Back to GetFilings.com
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, 2001
[ ]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
Commission File Number 0-19118
ABRAXAS PETROLEUM CORPORATION
------------------------------
(Exact name of Registrant as specified in its charter)
Nevada 74-2584033
- --------------------------------------------------------------------------------
(State or Other Jurisdiction of (I.R.S. Employer Identification Number)
Incorporation or Organization)
500 N. Loop 1604 East, Suite 100
San Antonio, Texas 78232
(Address of principal executive offices)
Registrant's telephone number,
including area code (210) 490-4788
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Common Stock, par value $.01 per share
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No__
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
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, 2002, based upon the closing per share price of $1.44, was approximately
$39,005,914 on such date.
The number of shares of the issuer's common stock, par value $.01 per
share, outstanding as of March 22, 2002 was 29,979,397 shares of which
27,087,440 shares were held by non-affiliates.
Documents Incorporated by Reference: Portions of the registrant's Proxy
Statement relating to the 2002 Annual Meeting of Shareholders to be held on May
24, 2002 have been incorporated by reference herein (Part III).
ABRAXAS PETROLEUM CORPORATION
FORM 10-K
TABLE OF CONTENTS
PART I
Page
Item 1. Business. .....................................................................................4
General.......................................................................................4
Recent Events.................................................................................5
Business Strategy ............................................................................6
Markets and Customers.........................................................................7
Risk Factors..................................................................................8
Regulation of Crude Oil and Natural Gas Activities...........................................19
Canadian Royalty Matters.....................................................................22
Environmental Matters ......................................................................23
Title to properties..........................................................................25
Employees....................................................................................25
Item 2. Properties....................................................................................25
Primary Operating Areas......................................................................25
Exploratory and Developmental Acreage........................................................26
Productive Wells.............................................................................26
Reserves Information.........................................................................27
Crude Oil, Natural Gas Liquids and Natural Gas Production and Sales Price ...................23
Drilling Activities..........................................................................29
Office Facilities............................................................................30
Other Properties.............................................................................30
Item 3. Legal Proceedings.............................................................................30
Item 4. Submission of Matters to a Vote of Security Holders...........................................31
Item 4a.Executive Officers of Abraxas..................................................................31
PART II
Item 5. Market for Registrant's Common Equity
and Related Stockholder Matters............................................................32
Market Information...........................................................................32
Holders......................................................................................32
Dividends....................................................................................32
Item 6. Selected Financial Data.......................................................................33
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations................................................33
General......................................................................................33
Results of Operations........................................................................33
Liquidity and Capital Resources..............................................................39
Critical Accounting Policies................................................................49
New Accounting Pronouncements...............................................................50
Item 7a. Quantitative and Qualitative Disclosures about Market Risk....................................50
Item 8. Financial Statements and Supplementary Data...................................................51
2
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure......................................................52
PART III
Item 10. Directors and Executive Officers of the Registrant .........................................52
Item 11. Executive Compensation.......................................................................52
Item 12. Security Ownership of Certain Beneficial Owners and Management...............................52
Item 13. Certain Relationships and Related Transactions...............................................52
PART IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K...................................................................52
SIGNATURES..................................................................................57
3
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 ("Abraxas" or the "Company") 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.
Since December 31, 2001 an improving price environment related to crude oil
and natural gas, recent drilling success of the Company and anticipated property
sales, all discussed below as "Recent Events", are important factors in
evaluation of the Company's prospects going forward.
Our principal areas of operation are Texas and western Canada. At December
31, 2001, we owned interests in 937,149 gross acres (636,516 net acres) and
operated properties accounting for 76% of our PV-10, affording us substantial
control over the timing and incurrence of operating and capital expenditures. At
December 31, 2001, estimated total proved reserves of Abraxas (U.S. operations)
and our wholly-owned subsidiaries, Canadian Abraxas Petroleum Limited ("Canadian
Abraxas") and Grey Wolf Exploration, Inc. ("Grey Wolf") were 229.6 Bcfe with an
aggregate PV-10 of $209.7 million. As of December 31, 2001, we had net natural
gas processing capacity of 107 MMcf per day through our various ownership
interests in 12 natural gas processing plants and compression facilities in
Canada, giving us substantial control over our Canadian production and marketing
activities.
PV-10 means estimated future net revenue discounted at a rate of 10% per
annum, before income taxes and with no price or cost escalation or de-escalation
in accordance with guidelines promulgated by the Securities and Exchange
Commission. A Mcf is one thousand cubic feet of natural gas. MMcf is used to
designate one million cubic feet of natural gas and Bcf refers to one billion
cubic feet of natural gas. Mcfe means thousands of cubic feet of natural gas
equivalents, using a conversion ratio of one barrel of crude oil to six Mcf of
natural gas. MMcfe means millions of cubic feet of natural gas equivalents and
Bcfe means billions of cubic feet of natural gas equivalents. Mmbtu means
million British Thermal Units. The term Bbl means one barrel of crude oil and
MBbls is used to designate one thousand barrels of crude oil or natural gas
liquids.
4
In accordance with the Securities and Exchange Commission requirements, the
estimated discounted future net cash flows from proved reserves are generally
based on prices and costs as of the end of the year, or alternatively, if prices
subsequent to that date have increased, a price near the periodic filing date of
the Company's financial statements. As of December 31, 2001, the Company's net
capitalized costs of crude oil and natural gas properties exceeded the present
value of its estimated proved reserves by $71.3 million ($38.9 million on the
U.S. properties and $32.4 million on the Canadian properties). These amounts
were calculated considering 2001 year-end prices of $19.84 per Bbl for crude oil
and $2.57 per Mcf for natural gas as adjusted to reflect the expected realized
prices for each of the full cost pools. The Company did not adjust its
capitalized costs for its U.S. properties because subsequent to December 31,
2001, crude oil and natural gas prices increased such that capitalized costs for
its U.S. properties did not exceed the present value of the estimated proved
crude oil and natural gas reserves for its U.S. properties as determined using
increased realized prices on March 22, 2002 of $24.16 per Bbl for crude oil and
$2.89 per Mcf for natural gas. The Company also used the subsequent prices to
evaluate its Canadian properties, and reduced the 2001 year-end write-down to an
amount of $2.6 million on those properties.
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.
