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<SEC-DOCUMENT>0000867665-01-500006.txt : 20010409
<SEC-HEADER>0000867665-01-500006.hdr.sgml : 20010409
ACCESSION NUMBER: 0000867665-01-500006
CONFORMED SUBMISSION TYPE: 10-K
PUBLIC DOCUMENT COUNT: 1
CONFORMED PERIOD OF REPORT: 20001231
FILED AS OF DATE: 20010402
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:
SEC FILE NUMBER: 001-16071
FILM NUMBER: 1589892
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>abp10k2000.txt
<DESCRIPTION>ABRAXAS PETROLEUM CORPORATION, 2000 FORM 10-K
<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, 2000
[ ]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
Incorporation or Organization) Identification Number)
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. [ ]
The aggregate market value of the voting stock (which consists solely
of shares of common stock) held by non-affiliates of the registrant as of March
22, 2001, based upon the closing per share price of $4.75, was approximately
$94,551,000 on such date.
The number of shares of the issuer's common stock, par value $.01 per
share, outstanding as of March 22, 2001 was 22,593,969 shares of which
19,905,411 shares were held by non-affiliates.
Documents Incorporated by Reference: Portions of the registrant's Proxy
Statement relating to the 2001 Annual Meeting of Shareholders to be held on May
24, 2001 have been incorporated by reference herein (Part III).
1
<PAGE>
ABRAXAS PETROLEUM CORPORATION
FORM 10-K
TABLE OF CONTENTS
PART I
Page
Item 1. Business. ...........................................................4
General ...........................................................4
Business Strategy ..................................................5
Markets and Customers...............................................6
Risk Factors........................................................6
Regulation of Crude Oil and Natural Gas Activities.................13
Canadian Royalty Matters...........................................16
Environmental Matters ............................................17
Title to properties................................................19
Employees..........................................................19
Item 2. Properties..........................................................20
Primary Operating Areas............................................20
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..................................26
Market Information.................................................26
Holders............................................................26
Dividends..........................................................26
Item 6. Selected Financial Data.............................................27
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations......................27
General............................................................27
Results of Operations..............................................27
Liquidity and Capital Resources....................................31
New Accounting Pronouncement......................................38
Item 7a. Quantitative and Qualitative Disclosures about Market Risk..........38
Item 8. Financial Statements and Supplementary Data.........................39
2
<PAGE>
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure............................39
PART III
Item 10. Directors and Executive Officers of the Registrant ...............39
Item 11. Executive Compensation.............................................39
Item 12. Security Ownership of Certain Beneficial Owners
and Management...................................................39
Item 13. Certain Relationships and Related Transactions.....................39
PART IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K.........................................40
SIGNATURES........................................................44
3
<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, 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 annual report is generally located in the material set forth
under the headings "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and "Business," 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 of our operations include, among others, the following:
o Our high debt level
o Our ability to raise capital
o Economic and business conditions
o Our success in completing acquisitions or in development
and exploration activities
o Prices for crude oil and natural gas; 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, exploration, exploitation and production of crude
oil and natural gas. Since January 1, 1991, our principal means of growth has
been through the acquisition and subsequent development and exploitation of
producing properties and related assets. As a result of our historical
acquisition activities, we believe we have a substantial inventory of low risk
exploration and development opportunities, the development of which is critical
to the maintenance and growth of our current production levels. We seek to
complement our acquisition and development activities by selectively
participating in exploration projects with experienced industry partners.
Our principal areas of operation are Texas and western Canada. At December
31, 2000, we owned interests in 1,200,778 gross acres (835,445 net acres) and
operated properties accounting for 79% of our PV-10, affording us substantial
control over the timing and incurrence of operating and capital expenditures.
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. An 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 and
MBbls is used to designate one thousand barrels of crude oil.
At December 31, 2000, estimated total proved reserves of Abraxas, our
wholly-owned subsidiary, Canadian Abraxas Petroleum Limited, and our 49%-owned
subsidiary, Grey Wolf Exploration Inc., were 244.4 Bcfe with an aggregate PV-10
of $1.0 billion. As of December 31, 2000, we had net natural gas processing
capacity of 120 MMcf per day through our 13 natural gas processing plants and
compression facilities in Canada, giving us substantial control over our
Canadian production and marketing activities.
4
<PAGE>
Business Strategy
Our primary business objectives are to increase reserves, production
and cash flow through the following:
o Improved Liquidity. Since January 1999, we have sought to improve our
liquidity in order to allow us to meet our debt service requirements and to
maintain and increase existing production.
o Our sale in March 1999 of 12.875% Senior Secured Notes due 2003
(the "First Lien Notes") allowed us to refinance our bank debt,
meet our near-term debt service requirements and make limited
crude oil and natural gas capital expenditures.
o In October 1999, we sold a dollar denominated production payment
for $4.0 million relating to existing natural gas wells in the
Edwards Trend in South Texas to a unit of Southern Energy, Inc.
which is now known as Mirant Americas Energy Capital, L.P. and in
2000, we sold additional production payments for $6.4 million
relating to additional natural gas wells in the Edwards Trend to
Mirant. We have the ability to sell up to $50 million to Mirant
for drilling opportunities in the Edwards Trend.
o In December 1999, Abraxas and our wholly-owned Canadian
subsidiary, Canadian Abraxas Petroleum Limited, completed an
Exchange Offer whereby we exchanged our new 11.5% Senior Secured
Notes due 2004, Series A (the "Second Lien Notes"), common stock
and contingent value rights for approximately 98.43% of our
outstanding 11.5% Senior Notes due 2004, Series D (the "Old
Notes"). The Exchange Offer reduced our long-term debt by
approximately $76 million after expenses.
o We are continuing to rationalize our significant non-core Canadian
assets to allow us to continue to grow while reducing our debt. We
may sell non-core assets or seek partners to fund a portion of the
exploration costs of undeveloped acreage and are considering other
potential strategic alternatives.
o In March 2000, we sold our interest in certain crude oil and
natural gas properties that we owned and operated in Wyoming.
