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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the Fiscal Year Ended December 31, 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.
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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:
Estimated Proved Reserves
---------------------------------
Proved Proved Total
Developed Undeveloped Proved
---------- ----------- ---------
As of January 1, 2000(1) (2) (3)(4)
Crude oil (MBbls) ................... 5,513 1,606 7,119
NGLs (MBbls) ........................ 4,961 562 5,523
Natural gas (MMcf) .................. 154,221 35,894 190,115
As of January 1, 2001(1) (2) (3)
Crude oil (MBbls) ................... 3,866 1,407 5,273
NGLs (MBbls) ........................ 3,135 436 3,571
Natural gas (MMcf) .................. 119,737 71,590 191,327
As of January 1, 2002
Crude oil (MBbls) ................... 1,980 1,170 3,150
NGLs (MBbls) ........................ 3,067 585 3,652
Natural gas (MMcf) .................. 111,243 77,514 188,757
- ------------------
(1) Includes 33,000 and 40,000 barrels of crude oil reserves owned by Grey Wolf
of which 16,900 and 20,525 barrels are applicable to the minority
interests' share of these reserves as of January 1, 2000 and 2001,
respectively.
(2) Includes 236,000 and 692,000 barrels of natural gas liquids reserves owned
by Grey Wolf of which 121,098 and 355,083 barrels are applicable to the
minority interests' share of these reserves as of January 1, 2000 and 2001,
respectively.
(3) Includes 21,710 and 21,389 Mmcf of natural gas reserves owned by Grey Wolf
of which 11,140 and 10,975 Mmcf are applicable to the minority interests'
share of these reserves as of January 1, 2000 and 2001, respectively.
(4) Includes 343,941 Bbls of crude oil reserves; 2,448.6 Mbbls of natural gas
liquids reserves and 25,810 Mmcf of natural gas reserves, attributable to
the Wyoming properties which were sold in March 2000. These reserves were
estimated internally.
27
The process of estimating crude oil and natural gas reserves is complex and
involves decisions and assumptions in the evaluation of available geological,
geophysical, engineering and economic data. Therefore, these estimates are
imprecise.
Actual future production, crude oil and natural gas prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable crude
oil and natural gas reserves most likely will vary from those estimated. Any
significant variance could materially affect the estimated quantities and
present value of reserves set forth in this annual report. In addition, we may
adjust estimates of proved reserves to reflect production history, results of
exploration and development, prevailing crude oil and natural gas prices and
other factors, many of which are beyond our control.
You should not assume that the present value of future net revenues referred
to in this annual statement is the current market value of our estimated crude
oil and natural gas reserves. In accordance with SEC requirements, the estimated
discounted future net cash flows from proved reserves are generally based on
prices and costs as of the end of the year of the estimate, or alternatively, if
prices subsequent to that date have increased, a price near the periodic filing
date of the Company's financial statements. 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.
The estimates of our reserves are based upon various assumptions about
future production levels, prices and costs that may not prove to be correct over
time. In particular, estimates of crude oil and natural gas reserves, future net
revenue from proved reserves and the PV-10 thereof for the crude oil and natural
gas properties described in this report are based on the assumption that future
crude oil and natural gas prices remain the same as crude oil and natural gas
prices at December 31, 2001. The average 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. It is also assumed that we will make
future capital expenditures of approximately $56.6 million in the aggregate,
which are necessary to develop and realize the value of proved undeveloped
reserves on our properties. Any significant variance in actual results from
these assumptions could also materially affect the estimated quantity and value
of reserves set forth herein.
We file reports of our estimated crude oil and natural gas reserves with the
Department of Energy and the Bureau of the Census. The reserves reported to
these agencies are required to be reported on a gross operated basis and
therefore are not comparable to the reserve data reported herein.
Crude Oil, Natural Gas Liquids, and Natural Gas Production and Sales Prices
The following table presents our net crude oil, net natural gas liquids and
net natural gas production, the average sales price per Bbl of crude oil and
natural gas liquids and per Mcf of natural gas produced and the average cost of
production per BOE of production sold, for the three years ended December 31,
2001:
28
2001 2000 1999
----------- ------------- -------------
Crude oil production (Bbls) ....... 454,063 636,734 777,855
Natural gas production (Mcf) ...... 17,495,598 19,962,470 25,697,899
Natural gas liquids production
(Bbls) ....................... 277,969 314,897 376,474
Mmcfe ............................. 21,888 25,672 32,623
Average sales price per Bbl of
crude oil ....................$ 24.63 $ 18.69 $ 14.57
Average sales price per MCF of
natural gas (1) ..............$ 3.20 $ 2.71 $ 1.66
Average sales price per Bbl of
natural gas liquids ..........$ 21.51 $ 22.42 $ 13.40
Average sales price per Mcfe (1)...$ 3.35 $ 2.84 $ 1.81
Average cost of production per
BOE produced (2) .............$ 5.10 $ 4.39 $ 3.30
(1) Average sales prices are net of hedging activity.
(2) Crude oil and natural gas were combined by converting natural gas to a
barrel oil equivalent ("BOE") on the basis of 6 Mcf natural gas =1 Bbl
of crude oil. Production costs include direct operating costs, ad
valorem taxes and gross production taxes.
Drilling Activities
The following table sets forth our gross and net working interests in
exploratory, development, and service wells drilled during the three years ended
December 31:
2001 2000 1999
----------------------------- ---------------------------- --------------------------
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
------------ ---------- ------------ --------- ----------- --------
Exploratory(3)
Productive(4)
Crude oil - - - - 2.0 2.0
Natural gas 2.0 1.0 3.0 2.5 8.0 5.3
Dry holes(5) 1.0 .5 9.0 5.6 11.0 6.2
------------ ---------- ------------ --------- ----------- --------
Total 3.0 1.5 12.0 8.1 21.0 13.5
============ ========== ============ ========= =========== ========
Development(6)
Productive (4)
Crude oil 2.0 2.0 9.0 9.0 8.0 1.6
Natural gas 13.0 11.0 16.0 12.2 20.0 13.1
Dry holes (5) - - 3.0 3.0 9.0 4.5
------------ ---------- ------------ --------- ----------- --------
15.0 13.0 28.0 24.2 37.0 19.2
============ ========== ============ ========= =========== ========
(1) A gross well is a well in which we own an interest.
29
(2) The number of net wells represents the total percentage of working
interests held in all wells (e.g., total working interest of 50% is
equivalent to 0.5 net well. A total working interest of 100% is
equivalent to 1.0 net well).
(3) An exploratory well is a well drilled to find and produce crude oil or
natural gas in an unproved area, to find a new reservoir in a field
previously found to be producing crude oil or natural gas in another
reservoir, or to extend a known reservoir.
(4) A productive well is an exploratory or a development well that is not a
dry hole.
(5) A dry hole is an exploratory or development well found to be incapable
of producing either crude oil or natural gas in sufficient quantities
to justify completion as a crude oil or natural gas well.
(6) A development well is a well drilled within the proved area of a crude
oil or natural gas reservoir to the depth of stratigraphic horizon
(rock layer or formation) noted to be productive for the purpose of
extracting proved crude oil or natural gas reserves.
As of March 22, 2002, we had 5 wells in process of drilling, 2 in the
U.S. and 3 in Canada. Since late 2001, Grey Wolf has drilled four wells of a six
well program in the Lady Fern area of Northeast British Columbia. 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.
Office Facilities
Our executive and administrative offices are located at 500 North Loop 1604
East, Suite 100, San Antonio, Texas 78232. We also have an office in Midland,
Texas. These offices, consisting of approximately 12,650 square feet in San
Antonio and 570 square feet in Midland, are leased until March 2006 at an
aggregate base rate of $19,500 per month.
Grey Wolf leases 17,522 square feet of office space in Calgary, Alberta
pursuant to a lease, which expires on April 30, 2003.
Other Properties
We own 10 acres of land, an office building, workshop, warehouse and house
in Sinton, Texas, 160 acres of land in Coke County, Texas and a 50% interest in
approximately two acres of land in Bexar County, Texas. All three properties are
used for the storage of tubulars and production equipment. We also own 19
vehicles which are used in the field by employees. We own 2 workover rigs, which
are used for servicing our wells as well as third party wells.
Item 3. Legal Proceedings
In 2001, the Company and the Partnership were named as defendants in a
lawsuit filed in U.S. District Court in the District of Wyoming. The claim
asserts breach of contract, fraud and negligent misrepresentation by the Company
and the Partnership related to the responsibility for year 2000 ad valorem taxes
on crude oil and natural gas properties sold by the Company and the Partnership.
In February 2002, a summary judgment was granted to the plaintiff in this matter
and a final judgment in the amount of $1.3 million was entered. The Company has
filed an appeal. The Company believes these charges are without merit. The
Company has established a reserve in the amount of $845,000, which represents
the Company's estimated share of the judgment.
In late 2000, the Company received a Final De Minimis Settlement Offer from
the United States Environmental Protection Agency concerning the Casmalia
Disposal Site, Santa Barbara County, California. The Company's liability for the
cleanup at the Superfund site is based on its acquisition of Bennett Petroleum
Corporation, which is alleged to have transported or arranged for the
transportation of oil field waste and drilling muds to the Superfund site. The
Company has engaged California counsel to evaluate the notice of proposed de
minimis settlement and its notice of potential strict liability under the
Comprehensive Environmental Response, Compensation and Liability Act. Defense of
30
the action is handled through a joint group of crude oil companies, all of which
are claiming a petroleum exclusion that limits the Company's liability. The
potential financial exposure and any settlement posture has yet not been
developed, but is considered by the Company to be immaterial.
Additionally, from time to time, the Company is involved in litigation
relating to claims arising out of its operations in the normal course of
business. At December 31, 2001, the Company was not engaged in any legal
proceedings that are expected, individually or in the aggregate, to have a
material adverse effect on the Company.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted to a vote of our security holders during the fourth
quarter of the fiscal year ended December 31, 2001.
Item 4a. Executive Officers of Abraxas
Certain information is set forth below concerning our executive officers,
each of whom has been selected to serve until the 2002 annual meeting of
shareholders and until his successor is duly elected and qualified.
Robert L. G. Watson, age 51, has served as Chairman of the Board, President,
Chief Executive Officer and a director of Abraxas since 1977. Since May 1996,
Mr. Watson has also served as Chairman of the Board and a director of Grey Wolf.
In November 1996, Mr. Watson was elected Chairman of the Board, President and as
a director of Canadian Abraxas. Prior to joining Abraxas, Mr. Watson was
employed in various petroleum engineering positions with Tesoro Petroleum
Corporation, a crude oil and natural gas exploration and production company,
from 1972 through 1977, and DeGolyer and McNaughton, an independent petroleum
engineering firm, from 1970 to 1972. Mr. Watson received a Bachelor of Science
degree in Mechanical Engineering from Southern Methodist University in 1972 and
a Master of Business Administration degree from the University of Texas at San
Antonio in 1974.
Chris E. Williford, age 50, was elected Vice President, Treasurer and Chief
Financial Officer of Abraxas in January 1993, and as Executive Vice President
and a director of Abraxas in May 1993. In November 1996, Mr. Williford was
elected Vice President and Assistant Secretary of Canadian Abraxas. In December
1999, Mr. Williford resigned as a director of Abraxas. Prior to joining Abraxas,
Mr. Williford was Chief Financial Officer of American Natural Energy
Corporation, a crude oil and natural gas exploration and production company,
from July 1989 to December 1992 and President of Clark Resources Corp., a crude
oil and natural gas exploration and production company, from January 1987 to May
1989. Mr. Williford received a Bachelor of Science degree in Business
Administration from Pittsburgh State University in 1973.
Robert W. Carington, Jr., age 40, was elected Executive Vice President and a
director of the Company in July 1998. In December 1999, Mr. Carington resigned
as a director of Abraxas. Prior to joining the Company, Mr. Carington was a
Managing Director with Jefferies & Company, Inc. Prior to joining Jefferies &
Company, Inc. in January 1993, Mr. Carington was a Vice President at Howard,
Weil, Labouisse, Friedrichs, Inc. Prior to joining Howard, Weil, Labouisse,
Friedrichs, Inc., Mr. Carington was a petroleum engineer with Unocal Corporation
from 1983 to 1990. Mr. Carington received a degree of Bachelor of Science in
Mechanical Engineering from Rice University in 1983 and a Masters of Business
Administration from the University of Houston in 1990.
31
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
Market Information
Our common stock began trading on the American Stock Exchange on August 18,
2000, under the symbol "ABP." Our common stock was formerly listed on the NASDAQ
Stock Market under the symbol "AXAS"; however, effective June 16, 1999, our
common stock was delisted from general quotation on the NASDAQ Stock Market for
failure to satisfy NASDAQ's listing and maintenance standards. During the period
between June 16, 1999 and August 17, 2000, our stock traded on the OTC Bulletin
Board under the symbol "AXAS".
The following table sets forth certain information as to the high and low
bid quotations quoted on NASDAQ for 1999 (through June 16, 1999), on the OTC
Bulletin Board for the remainder of 1999 and through August 17, 2000, and the
high low sales price on the American Stock Exchange for the remainder of 2000
and 2001. Information with respect to over-the-counter bid quotations represents
prices between dealers, does not include retail mark-ups, mark-downs, or
commissions, and may not necessarily represent actual transactions.
Period High Low
1999
First Quarter......................................$3.19 $1.19
Second Quarter......................................2.82 0.88
Third Quarter...................................... 2.97 0.88
Fourth Quarter..................................... 2.44 0.81
2000
First Quarter......................................$2.81 $1.06
Second Quarter..................................... 2.38 1.34
Third Quarter (OTC through August 17).............. 2.75 1.38
Third Quarter (AMEX from August 17)................ 4.00 2.75
Fourth Quarter.................................... 4.56 2.81
2001
First Quarter......................................$5.32 $3.69
Second Quarter......................................4.98 3.10
Third Quarter.......................................3.65 1.70
Fourth Quarter......................................1.85 0.88
Holders
As of March 22, 2002 we had 29,979,397 shares of common stock outstanding
and had approximately 1,579 stockholders of record.
Dividends
We have not paid any cash dividends on our common stock and it is not
presently determinable when, if ever, we will pay cash dividends in the future.
In addition, the indentures governing the First Lien and Second Lien Notes
prohibit the payment of cash dividends and stock dividends on our common stock.
You should read the discussion under "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Liquidity and Capital Resources"
for more information regarding the restrictions on our ability to pay dividends.
32
Item 6. Selected Financial Data
The following selected financial data are derived from our Consolidated
Financial Statements. The data should be read in conjunction with our
Consolidated Financial Statements and Notes thereto, and other financial
information included herein. See "Financial Statements."
Year Ended December 31,
--------------------------------------------------------------------------------
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(Dollars in thousands except per share data)
Total revenue.................................. $ 77,243 $ 76,600 $ 66,770 $ 60,084 $ 70,931
Income (loss) before extraordinary item........ $ (19,718)(1) $ 6,676 (2) $ (36,680)(3) $ (83,960) (3) $ (6,485)
Income (loss) before extraordinary item per
common share - diluted.................... $ (0.76) $ 0.21 $ (5.41) $ (13.26) $ (1.11)
Weighted average shares outstanding - basic
(in thousands)................................. 25,789 22,616 6,784 6,331 6,025
Total assets................................... $ 303,713 $ 335,560 $ 322,284 $ 291,498 $ 338,528
Long-term debt, excluding current maturities... $ 285,184 $ 266,441 $ 273,421 $ 299,698 $ 248,617
Total stockholders' equity (deficit)........... $ (28,488) $ (6,503) $ (9,505) $ (63,522) $ 26,813
(1) Includes ceiling test write-down of $2.6 million in 2001, based on
subsequent (March 22, 2002) realized prices, relating to our Canadian
properties.
(2) Includes gain on sale of partnership interest of $34 million in 2000.
(3) Includes ceiling write-down of $19.1 and $61.2 million for 1999 and 1998
respectively.
Item 7. Management's Discussion And Analysis Of Financial Condition And Results
Of Operations
The following is a discussion of our consolidated financial condition,
results of operations, liquidity and capital resources. This discussion should
be read in conjunction with our Consolidated Financial Statements and the Notes
thereto. See "Financial Statements."
General
We have incurred net losses in three of the last four years and there can be
no assurance that operating income and net earnings will be achieved in future
periods. Our revenues, profitability and future rate of growth are substantially
dependent upon prevailing prices for crude oil and natural gas and the volumes
of crude oil, natural gas and natural gas liquids we produce. Natural gas and
crude oil prices weakened during 1998. Crude oil and natural gas prices
increased somewhat in 1999 and increased substantially in 2000. During 2001
crude oil and natural gas prices weakened substantially from the 2000 levels. In
addition, because our proved reserves will decline as crude oil, natural gas and
natural gas liquids are produced, unless we are successful in acquiring
properties containing proved reserves or conduct successful exploration and
development activities, our reserves and production will decrease. Our ability
to acquire or find additional reserves in the near future will be dependent, in
part, upon the amount of available funds for acquisition, exploitation,
exploration and development projects. If crude oil and natural gas prices return
to the depressed levels experienced in the last six months of 2001, or if our
production levels decrease, our revenues, cash flow from operations and
financial condition will be materially adversely affected.
Results of Operations
Our financial results depend upon many factors, particularly the following
factors which most significantly affect our results of operations:
o the sales prices of crude oil, natural gas liquids and natural gas,
o the level of total sales volumes of crude oil, natural gas liquids and
natural gas,
o the ability to raise capital resources and provide liquidity to meet
cash flow needs,
o the level of and interest rates on borrowings, and
o the level and success of exploration and development activity.
33
Price volatility in the natural gas market has remained prevalent in the
last few years. In the first quarter of 1999, we experienced a decline in energy
commodity prices, resulting in lower revenues and net losses during this period.
However, in the summer of 1999 and continuing through 2000 and early in 2001,
prices improved. For the months of January 2001 through July 2001, we had
certain crude oil and natural gas hedges in place that prevented us from
realizing the full impact of this price environment. In January 2001, the market
price of natural gas was at its highest level in our operating history and the
price of crude oil was also at a high level. However, over the course of 2001,
prices again became depressed, primarily due to the economic downturn.
The table below illustrates how natural gas prices fluctuated over the
course of 2001. "Index" represents the last three days average of NYMEX traded
contracts index price. The "2001" price is the natural gas price realized by the
Company during the quarter, and it includes the impact of our hedging
activities.
(in $ per Mcf) Natural Gas Prices by Quarter
- --------------------------------------------------------------------------------
Quarter ended
---------------------------------------------------------
March 31 June 30 September 30 December 31
----------- ---------- ---------------- ----------------
Index $ 7.27 $ 4.82 $ 2.98 $ 2.47
2001 4.85 3.41 2.26 2.09
Prices have improved since December 31, 2001. The NYMEX natural gas
price on March 22, 2002 was $3.43 per Mcf.
