred stock;
o pay dividends on stock or purchase stock;
o make other asset transfers;
o transact business with affiliates;
o sell stock of subsidiaries;
o engage in any new line of business;
o impair the security interest in any collateral for the notes;
o use assets as security in other transactions; and
o sell certain assets or merge with or into other companies.
In addition, we are subject to certain financial covenants including covenants
limiting our selling, general and administrative expenses and capital
expenditures, a covenant requiring Abraxas to maintain a specified ratio of
consolidated EBITDA, as defined in the agreements, to cash interest and a
covenant requiring Abraxas to permanently, to the extent permitted, pay down
debt under the new senior secured credit agreement and, to the extent permitted
by the new senior secured credit agreement, the New Notes or, if not permitted,
paying indebtedness under the new senior secured credit agreement.
The indenture contains customary events of default, including nonpayment of
principal or interest, violations of covenants, inaccuracy of representations or
warranties in any material respect, cross default and cross acceleration to
certain other indebtedness, bankruptcy, material judgments and liabilities,
change of control and any material adverse change in our financial condition.
Senior Credit Agreement. In connection with the financial restructuring,
Abraxas entered into a new senior credit agreement providing a term loan
facility and a revolving credit facility as described below. Subsequently, on
February 23, 2004, Abraxas entered into an amendment to its existing senior
credit agreement providing for two revolving credit facilities and a new
non-revolving credit facility as described below. Subject to earlier termination
on the occurrence of events of default or other events, the stated maturity date
for these credit facilities is February 1, 2007. In the event of an early
termination, we will be required to pay a prepayment premium, except in the
limited circumstances described in the amended senior credit agreement.
First Revolving Credit Facility. Lenders under the amended senior credit
agreement have provided a revolving credit facility to Abraxas with a maximum
borrowing base of up to $20 million. Our current borrowing base under this
revolving credit facility is the full $20.0 million, subject to adjustments
based on periodic calculations and mandatory prepayments under the senior credit
agreement. We have borrowed $6.6 million under this revolving credit facility,
39
which was used to refinance principal and interest on advances under our
preexisting revolving credit facility under the senior credit agreement, and to
pay certain fees and expenses relating to the transaction. Outstanding amounts
under this revolving credit facility bear interest at the prime rate announced
by Wells Fargo Bank, N.A. plus 1.125%.
Second Revolving Credit Facility. Lenders under the amended senior credit
agreement have provided a second revolving credit facility to Abraxas, with a
maximum borrowing of up to $30 million. This revolving credit facility is not
subject to a borrowing base. We have borrowed $30.0 million under this revolving
credit facility, which was used to refinance principal and interest on advances
under our preexisting revolving credit facility, and to pay certain transaction
fees and expenses. Outstanding amounts under this revolving credit facility bear
interest at the prime rate announced by Wells Fargo Bank, N.A. plus 3.00%.
Non-Revolving Credit Facility. Abraxas has borrowed $15.0 million pursuant
to a non-revolving credit facility, which was used to repay the preexisting term
loan under our senior credit agreement, to refinance principal and interest on
advances under the preexisting revolving credit facility, and to pay certain
transaction fees and expenses. This non-revolving credit facility is not subject
to a borrowing base. Outstanding amounts under this credit facility bear
interest at the prime rate announced by Wells Fargo Bank, N.A. plus 8.00%.
Covenants. Under the amended senior credit agreement, Abraxas is subject to
customary covenants and reporting requirements. Certain financial covenants
require Abraxas to maintain minimum ratios of consolidated EBITDA (as defined in
the amended senior credit agreement) to adjusted fixed charges (which includes
certain capital expenditures), minimum ratios of consolidated EBITDA to cash
interest expense, a minimum level of unrestricted cash and revolving credit
availability, minimum hydrocarbon production volumes and minimum proved
developed hydrocarbon reserves. In addition, if on the day before the end of
each fiscal quarter the aggregate amount of our cash and cash equivalents
exceeds $2.0 million, we are required to repay the loans under the amended
senior credit agreement in an amount equal to such excess. The amended senior
credit agreement also requires us to enter into hedging agreements on not less
than 40% or more than 75% of our projected oil and gas production. We are also
required to establish deposit accounts at financial institutions acceptable to
the lenders and we are required to direct our customers to make all payments
into these accounts. The amounts in these accounts will be transferred to the
lenders upon the occurrence and during the continuance of an event of default
under the amended senior credit agreement.
In addition to the foregoing and other customary covenants, the amended
senior credit agreement contains a number of covenants that, among other things,
restrict our ability to:
o incur additional indebtedness;
o create or permit to be created liens on any of our properties;
o enter into change of control transactions;
o dispose of our assets;
o change our name or the nature of our business;
o make guarantees with respect to the obligations of third parties;
o enter into forward sales contracts;
o make payments in connection with distributions, dividends or
redemptions relating to our outstanding securities, or
o make investments or incur liabilities.
40
Security. The obligations of Abraxas under the amended senior credit
agreement continue to be secured by a first lien security interest in
substantially all of Abraxas' assets, including all crude oil and natural gas
properties.
Guarantees. The obligations of Abraxas under the amended senior credit
agreement continue to be guaranteed by Abraxas' subsidiaries, Sandia Oil & Gas,
Sandia Operating, Wamsutter, New Grey Wolf, Western Associated Energy and
Eastside Coal. The guarantees under the amended senior credit agreement continue
to be secured by a first lien security interest in substantially all of the
guarantors' assets, including all crude oil and natural gas properties.
Events of Default. The amended senior credit agreement contains customary
events of default, including nonpayment of principal or interest, violations of
covenants, inaccuracy of representations or warranties in any material respect,
cross default and cross acceleration to certain other indebtedness, bankruptcy,
material judgments and liabilities, change of control and any material adverse
change in our financial condition.
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 the senior credit agreement, we are required to maintain
hedge positions on not less than 40% or more than 75% of our projected oil and
gas production for a six month rolling period. See "Item 7A--Quantitative and
Qualitative Disclosures about Market Risk--Hedging Sensitivity" for further
information.
Net Operating Loss Carryforwards
At December 31, 2003, the Company had, subject to the limitation discussed
below, $100.6 million of net operating loss carryforwards for U.S. tax purposes.
These loss carryforwards will expire through 2022 if not utilized. In connection
with January 2003 transactions described in Note 2, in Notes to Consolidated
Financial Statements, Item 8, certain of the loss carryforwards were utilized.
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 $99.1 million
and $76.1 million for deferred tax assets at December 31, 2002 and 2003,
respectively.
Related Party Transactions
Accounts receivable - Other includes approximately $51,211 and $35,558 as
of December 31, 2002 and 2003, respectively, representing amounts due from
officers relating to advances made to employees.
On July 29, 2003 Abraxas acquired all of the shares of the capital stock of
Wind River Resources Corporation which owned an airplane. The sole shareholder
of Wind River was the Company's President. The consideration for the purchase
was 106,977 shares of Abraxas common stock and $35,000 in cash. Simultaneously
with this transaction, the airplane was sold. The airplane had previously been
made available to Abraxas employees for business use.
The Company paid Wind River a total of approximately $314,000, $345,000 and
$132,000 in 2001, 2002 and 2003, through July 29, 2003 respectively, for Wind
River's operating cost associated with the Company's use of the plane.
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.
41
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 Crude Oil and Natural Gas Activities.
SEC Regulation S-X defines the financial accounting and reporting standards for
companies engaged in crude oil and natural gas activities. Two methods are
prescribed: the successful efforts method and the full cost method. Abraxas has
chosen to follow the full cost method under which all costs associated with
property acquisition, exploration and development are capitalized. We also
capitalize internal costs that can be directly identified with our acquisition,
exploration 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 crude oil and natural gas 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 crude oil and
natural gas 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
crude oil and natural gas 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. The Company has experienced
this situation several times over the years, most recently in 2002. Our crude
oil and natural gas 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 crude oil and
natural gas 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. If net capitalized costs of crude oil and natural gas 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 crude oil and natural gas properties increases when crude oil
and natural gas 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 crude oil and natural gas prices may have
increased the ceiling applicable to the subsequent period.
For the year ended December 31, 2002, we recorded a write-down of
approximately $116.0 million. 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 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.
42
The Company's 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, the Company 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 the Company records 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.
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.
Revenue Recognition. 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.
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. If the liability is settled for an amount other than the recorded
amount, a gain or loss is recognized. 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 crude oil and natural gas prices. Results of
those hedging transactions are reflected in crude oil and natural gas sales.
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.
Under this statement, all derivatives, whether designated in hedging
relationships or not, are required to be recorded at fair value on our balance
sheet. The accounting for changes in the fair value of a derivative instrument
depends on the intended use of the derivative and the resulting designation,
which is established at the inception of a derivative. Special accounting for
qualifying hedges allows a derivative's gains and losses to offset related
results of the hedged item in the consolidated statement of operations. For
derivative instruments designated as cash flow hedges, changes in fair value, to
the extent the hedge is effective, are recognized in other comprehensive income
until the hedged item is recognized in earnings. For derivative instruments
43
designated as fair value hedges, changes in fair value, to the extent the hedge
is effective, are recognized as an increase or decrease to the value of the
hedged item until the hedged item is recognized in earnings. Hedge effectiveness
is measured at least quarterly based on the relative changes in fair value
between the derivative contract and the hedged item over time. Any change in the
fair value resulting from ineffectiveness, as defined by SFAS 133, is recognized
immediately in earnings. Changes in fair value of contracts that do not meet the
SFAS 133 definition of a cash flow or fair value hedge are also recognized in
earnings through risk management income. All amounts initially recorded in this
caption are ultimately reversed within the same caption and included in oil and
gas sales or interest expense, as applicable, over the respective contract
terms.
One of the primary factors that can have an impact on our results of
operations is the method used to value our derivatives. We have established the
fair value of all derivative instruments using estimates determined by our
counterparties and subsequently evaluated internally using established index
prices and other sources. These values are based upon, among other things,
futures prices, volatility, time to maturity and credit risk. The values we
report in our financial statements change as these estimates are revised to
reflect actual results, changes in market conditions or other factors, many of
which are beyond our control.
Another factor that can impact our results of operations each period is our
ability to estimate the level of correlation between future changes in the fair
value of the hedge instruments and the transactions being hedged, both at the
inception and on an ongoing basis. This correlation is complicated because
energy commodity prices, the primary risk we hedge, have quality and location
differences that can be difficult to hedge effectively. The factors underlying
our estimates of fair value and our assessment of correlation of our hedging
derivatives are impacted by actual results and changes in conditions that affect
these factors, many of which are beyond our control.
Due to the volatility of crude oil and natural gas 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 the net market value of our derivatives was
an asset of $21,136. As of December 31, 2002 we did not have any outstanding
derivatives.
New Accounting Pronouncements
A reporting issue has arisen regarding the application of certain
provisions of SFAS No. 141 and SFAS No. 142 to companies in the extractive
industries, including oil and gas companies. The issue is whether SFAS No. 142
requires registrants to classify the costs of mineral rights held under lease or
other contractual arrangement associated with extracting oil and gas as
intangible assets in the balance sheet, apart from other capitalized oil and gas
property costs, and provide specific footnote disclosures. Historically, the
Company has included the costs of such mineral rights associated with extracting
oil and gas as a component of oil and gas properties. If it is ultimately
determined that SFAS No. 142 requires oil and gas companies to classify costs of
mineral rights held under lease or other contractual arrangement associated with
extracting oil and gas as a separate intangible assets line item on the balance
sheet, the Company would be required to reclassify approximately $3.1 million
and $4.2 million at December 31, 2002 and December 31, 2003, respectively, out
of oil and gas properties and into a separate intangible assets line item. The
Company's cash flows and results of operations would not be affected since such
intangible assets would continue to be depleted and assessed for impairment in
accordance with full-cost accounting rules.
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. If the liability is settled for an amount other than the recorded
amount, a gain or loss is recognized. 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.
44
The Company adopted SFAS 143 effective January 1, 2003. For the year ended
December 31, 2003 the Company recorded a charge of $395,341 for the cumulative
effect of the change in accounting principal and a liability of $1.3 million.
During 2003, the Company charged approximately $379,000 to expense related to
the accretion of the liability. The impact on each of the prior periods was not
material.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" (SFAS 144). Effective January 1,
2002, the Company adopted SFAS 144. SFAS 144 retains the requirement to
recognize an impairment loss only where the carrying value of a long-lived asset
is not recoverable from its undiscounted cash flows and to measure such loss as
the difference between the carrying amount and fair value of the asset. SFAS
144, among other things, changes the criteria that have to be met to classify an
asset as held-for-sale and requires that operating losses from discontinued
operations be recognized in the period that the losses are incurred rather than
as of the measurement date. This new standard had no impact on the Company's
consolidated financial statements for the year ended December 31, 2003.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" (SFAS 146). SFAS 146 requires costs
associated with exit of disposal activities to be recognized when they are
incurred rather than at the date of commitment to an exit or disposal plan. The
Company is currently evaluating the impact the standard will have on its results
of operations and financial condition. The official effective date of this
standard has not been determined by the FASB.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts, and for
hedging activities under SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities." SFAS No. 149, among other things, clarifies the
circumstances under which a contract with an initial net investment meets the
characteristic of a derivative and amends the definition of an "underlying" to
conform it to language used in FIN 45. SFAS No. 149 is effective for contracts
entered into or modified after June 30, 2003. The Company adopted this statement
effective July 1, 2003. Implementation of this new standard did not have an
effect on the Company's consolidated financial position or results of
operations.
In November 2002 the FASB issued FASB Interpretation No. 45 (FIN 45),
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others." FIN 45 elaborates on the
disclosures to be made by a guarantor in its financial statements about its
obligations under certain guarantees that it has issued, including loan
guarantees such as standby letters of credit. It also requires a guarantor to
recognize, at the inception of a guarantee, a liability for the fair value of
the obligations it has undertaken in issuing the guarantee. The Interpretation
does not specify the subsequent measurement of the guarantor's recognized
liability over the term of the related guarantee. The guidance in FIN 45 does
not apply to certain guarantee contracts, such as those issued by insurance
companies or for a lessee's residual value guarantee embedded in a capital
lease. The provisions related to recognizing a liability at inception of the
guarantee for the fair value of the guarantor's obligations would not apply to
product warranties or to guarantees accounted for as derivatives. The initial
recognition and initial measurement provisions apply on a prospective basis to
guarantees issued or modified after December 31, 2002, regardless of the
guarantor's fiscal year-end. FIN 45 specifies additional disclosures effective
for financial statements of interim or annual periods ending after December 15,
2002.
In January 2003 the FASB issued FASB Interpretation No. 46 (FIN 46),
"Consolidation of Variable-Interest Entities (VIEs".) FIN 46 establishes the
definition of VIEs to encompass a broader group of entities than those
previously considered special-purpose entities (SPEs). FIN 46 specifies the
criteria under which it is appropriate for an investor to consolidate VIEs; in
order for an investor to consolidate a VIE, the entity must fall within the
definition of VIE and the investor must fall within the definition of primary
beneficiary, both newly defined terms under this FIN. The revised effective date
of FIN 46 for public companies with VIEs meeting certain conditions, will be the
end of the first interim or annual period ending after December 15, 2003. In
December 2003, the FASB issued FASB Interpretaion no. 46(R)m which expanded and
clarified the guidelines of FIN 46.
45
In May 2003, the FASB issued FAS No. 150, entitled "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity"(SFAS
150). This statement is effective for financial instruments entered into or
modified after May 31, 2003, and is otherwise effective at the beginning of the
first interim period beginning after June 15, 2003. The Company has no financial
instruments affected by SFAS 150, therefore adoption by the Company as of July
1, 2003 will not impact the Company's financial statements.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Commodity Price Risk
As an independent crude oil and natural gas producer, our revenue, cash
flow from operations, other income and 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 crude oil and natural
gas that we can produce economically. Prevailing prices for such commodities are
subject to wide fluctuation in response to relatively minor changes in supply
and demand and a variety of additional factors beyond our control, such as
global political and economic conditions. Historically, prices received for
crude oil and natural gas production have been volatile and unpredictable, and
such volatility is expected to continue. Most of our production is sold at
market prices. Generally, if the commodity indexes fall, the price that we
receive for our production will also decline. Therefore, the amount of revenue
that we realize is partially determined by factors beyond our control. Assuming
the production levels we attained during the year ended December 31, 2003, a 10%
decline in crude oil, natural gas and natural gas liquids prices would have
reduced our operating revenue, cash flow and net income by approximately $3.8
million for the year.
Hedging Sensitivity
On January 1, 2001, we adopted SFAS 133 "Accounting for Derivative
Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138. Under
SFAS 133, all derivative instruments are recorded on the balance sheet at fair
value. If the derivative does not qualify as a hedge or is not designated as a
hedge, the gain or loss on the derivative is recognized currently in earnings.
To qualify for hedge accounting, the derivative must qualify either as a fair
value hedge or cash flow hedge. If the derivative qualifies for cash flow hedge
accounting, the gain or loss on the derivative is deferred in Other
Comprehensive Income/Loss, a component of Stockholders' Equity, to the extent
that the hedge is effective. As of December 31, 2003 the derivatives that we
have in place are not designated as hedges. Accordingly, changes in the fair
market value of the derivatives are recorded in current period oil and gas
revenue.
If a derivative qualifies for hedge accounting, the relationship between
the hedging instrument and the hedged item must be highly effective in achieving
the offset of changes in cash flows attributable to the hedged risk both at the
inception of the contract and on an ongoing basis. Hedge accounting is
discontinued prospectively when a hedge instrument becomes ineffective. Gains
and losses deferred in accumulated Other Comprehensive Income/Loss related to a
cash flow hedge that becomes ineffective, remain unchanged until the related
production is delivered. If we determine that it is probable that a hedged
transaction will not occur, deferred gains or losses on the hedging instrument
are recognized in earnings immediately.
Gains and losses on qualified hedging instruments related to accumulated
Other Comprehensive Income and adjustments to carrying amounts on hedged
production are included in natural gas or crude oil production revenue in the
period that the related production is delivered. For derivatives not qualifying
for hedge accounting, changes in the fair market value of the instrument are
charged to income in the current period.
In 2001 and 2002, we experienced hedging losses of $12.1 million and $3.2
million, respectively. In October 2002, all of these hedge agreements expired.
Under the expired hedge agreements, we made total payments to various
counterparties in the amount of $35.1 million.
46
Under the terms of the senior secured credit agreement, we are required
to maintain hedging positions with respect to not less than 40% nor more than
75% of our crude oil and natural gas production for a rolling six month period.
As of December 31, 2003 the Company's hedge positions were as follows:
Time Period Notional Quantities Price
- --------------------------------- ------------------------------ ---------------
March 1, 2003 - February 29, 5,000 MMBtu of natural gas Floor of $4.50
2004 production per day
March 1, 2004 - April 30, 2004 2,000 MMBtu of natural gas Floor of $4.00
production per day
March 1, 2004 - April 30, 2004 500 Bbls of crude oil Floor of $22.00
production per day
May 2004 2,000 Mmbtu of natural gas Floor of $4.00
production per day
May 2004 500 Bbls of crude oil Floor of $22.00
production per day
June 2004 800 Bbls of crude oil Floor of $22.00
production per day
July 2004 2,000 Mmbtu of natural gas Floor of $4.00
production per day
July 2004 500 Bbls of crude oil Floor of $22.00
production per day
Subsequent to year-end we have entered into additional agreements similar to
those scheduled above (floors) in volume amounts sufficient to reach the 40%
threshold required by our senior credit agreement. The Company anticipates
continuing to purchase similar floors in the future to satisfy our requirements
under the senior credit agreement.
Interest rate risk
At December 31, 2003, as a result of the financial restructuring that
occurred in January 2003, we had approximately $47.4 million in outstanding
indebtedness under the new senior secured credit agreement, accruing interest at
a rate of prime plus 4.5%, subject to a minimum interest rate of 9.0%. In the
event that the prime rate (currently 4.0%) rises above 4.5% the interest rate
applicable to our outstanding indebtedness under the new senior secured credit
agreement will rise accordingly. For every percentage point that the prime rate
rises above 4.5%, our interest expense would increase by approximately $430,000
on an annual basis. Our New Notes accrue interest at fixed rates and are
accordingly not subject to fluctuations in market rates.