Simultaneously, a limited partnership of which one of our
subsidiaries was the general partner, which we accounted for on
the equity method of accounting, sold its interest in crude oil
and natural gas properties in the same area. Our net proceeds from
these transactions were approximately $34.0 million.
o In March 2001, we announced that we had engaged Credit Lyonnais
Securities (USA) Inc. and CIBC World Markets Corp. to assist us in
a review of alternative financial strategies. Under the terms of
this engagement, we may restructure, refinance or recapitalize
some or all of our existing debt and/or issue equity securities.
o Low Cost Operations. We seek to maintain low operating and G&A expenses per
Mcfe by operating a majority of our producing properties and related assets
and by maintaining a high rate of production on a per well basis. As a
result of this strategy, we have achieved per unit operating and G&A
expenses that compare favorably with similar companies.
o Exploitation of Existing Properties. We will allocate a portion of our
operating cash flow to the exploitation of our producing properties. We
believe that the proximity of our undeveloped reserves to existing
production makes development of these properties less risky and more
cost-effective than other drilling opportunities available to us. Given our
high degree of operating control, the timing and incurrence of operating
and capital expenditures is largely within our discretion. Our capital
expenditure budget for 2001 for existing leaseholds is approximately $42.0
million including approximately $13.5 million for our horizontal drilling
exploitation program. We currently have horizontal drilling or completion
operations in West Texas, South Texas and Wyoming. We focus our horizontal
drilling activities in deep wells containing known columns of hydrocarbons.
We believe that this drilling method provides increased production at low
incremental costs and very high rates of return.
5
<PAGE>
o Producing Property Acquisitions. As cash flow permits, we intend to
continue to acquire producing crude oil and natural gas properties that can
increase cash flow, production and reserves through operational
improvements and additional development. In January 2001, we announced that
we were in discussions with our 49%-owned subsidiary, Grey Wolf Exploration
Inc., concerning a stock for stock acquisition of the remaining 51%
ownership of Grey Wolf. If we complete this acquisition as contemplated, we
expect that the impact on us will include the streamlining of our Canadian
operations, an increase in net asset values for our stockholders, and an
accretive impact to stockholders on an earnings basis.
o Focused Exploration Activity. We may allocate a portion of our capital
budget to the drilling of exploratory wells that have high reserve
potential. We believe that by devoting a relatively small amount of capital
to high impact, high risk projects while reserving the majority of our
available capital for development projects, we can reduce drilling risks
while still benefiting from the potential for significant reserve
additions.
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
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.
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 hedging activities.
Substantially all of our crude oil and natural gas is sold at current market
prices under short-term contracts, as is customary in the industry. During the
year ended December 31, 2000, two purchasers accounted for approximately 26% of
our crude oil and natural gas sales. We believe that there are numerous other
companies available to purchase our crude oil and natural gas and that the loss
of one or both of these purchasers would not materially affect our ability to
sell crude oil and natural gas. The prices we receive 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 hedging activities.
Risk Factors
Our debt levels and our debt covenants may limit our ability to pursue
business opportunities and to obtain additional financing. We have substantial
indebtedness and debt service requirements. Our total debt and stockholders'
deficit were $267.6 million and $6.5 million, respectively, as of December 31,
2000. We may incur additional indebtedness in the future in connection with
acquiring, developing and exploiting producing properties, although our ability
to incur additional indebtedness is substantially limited by the terms of the
6
<PAGE>
First Lien Notes indenture and the Second Lien Notes indenture. You should read
the discussions under the heading " "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources" and the Consolidated Financial Statements and the notes thereto
included elsewhere in this annual report for more information regarding our
indebtedness.
Our high level of debt affects our operations in several important ways,
including:
o A substantial amount of our cash flow from operations will be used to pay
interest on the First Lien Notes, any outstanding Old Notes and the Second
Lien Notes;
o The covenants contained in the First Lien Notes indenture and the Second
Lien Notes indenture will limit our ability to borrow additional funds or
to dispose of assets and may affect our flexibility in planning for, and
reacting to, changes in our business, including possibly limiting
acquisition activities;
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; and
o The terms of the First Lien Notes indenture, the Old Notes indenture and
the Second Lien Notes indenture will permit the holders of the First Lien
Notes, any outstanding Old Notes and the Second Lien Notes to accelerate
payments upon an event of default or a change of control.
Our high level of debt increases the risk that we may default on our debt
obligations. Our ability to meet our debt obligations and to reduce our level of
debt depends on our future performance which, in turn, depends on general
economic conditions and financial, business and other factors many of which are
beyond our control.
We have substantial capital requirements. We make and will continue to make
substantial capital expenditures for the acquisition, exploitation, development,
exploration and production of crude oil and natural gas. In the past, we have
funded our operations primarily through cash flow from operations and borrowings
under our bank credit facilities and other sources. Due to severely depressed
crude oil and natural gas prices in 1999, our cash flow from operations was
substantially reduced. We met our liquidity needs in 1999 through the sale of
the First Lien Notes and the sale of the production payment to Mirant and the
sale of certain non-core properties together with cash flow from operations. In
2000, we met our liquidity needs through cash flow from operations, the sale of
additional non-core properties including those in Wyoming and further
installments on the production payment with Mirant. We are examining certain
alternative sources of long term capital including:
o restructuring, refinancing or recapitalizing our current
indebtedness;
o selling equity securities; and
o selling additional non-core properties.
The availability of these sources of capital depend upon a number of factors,
many of which are beyond our control such as general economic and financial
market conditions and crude oil and natural gas prices.
Our ability to raise funds through additional indebtedness will be
substantially limited by the terms of the indenture governing the First Lien
Notes, the indenture governing the Old Notes and the indenture governing the
Second Lien Notes, although many of the restrictive covenants contained in the
indenture governing the Old Notes were eliminated in connection with the
Exchange Offer.
The First Lien Notes indenture and the Second Lien Notes indenture restrict,
among other things, our ability to:
o incur additional indebtedness;
o incur liens;
o pay dividends or make certain other restricted payments;
7
<PAGE>
o consummate certain asset sales;
o enter into certain transactions with affiliates;
o merge or consolidate with any other person; or
o sell, assign, transfer, lease, convey or otherwise dispose of all or
substantially all of our assets.
Additionally, our ability to raise funds through additional indebtedness
will be limited because substantially all of our crude oil and natural gas
properties and natural gas processing facilities are subject to a first lien or
floating charge for the benefit of the holders of the First Lien Notes and a
second lien or floating charge for the benefit of the holders of the Second Lien
Notes. Finally, our indentures also place restrictions on the use of proceeds
from asset sales.
We believe that our improved cash flow from operations due to higher
commodity prices and operating results, the sale of non-core properties and
additional installments on the production payment with Mirant will provide us
with sufficient capital for the next 12 months. However, if our production or
commodity prices decrease or if our drilling activities cost more than we
anticipate, we may not be able to execute our business plan without additional
capital.
Crude oil and natural gas prices and their volatility could adversely affect
our revenue, cash flows and profitability. Our revenue, profitability and future
rate of growth depend substantially upon prevailing prices for crude oil and
natural gas. Crude oil and natural gas prices fluctuate and prior to 2000 had
declined significantly. Natural gas prices affect us more than crude oil prices
since 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. For example in 1999 we reduced our
capital expenditures budget because of lower crude oil and natural gas prices.