Prices for crude oil have followed a similar path as the commodity market
fell throughout 2001. The table below contains the last three days average of
NYMEX traded contracts index price ("Index") and the prices realized by the
Company during the quarter for 2001.
(in $ per Bbl) Crude oil Prices by Quarter
- --------------------------------------------------------------------------------
Quarter ended
---------------------------------------------------------
March 31 June 30 September 30 December 31
----------- ----------- ---------------- ----------------
Index $ 29.86 $ 27.94 $ 26.50 $ 22.12
2001 27.22 25.32 25.06 18.72
Prices have improved since December 31, 2001. The NYMEX crude oil price
on March 22, 2002 was $25.35 per Bbl.
Hedging Activities. Our results of operations are significantly affected by
fluctuations in commodity prices and we seek to reduce our exposure to price
volatility by hedging our production through swaps, options and other commodity
derivative instruments.
In November 1996, we assumed hedge agreements extending through October 2001
with a counterparty involving various quantities and fixed prices. These hedge
agreements provided that we make payments to the counterparty to the extent the
market prices, determined based on the price for crude oil on the NYMEX and the
Inside FERC, Tennessee Gas Pipeline Co. Texas (Zone O) price for natural gas,
exceeded certain fixed prices and for the counterparty to make payments to us to
the extent the market prices were less than such fixed prices. We accounted for
the related gains or losses in crude oil and natural gas revenue in the period
of the hedged production. We terminated these hedge agreements in January 1999
and were paid $750,000 by the counterparty for such termination. This amount is
included in other income in the accompanying financial statements.
In March 1998, we entered into a costless collar hedge agreement with Enron
Capital and Trade Resources Corp. for 2,000 Bbls of crude oil per day with a
34
floor price of $14.00 per Bbl and a ceiling price of $22.30 per Bbl for crude
oil on the NYMEX. The agreement was effective April 1, 1998 and extended through
March 31, 1999. Under the terms of the agreement, we were paid when the average
monthly price for crude oil on the NYMEX is below the floor price and paid the
counterparty when the average monthly price exceeded the ceiling price. During
the year ended December 31, 1999, we realized a loss of $1.8 million on this
agreement, which is accounted for in crude oil and natural gas revenue.
We also entered into a hedge agreement with Barrett Resources Corporation
("Barrett") for the period November 1999 through October 2000. This agreement
was for 1,000 Bbls per day with us being paid $20.30 and an additional 1,000
barrels per day with a floor price of $18.00 per barrel and a ceiling of $22.00
per Bbl. We realized losses from hedges of $ 20.2 million and $12.1 million for
the years ended December 31, 2000 and 2001 respectively, which is accounted for
in crude oil and natural gas revenue.
At year end 2001, Barrett had a swap call on either 1,000 Bbls of crude oil
or 20,000 MMBtu of natural gas per day at Barrett's option at fixed prices
($18.90 for crude oil or $2.95 to $2.60 for natural gas) through October 31,
2002. As of December 31, 2001, the fair market value of the remaining fixed
price hedge agreement was a liability of approximately $658,000 which is
expected to be charged to revenues in 2002.
Selected Operating Data. The following table sets forth certain of our
operating data for the periods presented:
Years Ended December 31,
--------------------------------------------------------------
(dollars in thousands, except per unit data)
2001 2000 1999
------------------ ------------------ ------------------
Operating revenue:*
Crude oil sales* $ 11,184 $ 11,899 $ 11,330
NGLs sales 5,979 7,061 5,043
Natural gas sales* 56,038 54,013 42,652
Gas processing revenue 2,438 2,717 4,244
Other 1,604 910 3,501
------------------ ------------------ ------------------
Total operating revenue* $ 77,243 $ 76,600 $ 66,770
================== ================== ==================
Operating income (loss) $ 19,125 $ 11,943 $ (10,972)
Crude oil production (MBbls) 454.1 636.7 777.9
NGLs production (MBbls) 278.0 314.9 376.5
Natural gas production (MMcf) 17,495.6 19,962.5 25,697.9
Average crude oil sales price (per Bbl)* $ 24.63 $ 18.69 $ 14.57
Average NGLs sales price (per Bbl)* $ 21.5 $ 22.42 $ 13.40
Average natural gas sales price (per Mcf)* $ 3.20 $ 2.71 $ 1.66
*Revenue and average sales prices are net of hedging activities.
Comparison of Year Ended December 31, 2001 to Year Ended December 31, 2000
Operating Revenue. During the year ended December 31, 2001, operating
revenue from crude oil, natural gas and natural gas liquids sales increased by
$200,000 from $73.0 million in 2000 to $73.2 million in 2001. This increase was
primarily attributable to an increase in commodity prices offset by a decline in
production volumes. Increased prices contributed $12.9 million in additional
revenue, which was offset by $12.7 million due to a decrease in production
volumes. The decline in production was due to the disposition of certain
properties, primarily in Canada, natural field declines and our inability to
replace the production represented by the properties we have sold with new
production from the producing properties we invested in with the proceeds of our
property sales.
35
Natural gas liquids volumes declined from 314.9 MBbls in 2000 to 278.0 MBbls
in 2001. Crude oil sales volumes declined from 636.7 MBbls in 2000 to 454.1
MBbls during 2001. Natural gas sales volumes decreased from 20.0 Bcf in 2000 to
17.5 Bcf in 2001. Production declines were primarily attributable to our
disposition of assets during 2001 and our inability to replace the production
represented by the properties we have sold with new production from the
producing properties we invested in with the proceeds of our property sales.
Average sales prices in 2001 net of hedging losses were:
o $24.63 per Bbl of crude oil,
o $21.51 per Bbl of natural gas liquids, and
o $3.20 per Mcf of natural gas.
Average sales prices in 2000 net of hedging losses were:
o $18.69 per Bbl of crude oil,
o $22.42 per Bbl of natural gas liquids, and
o $2.71 per Mcf of natural gas.
We also had natural gas processing revenue of $2.4 million in 2001 as compared
to $2.7 million in 2000. The decline in processing revenue is due to a decrease
in third party natural gas being processed. We are utilizing more of the plant
capacity to process our own natural gas, leaving less capacity for third party
processing.
Lease Operating Expense. Lease operating expense ("LOE") and natural gas
processing costs decreased slightly from $18.8 million in 2000 to $18.6 million
in 2001. LOE on a per Mcfe basis for 2001 was $0.85 per Mcfe as compared to
$0.73 per Mcfe in 2000. The increase in the per Mcfe cost is due to a decline in
production volumes.
G&A Expense. General and administrative ("G&A") expense decreased from $6.5
million in 2000 to $6.4 million in 2001. The decline in G&A expenses is
primarily due to our efforts to control cost. Our G&A expense on a per Mcfe
basis increased from $0.27 in 2000 to $0.29 in 2001. The increase in the per
Mcfe cost was due primarily to lower production volumes in 2001 as compared to
2000.
G&A - Stock-based Compensation Expense. Effective July 1, 2000, the
Financial Accounting Standards Board ("FASB") issued FIN 44, "Accounting for
Certain Transactions Involving Stock Compensation", an interpretation of
Accounting Principles Board Opinion No. ("APB") 25. Under the interpretation,
certain modifications to fixed stock option awards which were made subsequent to
December 15, 1998, and not exercised prior to July 1, 2000, require that the
awards be subject to variable accounting until they are exercised, forfeited, or
expired. In March 1999, we amended the exercise price to $2.06 on all options
with an existing exercise price greater than $2.06. We charged approximately
$2.8 million to stock-based compensation expense in 2000 compared to crediting
approximately $2.8 million in 2001. This was due to the decline in the market
price of our Common stock during 2001.
DD&A Expense. Depreciation, depletion and amortization ("DD&A") expense
decreased by $3.4 million from $35.9 million in 2000 to $32.5 million in 2001.
Our DD&A expense on a per Mcfe basis for 2001 was $1.48 per Mcfe as compared to
$1.40 per Mcfe in 2000. The decline in DD&A is due to reductions in our full
cost pool resulting from ceiling test write-downs in prior years, as well as
lower production volumes.
Interest Expense. Interest expense increased by $400,000 from $31.1 million
to $31.5 million for 2001 compared to 2000. This increase resulted from an
increase in debt levels during 2001 compared to 2000. The increase in our debt
level was the result of additional sales pursuant to our production payment
arrangement with Mirant Americas, as well as additional funding from the Grey
Wolf Facility.
Ceiling Limitation Write-down. We record the carrying value of our crude oil
and natural gas properties using the full cost method of accounting for crude
36
oil and natural gas properties. Under this method, the Company capitalizes the
cost to acquire, explore for and develop crude oil and natural gas properties.
Under the full cost accounting rules, the net capitalized cost of crude oil and
natural gas properties less related deferred taxes, are limited by country, to
the lower of the unamortized cost or the cost ceiling, defined as the sum of the
present value of estimated unescalated future net revenues from proved reserves,
discounted at 10%, plus the cost of properties not being amortized, if any, plus
the lower of cost or estimated fair value of unproved properties included in the
costs being amortized, if any, less related income taxes. If the net capitalized
cost of crude oil and natural gas properties exceeds the ceiling limit, the
Company is subject to a ceiling limitation write-down to the extent of such
excess. A ceiling limitation write-down is a charge to earnings which does not
impact cash flow from operating activities. However, such write-downs do impact
the amount of the Company's stockholders' equity. The cost ceiling represents
the present value (discounted at 10%) of net cash flows from sales of future
production, using commodity prices on the last day of the quarter, 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.
The risk that we will be required to write-down the carrying value of our
crude oil and natural gas assets increases when crude oil and natural gas prices
are depressed or volatile. In addition, write-downs may occur if we have
substantial downward revisions in our estimated proved reserves or if purchasers
or governmental action cause an abrogation of, or if we voluntarily cancel,
long-term contracts for our natural gas. We cannot assure you that we will not
experience additional write-downs in the future. If commodity prices decline or
if any of our proved resources are revised downward, a further write-down of the
carrying value of our crude oil and natural gas properties may be required. See
Note 18 of Notes to Consolidated Financial Statements.
Minority interest. We owned a 49% interest in the earnings of Grey Wolf
through August 2001. The consolidated financial statements include the results
of Grey Wolf. The net income attributable to the minority interest in Grey Wolf
through August 2001 increased to $1.7 million in 2001 from $1.3 million in 2000.
This increase is due to improved profitability of Grey Wolf as a result of
improved commodity prices received in 2001 as compared to 2000. As of December
31, 2001, we owned 100% of the outstanding capital stock of Grey Wolf. We
obtained the additional interest in Grey Wolf pursuant to a tender offer and
subsequent compulsory merger, completed in September 2001.
Income taxes. Income tax expense decreased from $3.7 million for the year
ended December 31, 2000 to $2.4 million for the year ended December 31, 2001.
The decrease was primarily due to the tax benefit relating to the ceiling
limitation write-down relating to Canadian producing properties in 2001.
Other. In March 2000, Abraxas Wamsutter L.P. ("Partnership") sold all of its
interest in its crude oil and natural gas properties to a third party. Prior to
the sale of these properties, effective January 1, 2000, the Company's equity
investee share of crude oil and natural gas property cost, results of operations
and amortization were not material to consolidated operations or financial
position. As a result of the sale, the Company received approximately $34
million, which represented a proportional interest in the Partnership's proved
properties.
In June 2000, we retired $3.5 million of the Old Notes and $3.6 million of
the Second Lien Notes at a discount of $1.8 million.
37
Comparison of Year Ended December 31, 2000 to Year Ended December 31, 1999
Operating Revenue. During the year ended December 31, 2000, operating
revenue from crude oil, natural gas and natural gas liquids sales increased by
$14.0 million from $59.0 million in 1999 to $73.0 million in 2000. This increase
was primarily attributable to an increase in commodity prices. Increased prices
contributed $26.5 million in additional revenue, which was offset by $12.5
million due to a decrease in production volumes. The decline in production was
due to the disposition of certain properties, primarily in Canada.
Natural gas liquids volumes declined from 376.5 MBbls in 1999 to 314.9 MBbls
in 2000. Crude oil sales volumes declined from 777.9 MBbls in 1999 to 636.7
MBbls during 2000. Natural gas sales volumes decreased from 25.7 Bcf in 1999 to
20.0 Bcf in 2000. Production declines were primarily attributable to our
disposition of assets during 2000.
Average sales prices in 2000 net of hedging losses were:
o $18.69 per Bbl of crude oil,
o $22.42 per Bbl of natural gas liquids, and
o $2.71 per Mcf of natural gas.
Average sales prices in 1999 net of hedging losses were:
o $14.57 per Bbl of crude oil,
o $13.40 per Bbl of natural gas liquids, and
o $1.66 per Mcf of natural gas.
We also had natural gas processing revenue of $2.7 million in 2000 as compared
to $4.2 million in 1999. The decline in processing revenue is due to a decrease
in third party natural gas being processed. We are utilizing more of the plant
capacity to process our own natural gas, leaving less capacity for third party
processing.
Lease Operating Expense. LOE and natural gas processing costs increased by
$0.8 million from $17.9 million for 1999 to $18.8 million for 2000. LOE on a per
Mcfe basis for 2000 was $0.73 per Mcfe as compared to $0.55 per Mcfe in 1999.
The increase was due primarily to a general increase in the cost of services and
increased production taxes due to higher commodity prices in 2000 as compared to
1999. The increase in the per Mcfe cost is due to a decline in production
volumes.
G&A Expense. G&A expense increased from $5.3 million for the year ended
December 31, 1999 to $6.5 million for the year ended December 31, 2000. The
increase in G&A was due to the loss of approximately $600,000 of overhead billed
to the partnership, substantially all of the assets of which were sold in March
2000, and an increase in director compensation as a result of our restructuring
in the fourth quarter of 1999. Our G&A expense on a per Mcfe basis increased
from $0.16 in 1999 to $0.27 in 2000. The increase in the per Mcfe cost was due
partly to lower production volumes in 2000 as compared to 1999 as well as the
increase in expense in 2000 as compared to 1999.
G&A - Stock-based Compensation Expense. Effective July 1, 2000, the
Financial Accounting Standards Board ("FASB") issued FIN 44, "Accounting for
Certain Transactions Involving Stock Compensation", an interpretation of
Accounting Principles Board Opinion No. ("APB") 25. Under the interpretation,
certain modifications to fixed stock option awards which were made subsequent to
December 15, 1998, and not exercised prior to July 1, 2000, require that the
awards be subject to variable accounting until they are exercised, forfeited, or
expired. In March 1999, we amended the exercise price to $2.06 on all options
with an existing exercise price greater than $2.06. We recognized approximately
$2.8 million as stock-based compensation expense during 2000 related to these
repricings.
DD&A Expense. DD&A expense increased by $1.1 million from $34.8 million for
the year ended December 31, 1999 to $35.9 million for the year ended December
31, 2000. Our DD&A expense on a per Mcfe basis for 1999 was $1.07 per Mcfe as
compared to $1.40 per Mcfe in 2000. The increase in DD&A is the result of higher
finding costs for 2000.
38
Interest Expense. Interest expense decreased by $5.7 million from $36.8
million to $31.1 million for the year ended December 31, 2000 compared to 1999.
This decrease resulted from reduced debt levels during 2000 compared to 1999.
The reduced debt level was the result of the exchange of approximately $269.7
million principal amount of our Old Notes for approximately $188.8 million
principal of our Second Lien Notes, shares of our common stock and contingent
value rights.
Ceiling Limitation Write-down. We record the carrying value of our crude oil
and natural gas properties using the full cost method of accounting for crude
oil and natural gas properties. Under this method, we capitalize the cost to
acquire, explore for and develop crude oil and natural gas properties. Under the
full cost accounting rules, the net capitalized cost of crude oil and natural
gas properties less related deferred taxes, is limited by country, to the lower
of the unamortized cost or the cost ceiling, defined as the sum of the present
value of estimated unescalated future net revenues from proved reserves,
discounted at 10%, plus the cost of properties not being amortized, if any, plus
the lower of cost or estimated fair value of unproved properties included in the
costs being amortized, if any, less related income taxes. If the net capitalized
cost of crude oil and natural gas properties exceeds the ceiling limit, we are
subject to a ceiling limitation write-down to the extent of such excess. A
ceiling limitation write-down is a charge to earnings, which does not impact
cash flow from operating activities. However, such write-downs do impact the
amount of our stockholders' equity.
The risk that we will be required to write-down the carrying value of our
crude oil and natural gas assets increases when crude oil and natural gas prices
are depressed or volatile. In addition, write-downs may occur if we have
substantial downward revisions in our estimated proved reserves or if purchasers
or governmental action cause an abrogation of, or if we voluntarily cancel,
long-term contracts for our natural gas. For the year ended December 31, 1999,
we recorded a write-down of $19.1 million, $11.9 million after tax, related to
our Canadian properties. We cannot assure you that we will not experience
additional write-downs in the future. Should commodity prices decline or if any
of our proved reserves are revised downward , a further write-down of the
carrying value of our crude oil and natural gas properties may be required. See
Note 18 of Notes to Consolidated Financial Statements.
Minority interest. Minority interest in the net income of Grey Wolf, our
49% owned subsidiary during 1999 and 2000, increased to $1.3 million in 2000
from $269,000 in 1999. This increase was due to improved profitability of Grey
Wolf as a result of improved commodity prices received in 2000 as compared to
1999.
Income taxes. Income tax expense (benefit) increased from a benefit of
$12.6 million for the year ended December 31, 1999 to expense of $3.7 million
for the year ended December 31, 2000. The benefit for the year ended December
31, 1999 was primarily attributable to the ceiling limitation write down that
occurred in that year.
Other. In March 2000, the Partnership sold all of its interest in its crude
oil and natural gas properties to a third party. Prior to the sale of these
properties, effective January 1, 2000, the Company's equity investee share of
crude oil and natural gas property cost, results of operations and amortization
were not material to consolidated operations or financial position. As a result
of the sale, the Company received approximately $34 million, which represented a
proportional interest in the Partnership's proved properties.
In June 2000, we retired $3.5 million of the Old Notes and $3.6 million of
the Second Lien Notes at a discount of $1.8 million.
Liquidity and Capital Resources
General. The crude oil and natural gas industry is a highly capital
intensive and cyclical business. Our capital requirements are driven principally
by our obligations to service debt and to fund the following costs:
o the development of existing properties, including drilling and
completion costs of wells;
o acquisition of interests in crude oil and natural gas properties; and
o production and transportation facilities.