We currently have significant interest payments due in 2002 of $30.2 million
and principal obligations payable in 2003 ($63.5 million) and 2004 ($191.0
million). Our debt service requirements may restrict our ability to fund capital
expenditures necessary to maximize the value of our assets. The debt levels also
restrict our ability to borrow additional amounts to fund asset growth or to
provide financial flexibility. Additionally, our ability to meet our debt
obligations and to reduce our level of debt depends on our future performance
and crude oil and natural gas production and commodity prices. General economic
conditions and financial, business and other factors affect our operations and
our future performance. Many of these factors are beyond our control. If we are
unable to make interest payments on our debt or to repay our debt at maturity
out of cash on hand, we could attempt to refinance such debt, or repay such debt
with the proceeds of the sale of certain producing properties or an equity
offering. The use of the sale proceeds from a property sale are substantially
limited by the terms of the indentures governing our indebtedness. Factors that
will affect our ability to raise cash through an offering of our capital stock
or a refinancing of our debt include financial market conditions and our value
and performance at the time of such offering or other financing. We cannot
assure you that any property sale, offering or refinancing can be successfully
completed.
Recent Events
Potential Property Sales
Our wholly owned Canadian subsidiaries, Grey Wolf and Canadian Abraxas, have
entered into a definitive Purchase and Sale Agreement related to the sale of
their interest in a natural gas plant and the associated reserves. The sale,
effective March 1, 2002, is scheduled to close in the second quarter of 2002
with estimated net proceeds of US $21.5 million.
We have also recently engaged Randall & Dewey, Inc. to explore a potential
sale of certain properties located in Texas. The data room was opened in March
of 2002, with bids due in the second quarter of 2002. There are no definitive
agreements related to any potential sale and we cannot assure you that any sale
will occur or, if it does, the sale price that we would receive.
If all of the potential sales are ultimately closed, we anticipate
aggregate proceeds in the range of $50 million to $100 million.
5
Lady Fern Drilling
Our wholly-owned Canadian subsidiary, Grey Wolf has drilled four wells of a
six well program in the Lady Fern area of Northeast British Columbia during this
winter drilling season. Two of the wells in which we own a 16.66% interest in
each well have indicated some success and are being completed and production
tested. Two wells were dry holes. The final two wells of the program are
currently drilling.
Improved Commodity Prices
Since December 31, 2001, commodity prices have improved significantly. As a
point of reference, on March 22, 2002, the NYMEX natural gas price was $3.43 per
Mcf, and the NYMEX crude oil price was $25.35 per Bbl as compared to December
31, 2001 natural gas price of $2.57 per Mcf and crude oil price of $19.84 per
Bbl. The improvement in prices since December 31, 2001, has limited our
potential impairment write down of crude oil and natural gas properties at year
end 2001 and if such prices are sustained, should improve our liquidity and cash
flows. For a more detailed description of commodity prices, you should read the
discussion under "Management's Discussion and Analysis of Financial Condition
and Results of Operations - Results of Operations."
Business Strategy
Our primary business objectives are to increase reserves, production
and cash flow through the following:
o Improved Liquidity. In recent years, 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 We are continuing to rationalize our Canadian assets to allow us to
continue to grow while reducing our debt. Our wholly owned Canadian
subsidiaries, Canadian Abraxas and Grey Wolf have entered into a
definitive Purchase and Sale Agreement related to the sale of their
interest in a natural gas plant and the associated reserves. The sale,
effective March 1, 2002, is scheduled to close in the second quarter of
2002 with estimated net proceeds of US $21.5 million. We may sell
additional assets or seek partners to fund a portion of the exploration
costs of undeveloped acreage, and we are considering other potential
strategic alternatives. We have recently engaged Randall & Dewey to
explore a potential sale of certain of our properties located in Texas.
There are no definitive agreements related to any potential sale and we
cannot assure you that any sale will occur or, if it does, the sale
price that we would receive. If all of the potential sales are
ultimately closed, we anticipate proceeds in the range of $50 million
to $100 million. See "Recent Events".
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 South Texas to a
unit of Southern Energy, Inc. which is now known as Mirant Americas
Energy Capital, L.P. and in 2000 and 2001, we sold additional
production payments for $6.4 million and $11.7 million, respectively,
relating to additional natural gas wells in South Texas to Mirant
Americas. We have the ability to sell up to $50 million of production
payments to Mirant Americas for drilling opportunities in South Texas .
o In December 1999, Abraxas and Canadian Abraxas, completed an Exchange
Offer whereby we exchanged our new 11.5% Senior Secured Notes due 2004,
(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 In March 2000, we sold our interest in certain crude oil and natural
gas properties that we owned and operated in Wyoming. Simultaneously, a
6
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 During 2001, we sold assets in the United States and Canada. Our net
proceeds from these transactions were approximately $29 million. These
proceeds were used to invest in additional producing properties through
drilling activities.
o In December 2001, Grey Wolf entered into a financing agreement with
Mirant Canada Energy Capital, Ltd. for CDN $150 million (approximately
US $96 million) (the "Grey Wolf Facility"), which is non-recourse to
Abraxas. Initial borrowings from this facility of approximately US $25
million were used to retire Grey Wolf's existing bank facility and for
general corporate purposes. Up to US $71 million is available to
finance drilling of wells and related activities under this credit
facility.
o Low Cost Operations. We seek to maintain low lease 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. As
cash flow permits, our capital expenditure budget for 2002 for existing
operations and leaseholds is approximately $37 million.
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.
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. You should read the discussion
under "Risk Factors - Crude oil and natural gas prices and their volatility
could adversely our revenues, cash flows and profitability." and "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Critical Accounting Policies" for more information relating to the effects on us
of decreases in crude oil and natural gas prices.
In order to manage our exposure to price risks in the marketing of our crude
oil and natural gas, from time to time we have entered into fixed price delivery
contracts, financial swaps and crude oil and natural gas futures contracts as
7
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, 2001, three purchasers accounted for approximately 41%
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 more 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
We lack financial liquidity due to our reduced cash flow. We have
historically funded our operations and capital expenditures primarily through
cash flow from operations, sales of properties and sales of production payments
to Mirant Americas and other credit sources. We anticipate that we will have
four principal sources of liquidity during the next 12 months: (i) cash on hand,
(ii) cash generated by operations, (iii) sales of production payments to Mirant
Americas, and (iv) sales of properties. In addition, Grey Wolf has additional
borrowing capacity under its credit facility with Mirant Canada to fund Grey
Wolf's drilling activities.