As discussed in "Business - General" the senior secured credit agreement
was amended in February 2004. Our interest rate under the terms of the amended
credit agreement is a floating rate, currently at approximately 7.5%, assuming
all available amounts are borrowed.
Foreign Currency
Our Canadian operations are measured in the local currency of Canada. As a
result, our financial results are affected by changes in foreign currency
exchange rates or weak economic conditions in the foreign markets. Our ongoing
Canadian operations reported a pre-tax income $218,000 for the year ended
December 31, 2003. It is estimated that a 5% change in the value of the U.S.
dollar to the Canadian dollar would have changed our net income by approximately
$10,900. We do not maintain any derivative instruments to mitigate the exposure
to translation risk. However, this does not preclude the adoption of specific
hedging strategies in the future.
Item 8. Financial Statements
For the financial statements and supplementary data required by this Item
8, see the Index to Consolidated Financial Statements.
47
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
As noted in the form 8-K filed on April 23, 2003, the Board of Directors of
Abraxas Petroleum Corporation engaged the accounting firm of BDO Seidman, LLP as
the Company's certifying accountant for the year ended December 31, 2003. The
engagement of BDO Seidman, LLP was approved by the Audit Committee of the Board
of Directors. The Audit Committee of the Board of Directors approved the
dismissal of Deloitte & Touche LLP. The reports of Deloitte & Touche LLP on the
Company's financial statements for the two fiscal years ended December 31, 2001
and 2002 did not contain any adverse opinion or disclaimer of opinion and were
not qualified or modified as to uncertainty, audit scope or accounting
principles.
In connection with the audits of the Company's financial statements for
each of the two fiscal years ended December 31, 2001 and 2002, there were no
disagreements with Deloitte & Touche LLP on any matters of accounting
principles, financial statement disclosure or audit scope and procedures which,
if not resolved to the satisfaction of Deloitte & Touche LLP, would have caused
the firm to make reference to the matter in their report.
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 Abraxas' "disclosure controls and procedures" (as defined in
the Securities Exchange Act of 1934 Rules 13a-15(e)and 15d-15(e)) and concluded
that the disclosure controls and procedures were adequate and designed to ensure
that material information relating to Abraxas and our consolidated subsidiaries
which is required to be included in our periodic Securities and Exchange
Commission filings would be made known to them by others within those entities.
There were no changes in our internal controls that could materially affect, or
are reasonably likely to materially affect our financial reporting.
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 2004 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 Abraxas' 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, Abraxas believes that all
its directors and executive officers during 2003 complied on a timely basis with
all applicable filing requirements under Section 16(a) of the Exchange Act.
48
Item 11. Executive Compensation
There is incorporated in this Item 11 by reference that portion of our
definitive proxy statement for the 2004 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
There is incorporated in this Item 12 by reference that portion of our
definitive proxy statement for the 2004 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 2004 Annual Meeting of Stockholders which
appears therein under the caption "Certain Transactions."
Item 14. Principal Accountant Fees and Services
There is incorporated in this Item 14 by reference that portion of our
definitive proxy statement for the 2004 Annual Meeting of Stockholders which
appears therein under the caption "Principal Auditor Fees and Services."
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a)1. Consolidated Financial Statements Page
Report of BDO Seidman LLP Independent Auditors....................F-2
Report of Deloitte & Touche LLP, Independent Auditors..............F-3
Consolidated Balance Sheets,
December 31, 2002 and 2003.......................................F-4
Consolidated Statements of Operations,
Years Ended December 31, 2001, 2002 and 2003.....................F-6
Consolidated Statements of Stockholders' Deficit
Years Ended December 31, 2001, 2002 and 2003 ...................F-7
Consolidated Statements of Cash Flows
Years Ended December 31, 2001, 2002 and 2003.....................F-9
Consolidated Statements of Other Comprehensive Income (loss)
Years Ended December 31, 2001, 2002 and 2003....................F-11
Notes to Consolidated Financial Statements........................F-12
Grey Wolf Exploration Inc.
Auditors' Reports for the years ended December 31, 2001 and 2002..F-45
49
Comments by Auditors' for US readers on Canada - US
reporting differences...........................................F-46
Balance Sheet at December 31, 2002................................F-47
Statements of Earnings and Retained Earnings for the years ended
December 31, 2002 and 2001 .....................................F-48
Statements of Cash Flows for the years ended
December 31, 2002 and 2001.....................................F-49
Notes to Financial Statements.....................................F-51
(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 Abraxas'
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).
3.4 Articles of Amendment to the Articles of Incorporation of Abraxas dated
June 8, 1995. (Filed as Exhibit 3.4 to Abraxas' 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 Abraxas' 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 Abraxas' Annual Report on Form 10-K filed on March 31, 1995).
4.3 Rights Agreement dated as of December 6, 1994 between Abraxas and First
Union National Bank of North Carolina ("FUNB"). (Filed as Exhibit 4.1
to Abraxas' Registration Statement on Form 8-A filed on December 6,
1994).
4.4 Amendment to Rights Agreement dated as of July 14, 1997 by and between
Abraxas and American Stock Transfer & Trust Company. (Filed as Exhibit
1 to Amendment No. 1 to Abraxas' Registration Statement on Form 8-A
filed on August 20, 1997).
50
4.5 Second Amendment to Rights Agreement as of May 22, 1998, by and between
Abraxas and American Stock Transfer & Trust Company. (Filed as Exhibit
1 to Amendment No. 2 to Abraxas' Registration Statement on Form 8-A
filed on August 24, 1998).
4.6 Indenture dated January 23, 2003, by and among Abraxas, as Issuer; the
subsidiary Guarantors party thereto and U.S. Bank, N.A., as Trustee,
relating to Abraxas' 11-1/2 % Secured Notes Due 2007. (filed as Exhibit
4.1 to Abraxas' Current Report on Form 8-K dated February 6, 2003).
4.7 Form of 111/2% Secured Notes due 2007. (Filed as Exhibit A to Exhibit
4.6).
*10.1 Abraxas Petroleum Corporation 1984 Non-Qualified Stock Option Plan, as
amended and restated. (Filed as Exhibit 10.7 to Abraxas' Annual Report
on Form 10-K filed April 14, 1993).
*10.2 Abraxas Petroleum Corporation 1984 Incentive Stock Option Plan, as
amended and restated. (Filed as Exhibit 10.8 to Abraxas' Annual Report
on Form 10-K filed April 14, 1993).
*10.3 Abraxas Petroleum Corporation 1993 Key Contributor Stock Option Plan.
(Filed as Exhibit 10.9 to Abraxas' Annual Report on Form 10-K filed
April 14, 1993).
*10.4 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")).
*10.5 Abraxas Petroleum Corporation Director Stock Option Plan. (Filed as
Exhibit 10.5 to the 1996 Exchange Offer Registration Statement).
*10.6 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).
*10.7 Abraxas Petroleum Corporation 1994 Long Term Incentive Plan. (Filed as
Exhibit 10.21 to Abraxas' Annual Report on Form 10-K filed on April 12,
1994).
*10.8 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).
10.10 Form of Indemnity Agreement between Abraxas and each of its directors
and officers. (Filed as Exhibit 10.30 to the 1993 S-1).
10.15 Common Stock Purchase Warrant dated September 1, 2000 between Basil
Street Company Filed as Exhibit 10.15 to Abraxas Annual Report on Form
10-K filed on April 2, 2001).
10.16 Common Stock Purchase Warrant dated September 1, 2000 between Jessup &
Lamont Holdings (Filed as Exhibit 10.16 to Abraxas Annual Report on
Form 10-K filed on April 2, 2001).
10.17 Common Stock Purchase Warrant dated August 1, 2000 between Abraxas and
TNC, Inc. (Filed as Exhibit 10.17 to Abraxas Annual Report on Form 10-K
filed on April 2, 2001).
10.18 Common Stock Purchase Warrant dated August 1, 2000 between Abraxas and
Charles K. Butler (Filed as Exhibit 10.17 to Abraxas Annual Report on
Form 10-K filed on April 2, 2001).
10.19 Agreement of Limited Partnership of Abraxas Wamsutter L.P. dated as of
November 12, 1999 by and between Wamsutter Holdings, Inc. and TIFD
III-X Inc. (Filed as Exhibit 10.2 to Abraxas' Current Report on Form
8-K filed November 30,1999).
51
10.20 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).
10.21 Amendment No. 2 dated as of February 23, 2004 to Loan and Security
Agreement by and among Abraxas Petroleum Corporation, the subsidiaries
of Abraxas that are signatories thereto, as Guarantors, the Lenders
that are signatories thereto, as Lenders, and Wells Fargo Foothill,
Inc., formerly known as Foothill Capital Corporation, as the Arranger
and Administrative Agent (Filed as Exhibit 10.1 to Abraxas Current
Report on Form 8-K filed on February 26, 2004).
10.22 Intercreditor and Subordination Agreement dated as of January 23, 2003,
by and among Foothill, in its capacity as agent (in such capacity,
together with any successor in such capacity, the "Senior Agent") for
the lenders who are from time to time parties to the Loan Agreement
(the "Senior Lenders"), U.S. Bank, N.A., a national banking association
in its capacity as trustee (in such capacity, together with any
successor in such capacity, the "Trustee") for the holders of the 11
1/2% Secured Notes Due 2007, issued under the Indenture. (Filed as
Exhibit 10.6 to Abraxas' Current Report on Form 8-K filed February 6,
2003).
16.1 Letter addressing change in certifying accountant (Filed on Abraxas'
Form 8-K filed on August 22, 2001).
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)
23.2 Consent of Deloitte & Touche LLP (filed herewith).
23.3 Consent of Deloitte & Touche LLP Chartered Accountants (filed
herewith).
23.4 Consent of DeGolyer and MacNaughton. (filed herewith).
23.5 Consent of McDaniel & Associates Consultants, Ltd. (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.
(b) Reports on Form 8-K
1. Current Report on Form 8-K filed on November 13, 2003, Disclosure of
Operations and Financial Condition, including press release announcing
Third Quarter 2003 Financial Results.
2. Current Report on Form 8-K filed on February 2, 2004, Regulation FD,
including press release announcing Operations Update and Exhibit of
materials presented to investors.
52
3. Current Report on Form 8-K filed on February 24, 2004, Regulation FD,
including press release announcing amendment to First Lien Credit
Facility.
4. Current Report on Form 8-K filed on February 26, 2004, Financial
Statements and Exhibits and Regulation FD disclosure, including
Amendment No. 2 to Loan and Security Agreement and press release
regarding such amendment.
5. Current Report on Form 8-K filed on March 9, 2004, Financial Statements
and Exhibits, including press release announcing Forth Quarter 2003 and
Year End 2003 Financial Results.
53
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 11, 2004
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
Robert L.G. Watson Executive Officer)and
Director March 11, 2004
/s/ Chris E. Williford Exec. Vice President and
- ----------------------- Treasurer (Principal Financial
Chris Williford and Accounting Officer) March 11, 2004
/s/ Craig S. Bartlett, Jr. Director March 11, 2004
- --------------------------
Craig S. Bartlett, Jr.
/s/ Franklin Burke Director March 11, 2004
- ------------------
Franklin Burke
/s/ Harold D. Carter Director March 11, 2004
- --------------------
Harold D. Carter
/s/ Ralph F. Cox Director March 11, 2004
- -----------------
Ralph F. Cox
/s/ Barry J. Galt Director March 11, 2004
- ------------------
Barry J. Galt
/s/ Dennis E. Logue Director March 11, 2004
- -------------------
Dennis E Logue
/s/ James C. Phelps Director March 11, 2004
- -------------------
James C. Phelps
/s/ Joseph A. Wagda Director March 11, 2004
- -------------------
Joseph A. Wagda
54
Exhibit 23.1
Independent Auditors' Consent
We consent to the incorporation by reference in the Registration Statements No.
33-48932, 33-48934, 33-72268, 33-81416, 33-81418, 333-17375, and 333-17377 of
Abraxas Petroleum Corporation on Form S-8 of our report dated february 13, 2004,
relating to the consolidated financial statements, which appears in the Annual
Report to Shareholders, which is incorporated in this Annual Report pmn Fornm
10-K.
BDO Seidman, LLP
March 9, 2003
55
Exhibit 23.2
Independent Auditors' Consent
We consent to the incorporation by reference in the Registration Statements No.
33-48932, 33-48934, 33-72268, 33-81416, 33-81418, 333-17375, and 333-17377 of
Abraxas Petroleum Corporation on Form S-8 of our report dated March 10, 2003,
July 18, 2003, as to Note 19, and the first paragraph of "New Accounting
Pronouncements" in Note 1, (which expresses an unqualified opinion and includes
two explanatory paragraphs referring to the subsequent events described in Note
2 and the restatement described in Note 19), appearing in this Annual Report on
Form 10-K of Abraxas Petroleum Corporation for the year ended December 31, 2003.
/s/ Deloitte & Touche LLP
San Antonio, Texas
March 9, 2004
56
Exhibit 23.3
Independent Auditors' Consent
We consent to the incorporation by reference in the Registration Statements No.
33-48932, 33-48934, 33-72268, 33-81416, 33-81418, 333-17375, and 333-17377 of
Abraxas Petroleum Corporation on Form S-8 of our report dated March 10, 2003 on
the financial statements of Grey Wolf Exploration Inc. (which report expresses
an unqualified opinion, and for U.S. readers has a Canada-U.S. reporting
difference which would require an explanatory paragraph relating to the
Company's changes in accounting policies and significant subsequent events that
have been disclosed in the financial statements), appearing in this Annual
Report on Form 10-K of Abraxas Petroleum Corporation for the year ended December
31, 2003.
Calgary, Canada /s/ Deloitte & Touche LLP
March 9, 2004 Chartered Accountants
57
Exhibit 23.3
Consent of DeGolyer and MacNaughton
We hereby consent to the incorporation in the "Reserves Information" section of
your Annual Report on Form 10-K of the references to DeGolyer and MacNaughton
and to the use by reference of information contained in our "Appraisal Report as
of December 31, 2003 on Certain Properties owned by Abraxas Petroleum
Corporation," "Appraisal Report as of December 31, 2003 on Certain Properties
owned by Grey Wolf Exploration Inc. in Canada," "Appraisal Report as of December
31, 2002 on Certain Properties owned by Abraxas Petroleum Corporation,"
"Appraisal Report as of December 31, 2002 on Certain Properties owned by Grey
Wolf Exploration Inc. in Canada," and "Appraisal Report as of December 31, 2001
on Certain Properties owned by Abraxas Petroleum Corporation" (our Reports).
However, since the crude oil, condensate, natural gas liquids, and natural gas
reserves estimates set forth in our Reports have been combined with reserves
estimates of other petroleum consultants or those estimated by Abraxas, we are
necessarily unable to verify the accuracy of the reserves estimates contained in
the aforementioned Annual Report.
DeGolyer and MacNaughton
Dallas, Texas
March 9, 2004
58
Exhibit 23.4
Consent of McDaniel and Associates Consultants LTD.
We consent to the incorporation in your Annual Report on Form 10-K/A of the
references to McDaniel and Associates Consultants Ltd. in the "Reserves
Information" section and to the use by reference of information contained in our
Evaluation Report "Canadian Abraxas Petroleum Ltd., Evaluation of Oil & Gas
Reserves, As of January 1, 2002, dated April 3, 2002.
McDaniel & Associates Consultants LTD
Calgary, Alberta
April 3, 2002
59
Exhibit 31.1
CERTIFICATIONS
I, Robert L. G. Watson, certify that:
1. I have reviewed this annual report on Form 10-K of Abraxas Petroleum
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the
registrant and have:
(a) designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made
known to us by others within those entities, particularly during
the period in which this annual report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures, and presented in this report our
conclusions about the effectiveness of the disclosure controls
and procedures, as of the end of the period covered by this
report based on such evaluation; and
(c) disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the
registrant's fourth fiscal quarter that has materially affected,
or is reasonably likely to materially affect, the registrant's
internal control over financial reporting.
5. The registrant's other certifying officer and I have disclosed, based
on our most recent evaluation of internal control over financial
reporting, to the registrant's auditors and the audit committee of the
registrant's board of directors (or persons performing the equivalent
functions):
(a) all significant deficiencies in the design or operation of
internal controls which are reasonably likely to adversely affect
the registrant's ability to record, process, summarize and report
financial information; and
(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal control over financial reporting.
Date: March 11, 2004
/s/ Robert L.G. Watson
Robert L.G. Watson
Chairman of the Board, President and
Principal Executive Officer
60
Exhibit 31.2
CERTIFICATIONS
I, Chris Williford, certify that:
1. I have reviewed this annual report on Form 10-K of Abraxas Petroleum
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the
registrant and have:
(a) designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made
known to us by others within those entities, particularly during
the period in which this annual report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures, and presented in this report our
conclusions about the effectiveness of the disclosure controls
and procedures, as of the end of the period covered by this
report based on such evaluation; and
(c) disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the
registrant's fourth fiscal quarter that has materially affected,
or is reasonably likely to materially affect, the registrant's
internal control over financial reporting.
5. The registrant's other certifying officer and I have disclosed, based
on our most recent evaluation of internal control over financial
reporting, to the registrant's auditors and the audit committee of the
registrant's board of directors (or persons performing the equivalent
functions):
(a) all significant deficiencies in the design or operation of
internal controls which are reasonably likely to adversely affect
the registrant's ability to record, process, summarize and report
financial information; and
(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal control over financial reporting.
Date: March 11, 2004
/s/ Chris Williford
Chris Williford
Executive Vice President and
Principal Accounting Officer
61
Exhibit 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Abraxas Petroleum Corporation (the
"Company") on Form 10-K for the year ended December 31, 2003 as filed with the
Securities and Exchange Commission on the date hereof (the "Report"), I, Robert
L.G. Watson, Chairman of the Board, President and Chief Executive Officer of the
Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, that:
(1)The Report fully complies with the requirements of Section 13(a) or
15(d) of the Securities Act of 1934; and
(2)The information contained in the Report fairly presents, in all
material respects, the financial condition and results of operations of
the Company.
/s/ Robert L.G. Watson
Robert L.G. Watson
Chairman of the Board,
President and Chief Executive Officer
March 11, 2004
This certification accompanies the Report pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the
Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of ss.18
of the Securities Exchange Act of 1964, as amended.
A signed original of this written statement required by Section 906 has been
provided to the Company and will be retained by the Company and furnished to the
Securities and Exchange Commission or its staff upon request.
62
Exhibit 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Abraxas Petroleum Corporation (the
"Company") on Form 10-K for the year ended December 31, 2003 as filed with the
Securities and Exchange Commission on the date hereof (the "Report"), I, Chris
E, Williford, Executive Vice President and Chief Financial Officer of the
Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, that:
(1)The Report fully complies with the requirements of Section 13(a) or
15(d) of the Securities Act of 1934; and
(2)The information contained in the Report fairly presents, in all
material respects, the financial condition and results of operations of
the Company.
/s/ Chris E. Williford
Chris E. Williford
Executive Vice President and
Chief Financial Officer
March 11, 2004
This certification accompanies the Report pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the
Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of ss.18
of the Securities Exchange Act of 1964, as amended.
A signed original of this written statement required by Section 906 has been
provided to the Company and will be retained by the Company and furnished to the
Securities and Exchange Commission or its staff upon request.
63
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Abraxas Petroleum Corporation and Subsidiaries
Independent Auditors' Report for the year ended December 31, 2003..........F-2
Independent Auditors' Reports for the years ended December 31, 2001
and 2002................................................................F-3
Consolidated Balance Sheets at December 31, 2002 and 2003..................F-4
Consolidated Statements of Operations for the years ended
December 31, 2001, 2002 and 2003........................................F-6
Consolidated Statements of Stockholders' Deficit for the years ended
December 31, 2001, 2002 and 2003.......................................F-7
Consolidated Statements of Cash Flows for the years ended
December 31, 2001, 2002 and 2003........................................F-9
Consolidated Statements of Other Comprehensive Income (loss)
for the years ended December 31, 2001, 2002 and 2003... ................F-11
Notes to Consolidated Financial Statements ................................F-12
Grey Wolf Exploration Inc.