In addition, we may have ceiling test writedowns when prices decline. 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 Mideast; and
o overall economic conditions.
Hedging transactions may limit our potential gains. We entered into hedge
agreements and other financial arrangements at various times to attempt to
minimize the effect of crude oil and natural gas price fluctuations. We cannot
assure you that such 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 additional revenues
from price increases. In addition, such transactions may expose us to risks of
financial loss under certain circumstances, such as:
o production is less than expected; or
o price differences between delivery points for our production and
those in our hedging agreements increase.
In 2000, we experienced hedging losses of $20.2 million. At year end 2000,
the fair value of future hedges was a liability of approximately $38 million,
which we estimate will reduce cash flow by $27 million in 2001 and $11 million
in 2002. To the extent that these hedge agreements require us to pay the
counterparty, our revenue will be reduced. You should read the discussion under
the heading "Management's Discussion and Analysis of Financial Condition and
8
<PAGE>
Results of Operations-- Liquidity and Capital Resources - Hedging Activities"
for more information regarding our hedging activities.
Lower crude oil and natural gas prices increase the risk of ceiling
limitation writedowns. 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. If net
capitalized costs of crude oil and natural gas properties exceed the ceiling
limit, we must charge the amount of the excess to earnings. This is called a
"ceiling limitation writedown." This charge does not impact cash flow from
operating activities, but does reduce our stockholders' equity. 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 or volatile.
In addition, writedowns may occur if we experience substantial downward
adjustments to our estimated proved reserves or if purchasers cancel long-term
contracts for our natural gas production. In 1999, we recorded a writedown of
$19.1 million ($11.9 million after tax) as a result of a downward adjustment to
our proved reserves in Canada. In 1998, we recorded a write down of $61 million
as a result of low commodity prices. We cannot assure you that we will not
experience additional ceiling limitation writedowns 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 year 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 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 document 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, 2000. The sales prices as of such date used for
purposes of such estimates were $25.73 per Bbl of crude oil, $30.63 per Bbl of
NGLs and $9.21 per Mcf of natural gas. This compares with $24.88 per Bbl of
crude oil, $14.79 per Bbl of NGLs and $2.11 per Mcf of natural gas as of
December 31, 1999. It is also assumed that we will make future capital
expenditures of approximately $55.5 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.
9
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We have experienced recurring net losses. The Company has experienced losses
in three of the last four years. Additionally in 2000 if the significant gain on
the sale of partnership is excluded the Company would have experienced a net
loss for the year.
You should read the discussions under the heading "Management's Discussion
and Analysis of Financial Condition and Results of Operations" and our
Consolidated Financial Statements and the notes thereto included elsewhere in
this document for more information regarding these losses. We cannot assure you
that we will remain profitable in the future.
Our ability to replace production with new reserves is highly dependent on
acquisitions or successful development and exploration 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 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. We cannot assure you that
our exploration and development activities will result in increases in reserves.
Our operations may be curtailed, delayed or cancelled if we lack necessary
capital and by other factors, such as title problems, weather, compliance with
governmental regulations, mechanical problems or shortages or delays in the
delivery of equipment.
Our ability to continue to acquire producing properties or companies that
own such properties assumes that major integrated oil companies and independent
oil companies will continue to divest many of their crude oil and natural gas
properties. We cannot assure you that such divestitures will continue or that we
will be able to acquire such properties at acceptable prices or develop
additional reserves in the future. In addition, under the terms of the First
Lien Notes indenture, the Old Notes indenture and the Second Lien Notes
indenture, our ability to obtain additional financing in the future for
acquisitions and capital expenditures will be limited
Our operations are subject to numerous risks of crude oil and natural gas
drilling and production activities. 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:
- title problems,
- weather conditions,
- compliance with governmental requirements, and
- mechanical difficulties or shortages or delays in the delivery
of drilling rigs, work boats 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 wells 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, 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.
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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
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.
We compete against other companies in our natural gas processing business
both for supplies of natural gas and for customers to which we sell our
products. Competition for natural gas supplies is based primarily on location of
natural gas gathering facilities and natural gas gathering plants, operating
efficiency and reliability and ability to obtain a satisfactory price for
products recovered. Competition for customers is based primarily on price and
delivery capabilities.
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 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 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
Our Canadian operations are subject to the risks of currency fluctuations
and in some instances economic and political developments. We have significant
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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 the 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.
Shares eligible for future sale may depress our stock price. At March 22,
2001, we had 22,593,969 shares of common stock outstanding of which 2,688,558
shares were held by affiliates, 4,035,524 shares of common stock subject to
outstanding options granted under certain stock option plans (of which 1,556,813
shares were vested at March 22, 2001) and 950,000 shares issuable upon exercise
of warrants. In addition, as part of the Exchange Offer, we issued CVRs which
entitled the holders thereof to receive up to a total of 105,408,978 shares of
our common stock if the price of our common stock does not reach certain target
prices. The target price on May 21, 2001 is $5.97. As of March 22, 2001, based
on the Abraxas Common Stock market price, CVR holders would be entitled to
receive approximately 3.3 million shares.
All of the shares of common stock held by affiliates are restricted or
control securities under Rule 144 promulgated under the Securities Act of 1933,
as amended (the "Securities Act"). The shares issuable pursuant to the CVRs are
exempt from registration under the Securities Act. The shares of the common
stock issuable upon exercise of the stock options have been registered under the
Securities Act. The shares of the common stock issuable upon exercise of the
warrants are subject to certain registration rights and, therefore, will be
eligible for resale in the public market after a registration statement covering
such shares has been declared effective. Sales of shares of common stock under
Rule 144 or another exemption under the Securities Act or pursuant to a
registration statement could have a material adverse effect on the price of the
common stock and could impair our ability to raise additional capital through
the sale of equity securities.
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 would have a materially adverse effect on our business. Mr. Watson has a
five-year employment contract with Abraxas which provides that he can be
terminated for cause only. 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.
Anti-takeover provisions could make a third party acquisition of Abraxas
difficult. Abraxas' articles of incorporation and by-laws provide for a
classified board of directors, with each member serving a three-year term and
eliminate the ability of stockholders to call special meetings or take action by
written consent. Abraxas has also adopted a stockholder rights plan. Each of the
provisions in the articles of incorporation and by-laws and the stockholder
rights plan could make it more difficult for a third party to acquire Abraxas
without the approval of Abraxas' board. In addition, the Nevada corporate
statute also contains certain provisions which could make an acquisition by a
third party more difficult
Use of our net operating loss carryforwards may be limited. At December 31,
2000, the Company had, subject to the limitation discussed below, $101,800,000
of net operating loss carryforwards for U.S. tax purposes. These loss
carryforwards will expire from 2001 through 2020 if not utilized. At December
31, 2000, the Company had approximately $11,400,000 of net operating loss
carryforwards for Canadian tax purposes. These carryforwards will expire from
2001 through 2020 if not utilized.