Our cash flow from operations has been severely impacted by depressed
commodity prices since the third quarter of 2001. While commodity prices have
recently increased, we cannot assure you that these price levels can be
sustained. The reduced cash flow from operations has also reduced the overall
volume of crude oil and natural gas that we can produce economically and
increased our dependence on external sources of capital to fund our operations
and capital expenditures. In addition, we have been unable to replace the
production represented by the properties that we have sold with new production
from the producing properties we drilled with the proceeds of our property
sales.
Our ability to raise funds through additional indebtedness will be
substantially limited by the terms of the indentures governing our outstanding
First Lien Notes and Second Lien Notes. We may also choose to issue equity
securities or sell certain of our properties to fund our operations and capital
expenditures, although the indentures substantially limit our use of the
proceeds of any such asset sales. You should read the discussions under the
headings "Our debt levels and our debt covenants may limit our ability to pursue
business opportunities and to obtain additional financing," "We may issue shares
of our preferred stock with greater rights than our common stock," "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 for more information regarding our lack of
liquidity.
Our substantial losses have put significant strain on our liquidity and
cash position. At December 31, 2001, we had cash of $7.6 million. We are
currently managing our cash position through the reduction of our 2002 capital
expenditures budget and other cost reduction efforts. However, while these
measures will help conserve our cash resources in the near term, they will also
limit our ability to replenish our depleting reserves, which could negatively
impact our cash flow from operations and results of operations in the future.
For more information, you should read "Our ability to replace production with
new reserves is highly dependent on acquisitions or successful development and
exploration activities." In addition, we are actively seeking potential
transactions for the sale of producing properties in order to increase our
liquidity. Our failure to achieve revenue goals or the disposition of producing
8
properties on favorable terms during 2002 and beyond will have a significant
adverse impact on the liquidity of the Company, and could possibly result in
insolvency.
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 $285.6 million and $28.5 million, respectively, as of December 31,
2001. 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
indentures. 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 and is not available for other purposes including developing our
producing properties;
o The covenants contained in the First Lien Notes indenture and the Second
Lien Notes indenture 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 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. If we are unable to generate cash flow from operations to
service the First Lien Notes, the Second Lien Notes and the Old Notes, we may be
required to refinance all or a portion of our debt or obtain additional
financing. Our ability to refinance all or a portion of our debt or to obtain
additional financing is substantially limited by the terms of the indentures.
Factors that will affect our ability to raise cash in a financing include our
financial condition and our value and performance at the time of any offering or
other financing. We also continue to explore the sale of properties; however,
the indentures substantially limit our ability to use the proceeds of any such
sale. We cannot assure you that we will be successful in any refinancing,
offering or property sale.
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 and capital expenditures primarily through cash flow from
operations, sales of properties, sales of production payments to Mirant Americas
and borrowings under our bank credit facilities and other sources. In 2001, we
met our liquidity needs through cash flow from operations, the sale of
additional properties and further installments on the production payment with
Mirant Americas. We are examining certain alternative sources of long term
capital including:
o refinancing or recapitalizing our current indebtedness;
o selling equity securities; and
o selling additional properties.
9
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. Further, our cash flow
from operations could be negatively affected by our limited ability, due to our
limited liquidity, to acquire producing properties, to undertake exploration and
development projects and to otherwise replenish our depleting reserves.
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;
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 a large portion 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 substantial restrictions on the use of
proceeds from asset sales.
While there can be no assurances, we believe that our improved cash flow
from operations due to successful development activities, the sale of properties
and additional installments on the production payment with Mirant Americas 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.
The collateral securing the First Lien Notes and the Second Lien Notes may
not be adequate. The First Lien Notes and the related guarantees are secured by
a first lien or charge on substantially all of the crude oil and natural gas
properties and natural gas processing facilities of Abraxas and the guarantors,
Canadian Abraxas, Sandia Oil and Gas Corp. ("Sandia") and Wamsutter Holdings,
Inc. ("Wamsutter"), as well as the shares of Grey Wolf common stock owned by
Abraxas and Canadian Abraxas (collectively, the "Collateral"), including crude
oil and natural gas properties with a PV-10 of $158.3 million at December 31,
2001. The Second Lien Notes and the related guarantees are secured by a second
lien or charge on the Collateral. The crude oil and natural gas properties of
Grey Wolf, which had a PV-10 of $51.4 million at December 31, 2001, are not
collateral for the First Lien Notes or the Second Lien Notes. These properties
secure Grey Wolf's obligations under the Grey Wolf Facility. The reserve data
with respect to such interests, however, represent estimates only and should not
be construed as exact. Moreover, the PV-10 estimates should not be construed as
the current market value of the estimated proved reserves attributable to our
properties. You should read the discussions under the heading "Estimates of
Proved Reserves and Future Net Revenue Are Uncertain and Inherently Imprecise"
and "Properties -- Reserves Information" for more information regarding our
reserves. We cannot assure you that if an event of default occurs that the
liquidation of the Collateral would produce proceeds sufficient to pay all of
our obligations under the First Lien Notes and the Second Lien Notes.
Fraudulent conveyance laws could allow a court to void the guarantees.
Abraxas' subsidiaries Canadian Abraxas, Wamsutter and Sandia are guarantors
under the First Lien Notes, and Canadian Abraxas is jointly and severally liable
with Abraxas and Wamsutter and Sandia are guarantors under the Second Lien
Notes. Under the federal bankruptcy law and comparable provisions of state
fraudulent transfer laws, a guarantee could be voided, or claims in respect of a
10
guarantee could be subordinated to all other debts of that guarantor if, among
other things, the guarantor, at the time it incurred the indebtedness evidenced
by its guarantee:
o received less than reasonably equivalent value or fair consideration
for the incurrence of such guarantee; and
o was insolvent or rendered insolvent by reason of such incurrence; or
o was engaged in a business or transaction for which the guarantor's
remaining assets constituted unreasonably small capital; or
o intended to incur, or believed that it would incur, debts beyond its
ability to pay such debts as they mature.
In addition, any payment by that guarantor pursuant to its guarantee could be
voided and required to be returned to the guarantor, or to a fund for the
benefit of the creditors of the guarantor.
The measures of insolvency for purposes of these fraudulent transfer laws
will vary depending upon the law applied in any proceeding to determine whether
a fraudulent transfer has occurred. Generally, however, a guarantor would be
considered insolvent if:
o the sum of its debts, including contingent liabilities, were greater
than the fair saleable value of all of its assets, or
o if the present fair saleable value of its assets were less than the
amount that would be required to pay its probable liability on its
existing debts, including contingent liabilities, as they become
absolute and mature, or
o it could not pay its debts as they become due.