Auditors' Reports for the years ended December 31, 2001 and 2002...........F-47
Comments by Auditors' for US readers on Canada - US reporting differences..F-48
Balance Sheet at December 31, 2002.........................................F-49
Statements of Earnings and Retained Earnings for the years ended
December 31, 2002 and 2001 .............................................F-50
Statements of Cash Flows for the years ended December 31, 2002 and 2001...F-51
Notes to Financial Statements..............................................F-52
F-1
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of
Abraxas Petroleum Corporation
We have audited the accompanying consolidated balance sheet of Abraxas Petroleum
Corporation (the "Company") as of December 31, 2003, and the related
consolidated statements of operations, stockholders' deficit, and cash flows and
other comprehensive income for the year ended December 31, 2003. 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 auditing standards generally accepted
in the United States of America. 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 financial position of Abraxas Petroleum Corporation at
December 31, 2003, and the results of its operations and its cash flows for the
year ended December 31, 2003 in conformity with accounting principles generally
accepted in the United States of America.
As discussed in Note 1 to the consolidated financial statements, as of January
1, 2003, the Company changed its method of accounting for asset retirement
obligations.
/s/BDO Seidman, LLP
Dallas, Texas
February 13, 2004
F-2
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of
Abraxas Petroleum Corporation
We have audited the accompanying consolidated balance sheet of Abraxas Petroleum
Corporation and Subsidiaries (the "Company") as of December 31, 2002, and the
related consolidated statements of operations, stockholders' deficit, and cash
flows and other comprehensive income for each of the two years in the period
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 audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. 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 audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of the Company at December 31, 2002,
and the results of its operations and its cash flows for each of the two years
in the period ended December 31, 2002 in conformity with accounting principles
generally accepted in the United States of America.
As discussed in Note 2 to the financial statements, on January 23, 2003, the
Company sold all of the outstanding common stock of two wholly owned
subsidiaries, Canadian Abraxas Petroleum Limited and Grey Wolf Exploration,
Inc., repaid certain debt, and also entered into an agreement to exchange cash,
new debt and common stock of the Company for certain other debt.
As discussed in Note 19 to the financial statements, the accompanying 2001 and
2002 financial statements have been restated.
/s/DELOITTE & TOUCHE LLP
San Antonio, Texas
March 10, 2003 (July 18, 2003, as to Note 19 and the first paragraph of "New
Accounting Pronouncements" in Note 1)
F-3
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31
--------------------------------------
2002 2003
------------------ -------------------
(Dollars in thousands)
Current assets:
Cash ................................................... $ 4,882 $ 493
Accounts receivable:
Joint owners ....................................... 2,215 1,360
Oil and gas production sales ....................... 7,466 5,873
Other .............................................. 364 1,090
------------------ -------------------
10,045 8,323
Equipment inventory .................................... 1,014 782
Other current assets ................................... 1,240 572
------------------ -------------------
Total current assets.................................. 17,181 10,170
Property and equipment:
Oil and gas properties, full cost method of accounting:
Proved ............................................. 521,995 325,222
Unproved, not subject to amortization .............. 7,052 4,304
Other property and equipment ......................... 44,189 4,540
------------------ -------------------
Total .......................................... 573,236 334,066
Less accumulated depreciation, depletion, and
amortization ....................................... 422,842 222,503
------------------ -------------------
Total property and equipment - net ................. 150,394 111,563
Deferred financing fees net ............................... 5,671 4,410
Deferred income taxes...................................... 7,820 -
Other assets .............................................. 359 294
------------------ -------------------
Total assets ........................................... $ 181,425 $ 126,437
================== ===================
See accompanying notes to consolidated financial statements
F-4
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS (CONTINUED)
LIABILITIES AND STOCKHOLDERS' DEFICIT
December 31
--------------------------------------
2002 2003
------------------ -------------------
(Dollars in thousands)
Current liabilities:
Accounts payable .......................................... $ 9,687 $ 6,756
Joint interest oil and gas production payable ............. 2,432 2,290
Accrued interest .......................................... 6,009 2,340
Other accrued expenses .................................... 1,162 1,228
Current maturities of long-term debt ...................... 63,500 -
------------------ -------------------
Total current liabilities................................ 82,790 12,614
Long-term debt ............................................... 236,943 184,649
Future site restoration ..................................... 3,946 1,377
Stockholders' equity (deficit):
Common stock, par value $.01 per share - authorized
200,000,000 shares; issued 30,145,280 and 36,024,308
at December 31, 2002 and 2003 respectively............ 301 360
Additional paid-in capital ................................ 136,830 141,835
Receivables from stock sale................................ (97) (97)
Accumulated deficit ...................................... (269,621) (213,701)
Treasury stock, at cost, 165,883 shares.................... (964) (964)
Accumulated other comprehensive income (loss).............. (8,703) 364
------------------ -------------------
Total stockholders' deficit................................... (142,254) (72,203)
------------------ -------------------
Total liabilities and stockholders' deficit................ $ 181,425 $ 126,437
================== ===================
See accompanying notes to consolidated financial statements
F-5
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31
----------------------------------------------------------
2001 2002 2003
----------------------------------------------------------
(In thousands except per share data)
Revenues:
Oil and gas production revenues ......................... $ 73,201 $ 50,862 $ 38,105
Gas processing revenues.................................. 2,438 2,420 133
Rig revenues ............................................ 756 635 663
Other .................................................. 848 403 118
--------------------------------------------------------
77,243 54,320 39,019
Operating costs and expenses:
Lease operating and production taxes .................... 18,616 15,240 9,599
Depreciation, depletion, and amortization ............... 32,484 26,539 10,803
Proved property impairment .............................. 2,638 115,993 -
Rig operations .......................................... 702 567 609
General and administrative .............................. 6,445 6,884 5,360
Stock-based compensation................................. (2,767) - 1,106
--------------------------------------------------------
58,118 165,223 27,477
--------------------------------------------------------
Operating income (loss)..................................... 19,125 (110,903) 11,542
Other (income) expense:
Interest income ......................................... (78) (92) (30)
Amortization of deferred financing fees ................. 2,268 2,095 1,678
Interest expense ........................................ 31,523 34,150 16,955
Financing costs.......................................... - 967 4,406
Loss on sale of equity investment ....................... 845 - -
Gain on sale of foreign subsidiaries..................... - - (68,933)
Other ................................................... 207 201 774
--------------------------------------------------------
34,765 37,321 (45,150)
--------------------------------------------------------
Income (loss) before cumulative effect of accounting change
and taxes................................................ (15,640) (148,224) 56,692
Income tax expense (benefit):
Current ................................................. 505 - -
Deferred ................................................ 1,897 (29,697) 377
Minority interest in income of foreign subsidiary (2001
prior to purchase)....................................... 1,676 - -
Cumulative effect of accounting change...................... - - 395
--------------------------------------------------------
Net income (loss)........................................ $ (19,718) $ (118,527) $ 55,920
========================================================
Basic earnings (loss)per common share:
Net earnings (loss)................................... $ (0.76) $ (3.95) $ 1.59
Cumulative effect of accounting change................ - - (0.01)
--------------------------------------------------------
Net income (loss) per common share - basic .............. $ (0.76) $ (3.95) $ 1.58
========================================================
Diluted earnings (loss) per common share:
Net earnings (loss)................................... $ (0.76) $ (3.95) $ 1.56
Cumulative effect of accounting change................ - - (0.01)
--------------------------------------------------------
Net income (loss) per common share - diluted............ $ (0.76) $ (3.95) $ 1.55
========================================================
See accompanying notes to consolidated financial statements
F-6
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' DEFICIT
(In thousands except share amounts)
Common Stock Treasury Stock Additional
-------------------------------------------- Paid-In
Shares Amount Shares Amount Capital
----------- -------------------------------------------------
Balance at December 31, 2000 . 22,759,852 $ 227 165,883 $ (964) $ 130,409
Comprehensive income (loss)
Net loss .................... -- -- -- --
Other comprehensive
income:
Hedge loss .............. -- -- -- --
Foreign currency
translation adjustment. -- -- -- --
adjustment
Comprehensive income ...... (28,480)
(loss)
Stock-based compensation
expense ................. -- -- -- (2,767)
Issuance of common stock
for contingent value
rights .................. 3,383,488 34 -- -- (34)
Issuance of common stock
and stock options for
acquisition of
minority interest in ....
Old Grey Wolf
Exploration, Inc. ....... 3,990,565 40 -- -- 9,206
Stock options exercised ... 8,375 -- -- 16 --
---------- --------- --------- ----------- ------------
Balance at December 31, 2001 . 30,145,280 $ 301 165,883 $ (964) $ 136,830
Comprehensive income
(loss):
Net loss .................. -- -- -- -- --
Other comprehensive
income:
Hedge income .......... -- -- -- -- --
Foreign currency
translation ......... -- -- -- -- --
adjustment
Comprehensive income (loss)
---------- ------- --------- ----------- ------------
Balance at December 31, 2002.. 30,145,280 $ 301 165,883 $ (964) $ 136,830
Accumulated
Other Recivables
Accumuated Comprehensive From
Deficit Income (loss) Stock Sale Total
------------- -------------- ------------- ----------
Balance at December 31, 2000 . $ (131,376) $ (4,799) $ (97) $ (6,600)
Comprehensive income (loss):
Net loss .................... (19,718) -- -- (19,718)
Other comprehensive
income:
Hedge loss .............. -- (566) -- (566)
Foreign currency
translation adjustment. -- (8,196) -- (8,196)
adjustment
---------
Comprehensive income (loss).. (24,480)
Stock-based compensation
expense ................. -- -- -- (2,767)
Issuance of common stock
for contingent value
rights .................. -- -- -- --
Issuance of common stock
and stock options for
acquisition of
minority interest in
Old Grey Wolf
Exploration, Inc. ........ -- -- -- 9,246
Stock options exercised ... -- -- -- 16
------------- -------------- ------------- ----------
Balance at December 31, 2001 . $(151,094) $ (13,561) $ (97) $ (28,585)
Comprehensive income
(loss):
Net loss ................. . (118,527) -- -- (118,527)
Other comprehensive
income:
Hedge income .......... -- 566 -- 566
Foreign currency
translation .........
adjustment -- 4,292 -- 4,292
-----------
Comprehensive income (loss) (113,669)
------------- -------------- ------------- ----------
Balance at December 31, 2002. . $ (269,621) $ (8,703) $ (97) $ (142,254)
F-7
ABRAXAS PETROLEUM CORPORATIONRIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' DEFICIT (continued)
(In thousands except share amounts)
Common Stock Treasury Stock Additional
-------------------------------------------- Paid-In
Shares Amount Shares Amount Capital
----------- --------- ---------- ----------- -----------------
Balance at December 31, 2002.. 30,145,280 $ 301 165,883 $ (964) $136,830
Comprehensive income
(loss):
Net income ............. -- -- -- -- --
Other comprehensive
income (loss):
Foreign currency
translation
adjustment ........ -- -- -- -- --
Comprehensive income ....
Stock-based compensation
expense ............... -- -- -- -- 1,106
Stock options exercised . 129,352 1 -- -- 84
Stock issued for
acquisition of Wind ...
River Resources 106,977 1 -- -- 91
Stock issued in
connection with
exchange offer 5,642,699 57 -- -- 3,724
----------- --------- ---------- ----------- -----------------
Balance at December 31, 2003. 36,024,308 $ 360 165,883 $ (964) $ 141,835
=========== ========= ========== =========== =================
Accumulated
Other Recivables
Accumuated Comprehensive From
Deficit Income (loss) Stock Sale Total
------------- -------------- ------------- ----------
Balance at December 31, 2002. $ (269,621) $ (8,703) $ (97) $ (142,254)
Comprehensive income
(loss):
Net income .......... 55,920 -- -- 55,920
Other comprehensive
income (loss):
Foreign currency
translation
adjustment ........ -- 9,067 -- 9,067
----------
Comprehensive income .... 64,987
Stock-based compensation
expense ............... -- -- -- 1,106
Stock options exercised . -- -- -- 85
Stock issued for
acquisition of Wind ...
River Resources -- -- -- 92
Stock issued in
connection with
exchange offer......... -- -- -- 3,781
------------- -------------- ------------- ----------
Balance at December 31, 2003 $ (213,701) $ 364 $ (97) $ (72,203)
============= ============== ============= ==========
See accompanying notes to consolidated financial statements.
F-8
Abraxas Petroleum Corporation
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31
----------------------------------------------------------------
2001 2002 2003
----------------------------------------------------------------
(In thousands)
Operating Activities
Net income (loss) ................................... $ (19,718) $ (118,527) $ 55,920
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Minority interest in income of foreign subsidiary 1,676 - -
Loss on sale of equity investment................ 845 - -
(Gain) on sale of foreign subsidiaries........... - - (68,933)
Depreciation, depletion, and
amortization ................................ 32,484 26,539 10,803
Non-cash interest and financing cost............ - - 16,422
Proved property impairment ..................... 2,638 115,993 -
Deferred income tax expense (benefit)........... 1,897 (29,697) 377
Amortization of deferred financing fees......... 2,268 2,095 1,678
Stock-based compensation ....................... (2,767) - 1,106
Changes in operating assets and liabilities:
Accounts receivable ......................... 12,693 (2,247) (1,446)
Equipment inventory ......................... (76) 201 78
Other ...................................... (106) 126 295
Accounts payable ............................ (14,848) (2,775) 3,417
Accrued expenses ............................ (723) (44) 4,133
------------------ ------------------ ------------------
Net cash provided by (used) in operations............ 16,263 (8,336) 23,850
Investing Activities
Capital expenditures, including purchases
and development of properties .................... (57,056) (38,912) (18,349)
Proceeds from sale of oil and gas
properties........................................ 28,938 33,876 -
Acquisition of minority interest..................... (2,679) - -
Proceeds from sale of foreign subsidiaries.......... - - 85,810
------------------ ------------------ ------------------
Net cash provided by (used ) in investing activities. (30,797) (5,036) 67,461
F-9
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
Years Ended December 31
----------------------------------------------------------------
2001 2002 2003
----------------------------------------------------------------
(In thousands)
Financing Activities
Proceeds from issuance of common stock............... 16 - 177
Proceeds from long-term borrowings .................. 29,995 20,551 43,342
Payments on long-term borrowings .................... (9,326) (8,176) (138,544)
Deferred financing fees ............................. - (1,539) (597)
------------------ ------------------ ------------------
Net cash (used in) provided by financing activities.. 20,685 10,836 (95,622)
------------------ ------------------ ------------------
Increase (decrease) in cash ......................... 6,151 (2,536) (4,311)
Effect of exchange rate changes on cash.............. (550) (187) (78)
------------------ ------------------ ------------------
Increase (decrease) in cash ......................... 5,601 (2,723) (4,389)
Cash at beginning of year ........................... 2,004 7,605 4,882
------------------ ------------------ ------------------
Cash at end of year.................................. $ 7,605 $ 4,882 $ 493
================== ================== ==================
Supplemental Disclosures
Supplemental disclosures of cash flow information:
Interest paid .......................... $ 31,752 $ 34,154 $ 4,279
================== ================== ==================
Taxes paid.............................. $ 505 $ - $ -
================== ================== ==================
Supplemental schedule of non-cash investing and
financing activities:
In May 2001 the Company issued 3,386,488 shares of common stock upon the
expiration of the CVRs issued in connection with the December 1999
exchange.
In September 2001 the Company issued 3,990,565
shares of common stock and options and paid
$2,679,000 million in cash in connection with the
acquisition of the minority interest in Old Grey
Wolf. (See Note 4.)
Decrease in oil and gas properties and other assets.. $ (2,925)
Decrease in deferred income tax liability............ $ 1,091
==================
Increase in stockholders equity...................... $ (9,246)
==================
Decrease in minority interest in foreign subsidiary.. $ 13,759
==================
See accompanying notes to consolidated financial statements.
F-10
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME (LOSS)
Years Ended December 31,
2001 2002 2003
---------------------------------------------------------
(In thousands)
Net income (loss)............................................ $ (19,718) $ (118,527) $ 55,920
Other Comprehensive income (loss):
Hedging derivatives (net of tax) - See Note 16 (566) -
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.............. - - 4,632
Effect of change in exchange rate........................... - - 4,435
------------------- ------------------ ------------------
Other comprehensive income (loss)................................ (8,762) 4,858 9,067
------------------- ------------------ ------------------
Comprehensive income (loss)...................................... $ (28,480) $ (113,669) $ 64,987
=================== ================== ==================
See accompanying notes to consolidated financial statements.
F-11
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 engaged in the exploration for 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 western Canada.
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.
The consolidated financial statements include the accounts of the Company
and its wholly-owned foreign subsidiary, Grey Wolf Exploration Inc. ("New Grey
Wolf"). In January 2003, the Company sold all of the common stock of its
wholly-owned foreign subsidiaries, Canadian Abraxas Petroleum Limited ("Canadian
Abraxas") and Grey Wolf Exploration Inc. ("Old Grey Wolf"). Certain oil and gas
properties were retained and transferred into New Grey Wolf which was
incorporated in January 2003. The operations of Canadian Abraxas and Old Grey
Wolf are included in the consolidated financial statements through January 23,
2003.
New Grey Wolf's assets and liabilities are translated to U.S. dollars at
period-end exchange rates. Income and expense items are translated at average
rates of exchange prevailing during the period. Translation adjustments are
accumulated as a separate component of shareholders' equity.
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
swap agreements. 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.
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 $77,000 and $11,000 at December 31, 2002 and 2003,
respectively. 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-12
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, by
country, 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. During
2001, 2002 and 2003 the Company capitalized $164,000, $152,000 and $49,000 of
interest expense respectively, based on the cost of major development projects
in progress.
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 and collars, which limit the impact of price
fluctuations 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.
All derivatives, whether designated in hedging relationships or not, will be
required to be recorded on the balance sheet at fair value. If the derivative is
designated a fair-value hedge, the changes in the fair value of the derivative
and the hedged item will be recognized in earnings. If the derivative is
designated a cash-flow hedge, changes in the fair value of the derivative will
be recorded in other comprehensive income (OCI) and will be recognized in the
income statement when the hedged item affects earnings. SFAS 133 defines new
requirements for designation and documentation of hedging relationships as well
as ongoing effectiveness assessments in order to use hedge accounting. For a
derivative that does not qualify as a hedge, changes in fair value will be
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-13
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. The Company
recognized a credit of $2.8 million during 2001 as stock-based compensation. The
credit for the year ended December 31, 2001 was due to a decline in the
Company's common stock price. There was no stock based compensation for the year
ended December 31, 2002. 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 million during 2003.
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 2001, 2002 and
2003, risk-free interest rates of 3.5%, 1.50% and 1.5%, respectively; 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
----------------------------------------------------------------
2001 2002 2003
------------------- ----------------- -----------------
Net income (loss) as reported $ (19,718) $ (118,527) $ 55,920
Add: Stock-based employee compensation expense included in
reported net income, net of related tax effects (2,767) - 1,106
Deduct: Total stock-based employee compensation expense
determined under fair value based method for all awards,
net of related tax effects (1,284) (670) (228)
------------------- ----------------- -----------------
Pro forma net income (loss) $ (23,769) $ (119,197) $ 56,798
=================== ================= =================
Earnings (loss) per share:
Basic - as reported $ (0.76) $ (3.95) $ 1.58
=================== ================= =================
Basic - pro forma $ (0.92) $ (3.98) $ 1.61
=================== ================= =================
Diluted - as reported $ (0.76) $ (3.95) $ 1.55
=================== ================= =================
Diluted - pro forma $ (0.92) $ (3.98) $ 1.57
=================== ================= =================
Foreign Currency Translation
The functional currency for Canadian Abraxas and Grey Wolf (Old and New) 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.
F-14
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.
Revenue Recognition
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, 2003.
Deferred Financing Fees
Deferred financing fees are being amortized on a level yield basis over the
term of the related debt arrangements.
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.
New Accounting Pronouncements
A reporting issue has arisen regarding the application of certain
provisions of SFAS No. 141 and SFAS No. 142 to companies in the extractive
industries, including oil and gas companies. The issue is whether SFAS No. 142
requires registrants to classify the costs of mineral rights held under lease or
other contractual arrangement associated with extracting oil and gas as
intangible assets in the balance sheet, apart from other capitalized oil and gas
property costs, and provide specific footnote disclosures. Historically, the
Company has included the costs of such mineral rights associated with extracting
oil and gas as a component of oil and gas properties. If it is ultimately
determined that SFAS No. 142 requires oil and gas companies to classify costs of
mineral rights held under lease or other contractual arrangement associated with
extracting oil and gas as a separate intangible assets line item on the balance
sheet, the Company would be required to reclassify approximately $3.1 million
and $4.2 million at December 31, 2002 and December 31, 2003, respectively, out
of oil and gas properties and into a separate intangible assets line item. The
Company's cash flows and results of operations would not be affected since such
intangible assets would continue to be depleted and assessed for impairment in
accordance with full-cost accounting rules.