39
The amount of capital available to us will affect our ability to service our
existing debt obligations and to continue to grow the business through the
development of existing properties and the acquisition of new properties. Our
lack of liquidity and high debt levels have had a substantial impact on our
ability to develop existing properties and acquire new producing properties.
Our sources of capital are primarily cash on hand, cash from operating
activities, the sale of properties and financing activities, including sales of
production payments to Mirant Americas and funding from the Grey Wolf Facility
with Mirant Canada. Our overall liquidity depends heavily on the prevailing
prices of crude oil and natural gas and our production volumes of crude oil and
natural gas. Significant down-turns in commodity prices, such as that
experienced in 1999 and the last six months of 2001, can reduce our cash from
operating activities. Although we have hedged a portion of our natural gas and
crude oil production and may continue this practice, future crude oil and
natural gas price declines would have a material adverse effect on our overall
results, and therefore, our liquidity. Prices for natural gas and crude oil have
increased substantially since December 31, 2001; however, we cannot assure you
that these prices can be sustained in the future. For more detailed descriptions
of commodity prices, you should read the discussion under "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Results of Operations". 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. Furthermore, low crude oil and natural gas prices
could affect our ability to raise capital on terms favorable to us. Similarly,
our cash flow from operations will decrease if the volume of crude oil and
natural gas produced by us decreases. Our production volumes will decline as
reserves are produced. In addition, we have sold, and intend to continue to
sell, certain of our properties. To offset the loss in production volumes
resulting from natural field declines and sales of producing properties, we must
conduct successful exploration and development activities, acquire additional
producing properties or identify additional behind-pipe zones or secondary
recovery reserves. While we have had some success in pursuing these activities,
we have not been able to fully replace the production volumes lost from natural
field declines and property sales.
Working Capital. At December 31, 2001, we had current assets of $17.3 million
and current liabilities of $22.3 million resulting in a working capital deficit
of $5.0 million. The majority of our current liabilities at December 31, 2001,
were trade accounts payable of $10.5 million, revenues due third parties of $3.6
million and accrued interest of $6.0 million. Our capital resources and
liquidity are affected by the timing of our interest payments of approximately
$4.1 million each March 15, $11.0 million each May 1, $4.1 million each
September 15, and $11.0 million each November 1. As a result of these periodic
interest payments on our outstanding debt obligations, our cash balances will
decrease dramatically on certain dates during the year.
We will need additional funds in the future for both the development of our
assets and the service of our debt, including the repayment of the $63.5 million
in principal amount of the First Lien Notes maturing in March 2003 and the
$191.0 million of the Second Lien Notes and Old Notes maturing in November 2004.
In order to meet the goals of developing our assets and servicing our debt
obligations, we will be required to obtain additional sources of capital and/or
reduce or reschedule our existing cash requirements. In order to do so, we may
pursue one or more of the following alternatives:
o refinancing existing debt;
o repaying debt with proceeds from the sale of assets;
o exchanging debt for equity;
o managing the timing and reducing the scope of our capital expenditures;
o issuing debt or equity securities or otherwise raising additional
funds; or
40
o selling all or a portion of our existing assets, including interests in
our assets.
There can be no assurance that any of the above alternatives, or some
combination thereof, will be available or, if available, will be on terms
acceptable to us. See Part I, Item 1, Business - "Recent Events".
Capital Expenditures. Capital expenditures in 1999, 2000 and 2001 were
$128.7 million, $74.4 million and $57.1 million, respectively. The table below
sets forth the components of these capital expenditures on a historical basis
for the three years ended December 31, 1999, 2000 and 2001.
Year Ended December 31,
-------------------------------
2001 2000 1999
-------- --------- ---------
(dollars in thousands)
Expenditure category:
Property acquisitions $ -- $ 7,189 $ 89,743
Development ......... 56,694 64,873 37,344
Facilities and other 362 2,350 1,621
-------- -------- --------
Total ............... $ 57,056 $ 74,412 $128,708
======== ======== ========
During 2001 and 2000, expenditures were primarily for the development of
existing properties. In 1999, expenditures were primarily the acquisition of New
Cache Petroleums, Ltd. These expenditures were funded through internally
generated cash flow, the issuance of $63.5 million of the First Lien Notes,
borrowings under a credit facility and the sale of assets.
As cash flow permits our current budget for capital expenditures for 2002
other than acquisition expenditures is $37.4 million, approximately $11.0
million of which has been spent as of March 15, 2002. The remaining portion of
such expenditures is largely discretionary and will be made primarily for the
development of existing properties. Additional capital expenditures may be made
for acquisition of producing properties if such opportunities arise, but we
currently have no agreements, arrangements or undertakings regarding any
material acquisitions. We have no material long-term capital commitments and are
consequently able to adjust the level of our expenditures as circumstances
dictate. Additionally, the level of capital expenditures will vary during future
periods depending on market conditions and other related economic factors.
Should the prices of crude oil and natural gas decline, our cash flows will
decrease which may result in a further reduction of the capital expenditures
budget. If we decrease our capital expenditures budget, we will not be able to
offset crude oil and natural gas production volumes decreases caused by natural
field declines and sales of producing properties.
Sources of Capital. The net funds provided by and/or used in each of the
operating, investing and financing activities are summarized in the following
table and discussed in further detail below:
2001 2000 1999
-------- --------- ---------
(dollars in thousands)
Net cash provided by operating activities ......... $ 16,300 $ 21,400 $ 3,900
Net cash provided by (used in) financing activities 20,700 (3,800) 49,100
Net cash provided by (used in) investing activities (30,800) (18,800) (111,200)
--------- --------- ---------
Total ............................................. $ 6,200 $ (1,200) $ (58,200)
========= ========= =========
Operating activities for the year ended December 31, 2001, provided us $16.3
million of cash. Investing activities used $30.8 million during 2001. Our
investing activities included the sale of properties which provided $28.9
million, and the use of $57.1 million primarily for the development of producing
properties. Financing activities provided $20.7 million during 2001, including
the provision of additional funding of $11.7 million under our production
payment arrangement with Mirant Americas, and the provision of $18.3 million
under the Grey Wolf Facility. Payments on long term debt used $9.3 million.
41
Operating activities for the year ended December 31, 2000, provided us $21.4
million of cash. Investing activities used $18.8 million during 2000 comprised
of $34.5 million provided from the sale of an equity investment in Wamsutter
Holdings LP, $21.2 million provided from the sale of properties and $74.4
million used primarily for the acquisition and development of producing
properties. Financing activities used $3.8 million during 2000.
Operating activities for the year ended December 31, 1999, provided us $3.9
million of cash. Investing activities used $111.2 million during 1999, comprised
of $17.5 million provided from the sale of crude oil and natural gas producing
properties and $128.7 million used primarily for the acquisition and development
of producing properties. Financing activities provided $49.1 million during
1999.
Current Liquidity Needs. For several 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.
Our sale in March 1999 of our 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.
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 the
Edwards Trend to Mirant Americas. We have the ability to sell up to $50 million
to Mirant for drilling opportunities in South Texas.
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.
In March 2000, we sold our interest in certain crude oil and natural gas
properties that we owned and operated in Wyoming. Simultaneously, a limited
partnership of which one of our subsidiaries was the general partner, 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.
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.
In December 2001, Grey Wolf entered into a financing agreement with Mirant
Canada for CDN $150 million (approximately US $96 million), 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.
For more information regarding our liquidity needs, you should also read
Business - "Recent Events".
Future Capital Resources. We will have four principal sources of liquidity
going forward: (i) cash on hand, (ii) cash flow from operations, (iii) the
production payment with Mirant Americas and (iv) sales of properties. In
addition, Grey Wolf has additional borrowing capacity under its credit facility
with Mirant Canada. The terms of the First Lien Notes indenture, the Second Lien
Notes indenture and the Old Notes indenture substantially limit our use of
proceeds from sales of properties.
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;
42
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.
Furthermore, 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 restrictions on the use of proceeds
from asset sales. Proceeds from asset sales must generally be used for
investments in producing properties or related assets. In addition, the
indenture for the Second Lien Notes permits using proceeds to make payments
under the First Lien Notes. In the event that such proceeds are not used in this
manner, we must make an offer to note holders to purchase notes at 100% of the
principal amount. Such an offer must be made within 180 days of a property sale.
If commodity prices remain at, or fall below their current levels, it will
be necessary for us to delay discretionary capital expenditures and seek
alternative sources of capital in order to maintain liquidity.
Due to our current debt levels and the restrictions contained in the
indentures described above, our best opportunity for additional sources of
capital will be through the disposition of assets and some of the other
alternatives discussed above. For more information regarding our liquidity
needs, you should also read Business -"Recent Events". Although there may be
questions regarding our viability as a going concern, management believes that
the successful disposition of certain assets will allow us to meet our liquidity
needs for the next year, including the repayment of the $63.5 million in
principal amount of the First Lien Notes maturing in March 2003. We cannot
assure you that we will be successful in any of our efforts to improve liquidity
or that such efforts will produce enough cash to fund our operating and capital
requirements, make our interest payments or to make the principal payments due
on our First Lien Notes, Old Notes and Second Lien Notes.
Contractual Obligations
We are committed to making cash payments in the future on the following
types of agreements:
o Long-term debt
o Operating leases for office facilities
We have no off-balance sheet debt or other such unrecorded obligations and
we have not guaranteed the debt of any other party. Below is a schedule of the
future payments that we are obligated to make based on agreements in place as of
December 31, 2001.
Payments due in:
----------------------------------------------------------------------------
2005 and
Contractual Obligations Total 2002 2003 2004 after
- ---------------------------------------------------------------------------------------------------------------
Dollars in thousands
- ---------------------------------------------------------------------------------------------------------------
Long-Term Debt (1) (2) $285,599 $ - $63,500 $190,979 $ 22,944 (3)
Operating Leases (4) 1,513 528 336 236 413
(1) Includes $63.5 million of the First Lien Notes, $191.0 million of the Old
Notes and Second Lien Notes, $22.9 million under the Grey Wolf Facility and $8.2
million under the production payment with Mirant Americas.
(2) Mirant Americas is paid a percentage of revenue from South Texas wells on
which they have advanced production payments, the amount of the future payments
is dependent on production from the subject wells. As a result, no payments are
reflected in the table.
43
(3) The Grey Wolf Facility does not have scheduled repayments of principal prior
to its maturing in 2007. Instead, Grey Wolf is required to pay its net cash flow
on a monthly basis to Mirant Canada. We have included the entire amount
outstanding under the Grey Wolf Facility at December 31, 2001 ($23.0 million)
although we will be making payments prior to 2007. For more information on the
Grey Wolf Facility, you should read the description under "Grey Wolf Facility."
(4) Office lease obligations.
Other obligations
We make and will continue to make substantial capital expenditures for the
acquisition, exploitation, development, exploration and production of crude oil
and natural gas. In the past, we have funded our operations and capital
expenditures primarily through cash flow from operations, sales of properties,
sales of production payments to Mirant Americas and borrowings under our bank
credit facilities and other sources. Given our high degree of operating control,
the timing and incurrence of operating and capital expenditures is largely
within our discretion. As cash flow permits our capital expenditure budget for
2002 for existing operations and leaseholds is approximately $37 million.
Long-Term Indebtedness
Old Notes. On November 14, 1996, Abraxas and Canadian Abraxas consummated
the offering of $215.0 million of their 11.5% Senior Notes due 2004, Series A,
which were exchanged for Series B Notes in February 1997. On January 27, 1998,
Abraxas and Canadian Abraxas completed the sale of $60.0 million of the Series C
Notes. The Series B Notes and the Series C Notes were subsequently exchanged for
$275.0 million in principal amount of the Old Notes in June 1998.
Interest on the Old Notes is payable semi-annually in arrears on May 1 and
November 1 of each year at the rate of 11.5% per annum. The Old Notes are
redeemable, in whole or in part, at the option of Abraxas and Canadian Abraxas,
on or after November 1, 2000, at the redemption prices set forth below, plus
accrued and unpaid interest to the date of redemption, if redeemed during the
12-month period commencing on November 1 of the years set forth below:
Year Percentage
---- ----------
2001.............................................. 102.875%
2002 and thereafter............................... 100.000%
The Old Notes are joint and several obligations of Abraxas and Canadian
Abraxas and rank pari passu in right of payment to all existing and future
unsubordinated indebtedness of Abraxas and Canadian Abraxas. The Old Notes rank
senior in right of payment to all future subordinated indebtedness of Abraxas
and Canadian Abraxas. The Old Notes are, however, effectively subordinated to
the First Lien Notes to the extent of the value of the collateral securing the
First Lien Notes and the Second Lien Notes to the extent of the value of the
collateral securing the Second Lien Notes. The Old Notes are unconditionally
guaranteed, on a senior basis by a wholly-owned Abraxas subsidiary, Sandia Oil &
Gas Corporation. The guarantee is a general unsecured obligation of Sandia and
ranks pari passu in right of payment to all unsubordinated indebtedness of
Sandia and senior in right of payment to all subordinated indebtedness of
Sandia. The guarantee is effectively subordinated to the First Lien Notes and
the Second Lien Notes to the extent of the value of the collateral securing
these obligations.
Upon a change of control, as defined in the Old Notes Indenture, each holder
of the Old Notes will have the right to require Abraxas and Canadian Abraxas to
repurchase all or a portion of such holder's Old Notes at a redemption price
equal to 101% of the principal amount thereof, plus accrued and unpaid interest
to the date of repurchase. In addition, Abraxas and Canadian Abraxas will be
obligated to offer to repurchase the Old Notes at 100% of the principal amount
thereof plus accrued and unpaid interest to the date of repurchase in the event
of certain asset sales.
44
First Lien Notes. In March 1999, Abraxas consummated the sale of $63.5
million of the First Lien Notes. Interest on the First Lien Notes is payable
semi-annually in arrears on March 15 and September 15, commencing September 15,
1999. The First Lien Notes are redeemable, in whole or in part, at the option of
Abraxas at 100% of the principal amount, plus accrued and unpaid interest to the
date of redemption.
The First Lien Notes are senior indebtedness of Abraxas secured by a first
lien or charge on substantially all of the crude oil and natural gas properties
of Abraxas and the shares of Grey Wolf owned by Abraxas. The First Lien Notes
are unconditionally guaranteed on a senior basis, jointly and severally, by
Canadian Abraxas, Sandia and one of our wholly-owned subsidiaries, Wamsutter
Holdings, Inc. (the "Restricted Subsidiaries"). The guarantees are secured by
substantially all of the crude oil and natural gas properties of the guarantors
and the shares of Grey Wolf owned by Canadian Abraxas.
Upon a change of control, as defined in the First Lien Notes Indenture, each
holder of the First Lien Notes will have the right to require Abraxas to
repurchase such holder's First Lien Notes at a redemption price equal to 101% of
the principal amount thereof plus accrued and unpaid interest to the date of
repurchase. In addition, Abraxas will be obligated to offer to repurchase the
First Lien Notes at 100% of the principal amount thereof plus accrued and unpaid
interest to the date of redemption in the event of certain asset sales.
The First Lien Notes indenture contains certain covenants that limit the
ability of Abraxas and certain of its subsidiaries, including the guarantors of
the First Lien Notes to, among other things, incur additional indebtedness, pay
dividends or make certain other restricted payments, consummate certain asset
sales, enter into certain transactions with affiliates, incur liens, merge or
consolidate with any other person or sell, assign, transfer, lease, convey or
otherwise dispose of all or substantially all of the assets of Abraxas.
The First Lien Notes indenture provides, among other things, that Abraxas
may not, and may not cause or permit the Restricted Subsidiaries, to, directly
or indirectly, create or otherwise cause to permit to exist or become effective
any encumbrance or restriction on the ability of such subsidiary to pay
dividends or make distributions on or in respect of its capital stock, make
loans or advances or pay debts owed to Abraxas or any other Restricted
Subsidiary, guarantee any indebtedness of Abraxas or any other Restricted
Subsidiary or transfer any of its assets to Abraxas or any other Restricted
Subsidiary except for such encumbrances or restrictions existing under or by
reason of:
(1) applicable law;
(2) the First Lien Notes indenture;
(3) customary non-assignment provisions of any contract or any lease
governing leasehold interest of such subsidiaries;
(4) any instrument governing indebtedness assumed by us in an
acquisition, which encumbrance or restriction is not applicable to such
Restricted Subsidiary or the properties or assets of such subsidiary other than
the entity or the properties or assets of the entity so acquired;
(5) agreements existing on the Issue Date (as defined in the First Lien
Notes indenture) to the extent and in the manner such agreements were in effect
on the Issue Date;
(6) customary restrictions with respect to subsidiaries of Abraxas
pursuant to an agreement that has been entered into for the sale or disposition
of capital stock or assets of such Restricted Subsidiary to be consummated in
accordance with the terms of the First Lien Notes indenture or any Security
Documents (as defined in the First Lien Notes indenture) solely in respect of
the assets or capital stock to be sold or disposed of;
(7) any instrument governing certain liens permitted by the First Lien
Notes indenture, to the extent and only to the extent such instrument restricts
the transfer or other disposition of assets subject to such lien; or
45
(8) an agreement governing indebtedness incurred to refinance the
indebtedness issued, assumed or incurred pursuant to an agreement referred to in
clause (2), (4) or (5) above; provided, however, that the provisions relating to
such encumbrance or restriction contained in any such refinancing indebtedness
are no less favorable to the holders of the First Lien Notes in any material
respect as determined by the Board of Directors of Abraxas in their reasonable
and good faith judgment that the provisions relating to such encumbrance or
restriction contained in the applicable agreement referred to in such clause
(2), (4) or (5) and do not extend to or cover any new or additional property or
assets and, with respect to newly created liens, (A) such liens are expressly
junior to the liens securing the First Lien Notes, (B) the refinancing results
in an improvement on a pro forma basis in Abraxas' Consolidated EBITDA Coverage
Ratio (as defined in the First Lien Notes indenture) and (C) the instruments
creating such liens expressly subject the foreclosure rights of the holders of
the refinanced indebtedness to a stand-still of not less than 179 days.