As a result of the acquisition of certain partnership interests and crude
oil and natural gas properties in 1990 and 1991, an ownership change under
Section 382 occurred in December 1991. Accordingly, it is expected that the use
of the U.S. net operating loss carryforwards generated prior to December 31,
1991 of $4,909,000 will be limited to approximately $235,000 per year.
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During 1992, the Company acquired 100% of the common stock of an unrelated
corporation. The use of net operating loss carryforwards of the acquired
corporation of $257,000 acquired in the acquisition are limited to approximately
$115,000 per year.
As a result of the issuance of additional shares of common stock for
acquisitions and sales of common stock, an additional ownership change under
Section 382 occurred in October 1993. Accordingly, it is expected that the use
of all U.S. net operating loss carryforwards generated through October 1993
(including those subject to the 1991 and 1992 ownership changes discussed above)
of $8,295,000 will be limited as described above and in the following paragraph.
An ownership change under Section 382 occurred in December 1999, following the
issuance of additional shares, as described in Note 5 to the Consolidated
Financial Statements. It is expected that the annual use of U.S. net operating
loss carryforwards subject to this Section 382 limitation will be limited to
approximately $363,000, subject to the lower limitations described above. Future
changes in ownership may further limit the use of the Company's carryforwards.
The annual Section 382 limitation may be increased during any year, within 5
years of a change in ownership, in which built-in gains that existed on the date
of the change in ownership are recognized.
In addition to the Section 382 limitations, uncertainties exist as to
the future utilization of the operating loss carryforwards under the criteria
set forth under FASB Statement No. 109. Therefore, the Company has established a
valuation allowance of $36,134,000 and $34,736,000 for deferred tax assets at
December 31, 1999 and 2000, respectively.
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, oil and 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, the Company's 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 gas into Mexico may substantially impact
the interstate 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. In the recent past interstate
pipeline companies in the United States generally acted as wholesale merchants
by purchasing natural gas from producers and reselling the gas to local
distribution companies and large end users. Commencing in late 1985, the Federal
Energy Regulatory Commission (the "FERC") issued a series of orders that have
had a major impact on interstate natural gas pipeline operations, services, and
rates, and thus have significantly altered the marketing and price of natural
gas. The FERC's key rule making action, Order No. 636 ("Order 636"), issued in
April 1992, required 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 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 were not
required to remain "merchants" of natural gas, and most of the interstate
pipeline companies have become "transporters only," although many have
affiliated marketers. Order 636 and related FERC orders have resulted in
increased competition within all phases of the natural gas industry. We do not
believe that Order 636 and the related restructuring proceedings affect us any
differently than other natural gas producers and marketers with which we
compete.
Transportation pipeline availability and 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 Order 636 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.
The courts have largely affirmed the significant features of Order No. 636 and
the numerous related orders pertaining to individual pipelines, although some
appeals remain pending and the 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 regulation 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 other important policy
initiatives which could significantly affect the marketing of natural gas in the
United States. Some of the more notable of these regulatory initiatives include:
(1) a series of orders in individual pipeline proceedings articulating a
policy of generally approving the voluntary divestiture of interstate pipeline
owned gathering facilities by interstate pipelines to their affiliates (the
so-called "spin down" of previously regulated gathering facilities to the
pipeline's nonregulated affiliates).
(2) Order No. 497 involving the regulation of pipelines with marketing
affiliates.
(3) various FERC orders adopting rules proposed by the Gas Industry
Standards Board which are designed to further standardize pipeline
transportation tariffs and business practices.
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(4) a notice of proposed rulemaking that, among other things, proposes (a)
to eliminate the cost-based price cap currently imposed on natural gas
transactions of less than one year in duration, (b) to establish mandatory
"transparent" capacity auctions of short-term capacity on a daily basis, and (c)
to permit interstate pipelines to negotiate terms and conditions of service with
individual customers.
(5) issuance of Policy Statements regarding Alternate Rates and Negotiated
Terms and Conditions of Service covering (a)the pricing of long-term pipeline
transportation services by alternative rate mechanism options, including the
pricing of interstate pipeline capacity utilizing market-based rates, incentive
rates, or indexed rates, and (b) investigating of whether FERC should permit
pipelines to negotiate the terms and conditions of service, in addition to rates
of service.
(6) a notice of proposed rulemaking that proposes generic procedures to
expedite the FERC's handling of complaints against interstate pipelines with the
goals of encouraging and supporting consensual resolutions of complaints and
organizing the complaint procedures so that all complaints are handled in a
timely and fair manner.
Several of these initiatives are intended to enhance competition in natural
gas markets, although some, such as "spin downs," 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 those facilities by their new,
unregulated owners. As to all of these FERC initiatives, the ongoing, or, in
some instances, preliminary and evolving nature of these regulatory initiatives
makes it impossible at this time to predict their ultimate impact on our
business. However, we do not believe that these FERC initiatives will affect us
any differently than other natural gas producers and marketers with which we
compete.
Since Order 636, FERC decisions involving onshore facilities have been 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 once 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 these FERC decisions have created the
potential for increasing the cost of shipping our gas on third party gathering
facilities, our shipping activities have not been materially affected by these
decisions.
Commencing in October 1993, the FERC issued a series of rules (Order Nos.
561 and 561-A) establishing an indexing system under which oil pipelines will be
able to change their transportation rates, subject to prescribed ceiling levels.
The indexing system, which allows or may require pipelines to make rate changes
to track changes in the Producer Price Index for Finished Goods, minus one
percent, became effective January 1, 1995. In certain circumstances, these rules
permit oil pipelines to establish rates using traditional cost of service or
other methods of rate making. We do not believe that these rules affect us any
differently than other crude oil producers and marketers with which we compete.
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 oil and 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 in which we own producing crude oil and natural gas
properties have statutory provisions regulating the exploration for and
production of crude oil and natural gas, including 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
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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 these regulations is to limit the 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 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 Order 636. For example, the Texas Railroad Commission
enacted a Natural Gas Transportation Standards and Code of Conduct to provide
regulatory support for the State's more active review of rates, services and
practices associated with the gathering and transportation of 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. 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") has recently issued a final rule to clarify or
severely limit the types of costs that are deductible transportation costs for
purposes of royalty valuation of production sold off the lease. In particular,
MMS will not allow 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 oil produced from federal lands for purposes of
calculating royalties owed to the government. The oil and 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 preference prices, well
productivity, geographical location, field discovery date and the type and
quality of the petroleum product produced.