We believe that Abraxas, Canadian Abraxas, Sandia and Wamsutter received
reasonably equivalent value at the time they incurred the indebtedness under the
First Lien Notes, the Second Lien Notes or related guarantees, as applicable,
and granted the security interests in the Collateral securing the First Lien
Notes, the Second Lien Notes and the related guarantees. In addition, Abraxas,
Canadian Abraxas, Sandia and Wamsutter believe that none of them were, at the
time of or as a result of the issuance of the First Lien Notes, the Second Lien
Notes or the related guarantees and the granting of the security interests in
the Collateral securing the First Lien Notes, the Second Lien Notes and the
related guarantees, insolvent under the foregoing standards, that none of
Abraxas, Canadian Abraxas, Sandia or Wamsutter will be engaged in a business or
transaction for which its remaining assets constitute unreasonably small capital
and that none of them intends or will intend to incur debts beyond its ability
to pay such debts as they mature. These beliefs are based upon management's
analysis of internal cash flow projections and estimated values of assets and
liabilities of Abraxas, Canadian Abraxas, Sandia and Wamsutter. We cannot assure
you, however, that a court passing on such questions would agree with Abraxas.
Under applicable provisions of Canadian federal bankruptcy law or comparable
provisions of provincial fraudulent preference laws, if a court in an action
brought by an unpaid creditor of Canadian Abraxas or by a bankruptcy trustee of
Canadian Abraxas were to find that the liens granted by Canadian Abraxas over
its assets were intended to prefer the holders of the First Lien Notes and the
Second Lien Notes over other creditors, such liens could be set aside. This
would become an issue if Canadian Abraxas became insolvent or bankrupt within a
certain period after granting the liens. However, to the extent that the grant
of security is to secure new loan advances, there would be no fraudulent
preference under Canadian bankruptcy or fraudulent preference laws.
Bankruptcy laws could impair your rights. In the event Abraxas or any of the
guarantors were to become a debtor subject to insolvency proceedings under the
United States Bankruptcy Code ("Bankruptcy Code"), Canadian Federal bankruptcy
law or general state or provincial laws (to the extent not superseded by
respective federal laws), it is likely delays may occur in payment of the First
Lien Notes and the Second Lien Notes and in enforcing remedies under the First
Lien Notes and the Second Lien Notes, any guarantee or the liens securing the
First Lien Notes and the Second Lien Notes and the guarantees because of
specific provisions of such laws or by a court applying general principles of
11
equity. Provisions under the Bankruptcy Code or general principles of equity
that could result in the impairment of your rights include, but are not limited
to:
o an automatic stay,
o avoidance of preferential transfers by a trustee or debtor-in-possession,
o substantive consolidation,
o limitations on collectability of unmatured interest or attorney fees and
forced restructuring of the First Lien Notes or the Second Lien Notes.
There are similar provisions under Canadian law. Under the Bankruptcy Code,
a trustee or debtor-in-possession may generally recover payments or transfers of
property of a debtor if such payment or transfer was:
o to or for the benefit of a creditor,
o in payment of an antecedent debt owed before the transfer was made,
o made while the debtor was insolvent,
o within ninety (90) days (or one year if the payment was to an "insider" of
the debtor) before the filing of the bankruptcy case that enabled the
creditor to receive more than it would have received in a liquidation under
Chapter 7 of the Bankruptcy Code, the transfer had not been made and the
creditor received payment of the debt as provided in the Bankruptcy Code.
As an example, if payments were made on the First Lien Notes or the Second
Lien Notes prior to the filing of a bankruptcy case and a court subsequently
determined that the value of the collateral pledged by the entity making the
payment was less than the debt owed, such payments could be subject to avoidance
as a preferential transfer.
Our financial failure could also result in impairment of payment of the
First Lien Notes or the Second Lien Notes if a bankruptcy court were to
"substantially consolidate" Abraxas and its subsidiaries. If a bankruptcy court
substantially consolidated Abraxas and its subsidiaries, the assets of each
entity would be subject to the claims of creditors for all entities. Such a
consolidation would expose the holders of the First Lien Notes or the Second
Lien Notes not only to the usual impairments arising from bankruptcy, but also
to potential dilution of the amount ultimately recoverable because of the larger
creditor base.
Forced restructuring of the First Lien Notes or the Second Lien Notes could
occur through the "cram-down" provision of the Bankruptcy Code. Under this
provision, the First Lien Notes or the Second Lien Notes could be restructured
over objections of holders of the First Lien Notes or the Second Lien Notes as
to their general terms, primarily interest rate and maturity. Additionally, the
First Lien Notes or the Second Lien Notes could be bifurcated into a secured
debt and unsecured debt if a bankruptcy court were to find that the debt owed by
Abraxas exceeded the value of the collateral. If this were to occur, the
unsecured portion of the debt could be afforded different treatment than the
secured portion of the debt, including the disallowance of the accrual of post
petition interest on the First Lien Notes or the Second Lien Notes.
Additionally, due to Abraxas and the guarantors being domiciled in Canada
and in the United States, Abraxas and the guarantors could be subject to
multi-jurisdictional insolvency proceedings in Canada and the United States. If
multi-jurisdictional insolvency proceedings were to occur, this could result in
additional delay in payment of the First Lien Notes or the Second Lien Notes, as
well as delay in or prevention from enforcing remedies under the First Lien
Notes or the Second Lien Notes, any guarantee and the liens securing the First
Lien Notes or the Second Lien Notes and the guarantees. Likewise, the First Lien
Notes or the Second Lien Notes could be subject to different treatment inasmuch
as the multiple insolvency proceedings would be conducted by different courts
applying different laws.
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. 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
12
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 write-downs 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.
In addition to decreasing our revenue and cash flow from operations, low or
declining crude oil and natural gas prices could have additional material
adverse effects on us, such as:
o reducing the overall volumes of crude oil and natural gas that we
can produce economically;
o cause a ceiling limitation write-down;
o increase our dependence on external sources of capital to meet our
liquidity requirements; and
o impair our ability to obtain needed equity capital.