Second Lien Notes. In December 1999, Abraxas and Canadian Abraxas completed
an Exchange Offer whereby $269,699,000 of the Old Notes were exchanged for
$188,778,000 of the new Second Lien Notes. An additional $5,000,000 of the
Second Lien Notes were issued in payment of fees and expenses. Interest on the
Second Lien Notes is payable semi-annually in arrears on May 1 and November 1,
commencing May 1, 2000. The Second Lien Notes are redeemable, in whole or in
part, at the option of Abraxas and Canadian Abraxas on or after December 1,
2000, at the redemption prices set forth below, plus accrued and unpaid interest
to the date of redemption, if redeemed during the 12-month period commencing on
December 1 of the years set forth below:
Year Percentage
----- ----------
2001............................................. 102.875%
2002 and thereafter.............................. 100.000%
The Second Lien Notes are senior indebtedness of Abraxas and Canadian
Abraxas and are secured by a second lien on substantially all of the crude oil
and natural gas properties of Abraxas and Canadian Abraxas and the shares of
Grey Wolf owned by Abraxas and Canadian Abraxas. The Second Lien Notes are
unconditionally guaranteed on a senior basis, jointly and severally, by Sandia
and Wamsutter. The guarantees are secured by substantially all of the crude oil
and natural gas properties of the guarantors. The Second Lien Notes are,
however, effectively subordinated to the First Lien Notes and related guarantees
to the extent the value of the collateral securing the Second Lien Notes and
related guarantees and the First Lien Notes and related guarantees is
insufficient to pay both the Second Lien Notes and the First Lien Notes.
Upon a change of control, as defined in Second Lien Notes Indenture, each
holder of the Second Lien Notes will have the right to require Abraxas and
Canadian Abraxas to repurchase such holder's Second Lien Notes at a redemption
price equal to 101% of the principal amount thereof plus accrued and unpaid
interest to the date of repurchase. In addition, Abraxas and Canadian Abraxas
will be obligated to offer to repurchase the Second Lien Notes at 100% of the
principal amount thereof plus accrued and unpaid interest to the date of
redemption in the event of certain asset sales.
The Second Lien Notes indenture contains certain covenants that limit the
ability of Abraxas and Canadian Abraxas and certain of their subsidiaries,
including the guarantors of the Second Lien Notes (the "Restricted
Subsidiaries") to, among other things, incur additional indebtedness, pay
dividends or make certain other restricted payments, consummate certain asset
sales, enter into certain transactions with affiliates, incur liens, merge or
consolidate with any other person or sell, assign, transfer, lease, convey or
otherwise dispose of all or substantially all of the assets of Abraxas or
Canadian Abraxas.
The Second Lien Notes indenture provides, among other things, that Abraxas
and Canadian Abraxas may not, and may not cause or permit the Restricted
Subsidiaries, to, directly or indirectly, create or otherwise cause to permit to
exist or become effective any encumbrance or restriction on the ability of such
subsidiary to pay dividends or make distributions on or in respect of its
capital stock, make loans or advances or pay debts owed to Abraxas, Canadian
Abraxas or any other Restricted Subsidiary, guarantee any indebtedness of
Abraxas, Canadian Abraxas or any other Restricted Subsidiary or transfer any of
its assets to Abraxas, Canadian Abraxas or any other Restricted Subsidiary
except for such encumbrances or restrictions existing under or by reason of:
46
(1) applicable law;
(2) the Old Notes indenture, the First Lien Notes indenture, or the
Second Lien Notes indenture;
(3) customary non-assignment provisions of any contract or any lease
governing leasehold interest of such subsidiaries;
(4) any instrument governing indebtedness assumed by us in an
acquisition, which encumbrance or restriction is not applicable to such
Restricted Subsidiary or the properties or assets of such subsidiary other than
the entity or the properties or assets of the entity so acquired;
(5) agreements existing on the Issue Date (as defined in the Second
Lien Notes indenture) to the extent and in the manner such agreements were in
effect on the Issue Date;
(6) customary restrictions with respect to subsidiaries of Abraxas and
Canadian Abraxas pursuant to an agreement that has been entered into for the
sale or disposition of capital stock or assets of such Restricted Subsidiary to
be consummated in accordance with the terms of the Second Lien Notes solely in
respect of the assets or capital stock to be sold or disposed of;
(7) any instrument governing certain liens permitted by the Second Lien
Notes indenture, to the extent and only to the extent such instrument restricts
the transfer or other disposition of assets subject to such lien; or
(8) an agreement governing indebtedness incurred to refinance the
indebtedness issued, assumed or incurred pursuant to an agreement referred to in
clause (2), (4) or (5) above; provided, however, that the provisions relating to
such encumbrance or restriction contained in any such refinancing indebtedness
are no less favorable to the holders of the Second Lien Notes in any material
respect as determined by the Board of Directors of Abraxas in their reasonable
and good faith judgment that the provisions relating to such encumbrance or
restriction contained in the applicable agreement referred to in such clause
(2), (4) or (5).
Grey Wolf Facility
General. On December 20, 2001, Grey Wolf entered into a credit facility with
Mirant Canada. The Grey Wolf facility established a revolving credit facility
with a commitment amount of CDN $150 million, (approximately US $96 million).
Subject to certain restrictions, the borrowing base may be reduced in the
discretion of Mirant Canada upon 30 days written notice. Subject to earlier
termination on the occurrence of events of default or other events, the stated
maturity date of the credit facility is December 20, 2007. The applicable
interest rate charged on the outstanding balance under the Grey Wolf Facility is
9.5%. Any amounts in default under the facility will accrue interest at 15%. The
Grey Wolf Facility is non-recourse to Abraxas and its properties, other than
Grey Wolf properties, and Abraxas has no additional direct obligations to Mirant
Canada under the facility.
Principal Payments. Prior to maturity, Grey Wolf is required to make
principal payments under the Grey Wolf Facility as follows:
(i) on the date of the sale of any producing properties, Grey Wolf is
required to make a payment equal to the amount of the net sales proceeds;
(ii) on a monthly basis, Grey Wolf is required to make a payment equal
to its net cash flow for the month prior to the date of the payment; and
(iii) on the date of any reduction in the commitment amount becomes
effective, Grey Wolf must repay all amounts over the commitment amount so
reduced.
47
Under the Grey Wolf Facility, "net cash flow" generally means the amount of
proceeds received by Grey Wolf from the sale of hydrocarbons less taxes, royalty
and similar payments (including overriding royalty interest payments made to
Mirant Canada), interest payments made to Mirant Canada and operating and other
expenses including approved capital and G&A expenses.
Grey Wolf may also make pre-payments at any time after December 20, 2002.
The Grey Wolf Facility matures in 2007. The Company treats the Grey Wolf
Facility as a revolving line of credit since, under ordinary circumstances, the
lender is paid on a net cash flow basis. It is anticipated that the Company will
be a net borrower for the next several years due to a large number of
exploration and exploitation projects and the associated capital needs to
complete the projects.
Security. Obligations under the Grey Wolf Facility are secured by a security
interest in substantially all of Grey Wolf's assets, including, without
limitation, working capital interests in producing properties and related assets
owned by Grey Wolf. None of Abraxas' assets are subject to a security interest
under the Grey Wolf Facility.
Covenants. The Grey Wolf Facility contains a number of covenants that, among
other things, restrict the ability of Grey Wolf to (i) enter into new business
areas, (ii) incur additional indebtedness, (iii) create or permit to be created
any liens on any of its properties, (iv) make certain payments, dividends and
distributions, (v) make any unapproved capital expenditures, (vi) sell any of
its accounts receivable, (vii) enter into any unapproved leasing arrangements,
(viii) enter into any take-or-pay contracts, (ix) liquidate, dissolve,
consolidate with or merge into any other entity, (x) dispose of its assets, (xi)
abandon any property subject to Mirant Canada's security interest, (xii) modify
any of its operating agreements, (xiii) enter into any unapproved hedging
agreements, and (xiv) enter into any new agreements affecting existing
agreements relating to or affecting properties subject to Mirant Canada's
security interests. In addition, Grey Wolf is required to submit a quarterly
development plan for Mirant Canada's approval and Grey Wolf must comply with
specified financial ratios and tests, including a minimum collateral coverage
ratio.
Events of Default. The Grey Wolf Facility contains customary events of
default, including nonpayment of principal or interest, violations of covenants,
inaccuracy of representations or warranties in any material respect, cross
default and cross acceleration to certain other indebtedness, bankruptcy,
material judgments and liabilities, change of control and any material adverse
change in the financial condition of Grey Wolf.
Overriding Royalty Interests. As a condition to the Grey Wolf Facility, Grey
Wolf has granted two overriding royalty interests to Mirant Canada, each in the
amount of 2.5% of the revenues received by Grey Wolf from crude oil and natural
gas sales from all of its properties.
Net Operating Loss Carryforwards
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
48
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.
Critical Accounting Policies
The preparation of financial statements in conformity with generally
accepted accounting principles requires that management apply accounting
policies and make estimates and assumptions that affect results of operations
and the reported amounts of assets and liabilities in the financial statements.
The following represents those policies that management believes are
particularly important to the financial statements and that require the use of
estimates and assumptions to describe matters that are inherently uncertain.
Full Cost Method of Accounting for Crude oil and Natural gas Activities.
SEC Regulation S-X defines the financial accounting and reporting standards for
companies engaged in crude oil and natural gas activities. Two methods are
prescribed: the successful efforts method and the full cost method. Abraxas has
chosen to follow the full cost method. At the time it was adopted, management
believed that this method would be preferable, as earnings tend to be less
volatile than under the successful efforts method. See Note 1 of the Notes to
Consolidated Financial Statements.
However, the full cost method makes us susceptible to significant non-cash
charges during times of volatile commodity prices because the full cost pool may
be impaired when prices are low. These charges are not recoverable when prices
return to higher levels. The Company has experienced this situation several
times over the years and experienced it again in 2001. Our crude oil and natural
gas reserves have a relatively long life. However, temporary drops in commodity
prices can have a material impact on our business including impact from the full
cost method of accounting.
Under the full cost method of accounting, we record the carrying value of
our crude oil and natural gas properties, and capitalize the cost to acquire,
explore for and develop crude oil and natural gas properties. The net
capitalized cost of crude oil and natural gas properties less related deferred
taxes, is limited by country, to the lower of the unamortized cost or the cost
ceiling, defined as the sum of the present value of estimated unescalated future
net revenues from proved reserves, discounted at 10%, plus the cost of
properties not being amortized, if any, plus the lower of cost or estimated fair
value of unproved properties included in the costs being amortized, if any, less
related income taxes. If the net capitalized cost of crude oil and natural gas
properties exceeds the ceiling limit, we are subject to a ceiling limitation
write-down to the extent of such excess. A ceiling limitation write-down is a
charge to earnings which does not impact cash flow from operating activities.
However, such write-downs do impact the amount of our stockholders' equity.
The risk that we will be required to write-down the carrying value of our
crude oil and natural gas assets increases when crude oil and natural gas prices
are depressed or volatile. In addition, write-downs may occur if we have
49
substantial downward revisions in our estimated proved reserves or if purchasers
or governmental action cause an abrogation of, or if we voluntarily cancel,
long-term contracts for our natural gas. For the year ended December 31, 2001,
we recorded a write-down of $2.6 million, related to our Canadian proved
reserves. The write-down in 2001 was due to low commodity prices. For the year
ended December 31, 1999, we recorded a write-down of $19.1 million, related to
our Canadian properties. We cannot assure you that we will not experience
additional write-downs in the future. Should commodity prices decline, a further
write-down of the carrying value of our crude oil and natural gas properties may
be required. See Note 18 of Notes to Consolidated Financial Statements.
Hedge Accounting. Statement of Financial Accounting Standards, ("SFAS") No.
133, "Accounting for Derivative Instruments and Hedging Activities", was
effective for the Company on January 1, 2001. SFAS 133, as amended and
interpreted, establishes accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts, and for hedging activities. All derivatives, whether designated in
hedging relationships or not, will be required to be recorded on the balance
sheet at fair value. If the derivative is designated a fair-value hedge, the
changes in the fair value of the derivative and the hedged item will be
recognized in earnings. If the derivative is designated a cash-flow hedge,
changes in the fair value of the derivative will be recorded in other
comprehensive income (OCI) and will be recognized in the income statement when
the hedged item affects earnings. SFAS 133 defines new requirements for
designation and documentation of hedging relationships as well as ongoing
effectiveness assessments in order to use hedge accounting. For a derivative
that does not qualify as a hedge, changes in fair value will we recognized in
earnings.
New Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 141, Business Combinations, which requires the purchase method of accounting
for business combinations initiated after June 30, 2001 and eliminates the
pooling-of-interests method. In July 2001, the FASB also issued SFAS No. 142,
Goodwill and Other Intangible Assets, which discontinues the practice of
amortizing goodwill and indefinite lived intangible assets and initiates an
annual review for impairment. Intangible assets with a determinable useful life
will continue to be amortized over that period. The amortization provisions
apply to goodwill and intangible assets acquired after June 30, 2001. The
Company has applied these standards to its purchase of the minority interest of
Grey Wolf.
In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations. SFAS No. 143 requires an asset retirement obligation to be recorded
at fair value during the period incurred and an equal amount recorded as an
increase in the value of the related long-lived asset. The capitalized cost is
depreciated over the useful life of the asset and the obligation is accreted to
its present value each period. SFAS No. 143 is effective for the Company
beginning January 1, 2003 with earlier adoption encouraged. The Company is
currently evaluating the impact the standard will have on its future results of
operations and financial condition.
In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment
of Disposal of Long-Lived Assets. SFAS No. 144 retains the requirement to
recognize an impairment loss only where the carrying value of a long-lived asset
is not recoverable from its undiscounted cash flows and to measure such loss as
the difference between the carrying amount and fair value of the asset. SFAS No.
144, among other things, changes the criteria that have to be met to classify an
asset as held-for-sale and requires that operating losses from the discontinued
operations be recognized in the period that the losses are incurred rather than
as of the measurement date. SFAS No. 144 is effective for the Company beginning
January 1, 2002 with earlier adoption encouraged. The Company is currently
evaluating the impact the standard will have on its future results of operations
and financial condition.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Commodity Price Risk
As an independent crude oil and natural gas producer, our revenue, cash flow
from operations, other income and equity earnings and profitability, reserve
values, access to capital and future rate of growth are substantially dependent
upon the prevailing prices of crude oil, natural gas and natural gas liquids.
50
Declines in commodity prices will materially adversely affect our financial
condition, liquidity, ability to obtain financing and operating results. Lower
commodity prices may reduce the amount of crude oil and natural gas that we can
produce economically. Prevailing prices for such commodities are subject to wide
fluctuation in response to relatively minor changes in supply and demand and a
variety of additional factors beyond our control, such as global political and
economic conditions. Historically, prices received for crude oil and natural gas
production have been volatile and unpredictable, and such volatility is expected
to continue. Most of our production is sold at market prices. Generally, if the
commodity indexes fall, the price that we receive for our production will also
decline. Therefore, the amount of revenue that we realize is partially
determined by factors beyond our control. We attempt to manage the volatility of
crude oil and natural gas prices through the periodic use of commodity price
hedging agreements. We covered approximately 42% of our production in 2001 with
hedge agreements. Without those arrangements, our realized natural gas prices
would have been $0.70 per Mcf higher in 2001. You should read the discussion
under "Management's Discussion and Analysis of Financial Condition and Results
of Operations " for more information regarding our hedging activities and impact
of commodity price changes. Assuming the production levels we attained during
the year ended December 31, 2001, a 10% decline in crude oil, natural gas and
natural gas liquids prices would have reduced our operating revenue, cash flow
and net income by approximately $7.3 million for the year. See Part I, Item 1,
Business - "Recent Events".
Hedging Sensitivity
The fair value of our remaining hedge instrument was determined based on
NYMEX forward price quotes as of December 31, 2001. As of December 31, 2001, a
commodity price increase of 10% would have resulted in an unfavorable change in
the fair market value of our hedging instrument of $1.2 million and a commodity
price decrease of 10% would have resulted in a favorable change in the fair
value of our hedge instrument of $852,000.
The following table sets forth our hedge position as of December 31, 2001.
Time Period Notional Quantities Price Fair Value
- ------------------------------------------------ --------------------------- ---------------------------- --------------------
January 1, 2002 - October 31, 2002 20,000 Mcf/day of natural Fixed price swap $(658,000)
gas or 1,000 Bbl/day of $2.60-$2.95 natural gas or
crude oil $18.90 Crude oil
Interest rate risk
At December 31, 2001, substantially all of Abraxas' long-term debt was at
fixed interest rates from 11.5% to 12.875% and not subject to fluctuations in
market rates and Grey Wolf's long-term debt was at a fixed interest rate of
9.5%.
Foreign currency
Our Canadian operations are measured in the local currency of Canada. As a
result, our financial results are affected by changes in foreign currency
exchange rates or weak economic conditions in the foreign markets. Canadian
operations reported a pre-tax loss of $1.3 million for the year ended December
31, 2001. It is estimated that a 5% change in the value of the U.S. dollar to
the Canadian dollar would have changed our net income by approximately $65,000.
We do not maintain any derivative instruments to mitigate the exposure to
translation risk. However, this does not preclude the adoption of specific
hedging strategies in the future.
Item 8. Financial Statements
For the financial statements and supplementary data required by this Item 8,
see the Index to Consolidated Financial Statements .
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None
51
PART III
Item 10. Directors and Executive Officers of the Registrant
There is incorporated in this Item 10 by reference that portion of our
definitive proxy statement for the 2002 Annual Meeting of Stockholders which
appears therein under the caption "Election of Directors". See also the
information in Item 4a of Part I of this Report.
Item 11. Executive Compensation
There is incorporated in this Item 11 by reference that portion of our
definitive proxy statement for the 2002 Annual Meeting of Stockholders which
appears therein under the caption "Executive Compensation", except for those
parts under the captions "Compensation Committee Report on Executive
Compensation," "Performance Graph", "Audit Committee Report" and "Report on
Repricing of Options."
Item 12. Security Ownership of Certain Beneficial Owners and Management
There is incorporated in this Item 12 by reference that portion of our
definitive proxy statement for the 2002 Annual Meeting of Stockholders which
appears therein under the caption "Securities Holdings of Principal
Stockholders, Directors and Officers."
Item 13. Certain Relationships and Related Transactions
There is incorporated in this Item 13 by reference that portion of our
definitive proxy statement for the 2002 Annual Meeting of Stockholders which
appears therein under the caption "Certain Transactions."
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a)1. Consolidated Financial Statements Page
----
Report of Deloitte & Touche LLP, Independent Auditors...............F-2
Report of Ernst & Young LLP, Independent Auditors...................F-3
Consolidated Balance Sheets,
December 31, 2001 and 2000........................................F-4
Consolidated Statements of Operations,
Years Ended December 31, 2001, 2000 and 1999......................F-6
Consolidated Statements of Stockholders' Equity (Deficit)
Years Ended December 31, 2001, 2000 and 1999.....................F-7
Consolidated Statements of Cash Flows
Years Ended December 31, 2001, 2000 and 1999......................F-9
Notes to Consolidated Financial Statements.........................F-11
Grey Wolf Exploration Inc.