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. If the liability is settled for an amount other than the recorded
amount, a gain or loss is recognized. 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.
F-15
The Company adopted SFAS 143 effective January 1, 2003. For the year ended
December 31, 2003 the Company recorded a charge of $395,341 for the cumulative
effect of the change in accounting principle and a liability of $1.3 million.
During 2003, the Company charged approximately $379,000 to expense related to
the accretion of the liability. The impact on each of the prior periods was not
material.
The following table summarizes the Company's asset retirement obligation
transactions during the following years:
2003 2002 2001
----------------------- ------------------- ---------------------
Beginning asset retirement obligation................ $ 3,946 $ 4,056 $ 4,305
Additions related to new properties.................. 973 196 -
Deletions related to property disposals.............. (3,921) (306) (249)
Accretion expense.................................... 379 - -
----------------------- ------------------- ---------------------
Ending asset retirement obligation................... $ 1,377 $ 3,946 $ 4,056
======================= =================== =====================
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" (SFAS 144). Effective January 1,
2002, the Company adopted SFAS 144. SFAS 144 retains the requirement to
recognize an impairment loss only where the carrying value of a long-lived asset
is not recoverable from its undiscounted cash flows and to measure such loss as
the difference between the carrying amount and fair value of the asset. SFAS
144, among other things, changes the criteria that have to be met to classify an
asset as held-for-sale and requires that operating losses from discontinued
operations be recognized in the period that the losses are incurred rather than
as of the measurement date. This new standard had no impact on the Company's
consolidated financial statements for the year ended December 31, 2003.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" (SFAS 146). SFAS 146 requires costs
associated with exit of disposal activities to be recognized when they are
incurred rather than at the date of commitment to an exit or disposal plan. The
Company is currently evaluating the impact the standard will have on its results
of operations and financial condition. The effective date of this standard has
not been determined by the FASB.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts, and for
hedging activities under SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities." SFAS 149, among other things, clarifies the
circumstances under which a contract with an initial net investment meets the
characteristic of a derivative and amends the definition of an "underlying" to
conform it to language used in FIN 45. SFAS 149 is effective for contracts
entered into or modified after June 30, 2003. The Company adopted this statement
effective July 1, 2003. Implementation of this new standard did not have an
effect on the Company's consolidated financial position or results of
operations.
In November 2002 the FASB issued FASB Interpretation No. 45 (FIN 45),
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others." FIN 45 elaborates on the
disclosures to be made by a guarantor in its financial statements about its
obligations under certain guarantees that it has issued, including loan
guarantees such as standby letters of credit. It also requires a guarantor to
recognize, at the inception of a guarantee, a liability for the fair value of
the obligations it has undertaken in issuing the guarantee. The Interpretation
does not specify the subsequent measurement of the guarantor's recognized
liability over the term of the related guarantee. The guidance in FIN 45 does
not apply to certain guarantee contracts, such as those issued by insurance
companies or for a lessee's residual value guarantee embedded in a capital
lease. The provisions related to recognizing a liability at inception of the
guarantee for the fair value of the guarantor's obligations would not apply to
product warranties or to guarantees accounted for as derivatives. The initial
recognition and initial measurement provisions apply on a prospective basis to
guarantees issued or modified after December 31, 2002, regardless of the
guarantor's fiscal year-end. FIN 45 specifies additional disclosures effective
for financial statements of interim or annual periods ending after December 15,
2002. This new standard did not have an effect on the Company's consolidated
financial position or results of operations.
In January 2003 the FASB issued FASB Interpretation No. 46 (FIN 46),
"Consolidation of Variable-Interest Entities (VIEs".) FIN 46 establishes the
definition of VIEs to encompass a broader group of entities than those
previously considered special-purpose entities (SPEs). FIN 46 specifies the
criteria under which it is appropriate for an investor to consolidate VIEs; in
order for an investor to consolidate a VIE, the entity must fall within the
definition of VIE and the investor must fall within the definition of primary
beneficiary, both newly defined terms under this interpretation. The revised
effective date of FIN 46 for public companies with VIEs meeting certain
conditions will be the end of the first interim or annual period ending after
F-16
December 15, 2003. In December 2003 the FASB issued FASB Interpretation no.
46(R), which expanded and clarified the guidelines of FIN 46. This new standard
did not have an effect on the Company's consolidated financial position or
results of operations.
In May 2003, the FASB issued SFAS No. 150, entitled "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity" (SFAS
150). This statement is effective for financial instruments entered into or
modified after May 31, 2003, and is otherwise effective at the beginning of the
first interim period beginning after June 15, 2003. The Company has no financial
instruments affected by SFAS 150, therefore adoption by the Company as of July
1, 2003 will not impact the Company's financial statements.
2. Restructuring transactions
In January 2003, the Company completed the following restructuring
transactions:
o The closing of the sale of the capital stock of Canadian Abraxas
Petroleum and Old Grey Wolf, to a Canadian royalty trust for
approximately $138 million.
o The closing of a new senior credit agreement consisting of a term
loan facility of $4.2 million and a revolving credit facility of up
to $50 million with an initial borrowing base of $49.9 million, of
which $42.5 million was used to fund the exchange offer described
below and the remaining availability will be used to fund the
continued development of our existing crude oil and natural gas
properties.
o The closing of an exchange offer, pursuant to which Abraxas paid
$264 in cash and issued $610 principal amount of new 11 1/2 %
Secured Notes due 2007, Series A, referred to herein as New Notes,
and 31.36 shares of Abraxas common stock for each $1,000 in
principal amount of the outstanding 11 1/2 % Senior Secured Notes
due 2004, Series A, and 11 1/2 % Senior Notes due 2004, Series D,
issued by Abraxas and Canadian Abraxas, which were tendered and
accepted in the exchange offer. An aggregate of approximately $179.9
million in principal amount of the notes were tendered in the
exchange offer and the remaining $11.1 million of notes not tendered
were redeemed.
o The repayment of Abraxas' 12? % Senior Secured Notes due 2003,
principal amount of $63.5 million, plus accrued interest.
o The repayment of Old Grey Wolf's senior secured credit facility with
Mirant Canada Energy Capital Ltd. (Mirant Canada Facility) in the
amount of approximately $46.3 million.
On February 23, 2004, the Company entered into an amendment to our existing
senior credit agreement providing for two revolving credit facilities and a new
non-revolving credit facility as described below. Subject to earlier termination
on the occurrence of events of default or other events, the stated maturity date
for these credit facilities is February 1, 2007. In the event of an early
termination, we will be required to pay a prepayment premium, except in the
limited circumstances described in the amended senior credit agreement.
First Revolving Credit Facility. Lenders under the amended senior credit
agreement have provided Abraxas a revolving credit facility with a maximum
borrowing base of up to $20 million. The Company's current borrowing base under
this revolving credit facility is the full $20.0 million, subject to adjustments
based on periodic calculations and mandatory prepayments under the senior credit
agreement. The Company has borrowed $6.6 million under this revolving credit
facility, which was used to refinance principal and interest on advances under
it's preexisting revolving credit facility under the senior credit agreement,
and to pay certain fees and expenses relating to the transaction. Outstanding
amounts under this revolving credit facility bear interest at the prime rate
announced by Wells Fargo Bank, N.A. plus 1.125%.
Second Revolving Credit Facility. Lenders under the amended senior credit
agreement have provided a second revolving credit facility, with a maximum
borrowing of up to $30 million. This revolving credit facility is not subject to
a borrowing base. The Company has borrowed $30.0 million under this revolving
credit facility, which was used to refinance principal and interest on advances
under our preexisting revolving credit facility, and to pay certain transaction
fees and expenses. Outstanding amounts under this revolving credit facility bear
interest at the prime rate announced by Wells Fargo Bank, N.A. plus 3.00%.
Non-Revolving Credit Facility. The Company has borrowed $15.0 million
pursuant to a non-revolving credit facility, which was used to repay the
preexisting term loan under it's senior credit agreement, to refinance principal
and interest on advances under the preexisting revolving credit facility, and to
pay certain transaction fees and expenses. This non-revolving credit facility is
not subject to a borrowing base. Outstanding amounts under this credit facility
bear interest at the prime rate announced by Wells Fargo Bank, N.A. plus 8.00%.
F-17
Covenants. Under the amended senior credit agreement, we are subject to
customary covenants and reporting requirements. Certain financial covenants
require us to maintain minimum ratios of consolidated EBITDA (as defined in the
amended senior credit agreement) to adjusted fixed charges (which includes
certain capital expenditures), minimum ratios of consolidated EBITDA to cash
interest expense, a minimum level of unrestricted cash and revolving credit
availability, minimum hydrocarbon production volumes and minimum proved
developed hydrocarbon reserves. In addition, if on the day before the end of
each fiscal quarter the aggregate amount of our cash and cash equivalents
exceeds $2.0 million, we are required to repay the loans under the amended
senior credit agreement in an amount equal to such excess. The amended senior
credit agreement also requires us to enter into hedging agreements on not less
than 40% or more than 75% of our projected oil and gas production. We are also
required to establish deposit accounts at financial institutions acceptable to
the lenders and we are required to direct our customers to make all payments
into these accounts. The amounts in these accounts will be transferred to the
lenders upon the occurrence and during the continuance of an event of default
under the amended senior credit agreement.
In addition to the foregoing and other customary covenants, the amended
senior credit agreement contains a number of covenants that, among other things,
restrict our ability to:
o incur additional indebtedness;
o create or permit to be created liens on any of our properties;
o enter into change of control transactions;
o dispose of our assets;
o change our name or the nature of our business;
o make guarantees with respect to the obligations of third parties;
o enter into forward sales contracts;
o make payments in connection with distributions, dividends or
redemptions relating to our outstanding securities, or
o make investments or incur liabilities.
Security. The obligations of Abraxas under the amended senior credit
agreement continue to be secured by a first lien security interest in
substantially all of Abraxas' assets, including all crude oil and natural gas
properties.
Guarantees. The obligations of Abraxas under the amended senior credit
agreement continue to be guaranteed by Abraxas' subsidiaries, Sandia Oil & Gas,
Sandia Operating, Wamsutter, Grey Wolf, Western Associated Energy and Eastside
Coal. The guarantees under the amended senior credit agreement continue to be
secured by a first lien security interest in substantially all of the
guarantors' assets, including all crude oil and natural gas properties.
Events of Default. The amended senior credit agreement contains customary
events of default, including nonpayment of principal or interest, violations of
covenants, inaccuracy of representations or warranties in any material respect,
cross default and cross acceleration to certain other indebtedness, bankruptcy,
material judgments and liabilities, change of control and any material adverse
change in our financial condition.
The following presents the summarized results of operations for the years
ended December 31, 2001, 2002, and for the period ended January 23, 2003, for
the Canadian properties which were not retained after the transaction in January
2003.
Year ended December 31,
2001 2002 2003
-------- -------- --------
Total revenue ................................. $ 41,468 $ 32,013 $ 3,275
======== ======== ========
Income (loss) from operations before income tax (102) (87,378) 1,250
Income tax expense (benefit) .................. 1,897 (29,697) 377
Minority interest in income ................... (1,676) -- --
-------- -------- --------
Income (loss) from operations ................. $ (3,675) $(57,681) $ 873
======== ======== ========
F-18
Assets and liabilities related to the Canadian properties which were
not retained after the January 2003 transaction:
December 31,
2002
--------
Assets:
Cash............................................ $ 4,325
Accounts receivable............................. 4,016
Net property and equipment...................... 54,468
Other........................................... 11,438
--------
$ 74,247
--------
Liabilities:
Accounts payable and accrued liabilities........ $ 7,320
Long-tern debt.................................. 45,964
Other........................................... 3,413
--------
$ 56,697
--------
Included in the loss from operations shown above is interest expense of
$7.6 million and $9.5 million, and general and administrative expense of $1.5
million and $1.7 million for the years ended December 31, 2001 and 2002,
respectively. The interest expense represents the amounts relating to an Old
Grey Wolf senior credit facility which was repaid in conjunction with the
transactions described above and the amounts related to the balance of certain
notes (approximately $52.6 million) which had historically been reflected by
Canadian Abraxas.
3. Long-Term Debt
As described in Note 2, the First Lien Notes were redeemed in January 2003.
The Old Notes and the Second Lien Notes were either redeemed or exchanged for
cash, common stock and New Notes in January 2003. Additionally, the 9.5% Mirant
Canada Energy Capital, Ltd. credit facility, with a balance outstanding at
December 31, 2002 of $45.9 million, was repaid in connection with the sale of
the common stock of Old Grey Wolf in January 2003.
The following is a brief description of the Company's debt as of December 31,
2002 and 2003, respectively:
December 31
--------------------------------
2002 2003
--------------------------------
(in thousands)
11.5% Senior Notes due 2004 ("Old Notes") ......................... $ 801 $ -
12.875% Senior Secured Notes due 2003 ("First Lien Notes") ........ 63,500 -
11.5% Second Lien Notes due 2004 ("Second Lien Notes")............. 190,178 -
9.5% Senior Credit Facility ("Grey Wolf Facility") providing for
borrowings up to approximately US $96 million (CDN $150
million). Secured by the assets of Old Grey Wolf and
non-recourse to Abraxas....................................... 45,964 -
11.5% Secured Notes due 2007 ("New Notes")......................... - 137,258 (a)
Senior Credit Agreement ........................................... - 47,391
---------------------------------
300,443 184,649
Less current maturities ........................................... 63,500 -
---------------------------------
$ 236,943 $ 184,649
=================================
(a) After the transactions described in Note 2, for financial reporting
purposes, the New Notes were reflected at the carrying value of the Second Lien
Notes and Old Notes prior to the exchange of $191.0 million, net of the cash
offered in the exchange of $47.5 million and net of the fair market value
related to equity of $3.8 million offered in the exchange transaction. The face
amount of the New Notes is $120.5 million at December 31, 2003 including $10.8
million in new notes issued for interest.
Old Notes. Interest on the Old Notes was payable semi-annually in arrears
on May 1 and November 1 of each year at the rate of 11.5% per annum. The Old
Notes were redeemable, in whole or in part, at the option of the Company.
First Lien Notes. Interest on the First Lien Notes was payable
semi-annually in arrears on March 15 and September 15 of each year at the rate
of 12.875% per annum.
Second Lien Notes. Interest on the Second Lien Notes was payable
semi-annually in arrears on May 1 and November 1, commencing May 1, 2000 at the
rate of 11.5% per annum.
F-19
New Notes - 11 1/2% Secured Notes. The New Notes accrue interest from the
date of issuance, at a fixed annual rate of 11 1/2%, payable in cash
semi-annually on each May 1 and November 1, commencing May 1, 2003, provided
that, if we fail, or are not permitted pursuant to our new senior secured credit
agreement or the intercreditor agreement between the trustee under the indenture
for the New Notes and the lenders under the new senior secured credit agreement,
to make such cash interest payments in full, we will pay such unpaid interest in
kind by the issuance of additional New Notes with a principal amount equal to
the amount of accrued and unpaid cash interest on the New Notes plus an
additional 1% accrued interest for the applicable period. Upon an event of
default, the New Notes accrue interest at an annual rate of 16.5%.
The New Notes are secured by a second lien or charge on all of our current
and future assets, including, but not limited to, all of our crude oil and
natural gas properties. All of Abraxas' current subsidiaries, Sandia Oil & Gas,
Sandia Operating (a wholly-owned subsidiary of Sandia Oil & Gas), Wamsutter, New
Grey Wolf, Western Associated Energy and Eastside Coal, are guarantors of the
New Notes, and all of Abraxas' future subsidiaries will guarantee the New Notes.
If Abraxas cannot make payments on the New Notes when they are due, the
guarantors must make them instead.
The New Notes and related guarantees
o are subordinated to the indebtedness under the senior credit
agreement;
o rank equally with all of Abraxas' current and future senior
indebtedness; and
o rank senior to all of Abraxas' current and future subordinated
indebtedness, in each case, if any.
The New Notes are subordinated to amounts outstanding under the new senior
secured credit agreement both in right of payment and with respect to lien
priority and are subject to an intercreditor agreement.
Abraxas may redeem the New Notes, at its option, in whole at any time or in
part from time to time, at redemption prices expressed as percentages of the
principal amount set forth below. If Abraxas redeems all or any New Notes, it
must also pay all interest accrued and unpaid to the applicable redemption date.
The redemption prices for the New Notes during the indicated time periods are as
follows:
Period Percentage
From January 24, 2004 to June 23, 2004................................97.1674%
From June 24, 2004 to January 23, 2005................................98.5837%
Thereafter...........................................................100.0000%
Under the indenture, we are subject to customary covenants which, among
other things, restrict our ability to:
o...borrow money or issue preferred stock;
o pay dividends on stock or purchase stock;
o make other asset transfers;
o transact business with affiliates;
o sell stock of subsidiaries;
o engage in any new line of business;
o impair the security interest in any collateral for the notes;
o use assets as security in other transactions; and
o sell certain assets or merge with or into other companies.
In addition, we are subject to certain financial covenants including covenants
limiting our selling, general and administrative expenses and capital
expenditures, a covenant requiring Abraxas to maintain a specified ratio of
consolidated EBITDA, as defined in the agreements, to cash interest and a
covenant requiring Abraxas to permanently, to the extent permitted, pay down
debt under the new senior secured credit agreement and, to the extent permitted
by the new senior secured credit agreement, the New Notes or, if not permitted,
paying indebtedness under the new senior secured credit agreement.
F-20
The indenture contains customary events of default, including nonpayment of
principal or interest, violations of covenants, inaccuracy of representations or
warranties in any material respect, cross default and cross acceleration to
certain other indebtedness, bankruptcy, material judgments and liabilities,
change of control and any material adverse change in our financial condition.
Senior Credit Agreement. In connection with the financial
restructuring, Abraxas entered into a new senior credit agreement providing a
term loan facility and a revolving credit facility which was amended in February
2004. A summary description of the senior credit agreement as amended, is set
forth in Note 2.
4. Acquisitions and Divestitures
Acquisition of Minority Interest in Old Grey Wolf
In September 2001, the Company completed a tender offer for the minority
interest in Old Grey Wolf, acquiring the approximately 52% of capital stock that
was not previously owned by the Company. The Company issued 3,990,565 common
shares and 588,916 stock options, valued together at approximately $9.2 million.
Additionally, the Company incurred direct costs of approximately $2.7 million
related to the acquisition. The elimination of the minority interest through an
acquisition at a purchase price less than Old Grey Wolf's book value in the
Company's consolidated financial statements had the effect of reducing the
property and other assets balances by $2.9 million and deferred income taxes by
$1.1 million.
5. Property and Equipment
The major components of property and equipment, at cost, are as follows:
Estimated December 31
----------------------------------
Useful Life 2002 2003
----------------- ---------------- -----------------
Years (In thousands)
Land, buildings, and improvements .............. 15 $ 331 $ 331
Crude oil and natural gas properties ........... - 529,047 329,526
Natural Gas Processing.......................... 18 38,735 -
Equipment and other ............................ 7 5,123 4,209
---------------- -----------------
$ 573,236 $ 334,066
================ =================
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 will
expire in November 2004, unless earlier exchanged or redeemed.
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. During the years ended December 31, 2001, 2002 and 2003, the Company
did not purchase any shares of its common stock for treasury stock.
F-21
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.
During 2001, the Company's stockholders approved an amendment to the
Abraxas Petroleum Corporation 1994 Long Term Incentive Plan to increase the
number of shares of Abraxas common stock reserved for issuance under the plan to
5,000,000 shares. The additional shares were necessary to accommodate the grant
of Abraxas options to Old Grey Wolf option holders in connection with the
acquisition of the minority interest in Old Grey Wolf in September 2001 (see
Note 4), and for the re-issuance of outstanding options granted under the
Abraxas Petroleum Corporation 2000 Long Term Incentive Plan, which was
terminated in 2001. The options were re-issued at the same exercise price and
term as the original issuances.