Hedging transactions may limit our potential gains. We have 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 and 2001, we experienced hedging losses of $20.2 million and $12.1
million, respectively. At year end 2001, the fair value of future hedges was a
liability of approximately $658,000, which we believe will reduce our cash flow
from operations in 2002. Our hedge agreements expire in October 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 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 write-downs. We use the full cost method to account for our crude oil
and natural gas operations. Accordingly, we capitalize the cost to acquire,
explore for and develop crude oil and natural gas properties. Under full cost
accounting rules, the net capitalized cost of crude oil and natural gas
properties may not exceed a "ceiling limit" which is based upon the present
value of estimated future net cash flows from proved reserves, discounted at
10%, plus the lower of cost or fair market value of unproved properties. If net
capitalized costs of crude oil and natural gas properties exceed the ceiling
limit, we must charge the amount of the excess to earnings. This is called a
"ceiling limitation write-down". This charge does not impact cash flow from
13
operating activities, but does reduce our stockholders' equity and earnings. The
risk that we will be required to write down the carrying value of crude oil and
natural gas properties increases when crude oil and natural gas prices are low.
In addition, write-downs may occur if we experience substantial downward
adjustments to our estimated proved reserves or if purchasers cancel long-term
contracts for our natural gas production. As of December 31, 2001, the Company's
net capitalized costs of crude oil and natural gas properties exceeded the
present value of its estimated proved reserves by $71.3 million ($38.9 million
on the U.S. properties and $32.4 million on the Canadian properties). These
amounts were calculated considering 2001 year-end prices of $19.84 per Bbl for
crude oil and $2.57 per Mcf for natural gas as adjusted to reflect the expected
realized prices for each of the full cost pools. The Company did not adjust its
capitalized costs for its U.S. properties because subsequent to December 31,
2001, crude oil and natural gas prices increased such that capitalized costs for
its U.S. properties did not exceed the present value of the estimated proved
crude oil and natural gas reserves for its U.S. properties as determined using
increased realized prices on March 22, 2002 of $24.16 per Bbl for crude oil and
$2.89 per Mcf for natural gas. The Company also used the subsequent prices to
evaluate its Canadian properties, and reduced the 2001 year-end write-down to an
amount of $2.6 million on those properties. In 1999, we recorded a write-down of
$19.1 million as a result of a downward adjustment to our proved reserves in
Canada. We cannot assure you that we will not experience additional ceiling
limitation write-downs in the future. For more information on the full cost
method of accounting and ceiling limitation write-downs, you should read the
discussion under "Management's Discussion and Analysis of Financial Condition
and Results of Operations - Critical Accounting Policies."
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, 2001. The sales prices as of such date used for
purposes of such estimates were $18.26 per Bbl of crude oil, $16.29 per Bbl of
NGLs and $2.20 per Mcf of natural gas. This compares with $25.73 per Bbl of
crude oil, $30.63 per Bbl of NGLs and $9.21 per Mcf of natural gas as of
December 31, 2000. It is also assumed that we will make future capital
expenditures of approximately $56.6 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.
14
We have experienced recurring net losses.
The following table shows the losses Abraxas had in 1997, 1998, 1999
and 2001:
1997 1998 1999 2001
---------- -------------- ------------- ------------
(US $ in millions)
----------------------------------------------------
Net loss applicable
to common stock......... $(6.5) $(84.0) $(36.7) $(19.7)
========== ============== ============= ============
While Abraxas had net income in 2000 of $8.4 million, if the significant
gain on the sale of an interest in a partnership were excluded, Abraxas would
have experienced a net loss for the year of $(25.5) million. Abraxas cannot
assure you that it will become profitable in the future.
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.
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 acquire or find additional reserves will
be severely diminished by our lack of available funds for acquisition,
exploration and development projects. We have implemented a number of measures
to conserve our cash resources, including postponement of exploration and
development projects. However, while these measures will conserve our cash
resources in the near term, they will also limit our ability to replenish our
depleting reserves, which could negatively impact our cash flow from operations
in the future.
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.
15
Drilling for crude oil and natural gas may be unprofitable. Dry holes and wells
that are productive but do not produce sufficient net revenues after drilling,
operating and other costs are unprofitable. In addition, our properties may be
susceptible to hydrocarbon draining from production by other operations on
adjacent properties.
Our industry also experiences numerous operating risks. These operating
risks include the risk of fire, explosions, blow-outs, pipe failure, abnormally
pressured formations and environmental hazards. Environmental hazards include
oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of
these industry operating risks occur, we could have substantial losses.
Substantial losses also may result from injury or loss of life, severe damage to
or destruction of property, clean-up responsibilities, regulatory investigation
and penalties and suspension of operations. In accordance with industry
practice, we maintain insurance against some, but not all, of the risks
described above. We cannot assure you that our insurance will be adequate to
cover losses or liabilities. Also, we cannot predict the continued availability
of insurance at premium levels that justify its purchase.
We operate in a highly competitive industry which may adversely affect our
operations. We operate in a highly competitive environment. Competition is
particularly intense with respect to the acquisition of desirable undeveloped
crude oil and natural gas properties. The principal competitive factors in the
acquisition of such undeveloped crude oil and natural gas properties include the
staff and data necessary to identify, investigate and purchase such properties,
and the financial resources necessary to acquire and develop such properties. We
compete with major and independent crude oil and natural gas companies for
properties and the equipment and labor required to develop and operate such
properties. Many of these competitors have financial and other resources
substantially greater than ours.
The principal resources necessary for the exploration and production of
crude oil and natural gas are leasehold prospects under which crude oil and
natural gas reserves may be discovered, drilling rigs and related equipment to
explore for such reserves and knowledgeable personnel to conduct all phases of
crude oil and natural gas operations. We must compete for such resources with
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 natural gas production and transportation,
general economic conditions, and changes in supply and demand. These factors and
the availability of markets are beyond our control. If market factors
dramatically change, the financial impact on us could be substantial and
adversely affect our ability to produce and market crude oil and natural gas.
Our crude oil and natural gas operations are subject to various U.S.
federal, state and local and Canadian federal and provincial governmental
16
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
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.
We depend on our key personnel. We depend to a large extent on Robert L.G.
Watson, our Chairman of the Board, President and Chief Executive Officer, for
our management and business and financial contacts. The unavailability of Mr.
Watson could have a materially adverse effect on our business. Mr. Watson has a
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.
Shares eligible for future sale may depress our stock price. At March 22,
2002, we had 29,979,397 shares of common stock outstanding of which 2,891,957
shares were held by affiliates, 4,923,537 shares of common stock were subject to
outstanding options granted under certain stock option plans (of which 2,834,457
shares were vested at March 22, 2002) and 950,000 shares were issuable upon
exercise of warrants.
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 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.