From time to time the governments of Canada, Alberta and Saskatchewan 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.
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. A
24-month, 8,000 cubic metres exemption is available to production from a well
that has not produced for a 12-month period, if resuming production after
January 31, 1993. 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 also introduced the Third Tier Royalty with a base
rate of 10% and a rate cap of 25% from oil pools discovered after September 30,
1992. The new oil royalty reserved to the Crown has a base rate of 10% and a
rate cap of 30% and for old oil a base rate of 10% and a rate cap of 35%.
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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 exploratory gas wells spudded or deepened after July 1, 1985 and
before June 1, 1988 continues to be eligible for a royalty exemption for a
period of 12 months, or such later time that the value of the exempted royalty
quantity equals a prescribed maximum amount. 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 metre and 35% for prices above CDN $210 per cubic
metre. 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. On December 22, 1997, the Government of Alberta gave notice that they
intended to review the ARTC program, but no amendments have yet been passed into
law. The government of Alberta did pass a law that effective January 1, 2001,
the ARTC would not be available to individuals or trusts and will not otherwise
be available unless the maximum credit is greater than or equal to $10,000 in
the taxation year.
Producers of 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 oil and gas produced from Crown and freehold
lands respectively. The amount payable as a royalty in respect of oil depends on
the vintage of the 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 oil produced in a month and the value of the oil. Oil
produced from newly discovered pools may be exempt from the payment of a royalty
for the first 36 months of production. The royalty payable on natural gas is
determined by a sliding scale based on a reference price which is the greater of
the amount obtained by the producer and at prescribed minimum price. Gas
produced in association with oil has a minimum royalty of 8% while the royalty
in respect of other gas may not be less than 15%.
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 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 oil
and gas industry in general, and thus we are unable to predict the ultimate cost
and effects of future changes in environmental laws and regulations.
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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 oil and 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 oil and 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
oil and 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 therefrom, and are usually causes
of action based on negligence, trespass, nuisance, strict liability and fraud.
United States federal regulations also require certain owners and operators
of facilities that store or otherwise handle oil, such as us, to prepare and
implement spill prevention, control and countermeasure plans and spill response
plans relating to possible discharge of oil into surface waters. The federal Oil
Pollution Act ("OPA") contains numerous requirements relating to prevention of,
reporting of, and response to 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
18
<PAGE>
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 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 have a Corporate Environmental Policy and a detailed Environmental
Management System in place to ensure continued compliance with environmental,
health and safety laws and regulations. We believe that we have obtained and are
in compliance with all material environmental permits, authorizations and
approvals.
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 22, 2001, we had 47 full-time employees in the United States,
including 3 executive officers, 3 non-executive officers, 2 petroleum engineers,
1 geologist, 5 managers, 1 landman , 10 secretarial and clerical personnel and
22 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 22, 2001, Grey Wolf had 42 full-time employees, including 2
executive officers, 2 non-executive officers, 4 petroleum engineers, 3
geologists, 1 geophysicist, 21 technical and clerical personnel and 9 field
personnel.
19
<PAGE>
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,
2000, located in those two regions. We operate 89% of our wells in Texas.
Operations in South Texas are concentrated along the Edwards trend in Live Oak
and Dewitt Counties and in the Frio/Vicksburg trend in San Patricio County. We
own an average 79% working interest in 69 wells with average daily production of
514 net Bbls of crude oil and NGLs and 16,566 net Mcf of natural gas per day for
the year ended December 31, 2000. As of December 31, 2000, we had estimated net
proved reserves in South Texas of 52,881 Mmcfe (75% natural gas) with a PV-10 of
$199.1 million, 79.3% of which was attributable to proved developed reserves.
Our West Texas operations are concentrated along the deep Devonian/Ellenberger
formations and shallow Cherry Canyon sandstones in Ward County, the Spraberry
trend in Midland County and in the Sharon Ridge Clearfork Field in Scurry
County. We own an average 77% working interest in 181 wells with average daily
production of 824 net Bbls of crude oil and NGLs and 5,810 net Mcf of natural
gas per day for the year ended December 31, 2000. As of December 31, 2000, we
had estimated net proved reserves in West Texas of 97,089 Mmcfe (77% natural
gas) with a PV 10 of $350.0 million, 27.6% of which was attributable to proved
developed reserves. During 2000, we drilled a total of 11 new wells (10 net) in
Texas with a 100% success rate.
Western Canada
We own producing properties in western Canada, consisting primarily of
natural gas reserves and interests ranging from 10% to 100% in approximately 200
miles of natural gas gathering systems and 13 natural gas processing plants. As
of December 31, 2000, Canadian Abraxas Petroleum Limited (" Canadian Abraxas")
and Grey Wolf had estimated net proved reserves of 92,991 Mmcfe (82% natural
gas) with a PV-10 of $455.0 million, 95.0% of which was attributable to proved
developed reserves. For the year ended December 31, 2000, the Canadian
properties produced an average of approximately 1,128 net Bbls of crude oil and
NGL's per day and 31,691 net Mcf of natural gas per day. The natural gas
processing plants had aggregate capacity of approximately 316 MMcf of natural
gas per day (120 net MMcf). During 2000, we drilled a total of 16 new wells
(13.39 net) in Canada with a 63% success rate.
Grey Wolf manages the operations of Canadian Abraxas pursuant to a
management agreement between Canadian Abraxas and Grey Wolf. Under the
management agreement, Canadian Abraxas reimburses Grey Wolf for reasonable costs
or expenses attributable to Canadian Abraxas and for administrative expenses
based upon the percentage that Canadian Abraxas' gross revenue bears to the
total gross revenue of Canadian Abraxas and Grey Wolf. In 2000, Canadian Abraxas
paid $2.5 million to Grey Wolf pursuant to this management agreement. Abraxas
and Canadian Abraxas own approximately 49% of the outstanding capital stock of
Grey Wolf. In January 2001, we announced that we were in discussions with Grey
Wolf concerning a stock for stock acquisition of the remaining 51% ownership of
Grey Wolf.
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, 2000:
<TABLE>
<CAPTION>
Developed and Undeveloped Acreage
-----------------------------------------------------------------------
As of December 31, 2000
-----------------------------------------------------------------------
Developed Acreage (1) Undeveloped Acreage (2)
--------------------------------- -----------------------------------
Gross Acres (3) Net Acres (4) Gross Acres (3) Net Acres (4)
--------------- --------------- --------------- ------------------
<S> <C> <C> <C> <C>
Canada 134,175 94,441 953,467 641,416
Texas 33,120 25,720 12,202 11,505
Wyoming 2,560 2,560 64,774 59,772
--------------- --------------- --------------- ------------------
Total 169,855 122,721 1,030,443 712,693
=============== =============== =============== ==================
</TABLE>
20
<PAGE>
- ---------------
(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 oil and 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, 2000:
<TABLE>
<CAPTION>
Productive Wells (1)
---------------------------------------------------------------------
As of December 31, 2000
---------------------------------------------------------------------
State/Country Crude Oil Natural Gas
-------------------------------- ----------------------------------
Gross(2) Net(3) Gross(2) Net(3)
--------------- -------------- --------------- ----------------
<S> <C> <C> <C> <C>
Canada 381.0 42.0 298.0 138.4
Texas 172.0 136.1 78.0 57.7
Wyoming 3.0 3.0 - -
--------------- -------------- --------------- ----------------
Total 556.0 181.1 376.0 196.1
=============== ============== =============== ================
</TABLE>
- -----------
(1) Productive wells are producing wells and wells capable of production.
(2) A gross well is a well in which we own an interest. The number of gross
wells is the total number of wells in which we own an interest.
(3) A net well is deemed to exist when the sum of fractional ownership working
interests in gross wells equals one. The number of net wells is the sum of
our fractional working interest owned in gross wells.
Substantially all of our existing crude oil and natural gas properties are
pledged to secure our indebtedness under the First Lien Notes and Second Lien
Notes. You should read the discussion under the heading "Management's Discussion
of Financial Condition and Results of Operations--Liquidity and Capital
Resources" for more information regarding our indebtedness.
Reserves Information
The crude oil and natural gas reserves of Abraxas have been estimated as of
January 1, 2001, January 1, 2000, and January 1, 1999, by DeGolyer and
MacNaughton, of Dallas, Texas. The reserves of Canadian Abraxas and Grey Wolf as
of January 1, 2001, January 1, 2000 and January 1, 1999 have been estimated by
McDaniel and Associates Consultants Ltd. of Calgary, Alberta. Crude oil and
natural gas reserves, and the estimates of the present value of future net
revenues therefrom, 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 therefrom. Such estimates are not precise and are based on assumptions
regarding a variety of factors, many of which are variable and uncertain.
The following table sets forth certain information regarding estimates of
our crude oil, natural gas liquids and natural gas reserves as of January 1,
2001, January 1, 2000 and January 1, 1999:
21
<PAGE>
<TABLE>
<CAPTION>
Estimated Proved Reserves
----------------------------------------------------------
Proved Proved Total
Developed Undeveloped Proved
-------------- --------------- ------------------
As of January 1, 1999(1) (2) (3)
<S> <C> <C> <C>
Crude oil (MBbls) 3,985 1,628 5,613
NGLs (MBbls) 1,834 248 2,082
Natural gas (MMcf) 144,588 52,890 197,478
As of January 1, 2000(1) (2) (3)(4)
Crude oil (MBbls) 5,513 1,606 7,119
NGLs (MBbls) 4,961 562 5,523
Natural gas (MMcf) 154,221 35,894 190,115
As of January 1, 2001(1) (2) (3)
Crude oil (MBbls) 3,866 1,406 5,272
NGLs (MBbls) 3,135 436 3,571
Natural gas (MMcf) 119,737 71,590 191,327
</TABLE>
- ------------------
(1) Includes 31,900, 33,000 and 40,000 barrels of crude oil reserves owned
by Grey Wolf of which 16,400, 16,900 and 20,525 barrels are applicable
to the minority interests share of these reserves as of January 1,
1999, 2000 and 2001, respectively.
(2) Includes 443,500, 236,000 and 692,000 barrels of natural gas liquids
reserves owned by Grey Wolf of which 227,600, 121,098 and 355,083
barrels are applicable to the minority interests share of these
reserves as of January 1, 1999, 2000 and 2001, respectively.
(3) Includes 28,610, 21,710 and 21,389 Mmcf of natural gas reserves owned
by Grey Wolf of which 14,700, 11,140 and 10,975 Mmcf are applicable to
the minority interests share of these reserves as of January 1, 1999,
2000 and 2001, respectively.
(4) Includes 343,941 Bbls of crude oil reserves; 2,448.6 Mbbls of natural
gas liquids reserves and 25,810 Mmcf of natural gas reserves,
attributable to the Wyoming properties which were sold in March 2000.
These reserves were estimated internally.
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. 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.
22
<PAGE>
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, 2000. The average sales prices as of such date used for
purposes of such estimates were $25.73 per Bbl of crude oil, $30.63 per Bbl of
NGLs and $9.21 per Mcf of natural gas. It is also assumed that we will make
future capital expenditures of approximately $55.5 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:
<TABLE>
<CAPTION>
2000 1999 1998
------------------ ------------------ ------------------
<S> <C> <C> <C>
Crude oil production (Bbls) 636,734 777,855 728,560
Natural gas production (Mcf) 19,962,470 25,697,899 24,929,866
Natural gas liquids production
(Bbls) 314,897 376,474 867,443
Mmcfe 25,672 32,623 34,506
Average sales price per Bbl of
crude oil $ 18.69 $ 14.57 $13.65
Average sales price per MCF of
natural gas (1) $ 2.71 $ 1.66 $ 1.54
Average sales price per Bbl of
natural gas liquids (1) $ 22.42 $ 13.40 $ 6.81
Average sales price per Mcfe (1) $ 2.84 $ 1.81 $ 1.57
Average cost of production per
BOE produced (2) $ 4.39 $ 3.30 $ 2.93
</TABLE>
(1) Average sales prices are net of hedging activity.
(2) Oil and gas were combined by converting gas to a barrel oil equivalent
("BOE") on the basis of 6 Mcf gas =1 Bbl of oil. Production costs include
direct operating costs, ad valorem taxes and gross production taxes.
Drilling Activities
The following table sets forth our gross and net working interests in
exploratory, development, and service wells drilled during the three years ended
December 31:
<TABLE>
<CAPTION>
2000 1999 1998
----------------------------- ---------------------------- ------------------------------
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
------------ ---------- ------------ --------- ----------- --------
<S> <C> <C> <C> <C> <C> <C>
Exploratory(3)
Productive(4)
Crude oil - - 2.0 2.0 1.0 1.0
Natural gas 3.0 2.5 8.0 5.3 7.0 5.6
Dry holes(5) 9.0 5.6 11.0 6.2 9.0 7.3
------------ ---------- ------------ --------- ----------- --------
Total 12.0 8.1 21.0 13.5 17.0 13.9
============ ========== ============ ========= =========== ========
23
<PAGE>
Development(6)
Productive
Crude oil 9.0 9.0 8.0 1.6 3.0 2.4
Natural gas 16.0 12.2 20.0 13.1 30.0 23.9
Service(7) - - - - 1.0 1.0
Dry holes 3.0 3.0 9.0 4.5 3.0 2.2
------------ ---------- ------------ --------- ----------- --------
Total 28.0 24.2 37.0 19.2 37.0 29.5
- ------------------------ ============ ----- ========== ---- ============ ----- ========= ---- =========== ---- ========
</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.
(7) A service well is used for water injection in secondary recovery projects or
for the disposal of produced water.
As of March 15, 2001, we had 3 wells in process of drilling.
Office Facilities
Our executive and administrative offices are located at 500 North Loop 1604
East, Suite 100, San Antonio, Texas 78232. We also have an office in Midland,
Texas. These offices, consisting of approximately 12,650 square feet in San
Antonio and 570 square feet in Midland, are leased until March 2005 at an
aggregate base rate of $19,500 per month.
Grey Wolf leases 17,522 square feet of office space in Calgary, Alberta
pursuant to a lease which expires on April 30, 2003.
Other Properties
We own 10 acres of land, an office building, workshop, warehouse and house
in Sinton, Texas, 160 acres of land in Coke County, Texas and a 50% interest in
approximately two acres of land in Bexar County, Texas. All three properties are
used for the storage of tubulars and production equipment. We also own 19
vehicles which are used in the field by employees. We own 2 workover rigs, which
are used for servicing our wells as well as third party wells.
24
<PAGE>
Item 3. Legal Proceedings
General. From time to time, we are involved in litigation relating to claims
arising out of our operations in the normal course of business. We are not
currently engaged in any legal proceedings that are expected, individually or in
the aggregate, to have a material adverse effect on us.
In 1995, certain plaintiffs filed a lawsuit against us alleging negligence
and gross negligence, tortious interference with contract, conversion and waste
We fully and finally resolved the litigation on April 25, 2000, through a
payment of $435,780 in the aggregate to the plaintiffs.
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, 2000.
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 2001 annual meeting of
shareholders and until his successor is duly elected and qualified.
Robert L. G. Watson, age 50, 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 49, 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
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 39, 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.
25
<PAGE>
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.
- -----------------------------------------------------------------------------
Market Information
Our common stock began trading on the American Stock Exchange on August 18,
2000, under the symbol "ABP." Our common stock was formerly listed on the NASDAQ
Stock Market under the symbol "AXAS"; however, effective June 16, 1999, our
common stock was delisted from general quotation on the NASDAQ Stock Market for
failure to satisfy NASDAQ's listing and maintenance standards. During the period
between June 16, 1999 and August 17, 2000, our stock traded on the OTC Bulletin
Board under the symbol "AXAS".
The following table sets forth certain information as to the high and low
bid quotations quoted on NASDAQ for 1998 and 1999 (through June 16, 1999), on
the OTC Bulletin Board for the remainder of 1999 and through August 17, 2000,
and the high low sales price on the American Stock Exchange for the remainder of
2000. Information with respect to over-the-counter bid quotations represents
prices between dealers, does not include retail mark-ups, mark-downs, or
commissions, and may not necessarily represent actual transactions.
Period High Low
1998
First Quarter...............................$15.00 $7.00
Second Quarter...............................11.25 8.25
Third Quarter.................................9.50 5.31
Fourth Quarter................................7.56 4.00
1999
First Quarter................................$3.19 $1.19
Second Quarter................................2.82 0.88
Third Quarter................................ 2.97 0.88
Fourth Quarter............................... 2.44 0.81
2000
First Quarter...............................$ 2.81 $1.06
Second Quarter............................... 2.38 1.34
Third Quarter (OTC through August 17)........ 2.75 1.38
Third Quarter (AMEX from August 17).......... 4.00 2.75
Fourth Quarter.............................. 4.56 2.81
Holders
As of March 22, 2001 we had 22,593,969 shares of common stock outstanding
and had approximately 1,542 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 indentures governing the First Lien and Second Lien Notes
prohibit 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.
26
<PAGE>
Item 6. Selected Financial Data
The following selected financial data are 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."
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------------------------
2000 1999 1998 1997 1996
------------ ------------ ------------ ------------- ----------
(Dollars in thousands except per share data)
<S> <C> <C> <C> <C> <C>
Total revenue .............................. $ 76,600 $ 66,770 $ 60,084 $ 70,931(1) $ 26,653
Income (loss) before extraordinary item .... $ 6,676 $ (36,680) $ (83,960)(2)$ (6,485) $ 1,940
Income (loss) before extraordinary item per
common share - diluted................... $ 0.21(3) $ (5.41) $ (13.26) $ (1.11) $ 0.23
Weighted average shares outstanding - basic 22,616 6,784 6,331 6,025 6,794
Total assets ............................... $ 335,560 $ 322,284 $ 291,498 $ 338,528 $ 304,842
Long-term debt, excluding current maturities $ 266,441 $ 273,421 $ 299,698 $ 248,617 $ 215,032
Total stockholders' equity (deficit) ....... $ (6,503) $ (9,505) $ (63,522) $ 26,813 $ 35,656
</TABLE>
(1) Increase due to acquisition of Canadian Abraxas and the Wyoming properties.
(2) Increase due to ceiling write down.
(3) Increase due to sale of partnership interest.
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."
General
We have incurred net losses in three of the last four years and there can be
no assurance that operating income and net earnings will be achieved in future
periods. Our revenues, profitability and future rate of growth are substantially
dependent upon prevailing prices for crude oil and natural gas and the volumes
of crude oil, natural gas and natural gas liquids we produce. Natural gas and
crude oil prices weakened somewhat during 1997 and continued to decrease during
1998. Crude oil and natural gas prices increased somewhat in 1999 and increased
substantially in 2000. In addition, because our proved reserves will decline as
crude oil, natural gas and natural gas liquids are produced, unless we are
successful in acquiring 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, exploration and development projects. If crude oil
and natural gas prices revert to depressed levels, or if our production levels
decrease, our revenues, cash flow from operations and financial condition will
be materially adversely affected.
Results of Operations
The factors which most significantly affect our results of operations are:
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,
o the level of and interest rates on borrowings, and
o the level and success of exploration and development activity.