The Company's various stock option plans have authorized the grant of
options to management, employees and directors for up to approximately 5.7
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, 2003
approximately 2.3 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:
2001 2002 2003
----------------------------- ----------------------------- -----------------------------
Weighted-Average Weighted-Average Weighted-Average
Options Exercise Price Options Exercise Price Options Exercise Price
(000s) (000s) (1) (000s)
---------- ------------------ ---------- ------------------ --------- ------------------
Outstanding-beginning of
year ................... 4,042 $ 3.37 4,942 $ 3.28 3,305 $ 1.85
Granted ................... 918 2.81 521 0.68 360 0.68
Exercised ................. (8) 1.95 - - (129) 0.66
Forfeited/Expired ......... (10) 1.79 (2,158) 4.84 (172) 1.61
---------- ---------- ---------
Outstanding-end of year ... 4,942 $ 3.28 3,305 $ 1.85 3,364 $ 0.90
========== ========== =========
Exercisable at end of year 2,259 $ 2.65 2,136 $ 1.91 2,331 $ 0.95
========== ========== =========
Weighted-average fair
value of options
granted during the year $ 1.19 $ 0.63 $ 0.38
- ------------------
(1) In September 2001, the Abraxas Petroleum Corporation 2000 Long Term
Incentive Plan was terminated, and options granted under the plan were
reissued under the Abraxas Petroleum Corporation 1994 Long Term
Incentive Plan at the same option price and term.
The following table represents the range of option prices and the weighted
average remaining life of outstanding options as of December 31, 2003:
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 2,761,160 6.0 $ 0.71 1,886,043 $ 0.69
$1.01 - 1.63 259,900 7.8 1.22 123,050 1.40
$2.06 - 2.21 311,958 2.1 2.07 305,979 2.06
$3.39 - 4.83 31,407 6.9 4.77 16,406 4.71
F-22
In January 2003, in connection with the financial restructuring discussed
in Note 2, 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 plans 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 2001, 2002 or 2003.
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 2001, 2002 or 2003.
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 have a four-year term
beginning July 1, 2000. The Company paid cash compensation of $191,000 during
2001 under the consulting agreement.
At December 31, 2003, the Company has approximately 3.3 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
---------------------------
2002 2003
------------- -------------
(In thousands)
Deferred tax liabilities:
U.S. full cost pool ..................................................... $ - $ 4,835
------------- -------------
Total deferred tax liabilities ............................................ - 4,835
Deferred tax assets:
U.S. full cost pool...................................................... 2,168 -
Capital loss carryforward................................................ - 12,895
Original issue discount on certain debt obligations...................... - 22,453
Canadian full cost pool.................................................. 9,787 2,971
Depletion ............................................................... 2,778 4,856
Net operating losses ("NOL")............................................ 58,811 35,218
Investment in foreign subsidiaries....................................... 32,038 -
Other ................................................................... 1,364 2,575
------------- -------------
Total deferred tax assets ................................................. 106,946 80,968
Valuation allowance for deferred tax assets ............................... (99,126) (76,133)
------------- -------------
Net deferred tax assets ................................................... 7,820 4,835
------------- -------------
Net deferred tax liabilities (assets) ..................................... $ (7,820) $ -
============= =============
Significant components of the provision (benefit) for income taxes are
as follows:
2001 2002 2003
-----------------------------------------
Current:
Federal.......................................................... $ 505 $ - $ -
Foreign ......................................................... - - -
----------------------------------------
$ 505 $ - $ -
=========================================
F-23
Deferred:
Federal ......................................................... $ - $ - $ -
Foreign ......................................................... 1,897 26,697 377
-----------------------------------------
$1,897 $ 26,697 $377
=========================================
At December 31, 2003 the Company had, subject to the limitation discussed
below, $100.6 million of net operating loss carryforwards for U.S. tax purposes.
These loss carryforwards will expire from 2003 through 2022 if not utilized. In
connection with the January 2003 transactions described in Note 2, certain of
the loss carryforward may be utilized.
At December 31, 2002, the Company was no longer permanently reinvested with
respect to its foreign subsidiaries, see Note 2. As a result, the Company
recorded net deferred tax assets of $32.0 million related to its investment in
foreign subsidiaries, offset by an equivalent valuation allowance due to
uncertainties as to the future utilization of these amounts.
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 $99.1 million and $71.3 million for deferred tax assets
at December 31, 2002 and 2003, respectively. , The reconciliation of income tax
computed at the U.S. federal statutory tax rates to income tax expense is:
December 31
---------------------------------------------------------------------
2001 2002 2003
-------------------------------------------- ------------------------
(In thousands)
Tax (expense) benefit at U.S.
statutory rates (35%) .............. $ 5,318 $ 51,878 $ (19,842)
(Increase) decrease in deferred tax
asset valuation allowance .......... (4,907) (59,456) 22,993
Write-down of non-tax basis assets.... (2,194) (7,009) -
Higher effective rate of foreign
operations.......................... (136) 7,349 (2,835)
Percentage depletion ................. 596 683 -
Investment in foreign subsidiaries .. - 35,604 -
Other ................................ (1,079) 648 (693)
-------------------------------------------- ------------------------
$ (2,402) $ 29,697 $ (377)
============================================ ========================
9. Related Party Transactions
Accounts receivable - Other includes approximately $51,211 and $35,558 as
of December 31, 2002 and 2003, respectively, representing amounts due from
officers relating to advances made to employees.
On July 29, 2003 the Company acquired all of the shares of the capital
stock of Wind River Resources Corporation which owned an airplane. The sole
shareholder of Wind River was the Company's President. The consideration for the
purchase was 106,977 shares of Abraxas common stock and $35,000 in cash.
Simultaneously with this transaction, the airplane was sold. The airplane had
previously been made available to Abraxas' employees for business use.
The Company paid Wind River a total of $314,000, $345,000 and $132,000 in
2001, 2002 and 2003, through July 29, respectively, for Wind River's operating
cost associated with the Company's use of the plane.
10. Commitments and Contingencies
Operating Leases
During the years ended December 31, 2001, 2002 and 2003 the Company
incurred rent expense related to leasing office facilities of approximately
$519,000, $236,000 and $464,000 respectively. Future minimum rental payments are
as follows at December 31, 2003.
2004............................................. $ 416,000
2005............................................. 412,000
F-24
2006............................................. 223,000
2007............................................. 161,000
Thereafter....................................... 161,000
------------------
$ 1,373,000
==================
Litigation and Contingencies
In 2001 the Company and a partnership were named in a lawsuit filed in U.S.
District Court in the District of Wyoming. The claim asserts breach of contract,
fraud and negligent misrepresentation by the Company 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 has filed an appeal. The Company
believes these charges are without merit. The Company has established a reserve
in the amount of $845,000, which represents the Company's interest in the
judgment. In 2002 the Company recorded $201,000 in other expense representing
its share of the ongoing legal cost related to this matter.
In 2003, Abraxas and Leam Drilling Systems each filed suit against the
other relating to certain drilling services that Leam contracted to provide
Abraxas. Abraxas believes that the services were provided in a grossly negligent
manner and that Leam committed fraud. Leam has asserted that Abraxas failed to
pay approximately $639,000 for services rendered. The cases are pending in Bexar
County and Ward County, Texas.
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, 2003, 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:
2001 2002 2003
--------------------------------------------------------
Numerator:
Net income (loss) before effect of accounting
change ......................................... $ (19,718,000) $ (118,527,000) $ 56,315,000
Cumulative effect of accounting change........... - - (395,000)
--------------------------------------------------------
$ (19,718,000) $ (118,527,000) 55,920,000
Denominator:
Denominator for basic earnings per share -
weighted-average shares ........................ 25,788,571 29,979,397 35,364,363
Effect of dilutive securities:
Stock options and warrants..................... - - 711,928
--------------------------------------------------------
Dilutive potential common shares Denominator for diluted earnings per share
- adjusted weighted-average shares and assumed
conversions..................................... 25,788,571 29,979,397 36,076,291
========================================================
Basic earnings (loss) per share:
Net income (loss) before cumulative effect of
accounting change................................e $ (0.76) $ (3.95) $ 1.59
Cumulative effect of accounting change.......... - - (0.01)
--------------------------------------------------------
F-25
Net income (loss) per common share................ $ (0.76) $ (3.95) $ 1.58
========================================================
Diluted earnings (loss) per share:
Net income (loss) before cumulative effect of
accounting change................................e $ (0.76) $ (3.95) $ 1.56
Cumulative effect of accounting change.......... - - (0.01)
--------------------------------------------------------
Net income (loss) per common share - diluted. $ (0.76) $ (3.95) $ 1.55
========================================================
For the year ended December 31, 2001and 2002, 4.3 million shares and 5.9
million shares respectively, 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, 2002 and 2003 are as follows:
1st 2nd 3rd 4th
Quarter Quarter Quarter Quarter
---------------- ---------------- --------------- ----------------
(In thousands, except per share data)
Year Ended December 31, 2002
Net revenue........................... $ 11,807 $ 14,235 $ 11,061 $ 17,217
Operating income (loss)............... (735) (115,879) 490 5,221
Net income (loss)..................... (8,699) (95,690) (8,438) (5,700)
Net income (loss) per common share -
basic and diluted................... $ (0.29) $ (3.19) $ (0.28) $ (0.19)
Year Ended December 31, 2003
Net revenue........................... $ 13,111 $ 8,430 $ 8,430 $ 9,048
Operating income (loss)............... 5,646 1,927 2,694 1,275
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)
During the second quarter of 2002, the Company incurred a ceiling
limitation write-down of approximately $116.0 million.
13. Benefit Plans
The Company has a defined contribution plan (401(k)) covering all eligible
employees of the Company. 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 $11,000 in 2002 and
$12,000 in 2003.
14. Guarantor Condensed Consolidation Financial Statements
The following table presents condensed consolidating balance sheets of
Abraxas, as a parent company, and its significant subsidiaries, Canadian Abraxas
and Old Grey Wolf, as of December 31, 2002 and 2003 and the related
consolidating statements of operations and cash flows for the years ended
December 31, 2001, 2002 and 2003. Canadian Abraxas was a guarantor of the First
Lien Notes ($63.5 million) and jointly and severally liable with Abraxas for the
Second Lien Notes ($190.2 million) and the Old Notes ($801,000). Old Grey Wolf
was a non-guarantor with respect to the First Lien Notes and the Old Notes.
The First Lien Notes and the Second Lien Notes were retired in connection
with the financial restructuring transactions which occurred in January 2003.
New Grey Wolf is a guarantor of the New Notes, there are no non-guarantor
subsidiaries, accordingly, condensed consolidating balance sheets of Abraxas, as
parent and its subsidiary New Grey Wolf are presented as of December 31, 2003
and the related consolidating statements of operations and cash flows for the
year ended December 31, 2003.
F-26
Condensed Consolidating Parent Company and Subsidiaries Balance Sheet
December 31, 2003
(In thousands)
Abraxas Abraxas
Petroleum Reclassifi-cations Petroleum
Corporation Subsidiary and Corporation and
Inc. Parent (New Grey eliminations Subsidiaries
Company(1) Wolf)
----------------------------------------------------------------
Assets:
Cash .................................... $ - $ 493 $ - $ 493
Accounts receivable, less allowance for
doubtful accounts...................... 14,101 903 (6,681) 8,323
Equipment inventory ..................... 782 - - 782
Other current assets .................... 418 154 - 572
-----------------------------------------------------------------
Total current assets.............. 15,301 1,550 (6,681) 10,170
Property and equipment - net................ 76,021 35,542 - 111,563
Deferred financing fees, net .............. 4,410 - - 4,410
Deferred income taxes and other assets ..... 27,551 - (27,257) 294
-----------------------------------------------------------------
Total assets ............................ $ 123,283 $ 37,092 $ (33,938) $ 126,437
=================================================================
Liabilities and Stockholders' deficit:
Current liabilities:
Accounts payable ............................. $ 7,075 $ 8,652 $ (6,681) $ 9,046
Accrued interest ............................. 2,340 - - 2,340
Other accrued expenses ....................... 1,228 - - 1,228
-----------------------------------------------------------------
Total current liabilities................... 10,643 8,652 (6,681) 12,614
Long-term debt .................................. 184,649 - - 184,649
Future site restoration ........................ 776 601 - 1,377
-----------------------------------------------------------------
196,068 9,253 (6,681) 198,640
Stockholders' equity (deficit)................... (72,785) 27,839 (27,257) (72,203)
-----------------------------------------------------------------
Total liabilities and stockholders' equity
(deficit)........................................ $ 123,283 $ 37,092 $ (33,938) $ 126,437
=================================================================
(1) Includes amounts for insignificant U.S. subsidiaries, Sandia Oil
and Gas, Sandia Operating, Western Energy Associates, East Side
Coal and Wamsutter, which are guarantors of the New Notes.
Condensed Consolidating Parent Company, Restricted Subsidiaries and Non-Guarantor Balance Sheet
December 31, 2002
(In thousands)
Abraxas Non-Guarantor Abraxas
Petroleum Restricted Subsidiary Reclassifi- Petroleum
Corporation Subsidiary (Old Grey cations and Corporation and
Inc. Parent (Canadian Wolf) eliminations Subsidiaries
Company(2) Abraxas)
-----------------------------------------------------------------------------
Assets:
Current assets:
Cash .................................... $ 557 $ 2,188 $ 2,137 $ - $ 4,882
Accounts receivable, less allowance for
doubtful accounts...................... 4,482 4,782 11,938 (11,157) 10,045
Equipment inventory ..................... 860 142 12 - 1,014
Other current assets .................... 316 682 242 - 1,240
-----------------------------------------------------------------------------
Total current assets.............. 6,215 7,794 14,329 (11,157) 17,181
F-27
Property and equipment - net................ 74,435 38,858 37,101 - 150,394
Deferred financing fees, net .............. 2,970 688 2,013 - 5,671
Deferred income taxes and other assets ..... 108,558 7,820 (108,199) 8,179
-----------------------------------------------------------------------------
Total assets ............................ $ 192,178 $47,340 $61,263 $ (119,199) $181,425
=============================================================================
Liabilities and Stockholders' deficit:
Current liabilities:
Accounts payable ............................. $ 15,928 $ 766 $ 6,398 $ (10,973) $ 12,119
Accrued interest ............................. 5,000 1,009 - - 6,009
Other accrued expenses ....................... 1,162 - - - 1,162
Current maturities of long-term debt ......... 63,500 - - - 63,500
-----------------------------------------------------------------------------
Total current liabilities................... 85,590 1,775 6,398 (10,973) 82,790
Long-term debt .................................. 138,350 52,629 45,964 - 236,943
Future site restoration ........................ - 3,171 775 - 3,946
-----------------------------------------------------------------------------
223,940 57,575 53,137 (10,973) 323,679
Stockholders' equity (deficit)................... (31,762) (10,235) 8,126 (108,383) (142,254)
-----------------------------------------------------------------------------
Total liabilities and stockholders' equity
(deficit)........................................ $ 192,178 $ 47,340 $ 61,263 $ (119,356) $ 181,425
=============================================================================
(2) Includes amounts for insignificant U.S. subsidiaries, Sandia
Oil and Gas, Sandia Operating, Western Energy Associates, East
Side Coal and Wamsutter, which are guarantors of the First and
Second Lien Notes. Sandia is also a guarantor of the Old
Notes. Additionally, these subsidiaries are designated as
Restricted Subsidiaries along with Canadian Abraxas.
Condensed Consolidating Parent Company and Subsidiary Statement of Operations
For the year ended December 31, 2003
(In thousands)
Abraxas Abraxas
Petroleum Reclassifi- Petroleum
Corporation Subsidiary cation Corporation
Inc. Parent (New Grey and and
Company(1) Wolf) eliminations Subsidiaries
------------------------------ ------------------------------
Revenues:
Oil and gas production revenues ............... $ 29,710 $ 8,395 $ - $ 38,105
Gas processing revenues........................ - 133 - 133
Rig revenues .................................. 663 - - 663
Other ........................................ 7 111 - 118
------------------------------ ------------------------------
30,380 8,639 - 39,019
Operating costs and expenses:
Lease operating and production taxes .......... 8,342 1,257 - 9,599
Depreciation, depletion, and amortization ..... 7,608 3,195 - 10,803
Rig operations ................................ 609 - - 609
General and administrative .................... 3,995 1,365 - 5,360
Stock-based compensation....................... 1,106 - - 1,106
------------------------------ ------------------------------
21,660 5,817 - 27,477
------------------------------ ------------------------------
Operating income (loss)........................... 8,720 2,822 - 11,542
Other (income) expense:
Interest income ............................... (30) - - (30)
Amortization of deferred financing fees........ 1,630 48 - 1,678
Interest expense............................... 16,323 632 - 16,955
Financing costs................................ 4,406 - - 4,406
Gain on sale of foreign subsidiaries........... (68,933) - - (68,933)
Other ......................................... 100 674 - 774
------------------------------ -----------------------------
(46,504) 1,354 - (45,150)
------------------------------ ------------------------------
Income (loss) before income tax and cumulative -
effect of accounting change.................... 55,224 1,468 56,692
Income tax expense (benefit)...................... - 377 - 377
Cumulative effect of accounting change............ 395 - - 395
F-28
------------------------------ ------------------------------
Net income (loss)................................ $ 54,829 $ 1,091 $ - $ 55,920
============================== ==============================
Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Statement of Operations
For the year ended December 31, 2002
(In thousands)
Abraxas
Petroleum Restricted Non-Guarantor Abraxas
Corporation Subsidiary Subsidiary Reclassifi- Petroleum
Inc. Parent (Canadian (Old Grey cations and Corporation and
Company(2) Abraxas) Wolf) eliminations Subsidiaries
-----------------------------------------------------------------------------
Revenues:
Oil and gas production revenues ............... $ 20,835 $ 14,726 $ 15,301 $ - $ 50,862
Gas processing revenues........................ - 1,955 465 2,420
Rig revenues .................................. 635 - - - 635
Other ........................................ 71 152 180 - 403
---------------------------------------------------------------------------
21,541 16,833 15,946 - 54,320
Operating costs and expenses:
Lease operating and production taxes .......... 7,639 3,751 3,850 - 15,240
Depreciation, depletion, and amortization ..... 9,194 10,633 6,712 - 26,539
Proved property impairment .................... 28,178 60,501 27,314 - 115,993
Rig operations ................................ 567 - - - 567
General and administrative ................... 4,045 1,312 1,527 - 6,884
---------------------------------------------------------------------------
49,623 76,197 39,403 - 165,223
---------------------------------------------------------------------------
Operating income (loss)........................... (28,082) (59,364) (23,457) - (110,903)
Other (income) expense:
Interest income ............................... (92) - - - (92)
Amortization of deferred financing fees........ 1,325 366 404 - 2,095
Interest expense............................... 24,689 6,665 2,796 - 34,150
Other ......................................... 1,168 - - - 1,168
---------------------------------------------------------------------------
27,090 7,031 3,200 - 37,321
---------------------------------------------------------------------------
Income (loss) before income tax .................. (55,172) (66,395) (26,657) - (148,224)
Income tax expense (benefit)...................... - (18,522) (11,175) - (29,697)
------------------------------ --------------------------------------------
Net income (loss)................................ $ (55,172) $ (47,873 $ (15,482) $ - $ (118,527)
===========================================================================
Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Statement of Operations
For the year ended December 31, 2001
(In thousands)
Abraxas
Petroleum Restricted Non-Guarantor Abraxas
Corporation Subsidiary Subsidiary Reclassifi- Petroleum
Inc. Parent (Canadian (Old Grey cations and Corporation and
Company(2) Abraxas) Wolf) eliminations Subsidiaries
-----------------------------------------------------------------------------
Revenues:
Oil and gas production revenues ............... $ 34,934 $ 24,308 $ 13,959 $ - $ 73,201
Gas processing revenues ....................... - 2,008 430 - 2,438
Rig revenues .................................. 756 - - - 756
Other ........................................ 85 471 292 - 848
---------------------------------------------------------------------------
35,775 26,787 14,681 - 77,243
Operating costs and expenses:
Lease operating and production taxes .......... 9,302 6,836 2,478 - 18,616
Depreciation, depletion, and amortization ..... 12,336 14,707 5,441 - 32,484
Proved property impairment..................... - 2,638 - - 2,638
F-29
Rig operations ................................ 702 - - - 702
General and administrative .................... 3,742 1,720 983 - 6,445
General and administrative (Stock-based
Compensation)................................ (2,767) - - - (2,767)
---------------------------------------------------------------------------
23,315 25,901 8,902 - 58,118
---------------------------------------------------------------------------
Operating income (loss)........................... 12,460 886 5,779 - 19,125
Other (income) expense:
Interest income ............................... (1,242) - - 1,164 (78)
Amortization of deferred financing fees........ 1,907 361 - - 2,268
Interest expense............................... 25,086 7,117 484 (1,164) 31,523
Other ......................................... 1,052 - - - 1,052
---------------------------------------------------------------------------
26,803 7,478 484 - 34,765
------------------------------ --------------------------------------------
Income (loss) before income tax .................. (14,343) (6,592) 5,295 - (15,640)
Income tax expense (benefit)...................... 505 (80) 1,977 - 2,402
Minority interest in income of consolidated
foreign subsidiary............................. - - 1,676 - 1,676
------------------------------ --------------------------------------------
Net income (loss)................................ $ (14,848) $ (6,512) $ 1,642 $ - $ (19,718)
============================== ============================================
Condensed Consolidating Parent and Subsidiary Statement of Cash Flow
For the year ended December 31, 2003
(In thousands)
Abraxas
Petroleum Reclassifi Abraxas
Corporation Subsidiary -cations Petroleum
Inc. Parent (New Grey and Corporation and
Company(1) Wolf) eliminations Subsidiaries
----------------------------------------------------------------
Operating Activities
Net income (loss) ........................... $ 54,829 $ 1,091 $ - $ 55,920
Adjustments to reconcile net income (loss)
to net cash provided by operating
activities:
Gain on sale of foreign subsidiaries.... (68,933) - - (68,933)
Depreciation, depletion, and
amortization ......................... 7,608 3,195 - 10,803
Non-cash interest and financing costs... 16,422 - - 16,422
Deferred income tax (benefit) expense... 377 - 377
Amortization of deferred financing fees. 1,630 48 - 1,678
Stock-based compensation................ 1,106 - - 1,106
Changes in operating assets and
liabilities:
Accounts receivable ................ (7,850) 394 6,010 (1,446)
Equipment inventory ................ 78 - - 78
Other ............................. 295 - - 295
Accounts payables and accrued
expenses ......................... 6,294 7,266 (6,010) 7,550
-----------------------------------------------------------------
Net cash provided by (used in)operations..... 11,479 12,371 - 23,850
Investing Activities
Capital expenditures, including purchases
and development of properties ............ (9,194) (9,155) - (18,349)
Proceeds from sale of foreign subsidiaries... 85,810 - - 85,810
-----------------------------------------------------------------
Net cash provided (used) by investing
activities................................ 76,616 (9,155) - 67,461
F-30
Financing Activities
Proceeds from issuance of common stock....... 177 - - 177
Proceeds from long-term borrowings........... 43,051 291 - 43,342
Payments on long-term borrowings ............ (131,283) (7,261) - (138,544)
Deferred financing fees...................... (597) - - (597)
-----------------------------------------------------------------
Net cash provided (used) by financing
activities................................ (88,652) (6,970) - (95,622)
Effect of exchange rate changes on cash ..... - (78) - (78)
-----------------------------------------------------------------
Increase (decrease) in cash ................. (557) (3,832) - (4,389)
Cash at beginning of year ................... 557 4,325 - 4,882
----------------------------------------------------------------
Cash at end of year.......................... $ - $ 493 $ - $ 493
=================================================================
Condensed Consolidating Parent, Restricted Subsidiary and Non-Guarantor Statement of Cash Flow
For the year ended December 31, 2002
(In thousands)
Abraxas
Petroleum Restricted Non-Guarantor Abraxas
Corporation Subsidiary Subsidiary Reclassifi- Petroleum
Inc. Parent (Canadian (Old Grey cations and Corporation and
Company(2) Abraxas) Wolf) eliminations Subsidiaries
-----------------------------------------------------------------------------
Operating Activities
Net income (loss) ........................... $ (55,172) $ (47,873) $ (15,482) $ - $ (118,527)
Adjustments to reconcile net income (loss)
to net cash provided by operating
activities:
Depreciation, depletion, and
amortization ......................... 9,194 10,633 6,712 - 26,539
Proved property impairment ............. 28,178 60,501 27,314 - 115,993
Deferred income tax (benefit) expense... - (18,522) (11,175) - (29,697)
Amortization of deferred financing fees. 1,325 366 404 - 2,095
Changes in operating assets and
liabilities:
Accounts receivable ................ 18,088 (3,187) 1,114 (18,262) (2,247)
Equipment inventory ................ 201 - - - 201
Other ............................. 381 (177) (78) - 126
Accounts payables and accrued
expenses ......................... (47) 479 (3,251) - (2,819)
------------------------------------------------------------------------------
Net cash provided by (used in)operations..... 2,148 2,220 5,555 (18,262) (8,336)
Investing Activities
Capital expenditures, including purchases
and development of properties ............ (5,070) (4,926) (28,916) - (38,912)
Proceeds from sale of oil and gas
properties................................ 9,725 21,789 2,362 - 33,876
------------------------------------------------------------------------------
Net cash provided (used) by investing
activities................................ 4,655 16,863 (26,554) - (5,036)
Financing Activities
Proceeds from long-term borrowings........... - - 20,551 - 20,551
Payments on long-term borrowings ............ (8,176) (18,262) - 18,262 (8,176)
Deferred financing fees...................... (1,663) 146 (22) - (1,539)
------------------------------------------------------------------------------
Net cash provided (used) by financing
activities................................ (9,839) (18,116) 20,529 18,262 10,836
------------------------------------------------------------------------------
Effect of exchange rate changes on cash ..... - (24) (163) - (187)
------------------------------------------------------------------------------
Increase (decrease) in cash ................. (3,036) 943 (630) - (2,723)
Cash at beginning of year ................... 3,593 1,245 2,767 - 7,605
------------------------------------------------------------------------------
Cash at end of year.......................... $ 557 $ 2,188 $ 2,137 $ - $ 4,882
==============================================================================
F-31
Condensed Consolidating Parent, Restricted Subsidiary and Non-Guarantor Statement of Cash Flow
For the year ended December 31, 2001
(In thousands)
Abraxas
Petroleum Restricted Non-Guarantor Abraxas
Corporation Subsidiary Subsidiary Reclassifi- Petroleum
Inc. Parent (Canadian (Old Grey cations and Corporation and
Company(2) Abraxas) Wolf) eliminations Subsidiaries
-----------------------------------------------------------------------------
Operating Activities
Net income (loss) ........................... $ (14,848) $ (6,512) $ 1,642 $ - $ (19,718)
Adjustments to reconcile net income (loss)
to net cash provided by operating
activities:
Minority interest in income of foreign
subsidiary............................ - - 1,676 - 1,676
Loss on sale of equity investment....... 845 - - - 845
Depreciation, depletion, and
amortization ......................... 12,336 14,707 5,441 - 32,484
Proved property impairment.............. - 2,638 - 2,638
Deferred income tax (benefit) expense... - (80) 1,977 - 1,897
Amortization of deferred financing fees. 1,907 361 - - 2,268
Stock-based compensation ............... (2,767) - - - (2,767)
Changes in operating assets and
liabilities:
Accounts receivable ................ 28,804 (9,721) (6,390) - 12,693
Equipment inventory ................ (76) - - - (76)
Other ............................. (281) - 175 - (106)
Accounts payables and accrued
expenses ......................... (12,915) (2,254) (402) - (15,571)
------------------------------------------------------------------------------
Net cash provided (used) by operating
activities ............................... 13,005 (861) 4,119 - 16,263
Investing Activities
Capital expenditures, including purchases
and development of properties ............ (19,126) (15,313) (22,617) - (57,056)
Proceeds from sale of oil and gas
properties................................ 9,677 15,882 3,379 - 28,938
Acquisition of minority interest ............ (2,679) - - - (2,679)
------------------------------------------------------------------------------
Net cash provided (used) by investing
activities................................ (12,128) 569 (19,238) - (30,797)
------------------------------------------------------------------------------
Financing Activities
Proceeds form issuance of common stock....... 16 - - - 16
Proceeds from long-term borrowings .......... 11,700 - 18,295 - 29,995
Payments on long-term borrowings ............ (9,326) - - - (9,326)
------------------------------------------------------------------------------
Net cash provided (used) by financing
activities 2,390 - 18,295 - 20,685
------------------------------------------------------------------------------
3,267 (292) 3,176 - 6,151
Effect of exchange rate changes on cash ..... - (141) (409) - (550)
------------------------------------------------------------------------------
Increase (decrease) in cash ................. 3,267 (433) 2,767 - 5,601
Cash at beginning of year ................... 326 1,678 - - 2,004
------------------------------------------------------------------------------
Cash at end of year.......................... $ 3,593 $ 1,245 $ 2,767 $ - $ 7,605
==============================================================================
15. Business Segments
The Company conducts its operations through two geographic segments, the
United States and Canada, and is engaged in the acquisition, development, and
production of crude oil and natural gas in each country. The Company's
F-32
significant operations are located in the Texas Gulf Coast, the Permian Basin of
western Texas, and Canada. Identifiable assets are those assets used in the
operations of the segment. Corporate assets consist primarily of deferred
financing fees and other property and equipment. The Company's revenues are
derived primarily from the sale of crude oil, condensate, natural gas liquids,
and natural gas to marketers and refiners and from processing fees from the
custom processing of natural gas. As a general policy, collateral is not
required for receivables; however, the credit of the Company's customers is
regularly assessed. The Company is not aware of any significant credit risk
relating to its customers and has not experienced significant credit losses
associated with such receivables.
In 2003, three customers accounted for approximately 67% of consolidated
oil and natural gas production revenue. Three customers accounted for
approximately 80% of United States revenue and three customer accounted for
approximately 91% of revenue in Canada. In 2002, four customers accounted for
approximately 79% of consolidated oil and natural gas production revenue. Three
customers accounted for approximately 77% of United States revenue and one
customer accounted for approximately 80% of revenue in Canada. In 2001, three
customers accounted for approximately 41% of oil and natural gas production
revenues. Three customers accounted for approximately 76% of United States
revenue and five customers accounted for approximately 76% of revenue in Canada.
Business segment information about the Company's 2001 operations in different
geographic areas is as follows:
U.S. Canada Total
------------------ ------------------ -------------------
(In thousands)
Revenues ................................... $ 35,775 $ 41,468 $ 77,243
================== ================== ===================
Operating profit............................ $ 13,795 $ 6,665 $ 20,460
================== ==================
General corporate ............................................................... (1,335)
Net interest expense and amortization of
deferred financing fees ...................................................... (33,713)
Other expense.................................................................... (1,052)
-------------------
Loss before income taxes......................................................... $ (15,640)
===================
Identifiable assets at December 31, 2001 ... $ 124,993 $ 174,063 $ 299,056
================== ==================
Corporate assets ........................... 4,560
-------------------
Total assets ............................ $ 303,616
===================
Business segment information about the Company's 2002 operations in different
geographic areas is as follows:
U.S. Canada Total
------------------ ------------------ -------------------
(In thousands)
Revenues ................................... $ 21,541 $ 32,779 $ 54,320
================== ================== ===================
Operating loss.............................. $ (23,677) $ (82,821) $ (106,498)
================== ==================
General corporate ............................................................... (4,405)
Net interest expense and amortization of
deferred financing fees ...................................................... (36,153)
Other expense.................................................................... (1,168)
-------------------
Loss before income taxes......................................................... $ (148,224)
===================
Identifiable assets at December 31, 2002.... $ 81,025 $ 94,059 $ 175,084
================== ==================
Corporate assets ........................... 6,341
-------------------
Total assets ............................ $ 181,425
===================
Business segment information about the Company's 2003 operations in different
geographic areas is as follows:
U.S. Canada Total
------------------ ------------------ -------------------
(In thousands)
Revenues ................................... $ 30,380 $ 8,639 $ 39,019
================== ================== ===================
Operating income............................ $ 14,001 $ 2,822 $ 16,823
================== ==================
F-33
General corporate ............................................................... (5,281)
Net interest expense, financing cost and
amortization of deferred financing fees ...................................... (23,009)
Gain on sale of foreign subsidiaries............................................. 68,933
Other income (expense) - net..................................................... (774)
Cumulative effect of accounting change........................................... (395)
-------------------
Income before income taxes....................................................... $ 56,297
===================
Identifiable assets at December 31, 2003.... $ 84,228 $ 37,092 $ 121,320
================== ==================
Corporate assets ........................... 5,117
-------------------
Total assets ............................ $ 126,437
===================
16. 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. Gains and losses on hedging instruments related
to accumulated Other Comprehensive Income (Loss) and adjustments to carrying
amounts on hedged production are included in natural gas or crude oil production
revenue in the period that the related production is delivered. The Company has
not elected hedge accounting for the floors that are in place as of December 31,
2003, accordingly, adjustments to the carrying value of the instruments are
recognized in oil and gas income in the current period.
Under the terms of the Company's senior credit agreement, 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. The credit agreement was amended in February 2004, see Note 2,
increasing the minimum hedged position to 40% of our estimated production. As of
December 31, 2003 the Company's hedging positions were as follows:
Time Period Notional Quantities Price
- --------------------------------- ---------------------------- ----------------
March 1, 2003 - February 29, 5,000 MMBtu of natural gas Floor of $4.50
2004 production per day
March 1, 2004 - April 30, 2004 2,000 MMBtu of natural gas Floor of $4.00
production per day
March 1, 2004 - April 30, 2004 500 Bbl of crude oil Floor of $22.00
production per day
May 2004 2,000 MMbtu of natural gas Floor of $4.00
production per day
May 2004 500 Bbls of crude oil Floor of $22.00
production per day
June 2004 800 Bbls of crude oil Floor of $22.00
production per day
July 2004 2,000 MMbtu of natural gas Floor of $4.00
production per day
July 2004 500 Bbl of crude oil Floor of $22.00
production per day
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.
The fair value of the hedging instrument was determined based on the base
price of the hedged item and NYMEX forward price quotes. As of December 31,
2003, a commodity price increase of 10% would have resulted in an unfavorable
change in the fair market value of approximately $2,000 and a commodity price
decrease of 10% would have resulted in a favorable change in fair market value
of approximately $2,000.
F-34
17. 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. As of December 31, 2001, the Company's net capitalized costs of oil
and gas properties exceeded the present value of its estimated proved reserves
by $71.3 million ($38.9 million on the U.S. properties and $32.4 million on the
Canadian properties). These amounts were calculated considering 2001 year-end
prices of $19.84 per barrel for oil and $2.57 per Mcf for gas as adjusted to
reflect the expected realized prices for each of the full cost pools. The
Company did not adjust its capitalized costs for its U.S. properties because
subsequent to December 31, 2001, oil and gas prices increased such that
capitalized costs for its U.S. properties did not exceed the present value of
the estimated proved oil and gas reserves for its U.S. properties as determined
using increased realized prices on March 22, 2002 of $24.16 per Bbl for oil and
$2.89 per Mcf for gas. During the second quarter of 2002, the Company had a
ceiling limitation write-down of approximately $116.0 million. At December 31,
2003, the net capitalized cost of crude oil and natural gas properties did not
exceed the present value of our estimated reserves, as such, no write-down was
recorded.
F-35
18. Supplemental Oil and Gas Disclosures (Unaudited)
<, The accompanying table presents information concerning the Company's
crude oil and natural gas producing activities 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 are
as follows:
Years Ended December 31
-----------------------------------------------------------------------------------------
2002 2003
-----------------------------------------------------------------------------------------
Total U.S. Canada Total U.S. Canada
-----------------------------------------------------------------------------------------
(In thousands)
Proved crude oil and natural
gas properties ............ $ 521,995 $ 279,401 $ 242,594 $ 325,222 $ 288,559 $ 36,663
Unproved properties ......... 7,052 - 7,052 4,304 - 4,304
------------- ------------- --------------- -------------- -------------- -------------
Total........................... 529,047 279,401 249,646 329,526 288,559 40,967
Accumulated depreciation,
depletion, and
amortization, and
impairment ................ (420,344) (205,181) (215,163) (219,404) (212,609) (6,795)
-------------- -------------- ------------- ------------- -------------- ------------
Net capitalized costs ... $ 108,703 $ 74,220 $ 34,483 $ 110,122 $ 75,950 $ 34,172
============= ============= =============== ============== ============== =============
Cost incurred in oil and gas property acquisitions, exploration and
development activities are as follows:
Years Ended December 31
---------------------------------------------------------------------------------------------------
2001 2002 2003
-------------------------------- -------------------------------- ----------------------------
Total U.S. Canada Total U.S. Canada (1) Total U.S. Canada
--------- -------- -------- -------- --------- --------- --------- -------- ------
(In thousands)
Property acquisition costs:
Proved ................... $ - $ - $ - $ - $ - $ - $ - $ - $ -
Unproved ................. - - - - - - - - -
--------- -------- -------- -------- --------- --------- --------- -------- ------
$ - $ - $ - $ - $ - $ - $ - $ - $ -
========= ======== ======== ======== ========= ========= ========= ======== ======
Property development and
exploration costs ........ $ 56,694 $ 18,867 $ 37,827 $ 38,560 $ 4,944 $ 33,616 $ 18,313 $ 9,158 $ 9,155
========= ======== ======== ======== ========= ========= ========= ======== ======
(1) Canadian costs in 2002 were primarily for exploratory purposes.
F-36
The results of operations for oil and gas producing activities for the
three years ending December 31, 2001, 2002 and 2003, respectively are as
follows:
Years Ended December 31
---------------------------------------------------------------------------------------------------
2001 2002 2003
-------------------------------- -------------------------------- ----------------------------
Total U.S. Canada Total U.S. Canada (1) Total U.S. Canada
--------- -------- -------- -------- --------- --------- --------- -------- ------
(In thousands)
Revenues ................... $ 73,201 $ 34,934 $ 38,267 $ 50,862 $ 20,835 $ 30,027 $ 38,105 $ 29,710 $ 8,395
Production costs ........... (18,616) (9,302) (9,314) (15,240) (7,639) (7,601) (9,599) (8,342) (1,257)
Depreciation, depletion,
and amortization ......... (32,124) (11,976) (20,148) (26,224) (8,879) (17,345) (9,410) (7,428) (1,982)
Proved property impairment . (2,638) - (2,638) (115,993) (28,178) (87,815) - - -
General and administrative . (1,565) (1,073) (492) (1,836) (1,011) (825) (1,339) (998) (341)
Income taxes (expense)
benefit................... (2,419) - (2,419) - - - (377) - (377)
--------- -------- --------- -------- --------- --------- --------- -------- ------
Results of operations from oil
and gas producing activities
(excluding corporate overhead
and interest costs) ......... $ 15,839 $ 12,583 $ 3,256 $ (108,431) $(24,872) $ (83,559) $ 17,380 $ 12,942 $ 4,438
========== ======== ========= ========== ========= =========- ========= ========= =======
Depletion rate per barrel
of oil equivalent, before
impact of impairment ..... $ 8.8 1 $ 6.96 $ 10.45 $ 8.52 $ 7.55 $ 8.94 $ 7.13 $ 7.24 $ 6.74
========== ======== ========= ========== ========= =========- ========= ========= =======
F-37
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, 2001, 2002, and 2003. 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.