The price of Abraxas' common stock has been volatile and could continue to
fluctuate substantially. Abraxas' common stock is traded on the American Stock
Exchange ("AMEX"). The market price of Abraxas' common stock has been volatile
and could fluctuate substantially based on a variety of factors, including the
following:
o fluctuations in commodity prices;
o variations in results of operations;
o legislative or regulatory changes;
o general trends in the industry;
17
o market conditions; and
o analysts' estimates and other events in the crude oil and natural
gas industry.
You should read the discussion under the heading "Market for Registrant's Common
Equity and Related Stockholder Matters" for more information regarding the
market price fluctuations of Abraxas' common stock.
We may issue shares of preferred stock with greater rights than our common
stock. Subject to the rules of the American Stock Exchange, our articles of
incorporation authorize our board of directors to issue one or more series of
preferred stock and set the terms of the preferred stock without seeking any
further approval from holders of our common stock. Any preferred stock that is
issued may rank ahead of our common stock in terms of dividends, priority and
liquidation premiums and may have greater voting rights than our common stock.
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, 2001
the Company had, subject to the limitation discussed below, $115,900,000 of net
operating loss carryforwards for U.S. tax purposes. These loss carryforwards
will expire from 2002 through 2021 if not utilized. At December 31, 2001, the
Company had approximately $6,700,000 of net operating loss carryforwards for
Canadian tax purposes. These carryforwards will expire from 2002 through 2008 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
$3,203,000 will be limited to approximately $235,000 per year.
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 $6,590,000 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. 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. In 2000, assets with built in gains were
sold, increasing the Section 382 limitation for 2001 by approximately
$31,000,000.
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 $34,763,000 and $39,670,000 for deferred tax assets at
December 31, 2000 and 2001, respectively.
18
Regulation of Crude Oil and Natural Gas Activities
The exploration, production and transportation of all types of hydrocarbons
are subject to significant governmental regulations. Our operations are affected
from time to time in varying degrees by political developments and federal,
state, provincial and local laws and regulations. In particular, crude oil and
natural gas production operations and economics are, or in the past have been,
affected by industry specific price controls, taxes, conservation, safety,
environmental, and other laws relating to the petroleum industry, by changes in
such laws and by constantly changing administrative regulations.
Price Regulations
In the past, maximum selling prices for certain categories of crude oil,
natural gas, condensate and NGLs in the United States were subject to
significant federal regulation. At the present time, however, all sales of our
crude oil, natural gas, condensate and NGLs produced in the United States under
private contracts may be sold at market prices. Congress could, however, reenact
price controls in the future. If controls that limit prices to below market
rates are instituted, 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
context of energy resources, Canada remains free to determine whether exports to
the U.S. or Mexico will be allowed provided that any export restrictions do not:
(i) reduce the proportion of energy resources exported relative to the total
supply of the energy resource (based upon the proportion prevailing in the most
recent 36 month period); (ii) impose an export price higher than the domestic
price; or (iii) disrupt normal channels of supply. All three countries are
prohibited from imposing minimum export or import price requirements.
NAFTA contemplates the reduction of Mexican restrictive trade practices in
the energy sector and prohibits discriminatory border restrictions and export
taxes. The agreement also contemplates clearer disciplines on regulators to
ensure fair implementation of any regulatory changes and to minimize disruption
of contractual arrangements, which is important for Canadian natural gas
exports. The Texas Railroad Commission has recently become the lead agency for
Texas for coordinating permits governing Texas to Mexico cross border pipeline
projects. The availability of selling natural gas into Mexico may substantially
impact the interstate natural gas market on all producers in the coming years.
United States Natural Gas Regulation
Historically, the natural gas industry as a whole has been more heavily
regulated than the crude oil or other liquid hydrocarbons market. Most
regulations focused on transportation practices. 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 natural 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"
19
its traditional bundled sales services and create and make available on an open
and nondiscriminatory basis numerous constituent services (such as gathering
services, storage services, firm and interruptible transportation services, and
standby sales and natural gas balancing services), and to adopt a new ratemaking
methodology to determine appropriate rates for those services. To the extent the
pipeline company or its sales affiliate markets natural gas as a merchant, it
does so pursuant to private contracts in direct competition with all of the
sellers, such as us; however, pipeline companies and their affiliates 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
regulations operate in conjunction with state proposals for natural gas
marketing restructuring and in the increasingly competitive marketplace for all
post-wellhead services related to natural gas.
In recent years the FERC also has pursued a number of 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.
(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
20
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 natural gas on third party
gathering facilities, our shipping activities have not been materially affected
by these decisions.
In summary, all of the FERC activities related to the transportation of
natural gas have resulted in improved opportunities to market our physical
production to a variety of buyers and market places, while at the same time
increasing access to pipeline transportation and delivery services. Additional
proposals and proceedings that might affect the natural gas industry in the
United States are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. We cannot predict when or if any such
proposals might become effective or their effect, if any, on our operations. The
crude oil and natural gas industry historically has been very heavily regulated;
thus there is no assurance that the less stringent regulatory approach recently
pursued by the FERC and Congress will continue indefinitely into the future.
State and Other Regulation
All of the jurisdictions 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
drilling and casing wells, the surface use and restoration of properties upon
which wells are drilled and the plugging and abandoning of wells. Our operations
are also subject to various conservation laws and regulations. These include the
regulation of the size of drilling and spacing units or proration units on an
acreage basis and the density of wells which may be drilled and the unitization
or pooling of crude oil and natural gas properties. In this regard, some states
and provinces allow the forced pooling or integration of tracts to facilitate
exploration while other states and provinces rely on voluntary pooling of lands
and leases. In addition, state and provincial conservation laws establish
maximum rates of production from crude oil and natural gas wells, generally
prohibit the venting or flaring of natural gas and impose certain requirements
regarding the ratability of production. Some states, such as Texas and Oklahoma,
have, in recent years, reviewed and substantially revised methods previously
used to make monthly determinations of allowable rates of production from fields
and individual wells. The effect of all of these conservation regulations is to
limit the speed, timing and amounts of crude oil and natural gas we can produce
from our wells, and to limit the number of wells or the location at which we can
drill.
State and provincial regulation of gathering facilities generally includes
various safety, environmental, and in some circumstances, non-discriminatory
take 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 natural gas by an
entity that provides such services to others for a fee, in order to prohibit
such entities from unduly discriminating in favor of their affiliates.