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Selected Operating Data. The following table sets forth certain of our
operating data for the periods presented:
Years Ended December 31,
-------------------------------
(dollars in thousands,
except per unit data)
2000 1999 1998
-------- -------- --------
Operating revenue:
Crude oil sales ....................... $ 11,899 $ 11,330 $ 9,948
NGLs sales ............................ 7,061 5,043 5,905
Natural gas sales ..................... 54,013 42,652 38,410
Gas processing revenue ................ 2,717 4,244 3,159
Other ................................. 910 3,501 2,662
-------- -------- --------
Total operating revenue .................. $ 76,600 $ 66,770 $ 60,084
======== ======== ========
Operating income (loss) .................. $ 11,583 $(10,972) $(56,500)
Crude oil production (MBbls) ............. 636.7 777.9 728.6
NGLs production (MBbls) .................. 314.9 376.5 867.4
Natural gas production (MMcf) ............ 19,962.5 25,697.9 24,929.9
Average crude oil sales price (per Bbl)* . $ 18.69 $ 14.57 $ 13.65
Average NGLs sales price (per Bbl)* ...... $ 22.42 $ 13.40 $ 6.81
Average natural gas sales price (per Mcf)* $ 2.71 $ 1.66 $ 1.54
*Revenue and average sales prices are net of hedging activities.
Comparison of Year Ended December 31, 2000 to Year Ended December 31, 1999
Operating Revenue. During the year ended December 31, 2000, operating
revenue from crude oil, natural gas and natural gas liquids sales increased by
$14.0 million from $59.0 million in 1999 to $73.0 million in 2000. This increase
was primarily attributable to an increase in commodity prices. Increased prices
contributed $26.5 million in additional revenue, which was offset by $12.5
million due to a decrease in production volumes. The decline in production was
due to the disposition of certain non-core properties, primarily in Canada.
Natural gas liquids volumes declined from 376.5 MBbls in 1999 to 314.9 in
2000. Crude oil sales volumes declined from 777.9 MBbls in 1999 to 636.7 MBbls
during 2000. Natural gas sales volumes decreased from 25.7 Bcf in 1999 to 20.0
Bcf in 2000. Production declines were primarily attributable to our disposition
of non-core assets during 2000.
Average sales prices in 2000 net of hedging losses were:
o $18.69 per Bbl of crude oil,
o $22.42 per Bbl of natural gas liquids, and
o $2.71 per Mcf of natural gas.
Average sales prices in 1999 net of hedging losses were:
o $14.57 per Bbl of crude oil,
o $13.40 per Bbl of natural gas liquids, and
o $1.66 per Mcf of natural gas.
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We also had natural gas processing revenue of $2.7 million in 2000 as compared
to $4.2 million in 1999. The decline in processing revenue is due to a decrease
in third party natural gas being processed. We are utilizing more of the plant
capacity to process our own natural gas, leaving less capacity for third party
processing.
Lease Operating Expense. Lease operating expense ("LOE") and natural gas
processing costs increased by $0.8 million from $17.9 million for the year ended
December 31, 1999 to $18.8 million for the same period of 2000. LOE on a per
Mcfe basis for 2000 was $0.73 per Mcfe as compared to $0.55 per Mcfe in 1999.
The increase was due primarily to a general increase in the cost of services and
increased production taxes due to higher commodity prices in 2000 as compared to
1999. The increase in the per Mcfe cost is due to a decline in production
volumes.
G&A Expense. General and administrative ("G&A") expense increased from $5.3
million for the year ended December 31, 1999 to $6.9 million for the year ended
December 31, 2000. The increase in G&A was due to the loss of approximately
$600,000 of overhead billed to a partnership, substantially all of the assets of
which were sold in March 2000 and an increase in director compensation as a
result of our restructuring in the fourth quarter of 1999. Our G&A expense on a
per Mcfe basis increased from $0.16 in 1999 to $0.27 in 2000. The increase in
the per Mcfe cost was due partly to lower production volumes in 2000 as compared
to 1999.
G&A - Stock-based Compensation Expense. Effective July 1, 2000, the
Financial Accounting Standards Board ("FASB") issued FIN 44, "Accounting for
Certain Transactions Involving Stock Compensation", an interpretation of
Accounting Principles Board Opinion No. ("APB") 25. Under the interpretation,
certain modifications to fixed stock option awards which were made subsequent to
December 15, 1998, and not exercised prior to July 1, 2000, require that the
awards be accounted for as variable until they are exercised, forfeited, or
expired. In March 1999, we amended the exercise price to $2.06 on all options
with an existing exercise price greater than $2.06. We recognized approximately
$2.8 million as stock-based compensation expense during 2000 related to these
repricings.
DD&A Expense. Depreciation, depletion and amortization ("DD&A") expense
increased by $1.1 million from $34.8 million for the year ended December 31,
1999 to $35.9 million for the year ended December 31, 2000. Our DD&A expense on
a per Mcfe basis for 1999 was $1.07 per Mcfe as compared to $1.40 per Mcfe in
2000. The increase in DD&A is the result of higher finding costs in the later
part of 1999 and 2000.
Interest Expense. Interest expense decreased by $5.9 million from $37.0
million to $31.1 million for the year ended December 31, 2000 compared to 1999.
This decrease resulted from reduced debt levels during 2000 compared to 1999.
The reduced debt level was the result of the exchange of approximately $269.7
million principal amount of our Old Notes for approximately $188.8 million
principal of our Second Lien Notes, shares of our common stock and contingent
value rights.
Ceiling Limitation Writedown. We record the carrying value of our crude oil
and natural gas properties using the full cost method of accounting for oil and
gas properties. Under this method, we capitalize the cost to acquire, explore
for and develop oil and gas properties. Under the full cost accounting rules,
the net capitalized cost of crude oil and natural gas properties less related
deferred taxes, is limited by country, to the lower of the unamortized cost or
the cost ceiling, defined as the sum of the present value of estimated
unescalated future net revenues from proved reserves, discounted at 10%, plus
the cost of properties not being amortized, if any, plus the lower of cost or
estimated fair value of unproved properties included in the costs being
amortized, if any, less related income taxes. If the net capitalized cost of
crude oil and natural gas properties exceeds the ceiling limit, we are subject
to a ceiling limitation writedown to the extent of such excess. A ceiling
limitation writedown is a charge to earnings which does not impact cash flow
from operating activities. However, such writedowns do impact the amount of our
stockholders' equity.
The risk that we will be required to writedown the carrying value of our oil
and gas assets increases when oil and gas prices are depressed or volatile. In
addition, writedowns may occur if we have substantial downward revisions in our
estimated proved reserves or if purchasers or governmental action cause an
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abrogation of, or if we voluntarily cancel, long-term contracts for our natural
gas. For the year ended December 31, 1999, we recorded a writedown of $19.1
million, $11.9 million after tax, related to our Canadian properties. We cannot
assure you that we will not experience additional writedowns in the future.
Should commodity prices decline, a further writedown of the carrying value of
our crude oil and natural gas properties may be required. See Note 17 of Notes
to Consolidated Financial Statements.
Minority intere