Total United States Canada
-----------------------------------------------------------------------------
Liquid Natural Liquid Natural Liquid Natural
Hydrocarbons Gas Hydrocarbons Gas Hydrocarbons Gas
----------------------------------------------------------- ----------------
(Barrels) (Mcf) (Barrels) (Mcf) (Barrels) (Mcf)
(In Thousands)
Proved developed and undeveloped reserves:
Balance at January 1, 2001................... 8,844 191,327 6,081 114,908 2,763 76,419
Revisions of previous estimates ........... (628) 2,944 (688) 3,318 60 (374)
Extensions and discoveries ................ 1,064 26,329 354 4,886 710 21,443
Production ................................ (732) (17,495) (416) (7,823) (316) (9,672)
Sale of minerals in place ................. (1,746) (14,348) (924) (6,821) (822) (7,527)
-----------------------------------------------------------------------------
Balance at December 31, 2001................. 6,802 188,757 4,407 108,468 2,395 80,289
Revisions of previous estimates ........... (798) (29,701) (63) (15,248) (735) (14,453)
Extensions and discoveries ................ 522 19,166 - - 522 19,166
Production ................................ (534) (15,453) (264) (5,472) (270) (9,981)
Sale of minerals in place ................. (1,387) (23,937) (843) (9,553) (544) (14,384)
------------------------------------------------------------------------------
Balance at December 31, 2002 ................ 4,605 138,832 3,237 78,195 1,368 60,637
Revisions of previous estimates ........... 310 5,564 268 6,760 42 (1,196)
Extensions and discoveries ................ 654 4,474 44 28 610 4,446
Production ................................ (288) (6,190) (229) (4,781) (59) (1,409)
Sale of minerals in place ................. (1,146) (46,396) - - (1,146) (46,396)
------------------------------------------------------------------------------
Balance at December 31, 2003................. 4,135 96,284 3,320 80,202 815 16,082
==============================================================================
F-38
Estimated Quantities of Proved Oil and Gas Reserves (continued)
Total United States Canada
-----------------------------------------------------------------------------
Liquid Natural Liquid Natural Liquid Natural
Hydrocarbons Gas Hydrocarbons Gas Hydrocarbons Gas
----------------------------------------------------------- ----------------
(Barrels) (Mcf) (Barrels) (Mcf) (Barrels) (Mcf)
Proved developed reserves:
December 31, 2001 ........................... 5,047 111,243 2,892 40,514 2,155 70,729
==============================================================================
December 31, 2002............................ 3,004 90,374 1,754 34,776 1,250 55,598
==============================================================================
December 31, 2003............................ 2,314 52,398 1,887 39,371 427 13,027
==============================================================================
F-39
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, 2003 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
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.
F-40
Set forth below is the Standardized Measure relating to proved oil and gas
reserves for the three years ending December 31, 2001, 2002 and 2003
Years Ended December 31
----------------------------------------------------------------------------------------------------
2001 2002 2003
-----------------------------------------------------------------------------------------------------
Total U.S. Canada Total U.S. Canada Total U.S. Canada
-----------------------------------------------------------------------------------------------------
(In thousands)
Future cash inflows ..... $ 607,375 $ 313,640 $ 293,735 $ 686,055 $ 389,061 $296,994 $ 621,290 $ 512,797 $108,493
Future production and
development costs ..... (220,613) (138,296) (82,317) (225,068) (158,507) (66,561) (204,537) (179,036) (25,498)
Future income tax expense - - - - - - - - -
------------------------------------------------------------------------------------------------------
Future net cash flows ... 386,762 175,344 211,418 460,987 230,554 230,433 416,756 333,761 82,995
Discount ................ (177,096) (98,157) (78,939) (206,134) (120,238) (85,896) (199,933) (172,177) (27,756)
------------------------------------------------------------------------------------------------------
Standardized Measure of
discounted future net
cash relating to proved
reserves .............. $ 209,666 $ 77,187 $ 132,479 $ 254,853 $ 110,316 $144,537 $ 216,823 $ 161,584 $ 55,239
======================================================================================================
F-41
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:
Year Ended December 31
------------------------------------
2001 2002 2003
--------- --------- ---------
(In thousands)
Standardized Measure, beginning
of year ............................................ $ 775,534 $ 209,666 $ 254,853
Sales and transfers of oil and gas
produced, net of production costs .................. (54,585) (35,622) (28,506)
Net changes in prices and development
and production costs from prior year ............... (613,325) 111,087 62,074
Extensions, discoveries, and improved
recovery, less related costs ....................... 39,982 46,803 21,819
Sales of minerals in place ........................... (96,096) (33,808) (120,150)
Revision of previous quantity estimates .............. (2,474) (36,007) 9,061
Change in future income tax expense .................. 230,987 -- --
Other ................................................ (147,910) (28,232) (7,813)
Accretion of discount ................................ 77,553 20,966 25,485
--------- --------- ---------
Standardized Measure, end of year .................. $ 209,666 $ 254,853 $ 216,823
========= ========= =========
19. Restatement
In January 2003, the Company sold its wholly owned Canadian subsidiaries,
Old Grey Wolf and Canadian Abraxas as part of a series of transactions related
to a financial restructuring - see Note 2 for additional information regarding
an exchange offer, redemption of certain notes and a new credit agreement.
Subsequent to the 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, the accompanying consolidated balance sheets as of
December 31, 2002, and the related consolidated statements of operations, and
cash flows for each of the two years in the period ended December 31, 2002 have
been restated to present the assets and liabilities, results of operations, and
cash flows as components of continuing operations.
A summary of the significant effects of the restatement is as follows (In
thousands):
For the years ended December 31,
--------------------------------------------------------------------
2001 2002
---------------------------------- ---------------------------------
As Previously As Restated As Previously As Restated
Reported Reported
------------------- -------------- ---------------- ----------------
Revenues:
Oil and gas production revenue $ 34,934 $ 73,201 $ 21,601 $ 50,862
Gas processing revenue - 2,438 - 2,420
Rig revenue 756 756 635 635
Other 85 848 71 403
------------- ------------ ------------- -------------
35,775 77,243 22,307 54,320
Operating costs and expenses:
Lease operating and
production taxes 9,302 18,616 7,910 15,240
Depreciation, depletion and
amortization 12,336 32,484 9,654 26,539
F-42
Proved property impairment - 2,638 32,850 115,993
Rig operations 702 702 567 567
General and administrative 4,937 6,445 5,082 6,884
General and administrative
(Stock-based compensation) (2,767) (2,767) - -
------------- ------------ ------------- -------------
24,510 58,118 56,063 165,223
------------- ------------ ------------- -------------
Operating income (loss) 11,265 19,125 (33,756) (110,903)
Other (income) expense:
Interest income (78) (78) (92) (92)
Amortization of deferred
financing fees 1,907 2,268 1,325 2,095
Interest expense 23,922 31,523 24,689 34,150
Financing costs - - 967 967
(Gain) loss on sale of equity
investment 845 845 - -
Gain on debt extinguishment (1) - - - -
Other 207 207 201 201
------------- ------------ ------------- -------------
26,803 34,765 27,090 37,321
------------- ------------ ------------- -------------
Income (loss) before income tax (15,538) (15,640) (60,846) (148,224)
Income tax expense (benefit):
Current 505 505 - -
Deferred - 1,897 - (29,697)
Minority interest in income of
consolidated foreign
subsidiary - 1,676 - -
Loss from discontinued operations (3,675) - (57,681) -
------------- ------------ ------------- -------------
Net income (loss) $ (19,718) $ (19,718) $ (118,527) $ (118,527)
============= ============ ============= =============
F-43
December 31, 2002
----------------------------------
As Previously As Restated
Reported
----------------- ------------
Current Assets:
Cash $ 557 $ 4,882
Accounts receivable:
Joint owners 516 2,215
Oil and gas production sales 5,292 7,466
Other 221 364
----------------- ------------
6,029 10,045
Equipment inventory 1,021 1,014
Other current assets 316 1,240
----------------- ------------
7,923 17,181
Assets held for sale 74,247 -
----------------- ------------
Total current assets 82,170 17,181
Property and equipment:
Oil and gas properties:
Proved 298,972 521,995
Unproved 7,052 7,052
Other property and equipment 2,713 44,189
----------------- ------------
Total 308,737 573,236
Less accumulated depreciation, depletion
and amortization 212,811 422,842
----------------- ------------
Total property and equipment - net 95,926 150,394
Deferred financing fees 2,970 5,671
Deferred income taxes - 7,820
Other 359 359
----------------- ------------
Total assets $ 181,425 $ 181,425
================= ============
Current Liabilities:
Accounts payable $ 4,171 $ 9,687
Joint interest oil and gas production payable 1,637 2,432
Accrued interest 5,000 6,009
Other accrued expenses 1,162 1,162
Hedge liability - -
Current maturities of long-term debt 63,500 63,500
----------------- ------------
75,470 82,790
Liabilities related to assets held for sale 56,697 -
----------------- ------------
Total current liabilities 132,167 82,790
Long-term debt 190,979 236,943
Deferred income taxes - -
Future site restoration 533 3,946
Stockholders' equity (deficit) (142,254) (142,254)
----------------- ------------
Total liabilities and stockholders' deficit $ 181,425 $ 181,425
================= ============
F-44
FINANCIAL STATEMENTS
GREY WOLF EXPLORATION INC.
December 31, 2002
F-45
Deloitte & Touche LLP
3000, 700 Second Street SW
Calgary AB Canada T2P 0S7
Telephone +1 403-267-1700
Facsimile +1 403-264-2871
AUDITORS' REPORT
To the Directors of
Grey Wolf Exploration Inc.
We have audited the balance sheet of Grey Wolf Exploration Inc. as at December
31, 2002 and the statements of earnings (loss) and retained earnings (deficit)
and of cash flows for each of the years in the two-year period 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 audits.
With respect to the financial statements for each of the years in the two-year
period ended December 31, 2002, we conducted our audits in accordance with
Canadian generally accepted auditing standards and auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform an audit to obtain reasonable assurance 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 audits provide a
reasonable basis for our opinion.
In our opinion, these financial statements present fairly, in all material
respects, the financial position of the Company as at December 31, 2002 and the
results of its operations and its cash flows for each of the years in the
two-year period ended December 31, 2002 in accordance with Canadian generally
accepted accounting principles.
Calgary, Canada /s/ Deloitte & Touche LLP
March 10, 2003 Chartered Accountants
F-46
COMMENTS BY AUDITORS FOR U.S. READERS ON
CANADA -U.S. REPORTING DIFFERENCES
In the United States, reporting standards for auditors require the addition of
an explanatory paragraph (following the opinion paragraph) outlining changes in
accounting principles that have been implemented in the financial statements. As
discussed in Note 7 to the financial statements, in 2001 the Company changed its
method of computing diluted earnings per share to conform to the new Canadian
Institute of Chartered Accountants Handbook recommendation section 3500.
In the United States, reporting standards for auditors require the addition of
an explanatory paragraph (following the opinion paragraph) outlining significant
subsequent events that have been disclosed in the financial statements. We have
not audited any financial statements of the Company for any period subsequent to
December 31, 2002. However, as discussed in Note 13, the Company's parent
company sold all of the outstanding common shares of the Company on January 23,
2003.
Calgary, Canada /s/ Deloitte & Touche LLP
March 10, 2003 Chartered Accountants
F-47
GREY WOLF EXPLORATION INC.
Balance Sheet
As At December 31
(Thousands of Canadian dollars)
2002
$
----------------------
ASSETS
Current
Cash 3,365
Accounts receivable (Note 10) 8,230
----------------------
11,595
Long-term receivable (Note 10) 10,000
Property and equipment (Note 3) 23,401
Future income taxes (Note 6) 25,233
----------------------
70,229
----------------------
Liabilities
Current
Accounts payable and accrued liabilities (Note 10) 10,078
Long-term debt (Note 4) 69,227
Future site restoration and abandonment 1,221
Future income taxes (Note 6) -
----------------------
80,526
----------------------
CONTINGENCIES (Note 11)
SHAREHOLDERS' EQUITY (DEFICIENCY)
Share capital (Note 5) 27,891
Retained earnings (deficit) (38,188)
----------------------
(10,297)
----------------------
70,229
----------------------
See accompanying notes
F-48
GREY WOLF EXPLORATION INC.
Statements of Earnings (Loss) and Retained Earnings (Deficit)
Years Ended December 31
(thousands of Canadian dollars, except for share amounts)
2002 2001
$ $
-----------------------------------
Revenue
Petroleum and natural gas sales 33,245 30,268
Royalties, net of Alberta Royalty Tax Credit (8,237) (7,615)
-----------------------------------
25,008 22,653
-----------------------------------
Expenses
Operating 6,032 3,844
General and administrative (Note 3) 2,367 1,278
Interest and finance charges (Note 10) 4,518 1,827
Depletion, depreciation and site restoration (Note 3) 8,003 8,364
Write down of petroleum and natural gas properties
and facilities 82,635 -
Amortization of deferred financing fees (Note 4) 634 -
-----------------------------------
104,189 15,313
-----------------------------------
Earnings (loss) before taxes (79,181) 7,340
-----------------------------------
Provision for (recovery of) taxes (Note 6)
Current 24 144
Future (31,592) 3,061
-----------------------------------
(31,568) 3,205
-----------------------------------
Net earnings (loss) (47,613) 4,135
Retained earnings, beginning of year 9,425 5,290
-----------------------------------
Retained earnings (deficit), end of year (38,188) 9,425
-----------------------------------
Basic and diluted earnings (loss) per share (Note 7) (3.71) 0.32
-----------------------------------
Weighted average number of shares
Basic 12,841,327 12,776,407
Diluted 12,841,327 12,776,407
-----------------------------------
See accompanying notes
F-49
GREY WOLF EXPLORATION INC.
Statements of Cash Flows
Years Ended December 31
(Thousands of Canadian dollars, except for share amounts)
2002 2001
$ $
-------------------------------------
Operating Activities
Net earnings (loss) (47,613) 4,135
Depletion, depreciation and site restoration 8,003 8,364
Write down of petroleum and natural gas properties
and facilities 82,635 -
Future income tax expense (recovery) (31,592) 3,061
Amortization of deferred financing fees 634 -
-------------------------------------
Cash flow from operations 12,067 15,560
Changes in non-cash working capital items (Note 9) (3,355) (746)
-------------------------------------
8,712 14,814
-------------------------------------
Financing Activities
Increase in long-term debt 67,994 28,334
Repayments of long-term debt (35,723) -
Increase in long-term receivable - (10,000)
Issuance of common shares - 336
-------------------------------------
32,271 18,670
-------------------------------------
-------------------------------------
Total cash resources provided 40,983 33,484
-------------------------------------
Investing Activities
Expenditures for property and equipment 45,558 36,800
Other acquisitions - 1,071
Dispositions of property and equipment (3,657) (8,838)
Site restoration 122 46
-------------------------------------
42,023 29,079
-------------------------------------
Increase (decrease) in cash (1,040) 4,405
Cash, beginning of year 4,405 -
-------------------------------------
Cash, end of year 3,365 4,405
-------------------------------------
Basic and diluted cash flow from operations
per share (Note 7) 0.94 1.22
-------------------------------------
Cash interest paid 5,483 1,840
Cash taxes paid 88 82
-------------------------------------
See accompanying notes
F-50
GREY WOLF EXPLORATION INC.
Notes to the Financial Statements
Years Ended December 31, 2002 and 2001
- -----------------------------------------------------------------------------
(Tabular amounts in thousands of Canadian dollars, except for share amounts)
1. DESCRIPTION OF BUSINESs
Grey Wolf Exploration Inc. ("Grey Wolf" or "the Company") was incorporated
under the laws of the Province of Alberta on December 23, 1986. The
Company's primary business is the exploration, development and production
of crude oil and natural gas in western Canada. As at December 31, 2002 the
Company was a wholly-owned subsidiary of Abraxas Petroleum Corporation
("Abraxas").
2. SIGNIFICANT ACCOUNTING POLICIES
These financial statements have been prepared in accordance with Canadian
generally accepted accounting principles. Differences between Canadian and
U.S. GAAP are outlined in Note 12 to the financial statements.
Cash
Cash includes amounts held in short-term deposits with original maturities
of 90 days or less.
Property and equipment
The Company follows the full cost method of accounting in accordance with
the guideline issued by the Canadian Institute of Chartered Accountants
("CICA") whereby all costs associated with the exploration for and
development of petroleum and natural gas reserves, whether productive or
unproductive, are capitalized in a Canadian cost centre and charged to
income as set out below. Such costs include acquisition, drilling,
geological and geophysical costs related to exploration and development
activities. Costs of acquiring and evaluating unproved properties are
excluded from the depletion base until it is determined whether or not
proved reserves are attributable to the properties or impairment occurs.
Gains or losses are not recognized upon disposition of petroleum and
natural gas properties unless crediting the proceeds against accumulated
costs would result in a change in the rate of depletion of 20% or more.
Depletion of petroleum and natural gas properties and depreciation of
production equipment, except for gas plants and related facilities, is
provided on accumulated costs using the unit-of-production method based on
estimated proved petroleum and natural gas reserves, before royalties, as
determined by independent engineers. For purposes of the depletion
calculation, proven petroleum and natural gas reserves are converted to a
common unit of measure on the basis of one barrel of oil or liquids being
equal to six thousand cubic feet of natural gas. Depreciation of gas plants
and related production facilities is calculated on a straight-line basis
over an average 18-year term.
F-51
The depletion and depreciation cost base includes capitalized costs, less
costs of unproved properties, plus provision for future development costs
of proved undeveloped reserves.
F-52
2. SIGNIFICANT ACCOUNTING POLICIES (Continued)
Petroleum and natural gas properties (Continued)
The net carrying value of the Company's petroleum and natural gas
properties is limited to an ultimate recoverable amount (the "ceiling
test"). This amount is the aggregate of estimated future net revenues from
proved reserves and the costs of unproved properties, net of impairment
allowances, less future estimated production costs, general and
administration costs, financing costs, site restoration and abandonment
costs, and income taxes. Future net revenues are estimated using period end
prices and costs without escalation or discounting, and the income tax and
Alberta Royalty Tax Credit legislation substantially enacted at the balance
sheet date.
Furniture, leasehold improvements, computer hardware, software and office
equipment are carried at cost and are depreciated over the estimated useful
life of the assets at rates varying between 20 percent and 30 percent, on a
declining-balance basis.
Future site restoration and abandonment costs
The estimated cost of future site restoration is based on the current cost
and the anticipated method and extent of site restoration in accordance
with existing legislation and industry practice. The annual charge is
provided for on a unit-of-production basis for all properties except for
gas plants for which the annual charge is calculated on a straight-line
basis over the estimated remaining life of the plants. Actual site
restoration expenditures are charged to the accumulated liability account
as incurred.
Use of estimates
The amounts recorded for depletion and depreciation of property and
equipment and the provision for site restoration are based on estimates of
proved reserves and production rates. The ceiling test calculation is based
on estimates of proved reserves, production rates, oil and natural gas
prices, future costs and other relevant assumptions. By their nature, these
estimates are subject to uncertainty and the effect on the financial
statements of changes in such estimates could be significant.
F-53
2. SIGNIFICANT ACCOUNTING POLICIES (Continued)
Joint operations
Substantially all of the Company's exploration and development activities
are conducted jointly with others, and accordingly, the financial
statements reflect only the Company's proportionate interest in such
activities.
Revenue recognition
Petroleum and natural gas sales are recognized when the commodities are
delivered to purchasers.
Future income taxes
The Company accounts for income taxes using the liability method. Under
this method future income tax assets and liabilities are measured based
upon temporary differences between the carrying values of assets and
liabilities and their tax basis. Income tax expense (recovery) is computed
based on the change during the year in the future tax assets and
liabilities. Effects of changes in tax laws and tax rates are recognized
when substantially enacted.
Stock options
Prior to December 31, 2001, the Company had a stock option plan as
described in Note 5. No compensation expense was recognized when the stock
options were issued. Consideration received on exercise of stock options
was credited to share capital.
Per share figures
Basic per share figures are calculated using the weighted average number of
common shares outstanding during the year.
Effective January 1, 2001, the Company retroactively adopted, with
restatement of prior periods, the new recommendations of CICA Handbook
Section 3500. Under the revised standard, diluted per share figures are
calculated based on the weighted average number of shares outstanding
during the year plus the additional common shares that would have been
outstanding if potentially dilutive common shares had been issued using the
treasury stock method. Prior to the adoption of the new recommendations,
diluted per share amounts were determined using the imputed earnings
method.
F-54
2. SIGNIFICANT ACCOUNTING POLICIES (Continued)
Comparative figures
Certain of the prior years' comparative figures have been reclassified to
conform to the current year's presentation.
3. PROPERTY AND EQUIPMENT
2002
--------------------------------------------------------
Accumulated
Depletion and Net Book
Cost Depreciation Value
$ $ $
--------------------------------------------------------
Petroleum and natural gas properties 120,727 (102,708) 18,019
Gas plants and related production facilities 21,641 (16,314) 5,327
Other assets 621 (566) 55
--------------------------------------------------------
Net property and equipment 142,989 (119,588) 23,401
--------------------------------------------------------
For the year ended December 31, 2002, $701,000 of general and
administrative expenses were capitalized as part of property and equipment
related directly to the Company's exploration and development activities
(2001 - $402,000).