For those operations on U.S. Federal or Indian oil and gas leases, such
operations must comply with numerous regulatory restrictions, including various
non-discrimination statutes, and certain of such operations must be conducted
pursuant to certain on-site security regulations and other permits issued by
various federal agencies. In addition, in the United States, the Minerals
Management Service ("MMS") 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 crude oil produced from federal lands for purposes of
calculating royalties owed to the government. The crude oil and natural gas
21
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 crude oil pools discovered after
September 30, 1992. The new crude oil royalty reserved to the Crown has a base
rate of 10% and a rate cap of 30% and for old crude oil a base rate of 10% and a
rate cap of 35%.
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 CDN $10,000
in the taxation year.
Producers of crude oil and natural gas in British Columbia are also required
to pay annual rental payments in respect of Crown leases and royalties and
freehold production taxes in respect of crude oil and natural gas produced from
Crown and freehold lands respectively. The amount payable as a royalty in
22
respect of crude oil depends on the vintage of the crude oil (whether it was
produced from a pool discovered before or after October 31, 1975) or a pool in
which no well was completed on June 1, 1998), the quantity of crude oil produced
in a month and the value of the crude oil. Crude oil produced from 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. Natural gas produced
in association with crude oil has a minimum royalty of 8% while the royalty in
respect of other natural 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 natural gas
processing activities; suspend, limit or prohibit construction, drilling and
other activities in certain lands lying within wilderness, wetlands, and other
protected areas; require remedial measures to mitigate pollution from historical
and on-going operations such as use of pits and plugging of abandoned wells;
restrict injection of liquids into subsurface strata that may contaminate
groundwater; and impose substantial liabilities for pollution resulting from our
operations. Environmental permits required for our operations may be subject to
revocation, modification, and renewal by issuing authorities. Governmental
authorities have the power to enforce compliance with their regulations and
permits, and violations are subject to injunction, civil fines, and even
criminal penalties. Our management believes that we are in substantial
compliance with current environmental laws and regulations, and that we will not
be required to make material capital expenditures to comply with existing laws.
Nevertheless, changes in existing environmental laws and regulations or
interpretations thereof could have a significant impact on us as well as the
crude oil and natural gas industry in general, and thus we are unable to predict
the ultimate cost and effects of future changes in environmental laws and
regulations.
In the United States, the Comprehensive Environmental Response, Compensation
and Liability Act ("CERCLA"), also known as "Superfund," and comparable state
statutes impose strict, joint, and several liability on certain classes of
persons who are considered to have contributed to the release of a "hazardous
substance" into the environment. These persons include the owner or operator of
a disposal site or sites where a release occurred and companies that generated,
disposed or arranged for the disposal of the hazardous substances released at
the site. Under CERCLA such persons or companies may be retroactively liable for
the costs of cleaning up the hazardous substances that have been released into
the environment and for damages to natural resources, and it is common for
neighboring land owners and other third parties to file claims for personal
injury, property damage, and recovery of response costs allegedly caused by the
hazardous substances released into the environment. The Resource Conservation
and Recovery Act ("RCRA") and comparable state statutes govern the disposal of
"solid waste" and "hazardous waste" and authorize imposition of substantial
civil and criminal penalties for failing to prevent surface and subsurface
pollution, as well as to control the generation, transportation, treatment,
storage and disposal of hazardous waste generated by crude oil and natural gas
operations. Although CERCLA currently contains a "petroleum exclusion" from the
definition of "hazardous substance," state laws affecting our operations impose
cleanup liability relating to petroleum and petroleum related products,
including crude oil cleanups. In addition, although RCRA regulations currently
classify certain oilfield wastes which are uniquely associated with field
operations as "non-hazardous," such exploration, development and production
wastes could be reclassified by regulation as hazardous wastes thereby
administratively making such wastes subject to more stringent handling and
disposal requirements.
We currently own or lease, and have in the past owned or leased, numerous
properties that for many years have been used for the exploration and production
of crude oil and natural gas. Although we utilized standard industry operating
and disposal practices at the time, hydrocarbons or other wastes may have been
disposed of or released on or under the properties we owned or leased or on or
under other locations where such wastes have been taken for disposal. In
addition, many of these properties have been operated by third parties whose
treatment and disposal or release of hydrocarbons or other wastes was not under
our control. These properties and the wastes disposed thereon may be subject to
CERCLA, RCRA, and analogous state laws. Our operations are also impacted by
regulations governing the disposal of naturally occurring radioactive materials
("NORM"). We must comply with the Clean Air Act and comparable state statutes
which prohibit the emissions of air contaminants, although a majority of our
23
activities are exempted under a standard exemption. Moreover, owners, lessees
and operators of crude oil and natural gas properties are also subject to
increasing civil liability brought by surface owners and adjoining property
owners. Such claims are predicated on the damage to or contamination of land
resources occasioned by drilling and production operations and the products
derived therefrom, and are usually causes of action based on negligence,
trespass, nuisance, strict liability and fraud.
United States federal regulations also require certain owners and operators
of facilities that store or otherwise handle crude oil, such as us, to prepare
and implement spill prevention, control and countermeasure plans and spill
response plans relating to possible discharge of crude oil into surface waters.
The federal Oil Pollution Act ("OPA") contains numerous requirements relating to
prevention of, reporting of, and response to crude oil spills into waters of the
United States. For facilities that may affect state waters, OPA requires an
operator to demonstrate $10 million in financial responsibility. State laws
mandate crude oil cleanup programs with respect to contaminated soil.
Our Canadian operations are also subject to environmental regulation
pursuant to local, provincial and federal legislation which generally require
operations to be conducted in a safe and environmentally responsible manner.
Canadian environmental legislation provides for restrictions and prohibitions
relating to the discharge of air, soil and water pollutants and other substances
produced in association with certain crude oil and natural gas industry
operations, and environmental protection requirements, including certain
conditions of approval and laws relating to storage, handling, transportation
and disposal of materials or substances which may have an adverse effect on the
environment. Environmental legislation can affect the location of wells and
facilities and the extent to which exploration and development is permitted. In
addition, legislation requires that well and facilities sites be abandoned and
reclaimed to the satisfaction of provincial authorities. A breach of such
legislation may result in the imposition of fines or issuance of clean-up
orders.