Report of Deloitte & Touche LLP, Independent Auditors..............F-43
Report of Ernst & Young LLP, Independent Auditors..................F-45
Balance Sheets at December 31, 2001 and 2000.......................F-46
Statements of Earnings and Retained Earnings
Years ended December 31, 2001, 2000 and 1999.....................F-47
Statements of Cash Flows
Years ended December 31, 2001, 2000 and 1999.....................F-48
Notes to Financial Statements......................................F-49
(a)2. Financial Statement Schedules
52
All schedules have been omitted because they are not applicable, not
required under the instructions or the information requested is set forth in the
consolidated financial statements or related notes thereto.
(a)3.Exhibits
The following Exhibits have previously been filed by the Registrant
or are included following the Index to Exhibits.
Exhibit Number. Description
3.1 Articles of Incorporation of Abraxas. (Filed as Exhibit 3.1 to Abraxas'
Registration Statement on Form S-4, No. 33-36565 (the "S-4 Registration
Statement")).
3.2 Articles of Amendment to the Articles of Incorporation of Abraxas dated
October 22, 1990. (Filed as Exhibit 3.3 to the S-4 Registration Statement).
3.3 Articles of Amendment to the Articles of Incorporation of Abraxas dated
December 18, 1990. (Filed as Exhibit 3.4 to the S-4 Registration Statement).
3.4 Articles of Amendment to the Articles of Incorporation of Abraxas dated June
8, 1995. (Filed as Exhibit 3.4 to Abraxas' Registration Statement on Form S-3,
No. 333-00398 (the "S-3 Registration Statement")).
3.5 Articles of Amendment to the Articles of Incorporation of Abraxas dated as
of August 12, 2000 (Filed as Exhibit 3.5 to Abraxas' Annual Report of Form 10-K
filed April 2, 2001)
3.6 Amended and Restated Bylaws of Abraxas. (Filed herewith).
4.1 Specimen Common Stock Certificate of Abraxas. (Filed as Exhibit 4.1 to the
S-4 Registration Statement).
4.2 Specimen Preferred Stock Certificate of Abraxas. (Filed as Exhibit 4.2 to
Abraxas' Annual Report on Form 10-K filed on March 31, 1995).
4.3 Rights Agreement dated as of December 6, 1994 between Abraxas and First
Union National Bank of North Carolina ("FUNB"). (Filed as Exhibit 4.1 to
Abraxas' Registration Statement on Form 8-A filed on December 6, 1994).
4.4 Amendment to Rights Agreement dated as of July 14, 1997 by and between
Abraxas and American Stock Transfer & Trust Company (Filed as Exhibit 1 to
Amendment No. 1 to Abraxas' Registration Statement on Form 8-A filed on August
20, 1997).
4.5 Second Amendment to Rights Agreement as of May 22, 1998, by and between
Abraxas and American Stock Transfer & Trust Company (Filed as Exhibit 1 to
Amendment No. 2 to Abraxas' Registration Statement on Form 8-A filed on August
24, 1998)
4.6 Indenture dated January 27, 1999 by and among Abraxas, Canadian Abraxas and
IBJ Schroder Bank & Trust Company (filed as Exhibit 4.1 to Abraxas' Current
Report on Form 8-K dated February 5, 1999).
4.7 Third Supplemental Indenture dated December 21, 1999, by and among Abraxas,
Canadian Abraxas and The Bank of New York f/k/a IBJ Schroder Bank & Trust
Company (Filed as Exhibit 4.7 to Abraxas' Registration Statement on Form S-1,
No. 333-95281 (the "2000 S-1 Registration Statement")).
53
4.8 Indenture dated March 26, 1999 by and among Abraxas, Canadian Abraxas, New
Cache, Sandia and Norwest Bank Minnesota, National Association (Filed as Exhibit
4.6 to Abraxas' Annual Report on Form 10-K dated March 31, 1999).
4.9 Indenture dated December 21, 1999, by and among Abraxas, Canadian Abraxas,
Sandia, New Cache, Wamsutter and Firstar Bank, National Association (Filed as
Exhibit T3C to Abraxas' and Canadian Abraxas' Indenture Qualification on Form
T3-A, No. 022-22449).
4.10 Form of Old Note (Filed as Exhibit A to Exhibit 4.6).
4.11 Form of First Lien Note (Filed as Exhibit A to Exhibit 4.8).
4.12 Form of Second Lien Note (Filed as Exhibit A to Exhibit 4.9).
*10.1 Abraxas Petroleum Corporation 1984 Non-Qualified Stock Option Plan, as
amended and restated. (Filed as Exhibit 10.7 to Abraxas' Annual Report on Form
10-K filed April 14, 1993).
*10.2 Abraxas Petroleum Corporation 1984 Incentive Stock Option Plan, as amended
and restated. (Filed as Exhibit 10.8 to Abraxas' Annual Report on Form 10-K
filed April 14, 1993).
*10.3 Abraxas Petroleum Corporation 1993 Key Contributor Stock Option Plan.
(Filed as Exhibit 10.9 to Abraxas' Annual Report on Form 10-K filed April 14,
1993
*10.4 Abraxas Petroleum Corporation 401(k) Profit Sharing Plan. (Filed as
Exhibit 10.4 to Abraxas and Canadian Abraxas' Registration Statement on Form
S-4, No. 333-18673, (the "1996 Exchange Offer Registration Statement")).
*10.5 Abraxas Petroleum Corporation Director Stock Option Plan. (Filed as
Exhibit 10.5 to the 1996 Exchange Offer Registration Statement).
*10.6 Abraxas Petroleum Corporation Restricted Share Plan for Directors. (Filed
as Exhibit 10.20 to Abraxas' Annual Report on Form 10-K filed on April 12,
1994).
*10.7 Abraxas Petroleum Corporation 1994 Long Term Incentive Plan. (Filed as
Exhibit 10.21 to Abraxas' Annual Report on Form 10-K filed on April 12, 1994).
*10.8 Abraxas Petroleum Corporation Incentive Performance Bonus Plan. (Filed as
Exhibit 10.24 to Abraxas' Annual Report on Form 10-K filed on April 12, 1994).
10.9 Common Stock Purchase Warrant dated August 11, 1993 between Abraxas and
Associated Energy Managers, Inc. (Filed as Exhibit 10.37 to the 1993 S-1
Registration Statement).
10.10 Form of Indemnity Agreement between Abraxas and each of its directors and
officers. (Filed as Exhibit 10.30 to the 1993 S-1 Registration Statement).
*10.11 Employment Agreement between Abraxas and Robert L. G. Watson. (Filed as
Exhibit 10.19 to the 2000 S-1 Registration Statement).
*10.12 Employment Agreement between Abraxas and Chris E. Williford. (Filed as
Exhibit 10.20 to the 2000 S-1 Registration Statement).
*10.13 Employment Agreement between Abraxas and Stephen T. Wendel. (Filed as
Exhibit 10.26 to the S-3 Registration Statement).
54
*10.14 Employment Agreement between Abraxas and Robert W. Carington, Jr. (Filed
as Exhibit 10.22 to the 2000 S-1 registration Statement).
10.15 Common Stock Purchase Warrant dated August 1, 2000 between Abraxas and
Basil Street Company (Filed as Exhibit 10.15 to Abraxas Annual Report on Form
10-K filed on April 2, 2001).
10.16 Common Stock Purchase Warrant dated September 1, 2000 between Jessup &
Lamont Holdings (Filed as Exhibit 10.16 to Abraxas Annual Report on Form 10-K
filed on April 2, 2001).
10.17 Common Stock Purchase Warrant dated August 1, 2000 between Abraxas and
TNC, Inc. (Filed as Exhibit 10.17 to Abraxas Annual Report on Form 10-K filed on
April 2, 2001).
10.18 Common Stock Purchase Warrant dated August 1, 2000 between Abraxas and
Charles K. Butler (Filed as Exhibit 10.17 to Abraxas Annual Report on Form 10-K
filed on April 2, 2001).
10.19 Management Agreement dated November 14, 1996 by and between Canadian
Abraxas and Cascade Oil & Gas Ltd. (Filed as Exhibit 10.36 to the 1996 Exchange
Offer Registration Statement).
10.20 Agreement of Limited Partnership of Abraxas Wamsutter L.P. dated as of
November 12, 1999 by and between Wamsutter Holdings, Inc. and TIFD III-X Inc.
(Filed as Exhibit 10.2 to Abraxas' Current Report on Form 8-K filed November
30,1999).
10.21 Credit agreement dated December 20, 2001 between Grey Wolf Exploration,
Inc. and Mirant Energy Capital, Ltd. (Filed herewith)
10.22 First Overriding Royalty Agreement dated as of December 20, 2001 between
Grey Wolf Exploration, Inc. and Mirant Energy Capital, Ltd (Filed herewith)
10.23 Second Over Overriding Royalty Agreement dated as of December 20, 2001
between Grey Wolf Exploration, Inc. and Mirant Energy Capital, Ltd (Filed
herewith)
10.24 Purchase Agreement for Dollar Denominated Production Payment dated as of
October 6, 1999 by and between Abraxas and Southern Producer Services, L.P.
(Filed as Exhibit 10.1 to Abraxas' Quarterly Report on Form 10-Q filed November
15, 1999)
10.25 Conveyance of Dollar Denominated Production Payment dated as of October 6,
1999 by and between Abraxas and Southern Producer Services, L.P. (Filed as
Exhibit 10.2 to Abraxas' Quarterly Report on Form 10-Q filed November 15, 1999)
21.1 Subsidiaries of Abraxas. (Filed as Exhibit 21.1 to Abraxas' Annual Report
on Form 10-K filed March 31, 2000).
23.1 Independent Auditors' Consent (Deloitte & Touche LLP). (Filed herewith).
23.2 Consent of Independent Auditors (Ernst & Young LLP). (Filed herewith).
23.3 Independent Auditors' Consent(Deloitte & Touche LLP Chartered Accountants).
(Filed herewith).
23.4 Independent Auditors' Consent(Deloitte & Touche LLP Chartered Accountants).
(Filed herewith).
23.5 Consent of DeGolyer and MacNaughton. (Filed herewith).
23.6 Consent of McDaniel & Associates Consultants, Ltd. (Filed herewith).
* Management Compensatory Plan or Agreement.
55
(b) Reports on Form 8-K
1. Current Report on Form 8-K filed on October 3, 2001, Item 5. Other
Events, including a press release relating to an update of operational
activities and operational guidance for the third and fourth quarter.
2. Current Report on Form 8-K filed on October 9, 2001, Item 5. Other
Events, including a press release announcing the completion of the
Company's tender offer for the shares of Grey Wolf not owned by the
Company.
3. Current Report on the Form 8-K filed on November 14, 2001, Item 5.
Other Events, including a press release relating to the announcement of
the Company's third quarter financial results and updating operations.
4. Current Report on the Form 8-K filed on January 3, 2002. Other Events,
including a press release relating to the announcement of the Company's
Canadian project financing.
5. Current Report on the Form 8-K on March 27, 2002. Other Events,
including a press release relating to the announcement of the Company's
2001 year end and fourth quarter financial results.
6. Current Report on the Form 8-K on March 28, 2002. Other Events,
including a press release relating to a definitive purchase and sale
agreement by wholly owned Canadian subsidiaries for the sale of their
interest in a natural gas processing plant and related reserves.
56
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
ABRAXAS PETROLEUM CORPORATION
By: /s/ Robert L.G. Watson By: /s/ Chris E. Williford
------------------------------------ ----------------------------
President and Principal Exec. Vice President and
Executive Officer Principal Financial and
Accounting Officer
DATED:April 5, 2002
Pursuant to the requirements of the Securities and Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the date indicated.
Signature Name and Title Date
/s/ Robert L.G. Watson Chairman of the Board,
- ----------------------------- President (Principal Executive
Robert L.G. Watson Officer) and Director 4/5/2002
/s/ Chris E. Williford Exec. Vice President and
- ----------------------------- Treasurer (Principal Financial
Chris Williford and Accounting Officer) 4/5/2002
/s/ Craig S. Bartlett, Jr. Director 4/5/2002
- -----------------------------
Craig S. Bartlett, Jr.
/s/ Franklin Burke Director 4/5/2002
- -----------------------------
Franklin Burke
/s/ Ralph F. Cox Director 4/5/2002
- ----------------------
Ralph F. Cox
/s/ Fredrick M. Pevow, Jr. Director 4/5/2002
- -----------------------------
Fredrick M. Pevow, Jr.
/s/ James C. Phelps Director 4/5/2002
- -----------------------------
James C. Phelps
/s/ Joseph A. Wagda Director 4/5/2002
- ----------------------
Joseph A. Wagda
57
Exhibit 23.1
Independent Auditors' Consent
We consent to the incorporation by reference in the Registration Statements
No. 33-48932, 33-48934, 33-72268, 33-81416, 33-81418, 333-17375, and 333-17377
of Abraxas Petroleum Corporation on Form S-8 of our report dated March 26, 2002,
appearing in this Annual Report on Form 10-K of Abraxas Petroleum Corporation
for the year ended December 31, 2001.
/s/ Deloitte & Touche LLP
San Antonio, Texas
March 29, 2002
58
Exhibit 23.2
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in the Registration Statements
(Form S-8 No. 33-48932) pertaining to the Abraxas Petroleum Corporation 1984
Non-Qualified Stock Option Plan; (Form S-8 No. 33-48934) pertaining to the
Abraxas Petroleum Corporation 1984 Incentive Stock Option Plan; (Form S-8 No.
33-72268) pertaining to the Abraxas Petroleum Corporation 1993 Key Contribution
Stock Option Plan; (Form S-8 No. 33-81416) pertaining to the Abraxas Petroleum
Corporation Restricted Share Plan for Directors; (Form S-8 No. 33-81418)
pertaining to the Abraxas Petroleum Corporation 1994 Long Term Incentive Plan;
(Form S-8 No. 333-17375) pertaining to the Abraxas Petroleum Corporation
Director Stock Option Plan; and (Form S-8 No. 333-17377) pertaining to the
Abraxas Petroleum Corporation 401(K) Profit Sharing Plan of our report dated
March 17, 2000, with respect to the consolidated financial statements of Abraxas
Petroleum Corporation included in the Annual Report (Form 10-K) for the year
ended December 31, 2001.
/s/ Ernst & Young LLP
Ernst & Young LLP
San Antonio, Texas
April 3, 2002
59
Exhibit 23.3
Independent Auditors' Consent
We consent to the incorporation by reference in the Registration Statements No.
33-48932, 33-48934, 33-72268, 33-81418, 333-17375 and 333-17377 of Abraxas
Petroleum Corporation on Form S-8 of our report dated March 31, 2002 on the
financial statements of Grey Wolf Exploration Inc. appearing in this Annual
Report on Form 10-K of Abraxas Petroleum Corporation for the year ended December
31, 2001.
Calgary, Canada /s/Deloitte & Touche LLP
April 3, 2002 Chartered Accountants
60
Exhibit 23.4
Consent of DeGolyer and MacNaughton
We hereby consent to the incorporation in your Annual Report on Form 10-K
of the references to DeGolyer and MacNaughton in the "Reserves Information"
section and to the use by reference of information contained in our "Appraisal
Report as of December 31, 2001 on Certain Interests owned by Abraxas Petroleum
Corporation," Appraisal Report as of December 31,02000 on Certain Interest owned
by Abraxas Petroleum Corporation," and "Appraisal Repost as of December 31,
1999, on Certain Interest owned by Abraxas Petroleum Corporation" (our Reports).
However, that since the crude oil, condensate, natural gas liquids, and natural
gas reserves estimates set forth in our Reports have been combined with reserve
estimates of other petroleum consultants, we are necessarily unable to verify
the accuracy of the reserves values contained in the aforementioned Annual
Report.
DeGolyer and MacNaughton
Dallas, Texas
April 3, 2002
61
Exhibit 23.5
Consent of McDaniel and Associates Consultants LTD.
We consent to the incorporation in your Annual Report on Form 10-K of the
references to McDaniel and Associates Consultants Ltd. in the "Reserves
Information" section and to the use by reference of information contained in our
Evaluation Report "Canadian Abraxas Petroleum Ltd., Evaluation of Oil & Gas
Reserves, As of January 1, 2002", dated March 22, 2002.
McDaniel & Associates Consultants LTD
Calgary, Alberta
April 3, 2002
62
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Abraxas Petroleum Corporation and Subsidiaries
Independent Auditors' Reports for the years ended
December 31, 2001 and 2000..............................................F-2
Independent Auditors' Report for the year ended December 31, 1999 ..........F-3
Consolidated Balance Sheets at December 31, 2000 and 2001 ..................F-4
Consolidated Statements of Operations for the years ended
December 31, 1999, 2000 and 2001 .......................................F-6
Consolidated Statements of Stockholders' Equity (Deficit)
for the years ended December 31, 1999, 2000 and 2001 ...................F-7
Consolidated Statements of Cash Flows for the years ended
December 31, 1999, 2000 and 2001 .......................................F-9
Notes to Consolidated Financial Statements .................................F-11
Grey Wolf Exploration Inc.
Auditors' Report for the years ended December 31, 2001 and 2000.............F-45
Comments by Auditors' for US readers on Canada - US reporting
differences............................................................F-46
Auditors' Report for the year ended December 31, 1999.......................F-47
Balance Sheets at December 31, 2000 and 2001................................F-48
Statements of Earnings and Retained Earnings for the years
ended December 31, 1999, 2000 and 2001.................................F-49
Statements of Cash Flows for the years ended
December 31, 1999, 2000 and 2001.......................................F-50
Notes to Financial Statements...............................................F-51
F-1
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of
Abraxas Petroleum Corporation
We have audited the accompanying consolidated balance sheets of Abraxas
Petroleum Corporation and Subsidiaries (the "Company") as of December 31, 2001
and 2000, and the related consolidated statements of operations, stockholders'
equity (deficit), and cash flows for the years then ended. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of the Company at December 31, 2001
and 2000, and the results of its operations and its cash flows for the years
then ended in conformity with accounting principles generally accepted in the
United States of America.
As discussed in Note 16 to the financial statements, in 2001 the Company changed
its method of accounting for derivative financial instruments to conform to
Statement of Financial Accounting Standards No. 133.
/s/DELOITTE & TOUCHE LLP
San Antonio, Texas
March 26, 2002
F-2
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
Abraxas Petroleum Corporation
We have audited the accompanying consolidated statement of operations
of Abraxas Petroleum Corporation and Subsidiaries as of December 31, 1999, and
the related consolidated statements of stockholders' equity (deficit) and cash
flows for the period ended December 31, 1999. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audit in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the consolidated results of operations and
cash flows of Abraxas Petroleeum Corporation and Subsidiaries for the year ended
December 31, 1999, in conformity with accounting principles accepted in the
United States.
ERNST & YOUNG LLP
San Antonio, Texas
March 17, 2000,
F-3
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31
--------------------------------------
2000 2001
------------------ -------------------
(Dollars in thousands)
Current assets:
Cash ................................................... $ 2,004 $ 7,605
Accounts receivable, less allowance for doubtful
accounts:
Joint owners ....................................... 3,771 2,785
Oil and gas production sales ....................... 16,106 4,758
Other .............................................. 841 504
------------------ -------------------
20,718 8,047
Equipment inventory .................................... 1,411 1,251
Other current assets ................................... 179 443
------------------ -------------------
Total current assets ................................. 24,312 17,346
Property and equipment:
Oil and gas properties, full cost method of accounting:
Proved ............................................. 481,802 486,098
Unproved, not subject to amortization .............. 12,831 10,626
Other property and equipment ......................... 63,720 67,632
------------------ -------------------
Total .......................................... 558,353 564,356
Less accumulated depreciation, depletion, and
amortization ..................................... 253,569 282,462
------------------ -------------------
Total property and equipment - net ................. 304,784 281,894
Deferred financing fees, net of accumulated amortization
of $6,917 and $8,668 at December 31, 2000 and 2001,
respectively ........................................... 5,556 3,928
Other assets .............................................. 908 545
------------------ -------------------
Total assets ........................................... $ 335,560 $ 303,713
================== ===================
See accompanying Notes to Consolidated Financial Statements.
F-4
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (CONTINUED)
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
December 31
--------------------------------------
2000 2001
------------------ -------------------
(Dollars in thousands)
Current liabilities:
Accounts payable .......................................... $ 22,721 $ 10,542
Joint interest oil and gas production payable ............. 6,281 3,596
Accrued interest .......................................... 6,079 6,013
Other accrued expenses .................................... 1,932 1,116
Hedge liability............................................ - 658
Current maturities of long-term debt ...................... 1,128 415
------------------ -------------------
Total current liabilities ............................... 38,141 22,340
Long-term debt ............................................... 266,441 285,184
Deferred income taxes ........................................ 21,079 20,621
Future site restoration ..................................... 4,305 4,056
Minority interest in foreign subsidiary ...................... 12,097 -
Commitments and contingencies
Stockholders' equity (deficit):
Common stock, par value $.01 per share - authorized 200,000,000 shares;
issued 22,759,852 and 30,145,280
shares at December 31, 2000 and 2001, respectively ... 227 301
Additional paid-in capital ................................ 130,409 136,830
Accumulated deficit ...................................... (131,376) (151,094)
Treasury stock, at cost, 165,883 shares at December 31, 2000
and 2001 ................................................ (964) (964)
Accumulated other comprehensive income (loss).............. (4,799) (13,561)
------------------ -------------------
Total stockholders' equity (deficit)......................... (6,503) (28,488)
------------------ -------------------
Total liabilities and stockholders' equity (deficit)...... $ 335,560 $ 303,713
================== ===================
See accompanying Notes to Consolidated Financial Statements.
F-5
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31
---------------------------------------------------------
1999 2000 2001
-------------------------------------------------------
(In thousands except per share data)
Revenues:
Oil and gas production revenues ......................... $ 59,025 $ 72,973 $ 73,201
Gas processing revenues ................................. 4,244 2,717 2,438
Rig revenues ............................................ 444 505 756
Other .................................................. 3,057 405 848
------------------- ----------------- -------------
66,770 76,600 77,243
Operating costs and expenses:
Lease operating and production taxes .................... 17,938 18,783 18,616
Depreciation, depletion, and amortization ............... 34,811 35,857 32,484
Proved property impairment .............................. 19,100 - 2,638
Rig operations .......................................... 624 717 702
General and administrative .............................. 5,269 6,533 6,445
General and administrative (Stock-based compensation).... - 2,767 (2,767)
------------------- ----------------- --------------
77,742 64,657 58,118
------------------- ----------------- --------------
Operating income (loss)..................................... (10,972) 11,943 19,125
Other (income) expense:
Interest income ......................................... (666) (530) (78)
Amortization of deferred financing fees ................. 1,915 2,091 2,268
Interest expense ........................................ 36,815 31,140 31,523
(Gain) loss on sale of equity investment ................ - (33,983) 845
Other ................................................... - 1,563 207
------------------- ----------------- --------------
38,064 281 34,765
------------------- ----------------- --------------
Income (loss) from operations before income tax and
extraordinary item....................................... (49,036) 11,662 (15,640)
Income tax expense (benefit):
Current ................................................. 491 (1,233) 505
Deferred ................................................ (13,116) 4,938 1,897
Minority interest in income of consolidated foreign
subsidiary (2001 prior to purchase)...................... 269 1,281 1,676
------------------- ------------------ --------------
Income (loss) before extraordinary item..................... (36,680) 6,676 (19,718)
Extraordinary item:
Gain on debt extinguishment ............................. - 1,773 -
------------------- ------------------ ---------------
Net income (loss)....................................... $ (36,680) $ 8,449 $ (19,718)
=================== ================== ===============
Basic earnings (loss) per common share:
Net income (loss) before extraordinary item ............. $ (5.41) $ 0.29 $ (0.76)
Extraordinary item ...................................... - 0.08 -
------------------- ------------------ ----------------
Net income (loss) per common share - basic .............. $ (5.41) $ 0.37 $ (0.76)
=================== ================== ================
Diluted earnings (loss) per common share :
Net income (loss) before extraordinary item ............. $ (5.41) $ 0.21 $ (0.76)
Extraordinary item ...................................... - 0.05 -
------------------- ------------------ ----------------
Net income (loss) per common share - diluted............ $ (5.41) $ 0.26 $ (0.76)
=================== ================== ================
See accompanying Notes to Consolidated Financial Statements.
F-6
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)
(In thousands except share amounts)
Accumulated
Common Stock Treasury Stock Additional Other
----------------------- --------------------- Paid-In Accumulated Comprehensive
Shares Amount Shares Amount Capital Deficit Income (Loss) Total
----------- ---------- --------------------- -------------- -------------- ------------------------
Balance at January 1, 1999 .... 6,501,441 $ 65 171,015 $ (1,167) $ 51,695 $ (103,145) $ $(10,970) $ (63,522)
Comprehensive income
(loss):
Net loss ................. - - - - - (36,680) - (36,680)
Other comprehensive
income:
Foreign currency
translation adjustment. - - - - - - 14,572 14,572
---------
Comprehensive income (22,108)
(loss)
Issuance of common stock
for compensation ...... 3,314 - (18,932) 96 (43) - - 53
Issuance of common stock
in connection with
Exchange Offer (Note
2, 5 and 6)............ 16,242,344 162 - - 75,910 - - 76,072
----------- ---------- --------- ---------- ------------ ------------ ----------- ------------
Balance at December 31, 1999 22,747,099 $ 227 152,083 $ (1,071) $127,562 $ (139,825) $ 3,602 $ (9,505)
Comprehensive income
(loss):
Net income............... - - - - - 8,449 - 8,449
Other comprehensive
income:
Foreign currency
translation
adjustment ........ - - - - - (8,401) - (8,401)
-----------
Comprehensive income 48
Stock-based
compensation expense.. - - - - 2,767 - - 2,767
Issuance of common stock
and warrants for
compensation .......... 12,753 - (25,000) 185 80 - - 265
Purchase of treasury
stock ................. - - 38,800 (78) - - - (78)
------------ ---------- --------- ---------- ------------ ------------ ----------- ------------
Balance at December 31, 2000 22,759,852 $ 227 165,883 $ (964) $130,409 $ (131,376) $ (4,799) $ (6,503)
------------ ---------- --------- ---------- ------------ ------------ ----------- ------------
(continued)
F-7
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)(continued)
(In thousands except share amounts)
Accumulated
Common Stock Treasury Stock Additional Other
----------------------- --------------------- Paid-In Accumulated Comprehensive
Shares Amount Shares Amount Capital Deficit Income (Loss) Total
----------- ---------- --------------------- -------------- -------------- ------------------------
Balance at January 1, 1999 .... 22,759,852 $ 227 165,883 $ (964) $130,409 $ (130,376) $ $ (4,799) $ (6,503)
Comprehensive income
(loss):
Net loss................. - - - - - (19,718) - (19,718)
Other comprehensive
income:
Hedge loss........... - - - - - - (566) (566)
Foreign currency
translation
adjustment ........ - - - - - - (8,196) (8,196)
-----------
Comprehensive loss - - - - - - - (28,480)
Stock-based compensation
expense................ - - - - (2,767) - - (2,767)
Issuance of common stock
for contingent value
rights ................ 3,386,488 34 - - (34) - - -
Issuance of common stock
and stock options for
acquisition of
minority interest in
Grey Wolf Exploration,
Inc.................... 3,990,565 40 - - 9,206 - - 9,246
Stock options exercised . 8,375 - - - 16 - - 16
------------ ---------- --------- ---------- ------------ ------------ ----------- ------------
Balance at December 31, 2001 30,145,280 $ 301 165,883 $ (964) $136,830 $ (151,094) $ (13,561) $ (28,488)
============ ========== ========= ========== ===========- ============ =========== ============
See accompanying Notes to Consolidated Financial Statements.
F-8
F-11
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31
----------------------------------------------------------
1999 2000 2001
------------------ ------------------ -------------------
(In thousands)
Operating Activities
Net income (loss) ........................ $ (36,680) $ 8,449 $ (19,718)
Adjustments to reconcile net income
(loss) to net cash provided by
operating activities:
Minority interest in income of
foreign subsidiary ................ 269 1,281 1,676
Extraordinary gain on
extinguishment of debt............. - (1,773) -
(Gain) loss on sale of equity
investment......................... - (33,983) 845
Depreciation, depletion, and
amortization ...................... 34,811 35,857 32,484
Proved property impairment .......... 19,100 - 2,638
Deferred income tax (benefit) expense
(13,116) 4,938 1,897
Amortization of deferred financing
fees............................... 1,915 2,091 2,268
Amortization of premium on long term
debt............................... (579) - -
Stock-based compensation ............ - 2,767 (2,767)
Issuance of common stock and
warrants for compensation ......... 53 265 -
Changes in operating assets and
liabilities:
Accounts receivable ............. (2,698) (7,036) 12,693
Equipment inventory ............. 57 (538) (76)
Other .......................... 396 (1,839) (106)
Accounts payable ................ (744) 11,318 (14,848)
Accrued expenses ................ 1,098 (425) (723)
------------------ ------------------ ----------------
Net cash provided by operating activities 3,882 21,372 16,263
Investing Activities
Capital expenditures, including purchases
and development of properties ......... (128,708) (74,412) (57,056)
Proceeds from sale of oil and gas
properties............................. 17,494 21,157 28,938
Acquisition of minority interest.......... - - (2,679)
Proceeds from sale of equity investment .. - 34,482 -
------------------ ------------------ ----------------
Net cash used in investing activities .... (111,214) (18,773) (30,797)
F-9
Abraxas Petroleum Corporation and Subsidiaries
Consolidated Statements of Cash Flows (continued)
Year Ended December 31
----------------------------------------------------------
1999 2000 2001
------------------ ------------------ ------------------
(In thousands)
Financing Activities
Purchase of treasury stock, net ............ $ - $ (78) $ -
Proceeds from issuance of common ock...... - - 16
Proceeds from long-term borrowings ......... 88,457 6,400 29,995
Payments on long-term borrowings ........... (35,747) (10,163) (9,326)
Deferred financing fees .................... (3,586) 23 -
------------------ ------------------ -------------------
Net cash provided by (used in) financing
activities .............................. 49,124 (3,818) 20,685
------------------ ------------------ -------------------
Increase (decrease) in cash ................ (58,208) (1,219) 6,151
------------------ ------------------ -------------------
Effect of exchange rate changes on cash .... 617 (576) (550)
------------------ ------------------ -------------------
Increase (decrease) in cash ................ (57,591) (1,795) 5,601
Cash at beginning of year .................. 61,390 3,799 2,004
------------------ ------------------ -------------------
Cash at end of year................... $ 3,799 $ 2,004 $ 7,605
================== ================== ===================
Supplemental Disclosures
Supplemental disclosures of cash flow
information:
Interest paid ......................... $ 35,979 $ 33,004 $ 31,752
================== ================== ===================
Taxes paid............................. $ - $ - $ 505
================== ================== ===================
Supplemental schedule of noncash investing and financing activities:
In December 1999 the Company completed the exchange of
$269,699,000 of its 11.5% Old Notes for $188,778,000 of new
Second Lien Notes, issuance of up to 16,078,990 shares of
common stock and contingent value rights. An additional
$5,000,000 of the Second Lien Notes were issued for payment
of fees and expenses. See Note 2, 5 and 6.
Decrease in long-term debt......... $ 75,921
==================
Increase in stockholder's equity... $ 75,921
==================
In May 2001 the Company issued 3,386,488 shares of common
stock upon the expiration of the CVRs issued in connection
with the December 1999 exchange. See Note 6.
In September 2001 the Company issued 3,990,565 shares of common stock and
options and paid $2,679,000 million in cash in connection with the
acquisition of the minority interest in Grey Wolf. See Note 3.
Decrease in oil and gas properties and other assets...................... $ (2,925)
=====================
Decrease in deferred income tax liability................................ $ 1,091
=====================
Increase in stockholders equity.......................................... $ (9,246)
=====================
Decrease in minority interest in foreign subsidiary...................... $ 13,759
=====================
See accompanying Notes to Consolidated Financial Statements.
F-10
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 2000, and 2001
1. Organization and Significant Accounting Policies
Nature of Operations
Abraxas Petroleum Corporation (the "Company" or "Abraxas") is an
independent energy company engaged in the exploration for and the acquisition,
development, and production of crude oil and natural gas primarily along the
Texas Gulf Coast, in the Permian Basin of western Texas and in Canada and the
processing of natural gas primarily in Canada. The consolidated financial
statements include the accounts of the Company and its subsidiaries. All
significant intercompany accounts and transactions have been eliminated in
consolidation.
The consolidated financial statements include the accounts of the
Company, its wholly-owned foreign subsidiaries Canadian Abraxas Petroleum
Limited ("Canadian Abraxas") and Grey Wolf Exploration Inc. ("Grey Wolf").
Minority interest represents the minority shareholders' proportionate share of
the equity and income of Grey Wolf prior to the Company's acquisition of the
remaining interest in September 2001.
Use of Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates. Management believes that it is reasonably possible that estimates of
proved crude oil and natural gas revenues could significantly change in the
future.
Concentration of Credit Risk
Financial instruments which potentially expose the Company to credit
risk consist principally of trade receivables, interest rate and crude oil and
natural gas price swap agreements. Accounts receivable are generally from
companies with significant oil and gas marketing activities. The Company
performs ongoing credit evaluations and, generally, requires no collateral from
its customers.
Equipment Inventory
Equipment inventory principally consists of casing, tubing, and
compression equipment and is carried at the lower of cost or market.
Oil and Gas Properties
The Company follows the full cost method of accounting for crude oil
and natural gas properties. Under this method, all direct costs and certain
indirect costs associated with acquisition of properties and successful as well
as unsuccessful exploration and development activities are capitalized.
Depreciation, depletion, and amortization ("DD&A") of capitalized crude oil and
natural gas properties and estimated future development costs, excluding
unproved properties, are based on the unit-of-production method based on proved
reserves. Net capitalized costs of crude oil and natural gas properties, less
related deferred taxes, are limited, by country, to the lower of unamortized
cost or the cost ceiling, defined as the sum of the present value of estimated
future net revenues from proved reserves based on unescalated prices discounted
at 10 percent, plus the cost of properties not being amortized, if any, plus the
lower of cost or estimated fair value of unproved properties included in the
costs being amortized, if any, less related income taxes. Excess costs are
charged to proved property impairment expense. No gain or loss is recognized
upon sale or disposition of crude oil and natural gas properties, except in
unusual circumstances - see Note 3.
F-11
Unproved properties represent costs associated with properties on which
the Company is performing exploration activities or intends to commence such
activities. These costs are reviewed periodically for possible impairments or
reduction in value based on geological and geophysical data. If a reduction in
value has occurred, costs being amortized are increased. The Company believes
that the unproved properties will be substantially evaluated in six to
thirty-six months and it will begin to amortize these costs at such time. During
1999, 2000 and 2001, the Company capitalized $193,000, $589,000 and $164,000 of
interest expense, respectively, based on the cost of major development projects
in progress.
Other Property and Equipment
Other property and equipment are recorded on the basis of cost.
Depreciation of gas gathering and processing facilities and other property and
equipment is provided over the estimated useful lives using the straight-line
method. Major renewals and betterments are recorded as additions to the property
and equipment accounts. Repairs that do not improve or extend the useful lives
of assets are expensed.
Turnaround costs
Turnaround costs represent major maintenance performed on the Company's
gas processing plants and are expensed as incurred.
Hedging
The Company periodically enters into agreements to hedge the risk of
future crude oil and natural gas price fluctuations. Such agreements, primarily
in the form of price swaps, may either fix or support crude oil and natural gas
prices or limit the impact of price fluctuations with respect to the Company's
sale of crude oil and natural gas. Gains and losses on such hedging activities
are recognized in oil and gas production revenues when hedged production is
sold. The net cash flows related to any recognized gains or losses associated
with these hedges are reported as cash flows from operations. If the hedge is
terminated prior to expected maturity, gains or losses are deferred and included
in income in the same period as the physical production required by the contract
is delivered.
Statement of Financial Accounting Standards, ("SFAS") No. 133,
"Accounting for Derivative Instruments and Hedging Activities", is effective for
the Company on January 1, 2001. SFAS 133, as amended and interpreted,
establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts, and for
hedging activities. All derivatives, whether designated in hedging relationships
or not, will be required to be recorded on the balance sheet at fair value. If
the derivative is designated a fair-value hedge, the changes in the fair value
of the derivative and the hedged item will be recognized in earnings. If the
derivative is designated a cash-flow hedge, changes in the fair value of the
derivative will be recorded in other comprehensive income (OCI) and will be
recognized in the income statement when the hedged item affects earnings. SFAS
133 defines new requirements for designation and documentation of hedging
relationships as well as ongoing effectiveness assessments in order to use hedge
accounting. For a derivative that does not qualify as a hedge, changes in fair
value will be recognized in earnings.
Stock-Based Compensation
The Company accounts for stock-based compensation using the intrinsic
value method prescribed in Accounting Principles Board Opinion ("APB") No. 25,
"Accounting for Stock Issued to Employees," and related interpretations.
Accordingly, compensation cost for stock options is measured as the excess, if
any, of the quoted market price of the Company's stock at the date of the grant
over the amount an employee must pay to acquire the stock.
Effective July 1, 2000, the Financial Accounting Standards Board
("FASB") issued FIN 44, "Accounting for Certain Transactions Involving Stock
Compensation", an interpretation of APB No. 25. Under the interpretation,
certain modifications to fixed stock option awards which were made subsequent to
December 15, 1998, and were not exercised prior to July 1, 2000, require that
the awards be accounted for as variable until they are exercised, forfeited, or
expired. In March 1999, the Company amended the exercise price to $2.06 on all
options with an existing exercise price greater than $2.06. See Note 7. The
Company recognized approximately $2.8 million in expense during 2000 and a
credit of $2.8 million during 2001 as General and Administrative (Stock-based
compensation). The credit for the year ended December 31, 2001 was due to a
decline in the Company's common stock price.
F-12
Foreign Currency Translation
The functional currency for Canadian Abraxas and Grey Wolf is the
Canadian dollar ($CDN). The Company translates the functional currency into U.S.
dollars ($US) based on the current exchange rate at the end of the period for
the balance sheet and a weighted average rate for the period on the statement of
operations. Translation adjustments are reflected as Accumulated Other
Comprehensive Income (Loss) in Stockholders' Equity (Deficit).
Fair Value of Financial Instruments
The Company includes fair value information in the notes to
consolidated financial statements when the fair value of its financial
instruments is materially different from the book value. The Company assumes the
book value of those financial instruments that are classified as current
approximates fair value because of the short maturity of these instruments. For
noncurrent financial instruments, the Company uses quoted market prices or, to
the extent that there are no available quoted market prices, market prices for
similar instruments.
Restoration, Removal and Environmental Liabilities
The estimated costs of restoration and removal of major processing
facilities are accrued on a straight-line basis over the life of the property.
The estimated future costs for known environmental remediation requirements are
accrued when it is probable that a liability has been incurred and the amount of
remediation costs can be reasonably estimated. These amounts are the
undiscounted, future estimated costs under existing regulatory requirements and
using existing technology.
Revenue Recognition
The Company recognizes crude oil and natural gas revenue from its
interest in producing wells as crude oil and natural gas is sold from those
wells, net of royalties. Revenue from the processing of natural gas is
recognized in the period the service is performed. The Company utilizes the
sales method to account for gas production volume imbalances. Under this method,
income is recorded based on the Company's net revenue interest in production
taken for delivery. Management does not believe that the Company had material
gas imbalances at December 31, 2000 or 2001.
Deferred Financing Fees
Deferred financing fees are being amortized on a level yield basis over
the term of the related debt arrangements.
Income Taxes
The Company records income taxes using the liability method. Under this
method, deferred tax assets and liabilities are determined based on differences
between financial reporting and tax bases of assets and liabilities and are
measured using the enacted tax rates and laws that will be in effect when the
differences are expected to reverse.
New Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 141, Business Combinations, which requires the purchase method of
accounting for business combinations initiated after June 30, 2001 and
eliminates the pooling-of-interests method. In July 2001, the FASB also issued
SFAS No. 142, Goodwill and Other Intangible Assets, which discontinues the
practice of amortizing goodwill and indefinite lived intangible assets and
initiates an annual review for impairment. Intangible assets with a determinable
useful life will continue to be amortized over that period. The amortization
provisions apply to goodwill and intangible assets acquired after June 30, 2001.
The Company has applied these standards to its purchase of the minority interest
in Grey Wolf.
In June 2001, the FASB issued SFAS No. 143, Accounting for Asset
Retirement Obligations. SFAS No. 143 requires an asset retirement obligation to
be recorded at fair value during the period incurred and an equal amount
recorded as an increase in the value of the related long-lived asset. The
capitalized cost is depreciated over the useful life of the asset and the
obligation is accreted to its present value each period. SFAS No. 143 is
effective for the Company beginning January 1, 2003 with earlier adoption
encouraged. The Company is currently evaluating the impact the standard will
have on its future results of operations and financial condition.
F-13
In August 2001, the FASB issued SFAS No. 144 Accounting for the
Impairment of Disposal of Long-Lived Assets. SFAS No. 144 retains the
requirement to recognize an impairment loss only where the carrying value of a
long-lived asset is not recoverable from its undiscounted cash flows and to
measure such loss as the difference between the carrying amount and fair value
of the asset. SFAS No. 144, among other things, changes the criteria that have
to be met to classify an asset as held-for-sale and requires that operating
losses from the discontinued operations be recognized in the period that the
losses are incurred rather than as of the measurement date. The Company adopted
the accounting standard effective January 1, 2002, which did not have a
significant impact on the Company's financial condition or results of
operations.
Reclassifications
Certain prior years balances have been reclassified for comparative
purposes.
2. Liquidity
At December 31, 2001 the Company's current liabilities of approximately
$22.3 million exceeded its current assets of $17.3 million. Included in current
liabilities are trade payables of $10.5 million, revenues due third parties of
$3.6 million and accrued interest of $6.0 million. The Company's results of
operations in 2001 generated $16.3 million in cash flows from operations. The
Company will need additional funds in the future for both the development of its
assets and the service of its debt, including the repayment of the $63.5 million
in principal amount of the First Lien Notes maturing in March 2003 and the $191
million of the Second Lien Notes and Old Notes maturing in November 2004. In
order to meet the goals of developing its assets and servicing its debt
obligations, the Company will be required to obtain additional sources of
capital and/or reduce or reschedule its existing cash requirements. In order to
do so, the Company may pursue one or more of the following alternatives:
o refinancing existing debt;
o repaying debt with proceeds from the sale of assets;
o exchanging debt for equity;
o managing the timing and reducing the scope of its capital expenditures;
o issuing debt or equity securities or otherwise raisi ng additional
funds; or
o selling all or a portion of its existing assets, including interests in
its assets.
The Company has implemented a number of measures to conserve its cash
resources, including postponement of certain exploration and development
projects. However, while these measures will help conserve the Company's cash
resources in the near term, they will also limit the Company's ability to
replenish its depleting reserves, which could negatively impact the Company's
operating cash flow and results of operations in the future.
There can be no assurance that any of the above alternatives, or some
combination thereof, will be available or, if available, will be on terms
acceptable to the Company.
The Company will have four principal sources of liquidity going
forward: (i) cash on hand, (ii) cash flow from operations, (iii) a production
payment related to certain U.S. properties, and (iv) sale of assets and
property. Grey Wolf also has availability under its new financing agreement
entered into in December 2001, see discussion below. The First Lien Notes
indenture, the Second Lien Notes indenture and the Old Notes indenture
substantially limit its use of proceeds from asset sales. Should commodity
prices not increase from levels at December 31, 2001, most of the Company's
capital expenditures are discretionary and can be delayed to maintain current
liquidity. While the availability of capital resources cannot be predicted with
certainty and is dependent upon a number of factors including factors outside of
management's control, management believes that the net cash flow from operations
plus cash on hand, cash available under the production payment and the proceeds
from the sale of additional properties will be adequate to fund operations and
planned capital expenditures.
The Company's 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. See Note 19.
F-14
In December 2001, the Company's wholly owned subsidiary, Grey Wolf,
entered into a financing agreement ("Grey Wolf Facility") with Mirant Canada
Energy Capital, Ltd. ("Mirant Canada") for US $96 million (CDN $150 million)
senior secured facility, which is non-recourse to Abraxas. Initial proceeds from
this facility of approximately US $25 million were used to retire Grey Wolf's
existing bank debt and for general corporate purposes. Up to US $71 million is
available to finance the drilling of wells and related activities in the Grey
Wolf development plan, as anticipated over the next two years.
3. Acquisitions and Divestitures
New Cache Petroleums LTD Acquisition
In January 1999, Canadian Abraxas completed the acquisition of New
Cache Petroleums, LTD ("New Cache"), for approximately $78 million in cash and
the assumption of approximately $10 million in debt. The debt was paid off with
a portion of the proceeds from the sale of the First Lien Notes.
The acquisition was accounted for as a purchase, and the purchase price
was allocated to the crude oil and natural gas properties based on the fair
values of the properties acquired. Results of operations for New Cache have been
included in the consolidated financial statements since January 1999.
Abraxas Wamsutter L.P. Divestiture
In November 1998, the Company sold its interest in certain Wyoming
properties to Abraxas Wamsutter L.P., a Texas limited partnership (the
"Partnership"), for approximately $58.6 million and a minority equity ownership
in the Partnership. Wamsutter Holdings, Inc. ("Wamsutter") initially owned a one
percent interest and acted as general partner of the Partnership. The investment
in the Partnership was accounted for by the equity method. After certain payback
requirements were satisfied, the Company's interest would increase to 35%
initially and could increase to as high as 65%. The Company also received a
management fee and reimbursement of certain overhead costs from the Partnership
which amounted to $594,700 and $112,700 for the years ended December 31, 1999
and 2000 respectively.
In March 2000, the Partnership sold all of its interest in its crude
oil and natural gas properties to a third party. Prior to the sale of these
properties, effective January 1, 2000, the Company's equity investee share of
oil and gas property cost, results of operations and amortization were not
material to consolidated operations or financial position. As a result of the
sale, the Company received approximately $34 million, which represented a
proportional interest in the Partnership's proved properties. See Note 10
regarding a litigation provision in 2001 of $845,000 related to ad valorem
taxes.
The condensed pro forma financial information presented below
summarizes on an unaudited pro forma basis, approximate results of the Company's
consolidated results of operations for the year ended December 31, 1999,
assuming the divestiture had occurred on January 1, 1999.
(In thousands except
per share data)
-----------------------
Revenue ..................................... $ 66,770
=======================
Net loss .................................... $ (3,294)
=======================
Loss per common share ....................... $ (0.49)
=======================
Acquisition of Minority Interest in Grey Wolf
In September 2001, the Company completed a tender offer for the
minority interest in Grey Wolf, acquiring the approximately 52% of capital stock
that was not previously owned by the Company. The Company issued 3,990,565
common shares and 588,916 stock options, valued together at approximately $9.2
million. Additionally, the Company incurred direct costs of approximately $2.7
million related to the acquisition. The elimination of the minority interest
through an acquisition at a purchase price less than Grey Wolf's book value in
the Company's consolidated financial statements had the effect of reducing the
property and other assets balances by $2.9 million and deferred income taxes by
$1.1 million.
The condensed pro forma financial information presented below
summarizes, on an unaudited pro forma basis, approximate results of the
Company's consolidated results of operations for the years ended December 31,
1999, 2000 and 2001, assuming the acquisition of the minority interest in Grey
Wolf had occurred at the beginning of each period presented.
F-15
Years ended December 31,
1999 2000 2001
-------------- -------------- -----------
(In thousands except per share items)
--------------------------------------------
Revenue .................................... $ 66,770 $ 76,600 $ 77,243
============== ============= ==========
Income (loss) before extraordinary item .... (36,411) 7,957 (18,042)
============== ============= ==========
Net income (loss) ........................... (36,411) 9,730 (18,042)
============== ============= ==========
Income (loss) before extraordinary item, per
common share - basic ..................... (3.38) 0.30 (0.63)
============== ============= ==========
Net income (loss) per common share - basic
(3.38) 0.37 (0.63)
============== ============= ==========
Income (loss) before extraordinary item, per
common share - diluted ................... (3.38) 0.22 (0.63)
============== ============= ==========
Net income (loss) per common share - diluted (3.38) 0.27 (0.63)
============== ============= ==========
4. Property and Equipment
The major components of property and equipment, at cost, are as
follows:
Estimated December 31
----------------------------------
Useful Life 2000 2001
-------------- ---------------- -----------------
Years (In thousands)
Land, buildings, and improvements .............. 15 $ 318 $ 318
Crude oil and natural gas properties ........... - 494,633 496,724
Natural gas processing plants .................. 18 60,299 63,964
Equipment and other ............................ 7 3,103 3,350
---------------- -----------------
$ 558,353 $ 564,356
================ =================
5. Long-Term Debt
Long-term debt consists of the following:
December 31
----------------------------------
2000 2001
---------------- -----------------
(In thousands)
11.5% Senior Notes due 2004 ("Old Notes") ............................. $ 801 $ 801
12.875% Senior Secured Notes due 2003 ("First Lien Notes") ............ 63,500 63,500
11.5% Second Lien Notes due 2004 ("Second Lien Notes")................. 190,178 190,178
Grey Wolf Credit facility repaid in 2001.......................... 7,859 -
9.5% Senior Credit Facility ("Grey Wolf Facility"), providing for
borrowings up to approximately US $96 million (CDN $150 million).
Secured by the assets of Grey Wolf and non-recourse to Abraxas, net
of US $2.3 million discount...................................... - 22,944
Production Payment ................................................... 5,231 8,176
---------------- ----------------
267,569 285,599
Less current maturities ............................................... 1,128 415
---------------- ----------------
$ 266,441 $ 285,184
================ ================
Long-Term Indebtedness
Old Notes. On November 14, 1996, the Company consummated the offering
of $215.0 million of it's 11.5% Senior Notes due 2004, Series A, which were
exchanged for the Series B Notes in February 1997. On January 27, 1998, the
Company completed the sale of $60.0 million of its 11.5% Senior Notes due 2004,
Series C. The Series B Notes and the Series C Notes were subsequently combined
into $275.0 million in principal amount of the Old Notes in June 1998.
F-16
Interest on the Old Notes is payable semi-annually in arrears on May 1
and November 1 of each year at the rate of 11.5% per annum. The Old Notes are
redeemable, in whole or in part, at the option of the Company at the redemption
prices set forth below, plus accrued and unpaid interest to the date of
redemption, if redeemed during the 12-month period commencing on November 1 of
the years set forth below:
Year Percentage
---- ----------
2001................................................. 102.875%
2002 and thereafter.................................. 100.000%
The Old Notes are joint and several obligations of Abraxas and Canadian
Abraxas and rank pari passu in right of payment to all existing and future
unsubordinated indebtedness of Abraxas and Canadian Abraxas. The Old Notes rank
senior in right of payment to all future subordinated indebtedness of Abraxas
and Canadian Abraxas. The Old Notes are, however, effectively subordinated to
the First Lien Notes to the extent of the value of the collateral securing the
First Lien Notes and to the Second Lien Notes to the extent of the value of the
collateral securing the Second Lien Notes. The Old Notes are unconditionally
guaranteed, on a senior basis by Sandia Oil and Gas Company ("Sandia"), a wholly
owned subsidiary of the Company. The guarantee is a general unsecured obligation
of Sandia and ranks pari passu in right of payment to all unsubordinated
indebtedness of Sandia and senior in right of payment to all subordinated
indebtedness of Sandia. The guarantee is effectively subordinated to the First
Lien Notes and the Second Lien Notes to the extent of the value of the
collateral securing the First Lien Notes and the Second Lien Notes.
Upon a Change of Control, as defined in the Old Notes Indenture, each
holder of the Old Notes will have the right to require the Company to repurchase
all or a portion of such holder's Old Notes at a redemption price equal to 101%
of the principal amount thereof, plus accrued and unpaid interest to the date of
repurchase. In addition, the Company will be obligated to offer to repurchase
the Old Notes at 100% of the principal amount thereof plus accrued and unpaid
interest to the date of repurchase in the event of certain asset sales.
First Lien Notes. In March 1999, Abraxas consummated the sale of $63.5
million of the First Lien Notes. Interest on the First Lien Notes is payable
semi-annually in arrears on March 15 and September 15, commencing September 15,
1999. Beginning March 15, 2002, the First Lien Notes are redeemable, in whole or
in part, at the option of Abraxas at the par value price, plus accrued and
unpaid interest to the date of redemption.
The First Lien Notes are senior indebtedness of Abraxas secured by a
first lien on substantially all of the crude oil and natural gas properties of
Abraxas and the shares of Grey Wolf owned by Abraxas. The First Lien Notes are
unconditionally guaranteed on a senior basis, jointly and severally, by Canadian
Abraxas, Sandia and Wamsutter, wholly-owned subsidiaries of the Company (the
"Restricted Subsidiaries"). The guarantees are secured by substantially all of
the crude oil and natural gas properties of the guarantors and the shares of
Grey Wolf owned by Abraxas and Canadian Abraxas.
Upon a Change of Control, as defined in the First Lien Notes Indenture,
each holder of the First Lien Notes will have the right to require Abraxas to
repurchase such holder's First Lien Notes at a redemption price equal to 101% of
the principal amount thereof plus accrued and unpaid interest to the date of
repurchase. In addition, Abraxas will be obligated to offer to repurchase the
First Lien Notes at 100% of the principal amount thereof plus accrued and unpaid
interest to the date of redemption in the event of certain asset sales.
The First Lien Notes indenture contains certain covenants that limit
the ability of Abraxas and certain of its subsidiaries, including the guarantors
of the First Lien Notes to, among other things, incur additional indebtedness,
pay dividends or make certain other restricted payments, consummate certain
asset sales, enter into certain transactions with affiliates, incur liens, merge
or consolidate with any other person or sell, assign, transfer, lease, convey or
otherwise dispose of all or substantially all of the assets of Abraxas.
The First Lien Notes indenture provides, among other things, that
Abraxas may not, and may not cause or permit the Restricted Subsidiaries, to,
directly or indirectly, create or otherwise cause to permit to exist or become
effective any encumbrance or restriction on the ability of such subsidiary to
pay dividends or make distributions on or in respect of its capital stock, make
loans or advances or pay debts owed to Abraxas or any other Restricted
Subsidiary, guarantee any indebtedness of Abraxas or any other Restricted
Subsidiary or transfer any of its assets to Abraxas or any other Restricted
Subsidiary except in certain situations as described in the First Lien Notes
indenture.
F-17
Second Lien Notes. In December 1999, Abraxas and Canadian Abraxas
consummated an exchange offer whereby $269,699,000 of the Old Notes were
exchanged for $188,778,000 of the Second Lien Notes, and 16,078,990 shares of
Abraxas common stock and contingent value rights. An additional $5,000,000 of
the Second Lien Notes were issued in payment of fees and expenses.
Interest on the Second Lien Notes is payable semi-annually in arrears
on May 1 and November 1, commencing May 1, 2000. The Second Lien Notes are
redeemable, in whole or in part, at the option of Abraxas and Canadian Abraxas
at the redemption prices set forth below, plus accrued and unpaid interest to
the date of redemption, if redeemed during the 12-month period commencing on
December 1 of the years set forth below:
Year Percentage
----- ----------
2001.......................................... 102.875%
2002 and thereafter........................... 100.000%
The Second Lien Notes are senior indebtedness of Abraxas and Canadian
Abraxas and are secured by a second lien on substantially all of the crude oil
and natural gas properties of Abraxas and Canadian Abraxas and the shares of
Grey Wolf owned by Abraxas and Canadian Abraxas. The Second Lien Notes are
unconditionally guaranteed on a senior basis, jointly and severally, by Sandia
and Wamsutter. The guarantees are secured by substantially all of the crude oil
and natural gas properties of the guarantors. The Second Lien Notes are,
however, effectively subordinated to the First Lien Notes and related guarantees
to the extent the value of the collateral securing the Second Lien Notes and
related guarantees and the First Lien Notes and related guarantees is
insufficient to pay both the Second Lien Notes and the First Lien Notes.