As a result of the quarterly ceiling test calculation at June 30, 2002, the
Company recorded a write-down of its petroleum and natural gas properties
and facilities in the amount of $82,635,000 ($49,649,000 net of related tax
recovery). The impairment was primarily due to lower gas prices and reserve
revisions subsequent to December 31, 2001, and higher future estimated
interest costs relating to the Mirant Facility (Note 4).
F-55
3. PROPERTY AND EQUIPMENT (Continued)
Undeveloped property costs of $4,961,511 were excluded from the depletion
base for the year ended December 31, 2002 (2001 - $6,065,907).
Future site restoration and abandonment charges of $294,029 are included in
depletion, depreciation and site restoration expense for the year ended
December 31, 2002 (2001 - $197,987).
4. LONG-TERM DEBT
Long term debt is comprised of the following:
2002
$
--------------------
Mirant Facility 72,398
Unamortized deferred financing charges (3,171)
--------------------
69,227
--------------------
At December 31, 2002, the Company had a credit facility with Mirant Canada
Energy Capital Ltd., (the "Mirant Facility") with a maximum available limit
of $150,000,000. At December 31, 2002, $72,398,000 was drawn on this
facility. Of the $72,398,000 drawn, $10,000,000 was advanced to Canaxas
(Note 10). The Company is required to pay an amount equal to monthly net
cash flow from operations less interest payments, general and
administrative expenses and approved capital expenditures. Loan advances
are supported by a first charge demand debenture in the amount of
$200,000,000 together with a debenture pledge agreement providing a first
priority lien on all the assets of the Company.
Under the Mirant Facility, loan advances bear interest at 9.5%, plus a 5%
overriding royalty which will decrease to 2.5% when certain conditions are
met. The overriding royalty granted to Mirant was treated as a disposition
of petroleum and natural gas properties in the amount of $3,600,000, with a
corresponding deferred financing charge recorded of $3,600,000, based on
the fair value at the date of disposition. This deferred charge plus
additional fees paid in 2001 and 2002 to secure the facility have been
netted against the outstanding loan balance and are being amortized over a
6-year period ending in 2007.
F-57
4. LONG-TERM DEBT (Continued)
At January 1, 2001, the Company had a revolving term credit facility with a
Canadian chartered bank with a maximum limit of $20,000,000. Under the
facility, loan advances bore interest at bank prime plus 1/8%, or the then
current bankers' acceptances rate plus 1 1/8%. Loan advances were supported
by a first floating charge demand debenture in the amount of $25,000,000
covering all the assets of the Company. During May 2001, the maximum limit
under the revolving term credit facility was increased to $27,000,000 and
remained at this level until replaced by the Mirant Facility in December
2001.
Effective January 1, 2002, the Emerging Issues Committee of the CICA issued
Abstract No. 122, which requires callable debt obligations to be presented
with current liabilities on the balance sheet. The maximum available amount
under the Mirant Facility may be terminated or reduced below the
outstanding amount only upon certain unanticipated events of default, and
therefore is not classified as a callable debt obligation. In addition, it
is anticipated the Company will be a net borrower due to a number of
planned capital projects over the next several years. Accordingly, the
outstanding balance has been classified as a long-term liability on the
balance sheet. The facility matures in December 2007.
Interest and financing charges for the year ended December 31, 2002
includes $5,483,000 of interest expense relating to long-term debt (2001 -
$843,000).
F-58
5. SHARE CAPITAL
Authorized
Unlimited number of common shares without nominal or par value.
Issued
Number of Amount
Shares $
---------------------------------------------
---------------------------------------------
Balance, December 31, 2000 12,661,541 27,555
Exercise of stock options 179,786 336
---------------------------------------------
Balance, December 31, 2001 and 2002 12,841,327 27,891
---------------------------------------------
Stock options
Prior to December 31, 2001, a maximum of 1,270,000 options to purchase
common shares were authorized for issuance under the Company's stock option
plan. The options were exercisable on a cumulative basis at 25% per year
commencing one year after the grant date and expiring in five years from
the date of grant. During the year ended December 31, 2001, all options
outstanding in the Company were cancelled and new options were issued by
Abraxas.
Number Weighted Average
of Options Option Price
----------------------------------------------
Balance, December 31, 2000 1,010,029 2.30
Exercised (179,786) 1.87
Cancelled (830,243) 2.39
------------------------
Balance, December 31, 2001 and 2002 -
------------------------
F-59
6. PROVISION FOR TAXES
The total provision for taxes recorded differs from the tax calculated by
applying the combined statutory Canadian corporate and provincial income
tax rates as follows:
2002 2001
$ $
-------------------------------------
Calculated income tax (recovery) expense at
42.12% (2001 - 42.62%) (33,351) 3,128
Increase (decrease) in tax resulting from:
Non-deductible crown royalties and other charges 2,511 2,950
Resource allowance and related items (583) (2,757)
Alberta Royalty Tax Credit (105) (177)
Large Corporation Tax 24 144
Tax rate adjustment (62) (151)
Other (2) 68
-------------------------------------
Provision for (recovery of) taxes (31,568) 3,205
-------------------------------------
The major components of future income tax asset (liability) at December 31,
2002 is as follows:
2002
$
------------------
Property and equipment 25,522
Future site restoration 514
Share issue costs 19
Attributed royalty income carried forward 607
Resource allowance (1,357)
Deferred financing costs (72)
------------------
25,233
------------------
No valuation allowance has been recorded with respect to the future income
tax asset balance at December 31, 2002 based on management's assessment
that the amount is more likely than not to be realized.
F-60
7. PER SHARE figures
The treasury method of calculating per share figures was adopted
retroactively effective January 1, 2001. There was no impact on 2001
diluted per share figures as a result of adopting the new treasury method.
8. FINANCIAL INSTRUMENTS
Financial instruments of the Company consist of accounts receivable,
long-term receivable, accounts payable and accrued liabilities, and
long-term debt. As at December 31, 2002, there were no significant
differences between the carrying amounts of these financial instruments
reported on the balance sheets and their estimated fair values.
Credit risk
The majority of the Company's accounts receivable are in respect of oil and
gas operations. The Company generally extends unsecured credit to these
customers, and therefore, the collection of accounts receivable may be
affected by changes in economic or other conditions. Management believes
the risk is mitigated by the size and reputation of the companies to which
they extend credit. The Company has not previously experienced any material
credit loss in the collection of receivables.
Interest rate risk
The Company's long-term debt bears interest at a floating market rate plus
1/8%. Accordingly, the Company is subject to interest rate risk, as the
required cash flow to service the debt will fluctuate as a result of
changes in market rates.
Commodity price risk
The nature of the Company's operations results in exposure to fluctuations
in commodity prices. The Company from time to time employs financial
instruments to manage its exposure to commodity prices. These instruments
are not used for speculative trading purposes. Gains and losses on
commodity price hedges are included in revenues upon the sale of the
related production. The Company had not entered into any contracts as at
December 31, 2002.
F-61
9. SUPPLEMENTARY CASH FLOW INFORMATION
2002 2001
$ $
-------------------------------------
Accounts receivable 1,750 (165)
Accounts payable and accrued liabilities (5,105) (581)
-------------------------------------
Changes in non-cash working capital items (3,355) (746)
-------------------------------------
10. RELATED PARTY TRANSACTIONS
The Company manages the assets and operations of Canadian Abraxas Petroleum
Limited ("Canaxas") pursuant to a Management Agreement dated November 12,
1996. Canaxas is a wholly-owned subsidiary of Abraxas. As at December 31,
2002, Abraxas owned 97.3% (2000 - 46.0%) of the common shares of the
Company and Canaxas owned 2.7% (2000 - 2.7%) of the common shares of the
Company. The aggregate common costs of operations and administration of the
Canaxas and Grey Wolf assets are shared on a pro-rata basis, based on
revenue.
During the year ended December 31, 2002, $2,967,200 was charged to Canaxas
with respect to the Management Agreement (2001 - $2,633,716). Abraxas also
charged the Company a corporate service charge of $885,000 for the year
ended December 31, 2002 of which $480,000 was charged out to Canaxas. For
the year ended December 31, 2001, the Abraxas corporate service charge was
$849,000 of which $589,000 was charged out to Canaxas. All amounts relating
to the Abraxas corporate service charge and the Management Agreement with
Canaxas are non-interest bearing, are not collateralized and are due on
demand.
At December 31, 2002 the Company had a long-term receivable from Canaxas in
the amount of $10,000,000 (Note 4). The balance bears interest at 9.65% and
has no fixed terms of repayment. Interest and financing charges of
$4,518,000 for the year ended December 31, 2002 are net of $965,000 (2001 -
$Nil)interest income accrued related to the long-term receivable from
Canaxas.
Following is a summary of amounts included in accounts receivable and
long-term receivable that are due from related parties as at December 31,
2002:
F-62
10. RELATED PARTY TRANSACTIONS (Continued)
2002
$
----------------------
Short-term receivable from Canaxas 1,236
Long-term receivable from Canaxas 10,000
11. contingencies
The Company is subject to various claims arising from its operations in the
normal course of business, none of which are expected, individually or in
the aggregate, to have a material adverse impact on the Company's
operations or financial position.
12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES
Reconciliation to United States Generally Accepted Accounting Principles
The financial statements of the Company have been prepared in accordance
with Canadian generally accepted accounting principles ("Canadian GAAP"),
which in most respects, conform to accounting principles generally accepted
in the United States of America ("U.S. GAAP"). Differences from U.S. GAAP
having a significant effect on the Company's balance sheets and statements
of earnings (loss) and retained earnings (deficit) and of cash flows are
described and quantified below for the years indicated:
(a)Under U.S. GAAP, interest costs associated with certain capital
expenditures are required to be capitalized as part of the historical
cost of the oil and gas assets. Under Canadian GAAP, the calculation of
interest costs eligible for capitalization differs from the calculation
under U.S. GAAP in certain respects and is optional at the discretion of
the entity. Accordingly, no amounts have been capitalized with respect
to the Canadian GAAP financial statements. The impact of recording
capitalized interest under U.S. GAAP would be to increase the carrying
value of property and equipment by $168,000 in 2002 and $119,000 in 2001
with a corresponding decrease in interest expense in the respective
periods. The cumulative decrease in interest expense under U.S. GAAP for
years prior to 2001 was $69,000.
F-63
12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATESc GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES (Continued)
(b)In September 2001, Abraxas acquired the remaining non-controlling
interest of the Company. Consideration was comprised of 0.6 common
shares of Abraxas, in exchange for each common share of the Company.
Under U.S. GAAP, the costs assigned to assets and liabilities by the
acquiring company under a business combination are considered to
constitute a new basis of accounting. Accordingly, the historical
carrying values of assets and liabilities of the subsidiary are
comprehensively revalued based on the purchase price assigned for
consolidation purposes at the time it becomes wholly owned ("push down
accounting"). Under Canadian GAAP, comprehensive revaluation of assets
and liabilities in the financial statements of a subsidiary based on a
purchase transaction involving acquisition of all of the equity
interests is permitted, but not required. Had the consolidation entries
of Abraxas related to the acquisition been applied in the Company's
financial statements using "push down accounting", property and
equipment and future income tax liability would be reduced by $4,074,000
and $1,736,000, respectively, accounts receivable would be increased and
interest and financing charges decreased by $984,000 (relating to
certain costs of the transaction paid by the Company), with the
remaining amount of $2,338,000 recorded as a revaluation adjustment
within shareholders' equity.
(c)Under U.S. GAAP, the carrying value of petroleum and natural gas
properties and related facilities at the balance sheet date, net of
deferred income taxes and accumulated site restoration and abandonment
liability, is limited to the present value of after-tax future net
revenue from proven reserves, discounted at 10 percent, plus the lower
of cost and fair value of unproved oil and gas properties. Under
Canadian GAAP, the "ceiling test" calculation is performed using
undiscounted after-tax net revenues, less future estimated general and
administrative and financing costs plus the lower of cost and fair value
of unproved oil and gas properties. Had the ceiling test been applied in
accordance with U.S. GAAP, the write-down recorded for the year ended
December 31, 2002 would have been lower by $41,155,000 ($25,464,000
after-tax). There were no differences between the application of the
Canadian and U.S. GAAP ceiling tests in 2001, or for years prior to
2001.
F-64
12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES (Continued)
(d)Prior to 2000, Canadian GAAP required the use of the deferral method of
accounting for income taxes. For fiscal periods beginning on or after
January 1, 2000, retroactive adoption of the liability method of
accounting for income taxes was required, which is substantially the
same as Financial Accounting Standards Board Statement No. 109 under
U.S. GAAP. However, upon adoption of the new recommendation for Canadian
GAAP, companies were permitted to record the impact of differences in
accounting and tax bases to retained earnings as a one-time transition
adjustment. Accordingly, property and equipment would have been higher
under U.S. GAAP by $682,000 for 2002 and 2001 before the impact of
depletion. In addition, future income tax expense of $480,000 would have
been recorded for 1999 under U.S. GAAP.
(e)As a result of the Canadian - U.S. GAAP differences in capitalization
of interest, "push down accounting", ceiling test write-down and
adoption of the deferral method of accounting for incomes taxes as
outlined in (a), (b), (c) and (d), respectively, depletion and
depreciation expense and property and equipment under U.S. GAAP have
been adjusted for each of the years ended December 31, 2002 and 2001.
The cumulative increase in depletion and depreciation expense for years
prior to 2001 was $246,000.
(f)Future income taxes have been adjusted for the year ended December 31,
2002 for the tax impact of the Canadian - U.S. GAAP differences outlined
in (a) through (e). Except for the impact on future tax expense for 1999
as noted in (d), the cumulative impact on future income taxes for years
prior to 2002 was not significant.
(g)Prior to 2001, Canadian GAAP required the use of the imputed earnings
method for purposes of the calculation of fully diluted earnings per
share. For fiscal periods beginning on or after January 1, 2001,
retroactive application of the treasury stock method with restatement of
prior periods is required, which is substantially the same as Financial
Accounting Standards Board Statement No. 128 under U.S. GAAP.
Accordingly, no adjustments are required to conform the diluted earnings
(loss) per share figures to U.S. GAAP, except for the net income (loss)
effect of the above-noted Canadian - U.S. GAAP differences identified.
F-65
12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLYACCEPTED ACCOUNTING
PRINCIPLES (Continued)
The application of U.S. GAAP would have the following effect on the
Statements of Earnings (Loss):
Years Ended December 31,
----------------- -----------------
2002 2001
$ $
----------------- -----------------
Net earnings (loss), as reported (47,613) 4,135
Capitalized interest (a) 168 119
Depreciation, depletion and site restoration (e) (2,401) (62)
Write-down of petroleum and natural gas properties
and facilities (c) 41,155 -
Interest and financing charges (b) - 984
Future income tax expense (recovery) (f) (14,495) -
----------------- -----------------
Net earnings (loss), U.S. GAAP (23,186) 5,176
----------------- -----------------
Basic and diluted earnings (loss) per share, as reported (3.71) 0.32
Effect of increase (decrease) in net earnings
(loss) under U.S. GAAP 1.90 0.09
----------------- -----------------
Basic and diluted earnings (loss) per share, U.S. GAAP (g) (1.81) 0.41
----------------- -----------------
F-66
12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES (Continued)
The application of U.S. GAAP would have the following effect on the Balance
Sheets:
As At December 31, 2002
--------------------------------------------
Cumulative
As Increase U.S.
Reported (Decrease) GAAP
-------------- ---------------- ------------
ASSETS
Accounts receivable (b) 8,230 984 9,214
Property and equipment (a)(b)(c)(d)(e)
23,401 35,414 58,815
Future income taxes (f) 25,233 (12,759) 12,474
LIABILITIES
Future income taxes (d)(f) - - -
SHAREHOLDERS'
EQUITY (DEFICIENCY)
Revaluation adjustment (b) - (2,338) (2,338)
Retained earnings (deficit)
(a)(b)(c)(d)(e)(f) (38,188) 25,977 (15,255)
F-67
12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES (Continued)
The application of U.S. GAAP would have the following effect on the
Statements of Cash Flows:
Years Ended December 31,
------------- --------------
2002 2001
$ $
------------- --------------
OPERATING ACTIVITIES
Cash flow from operating activities, as reported 8,712 14,814
Increase (decrease) in:
Net earnings (loss) 24,427 1,041
Depletion, depreciation and site restoration (e) 2,401 62
Write-down of petroleum and natural gas properties
and facilities (c) (41,155) -
Future income tax expense (recovery) (f) 14,495 -
Changes in non-cash working capital items (b) - (984)
------------- --------------
Cash flow from operating activities, U.S. GAAP 8,880 14,933
------------- --------------
INVESTING ACTIVITIES
Net cash (used) provided by investing activities, as reported (42,023) (29,079)
Increase in capital expenditures (a) (168) (119)
------------- --------------
Net cash (used) provided by investing activities,
U.S. GAAP (42,191) (29,198)
------------- --------------
F-68
12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES (Continued)
Under Canadian GAAP, companies are permitted to present a sub-total prior
to changes in non-cash working capital within operating activities. This
information is perceived to be useful information for various users of the
financial statements and is commonly presented by Canadian public
companies. Under U.S. GAAP, this sub-total is not permitted to be shown and
would be removed in the statements of cash flows for all periods presented.
In addition, cash flow from operations per share figures would not be
presented under U.S. GAAP.
Recent U.S. Accounting Developments
Statement No. 143, "Accounting for Asset Retirement Obligations" (FAS 143)
was released by the Financial Accounting Standards Board in June 2001. FAS
143 requires liability recognition for retirement obligations associated
with tangible long-lived assets. The initial amount of the asset retirement
obligation is to be recorded at fair value. The asset retirement cost equal
to the fair value of the retirement obligation is to be capitalized as part
of the cost of the related long-lived asset and amortized to expense over
the useful life of the asset. Enterprises are required to adopt FAS 143 for
fiscal years beginning after June 15, 2002. The Company is currently
assessing the impact that adoption of this standard would have on its
financial position and results of operations, in conjunction with the
January 23, 2003 transaction as described in Note 13.
The Financial Accounting Standards Board also recently issued Statement No.
144, "Accounting for the Impairment of Disposal of Long-Lived Assets" (FAS
144). FAS 144 will replace previous United States generally accepted
accounting principles regarding accounting for impairment of long-lived
assets and accounting and reporting for discontinued operations. FAS 144
retains the fundamental provisions of the prior standard for recognizing
and measuring impairment losses on long-lived assets. FAS 144 retains the
basic provisions of the prior standard for presentation of discontinued
operations in the income statement, but broadens that presentation to
include a component of an entity rather than a segment of a business.
Enterprises are required to adopt FAS 144 for fiscal years beginning after
December 15, 2001. The Company has adopted the accounting standard
effective January 1, 2002. The standard is not expected to have a
significant future impact on the Company's financial position and results
of operations.
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12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES (Continued)
The Financial Accounting Standards Board also recently issued Statement No.
146, "Accounting for Costs Associated With Exit or Disposal Activities"
(FAS 146). FAS 146 addresses financial accounting and reporting for costs
associated with exit or disposal activities and nullifies Emerging Issues
Task Force (EITF) Issue No. 94-3, "Liability Recognition for Certain
Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring)." The provisions of
this Statement are effective for exit or disposal activities that are
initiated after December 31, 2002, with early application encouraged. The
standard is not expected to have a significant impact on the Company's
financial position or results of operations.
13. SUBSEQUENT EVENTS
On January 23, 2003, Abraxas completed the sale of all of the outstanding
common shares of the Company to an unrelated third party (the "Purchaser")
for gross cash proceeds of approximately $110,790,000, subject to closing
adjustments. Upon closing of the sale, the Company was required to repay
the outstanding indebtedness including accrued interest under the Mirant
Facility, totaling $72,847,000. Prior to the sale, certain petroleum and
natural gas assets of the Company with a net book value of $8,871,000 were
transferred to a related newly-formed subsidiary of Abraxas, a portion of
which will be developed jointly under farmout arrangements with the
Purchaser.
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