Certain federal environmental laws that may affect us include the Canadian
Environmental Assessment Act which ensures that the environmental effects of
projects receive careful consideration prior to licenses or permits being
issued, to ensure that projects that are to be carried out in Canada or on
federal lands do not cause significant adverse environmental effects outside the
jurisdictions in which they are carried out, and to ensure that there is an
opportunity for public participation in the environmental assessment process;
the Canadian Environmental Protection Act ("CEPA") which is the most
comprehensive federal environmental statute in Canada, and which controls toxic
substances (broadly defined), includes standards relating to the discharge of
air, soil and water pollutants, provides for broad enforcement powers and
remedies and imposes significant penalties for violations; the National Energy
Board Act which can impose certain environmental protection conditions on
approvals issued under the Act; the Fisheries Act which prohibits the depositing
of a deleterious substance of any type in water frequented by fish or in any
place under any condition where such deleterious substance may enter any such
water and provides for significant penalties; the Navigable Waters Protection
Act which requires any work which is built in, on, over, under, through or
across any navigable water to be approved by the Minister of Transportation, and
which attracts severe penalties and remedies for non-compliance, including
removal of the work.
In Alberta, environmental compliance has been governed by the Alberta
Environmental Protection and Enhancement Act ("AEPEA") since September 1, 1993.
In addition to consolidating a variety of environmental statutes, the AEPEA also
imposes certain new environmental responsibilities on crude oil and natural gas
operators in Alberta. The AEPEA sets out environmental standards and compliance
for releases, clean-up and reporting. The Act provides for a broad range of
liabilities, enforcement actions and penalties.
We are not currently involved in any administrative, judicial or legal
proceedings arising under domestic or foreign federal, state, or local
environmental protection laws and regulations, or under federal or state common
law, which would have a material adverse effect on our financial position or
results of operations. Moreover, we maintain insurance against costs of clean-up
operations, but we are not fully insured against all such risks. A serious
incident of pollution may result in the suspension or cessation of operations in
the affected area.
We 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.
24
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, 2002, we had 47 full-time employees in the United States,
including 3 executive officers, 3 non-executive officers, 1 petroleum engineer,
1 geologist, 5 managers, 1 landman, 12 secretarial and clerical personnel and 21
field personnel. Additionally, we retain contract pumpers on a month-to-month
basis. We retain independent geological and engineering consultants from time to
time on a limited basis and expect to continue to do so in the future.
As of March 22, 2002, Grey Wolf in Canada had 42 full-time employees,
including 3 executive officers, 2 non-executive officers, 3 petroleum engineers,
3 geologists, 1 geophysicist, 18 technical and clerical personnel and 12 field
personnel.
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 2001, Canadian Abraxas
paid approximately $1.7 million to Grey Wolf pursuant to this management
agreement.
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,
2001, located in those two regions. We operate 91% 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 78% working interest in 57 wells with average daily production of
444 net Bbls of crude oil and NGLs and 14,057 net Mcf of natural gas per day for
the year ended December 31, 2001. As of December 31, 2001 we had estimated net
proved reserves in South Texas of 46,521 Mmcfe (78% natural gas) with a PV-10 of
$35.6 million, 80% 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 76% working interest in 154 wells with average daily
production of 621 net Bbls of crude oil and NGLs and 7,351 net Mcf of natural
gas per day for the year ended December 31, 2001. As of December 31, 2001, we
had estimated net proved reserves in West Texas of 88,039 Mmcfe (82% natural
gas) with a PV 10 of $41.6 million, 47% of which was attributable to proved
developed reserves. During 2001, we drilled a total of 4 new wells (4 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 12 natural gas processing plants. As
25
of December 31, 2001, Canadian Abraxas and Grey Wolf had estimated net proved
reserves of 94,664 Mmcfe (85% natural gas) with a PV-10 of $132.5 million, 93%
of which was attributable to proved developed reserves. For the year ended
December 31, 2001, the Canadian properties produced an average of approximately
866 net Bbls of crude oil and NGLs per day and 26,500 net Mcf of natural gas per
day. The natural gas processing plants had aggregate capacity of approximately
211 MMcf of natural gas per day (107 net MMcf). During 2001, we drilled a total
of 12 new wells (9.3 net) in Canada with a 92% success rate.
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, 2001:
Developed and Undeveloped Acreage
-----------------------------------------------------------------------
As of December 31, 2001
-----------------------------------------------------------------------
Developed Acreage (1) Undeveloped Acreage (2)
--------------------------------- -----------------------------------
Gross Acres (3) Net Acres (4) Gross Acres (3) Net Acres (4)
--------------- --------------- --------------- ------------------
Canada 79,380 51,456 755,623 494,138
Texas 27,479 20,444 11,876 11,520
Wyoming 3,200 3,200 59,591 55,758
--------------- --------------- --------------- ------------------
Total 110,059 75,100 827,090 561,416
=============== =============== =============== ==================
- ---------------
(1) Developed acreage consists of acres spaced or assignable to productive
wells.
(2) Undeveloped acreage is considered to be those leased acres on which
wells have not been drilled or completed to a point that would permit
the production of commercial quantities of crude oil and natural gas,
regardless of whether or not such acreage contains proved reserves.
(3) Gross acres refers to the number of acres in which we own a working
interest.
(4) Net acres represents the number of acres attributable to an owner's
proportionate working interest and/or royalty interest in a lease
(e.g., a 50% working interest in a lease covering 320 acres is
equivalent to 160 net acres).
Productive Wells
The following table sets forth our total gross and net productive wells,
expressed separately for crude oil and natural gas, as of December 31, 2001:
Productive Wells (1)
---------------------------------------------------------------------
As of December 31, 2001
---------------------------------------------------------------------
State/Country Crude Oil Natural Gas
----------------- -------------------------------- ----------------------------------
Gross(2) Net(3) Gross(2) Net(3)
- - - -
--------------- -------------- --------------- ----------------
Canada 276.0 9.1 205.0 110.5
Texas 142.0 111.9 69.0 49.9
Wyoming 5.0 5.0 - -
--------------- -------------- --------------- ----------------
Total 423.0 126.0 274.0 160.4
=============== ============== =============== ================
- ------------
(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,
except for Grey Wolf's, are pledged to secure our indebtedness under the First
Lien Notes and Second Lien Notes and substantially all of Grey Wolf's existing
crude oil and natural gas properties are pledged to secure its indebtedness
26
under the Grey Wolf Facility. 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, 2002, January 1, 2001, and January 1, 2000, by DeGolyer and
MacNaughton, of Dallas, Texas. The reserves of Canadian Abraxas and Grey Wolf as
of January 1, 2002, January 1, 2001 and January 1, 2000 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,
2002, January 1, 2001 and January 1, 2000: