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<SEC-DOCUMENT>0000867665-04-000019.txt : 20040311
<SEC-HEADER>0000867665-04-000019.hdr.sgml : 20040311
<ACCEPTANCE-DATETIME>20040311170049
ACCESSION NUMBER: 0000867665-04-000019
CONFORMED SUBMISSION TYPE: 10-K
PUBLIC DOCUMENT COUNT: 1
CONFORMED PERIOD OF REPORT: 20031231
FILED AS OF DATE: 20040311
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: ABRAXAS PETROLEUM CORP
CENTRAL INDEX KEY: 0000867665
STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311]
IRS NUMBER: 742584033
STATE OF INCORPORATION: NV
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-K
SEC ACT: 1934 Act
SEC FILE NUMBER: 001-16071
FILM NUMBER: 04663479
BUSINESS ADDRESS:
STREET 1: 500 N LOOP 1604 E STE 100
CITY: SAN ANTONIO
STATE: TX
ZIP: 78232
BUSINESS PHONE: 2104904788
MAIL ADDRESS:
STREET 1: 500 N LOOP 1604 EAST STE 100
CITY: SAN ANTONIO
STATE: TX
ZIP: 78232
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K
<SEQUENCE>1
<FILENAME>abp10k2003.txt
<TEXT>
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the Fiscal Year Ended December 31, 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.
<PAGE>
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).
<PAGE>
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
<PAGE>
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
4
<PAGE>
FORWARD-LOOKING INFORMATION
We make forward-looking statements throughout this document. Whenever you
read a statement that is not simply a statement of historical fact (such as 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.
5
<PAGE>
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
<PAGE>
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;
7
<PAGE>
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
<PAGE>
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
<PAGE>
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
10
<PAGE>
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,
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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
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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.
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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.
19
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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.
<TABLE>
<CAPTION>
2001 (1) 2002 (1) 2003 (1)
----------------- ---------------- -----------------
<S> <C> <C> <C>
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
- ------------------
</TABLE>
(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
<PAGE>
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:
<TABLE>
<CAPTION>
2001 2002 2003
----------------------------- ----------------------------- -------------------------------
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
------------ ---------- ------------ ---------- ---------- --------
Exploratory(3)
Productive(4)
<S> <C> <C> <C> <C> <C> <C>
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
============ ========== ============ ========== ========== ========
- ------------------
</TABLE>
(1) A gross well is a well in which we own an interest.
(2) The number of net wells represents the total percentage of working
interests held in all wells (e.g., total working interest of 50% is
equivalent to 0.5 net well. A total working interest of 100% is equivalent
to 1.0 net well).
(3) An exploratory well is a well drilled to find and produce 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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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.
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------------------------------------------
1999* 2000* 2001* 2002* 2003*
----- ----- ----- ----- -----
(Dollars in thousands except per share data)
<S> <C> <C> <C> <C> <C>
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)
</TABLE>
(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
<PAGE>
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.
<TABLE>
<CAPTION>
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
------------ ----------- ----------- ------------ ----------- ------------- ----------- ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
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
</TABLE>
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.
<TABLE>
<CAPTION>
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
----------- ----------- ------------ -------------- ------------- ----------- ------------ ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
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
</TABLE>
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
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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:
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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.
<TABLE>
<CAPTION>
Years Ended December 31,
---------------------------------------------------------------
(dollars in thousands, except per unit data)
2001 (1) 2002 (1) 2003 (1)
------------------- ------------------- -------------------
Operating revenue:
<S> <C> <C> <C>
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)..........