Upon a Change of Control, as defined in the Second Lien Notes
Indenture, each holder of the Second Lien Notes will have the right to require
Abraxas and Canadian Abraxas to repurchase such holder's Second Lien Notes at a
redemption price equal to 101% of the principal amount thereof plus accrued and
unpaid interest to the date of repurchase. In addition, Abraxas and Canadian
Abraxas will be obligated to offer to repurchase the Second Lien Notes at 100%
of the principal amount thereof plus accrued and unpaid interest to the date of
redemption in the event of certain asset sales.
The Second Lien Notes indenture contains certain covenants that limit
the ability of Abraxas and Canadian Abraxas and certain of their subsidiaries,
including the guarantors of the Second Lien Notes (the "Restricted
Subsidiaries") to, among other things, incur additional indebtedness, pay
dividends or make certain other restricted payments, consummate certain asset
sales, enter into certain transactions with affiliates, incur liens, merge or
consolidate with any other person or sell, assign, transfer, lease, convey or
otherwise dispose of all or substantially all of the assets of Abraxas or
Canadian Abraxas.
The Second Lien Notes indenture provides, among other things, that
Abraxas and Canadian Abraxas may not, and may not cause or permit the Restricted
Subsidiaries, to, directly or indirectly, create or otherwise cause to permit to
exist or become effective any encumbrance or restriction on the ability of such
subsidiary to pay dividends or make distributions on or in respect of its
capital stock, make loans or advances or pay debts owed to Abraxas, Canadian
Abraxas or any other Restricted Subsidiary, guarantee any indebtedness of
Abraxas, Canadian Abraxas or any other Restricted Subsidiary or transfer any of
its assets to Abraxas, Canadian Abraxas or any other Restricted Subsidiary
except in certain situations as described in the Second Lien Notes indenture
The fair value of the Old Notes, First Lien Notes and Second Lien Notes
was approximately $235.2 million as of December 31, 2001. The Company has
approximately $325,000 of standby letters of credit and a $10,000 performance
bond open at December 31, 2001. Approximately $336,000 of cash is restricted and
in escrow related to certain of the letters of credit and the bond.
Grey Wolf Facility
On December 20, 2001, Grey Wolf entered into a credit facility with
Mirant Canada. The Grey Wolf Facility established a revolving credit facility
with a commitment amount of CDN $150 million, (approximately US $96 million).
Subject to certain restrictions, the borrowing base may be reduced at the
discretion of Mirant Canada upon 30 days written notice. Subject to earlier
termination on the occurrence of events of default or other events, the stated
maturity date is December 20, 2007. The applicable interest rate charged on the
outstanding balance under the Grey Wolf Facility is 9.5%. Any amounts in default
will accrue interest at 15%. The Grey Wolf Facility is non-recourse to Abraxas
and its properties, other than Grey Wolf properties, and Abraxas has no
additional direct obligations to Mirant Canada under the facility.
F-18
Prior to maturity, Grey Wolf is required to make principal payments
under the Grey Wolf Facility as follows: (i) on the date of the sale of any
producing properties, Grey Wolf is required to make a payment equal to the
amount of the net sales proceeds; (ii) on a monthly basis, Grey Wolf is required
to make a payment equal to its net cash flow for the month prior to the date of
the payment; and (iii) on the date that any reduction in the commitment amount
becomes effective, Grey Wolf must repay all amounts over the commitment amount
so reduced.
Under the Grey Wolf Facility, "net cash flow" generally means the
amount of proceeds received by Grey Wolf from the sale of hydrocarbons less
taxes, royalty and similar payments (including overriding royalty interest
payments made to Mirant Canada), interest payments made to Mirant Canada and
operating and other expenses including approved capital and G&A expenses.
Grey Wolf may also make pre-payments at any time after December 20,
2002.
The Company treats the Grey Wolf Facility as a revolving line of credit
since, under ordinary circumstances, the lender is paid on a net cash flow
basis. It is anticipated that the Company will be a net borrower for the next
several years due to a large number of exploration and exploitation projects and
the associated capital needs to complete the projects.
Obligations under the Grey Wolf Facility are secured by a security
interest in substantially all of Grey Wolf's assets, including, without
limitation, working interests in producing properties and related assets owned
by Grey Wolf. None of Abraxas' assets are subject to a security interest under
the Grey Wolf Facility.
The Grey Wolf Facility contains a number of covenants that, among other
things, restrict the ability of Grey Wolf to (i) enter into new business areas,
(ii) incur additional indebtedness, (iii) create or permit to be created any
liens on any of its properties, (iv) make certain payments, dividends and
distributions, (v) make any unapproved capital expenditures, (vi) sell any of
its accounts receivable, (vii) enter into any unapproved leasing arrangements,
(viii) enter into any take-or-pay contracts, (ix) liquidate, dissolve,
consolidate with or merge into any other entity, (x) dispose of its assets, (xi)
abandon any property subject to Mirant Canada's security interest, (xii) modify
any of its operating agreements, (xiii) enter into any unapproved hedging
agreements, and (xiv) enter into any new agreements affecting existing
agreements relating to or affecting properties subject to Mirant Canada's
security interests. In addition, Grey Wolf is required to submit a quarterly
development plan for Mirant Canada's approval and Grey Wolf must comply with
specified financial ratios and tests, including a minimum collateral coverage
ratio.
Upon receipt by the Company of a written request from the Miranat
Canada, the Company shall promptly, and in any event within 10 days of receipt
of such request, have entered into one or more swap, hedge, floor, collar or
similar agreements which are satisfactory to the lender at a price and for a
term which is mutually acceptable to the Company and the Mirant Canada.
The Grey Wolf Facility contains customary events of default, including
nonpayment of principal or interest, violations of covenants, inaccuracy of
representations or warranties in any material respect, cross default and cross
acceleration to certain other indebtedness, bankruptcy, material judgments and
liabilities, change of control and any material adverse change in the financial
condition of Grey Wolf.
As a condition to the Grey Wolf Facility, Grey Wolf has granted two
overriding royalty interests to Mirant Canada, each in the amount of 2.5% of the
revenues received by Grey Wolf from oil and gas sales from all of its
properties. These overriding royalty interest result in the recording of a $2.3
million discount on the Grey Wolf Facility borrowings at December 31, 2001.
Production Payment
In October 1999 the Company entered into a non-recourse Dollar
Denominated Production Payment agreement (the "Production Payment") with a third
party. The Production Payment has an aggregate total availability of up to $50
million at 15% interest. The Production Payment relates to a portion of the
production from several natural gas wells in South Texas. As of December 31,
2001, the Company had received $22.1 million under this agreement. The
outstanding balance as of December 31, 2001 is $8.2 million.
F-19
Extraordinary Item
In June 2000, the Company retired $3.5 million of the Old Notes and
$3.6 million of the Second Lien Notes at a discount of $1.8 million.
6. Stockholders' Equity
Common Stock
In 1994, the Board of Directors adopted a Stockholders' Rights Plan and
declared a dividend of one Common Stock Purchase Right ("Rights") for each share
of common stock. The Rights are not initially exercisable. Subject to the Board
of Directors' option to extend the period, the Rights will become exercisable
and will detach from the common stock ten days after any person has become a
beneficial owner of 20% or more of the common stock of the Company or has made a
tender offer or Exchange Offer (other than certain qualifying offers) for 20% or
more of the common stock of the Company.
Once the Rights become exercisable, each Right entitles the holder,
other than the acquiring person, to purchase for $40 a number of shares of the
Company's common stock having a market value of two times the purchase price.
The Company may redeem the Rights at any time for $.01 per Right prior to a
specified period of time after a tender or Exchange Offer. The Rights will
expire in November 2004, unless earlier exchanged or redeemed
Contingent Value Rights ("CVRs")
As part of the exchange offer consummated by the Company in December
1999, Abraxas issued contingent value rights or CVRs, which entitled the holders
to receive up to a total of 105,408,978 of Abraxas common stock under certain
circumstances as defined. In May 2001, Abraxas issued 3,386,488 shares upon the
expiration of the CVRs.
Treasury Stock
In March 1996, the Board of Directors authorized the purchase in the
open market of up to 500,000 shares of the Company's outstanding common stock,
the aggregate purchase price not to exceed $3,500,000. During the year ended
December 31, 2000, 38,800 shares with an aggregate cost of $78,000 were
purchased. During the years ended December 31, 1999 and 2001, the Company did
not purchase any shares of its common stock for treasury stock.
7. Stock Option Plans and Warrants
Stock Options
The Company grants options to its officers, directors, and key
employees under various stock option and incentive plans.
During 2001, the Company's stockholders approved an amendment to the
Abraxas Petroleum Corporation 1994 Long Term Incentive Plan to increase the
number of shares of Abraxas common stock reserved for issuance under the plan to
5,000,000. The additional shares were necessary to accommodate the grant of
Abraxas options to Grey Wolf option holders in connection with the acquisition
of the minority interest in Grey Wolf in September 2001 (see Note 3), and for
the re-issuance of outstanding options granted under the Abraxas Petroleum
Corporation 2000 Long Term Incentive Plan, which was terminated in 2001. The
options were re-issued at the same exercise price and term as the original
issuances.
The Company's various stock option plans have authorized the grant of
options to management, employees and directors for up to approximately 5.6
million shares of the Company's common stock. All options granted have ten year
terms and vest and become fully exercisable over three to four years of
continued service at 25% to 33% on each anniversary date. At December 31, 2001
approximately 695,000 options remain available for grant.
Pro forma information regarding net income (loss) and earnings (loss)
per share is required by SFAS 123, "Accounting for Stock-Based Compensation",
which also requires that the information be determined as if the Company has
accounted for its employee stock options granted subsequent to December 31, 1995
under the fair value method prescribed by that SFAS. The fair value for these
options was estimated at the date of grant using a Black-Scholes option pricing
model with the following weighted-average assumptions for 1999, 2000, and 2001,
risk-free interest rates of 6.25%, 6.25% and 3.50%, respectively; dividend
yields of -0-%; volatility factors of the expected market price of the Company's
common stock of .928, .916 and .35, respectively; and a weighted-average
expected life of the option of ten years.
F-20
The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions including the expected stock price
volatility. Because the Company's employee stock options have characteristics
significantly different from those of traded options, and because changes in the
subjective input assumptions can materially affect the fair value estimate, in
management's opinion, the existing models do not necessarily provide a reliable
single measure of the fair value of its employee stock options.
For purposes of pro forma disclosures, the estimated fair value of the
options is amortized to expense over the options' vesting period. The Company's
pro forma information follows:
1999 2000 2001
---------------------------------------------
(In thousands except per share data)
Pro forma net income (loss) ............................ $ (37,240) $ 10,089 $ (21,002)
Pro forma net income (loss) per common share ........... $ (5.49) $ 0.45 $ (0.81)
Pro forma net income (loss) per common share - diluted $ (5.49) $ 0.31 $ (0.81)
A summary of the Company's stock option activity, and related
information for the years ended December 31, follows:
1999 2000 2001
----------------------------- ----------------------------- -----------------------------
Weighted-Average Weighted-Average Weighted-Average
Options Exercise Price(1) Options Exercise Price Options Exercise Price
(000s) (000s) (000s) (2)
---------- ------------------ ---------- ------------------ --------- ------------------
Outstanding-beginning of
year ................... 1,572 $ 7.33 1,890 $ 1.82 4,042 $ 3.37
Granted ................... 534 1.19 2,240 4.62 918 2.81
Exercised ................. - - - - (8) 1.95
Forfeited/Expired ......... (216) 2.06 (88) 1.89 (10) 1.79
---------- ---------- ---------
Outstanding-end of year ... 1,890 $ 1.82 4,042 $ 3.37 4,942 $ 3.28
========== ========== =========
Exercisable at end of year 685 $ 2.06 1,067 $ 1.99 2,259 $ 2.65
========== ========== =========
Weighted-average fair
value of options
granted during the year $ 1.07 $ 1.21 $ 1.19
Exercise prices for options outstanding as of December 31, 2001 ranged
from $0.97 to $5.03. The weighted-average remaining contractual life of those
options is approximately 7 years.
(1) In March 1999, the Company amended the exercise price to $2.06 per
share on all options with an existing exercise price greater than
$2.06. See Note 1 Stock-based compensation.
(2) In September 2001, the Abraxas Petroleum Corporation 2000 Long Term
Incentive Plan was terminated, and options granted under the plan were
reissued under the Abraxas Petroleum Corporation 1994 Long Term
Incentive Plan at the same option price and term.
Stock Awards
In addition to stock options granted under the plans described above,
the 1994 Long-Term Incentive Plan also provides for the right to receive
compensation in cash, awards of common stock, or a combination thereof. In 1999,
the Company made direct awards of common stock of 18,932 shares at weighted
average fair values of $5.09 per share. The Company recorded compensation
expense of $37,900 for the year ended December 31, 1999. There were no awards in
2000 or 2001.
F-21
The Company also has adopted the Restricted Share Plan for Directors
which provides for awards of common stock to nonemployee directors of the
Company who did not, within the year immediately preceding the determination of
the director's eligibility, receive any award under any other plan of the
Company. In 1999 and 2000, the Company made direct awards of common stock of
3,314 shares and 12,753 shares, respectively, at weighted average fair values of
$4.38 and $0.94 per share, respectively. The Company recorded compensation
expense of $13,700 and $11,900 for the years ended December 31, 1999 and 2000,
respectively. There were no direct awards of common stock in 2001.
During 1996, the Company's stockholders approved the Abraxas Petroleum
Corporation Director Stock Option Plan (Plan), which authorizes the grant of
nonstatutory options to acquire an aggregate of 104,000 common shares to those
persons who are directors and not officers of the Company. In March 1999 each of
the seven eligible directors were granted an option to purchase 2,000 common
shares at $2.06, in November 1999 five of the eligible directors were granted
options to purchase 15,000 common shares at $1.41. In December 1999 a new board
was appointed in connection with the Company's Exchange Offer, each of the four
new eligible directors were granted options for 75,000 common shares at $0.97.
Stock Warrants and Other
In 2000, the Company issued 950,000 warrants in conjunction with a
consulting agreement. Each is exercisable for one share of common stock at an
exercise price of $3.50 per share. These warrants have a four-year term
beginning July 1, 2000. The Company recorded approximately $219,000 of
compensation expense which is included in Other expense in 2000. In addition,
the Company paid cash compensation of $360,000 and $191,000 in 2000 and 2001,
respectively, under the agreement.
At December 31, 2001, the Company has approximately 6.6 million shares
reserved for future issuance for conversion of its stock options, warrants, and
incentive plans for the Company's directors, employees and consultants.
8. Income Taxes
Deferred income taxes reflect the net tax effects of temporary
differences between the carrying amounts of assets and liabilities for financial
reporting purposes and the amounts used for income tax purposes. Significant
components of the Company's deferred tax liabilities and assets are as follows:
December 31
--------------------
2000 2001
-------- --------
(In thousands)
Deferred tax liabilities:
U.S. full cost pool ..................... $ 2,359 $ 2,714
Canadian full cost pool ................. 21,079 24,809
-------- --------
Total deferred tax liabilities ............ 23,438 27,523
Deferred tax assets:
Depletion ............................... 1,439 2,035
Net operating losses ("NOL") ........... 34,624 42,264
Other ................................... 1,059 2,273
-------- --------
Total deferred tax assets ................. 37,122 46,572
Valuation allowance for deferred tax assets (34,763) (39,670)
-------- --------
Net deferred tax assets ................... 2,359 6,902
-------- --------
Net deferred tax liabilities .............. $ 21,079 $ 20,621
======== ========
Significant components of the provision (benefit) for income taxes are
as follows:
1999 2000 2001
---------- ----------- -----------
Current:
Federal..................... $ - $ - $ 505
Foreign .................... 491 (1,233) -
---------- ----------- -----------
$ 491 $ (1,233) $ 505
========== =========== ===========
Deferred:
Federal ..................... $ - $ 3,433 $ -
Foreign ..................... (13,116) 1,505 1,897
---------- ----------- -----------
$(13,116) $ 4,938 $ 1,897
========== =========== ===========
F-22
As a result of the acquisition described in Note 3, deferred tax
liabilities decreased by $1,091,000.
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 US $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.
The reconciliation of income tax attributable to continuing operations
computed at the U.S. federal statutory tax rates to income tax expense is:
December 31
---------------------------------------------
1999 2000 2001
-------------- --------------- --------------
(In thousands)
Tax (expense) benefit at U.S.
statutory rates (34%) ...... $ 16,672 $ (3,965) $ 5,318
(Increase) decrease in deferred
tax asset valuation
allowance ................... (3,312) 1,371 (4,907)
NOL utilization -
extraordinary gain -........ - (603) -
Write-down of non-tax basis
assets....................... - - (2,194)
Higher effective rate of
foreign operations......... (491) (1,098) (136)
Percentage depletion ......... - 363 596
Other ........................ (244) 227 (1,079)
-------------- --------------- --------------
$ 12,625 $ (3,705) $ (2,402)
============== =============== ==============
F-23
9. Related Party Transactions
Accounts receivable - Other and Other assets includes approximately
$268,000 and $195,000 as of December 31, 2000 and 2001, respectively,
representing amounts due from officers and stockholders relating primarily to
joint interest billings on properties which the Company operates and advances
made to employees.
Grey Wolf owns a 10% interest in the Canadian Abraxas oil and gas
properties and the Canadian Abraxas gas processing plants acquired by Canadian
Abraxas in November 1996 and 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. Amounts paid under
this agreement were $2.3 million, $2.5 million and $1.7 million for the years
ended December 31, 1999, 2000 and 2001, respectively.
Wind River Resources Corporation ("Wind River"), all of the capital
stock of which is owned by the Company's President, owns a twin-engine airplane.
The airplane is available for business use by the employees of Abraxas from time
to time at Wind River's cost. Abraxas paid Wind River a total of $336,000,
$336,000 and $314,000 in 1999, 2000 and 2001 respectively.
10. Commitments and Contingencies
Operating Leases
During the years ended December 31, 1999, 2000 and 2001, the Company
incurred rent expense related to leasing office facilities of approximately
$396,000, $465,000 and $519,000, respectively. Future minimum rental payments
are as follows at December 31, 2001.
2002............................................. $ 528,000
2003 ............................................ 336,000
2004 ............................................ 236,000
2005 ............................................ 236,000
2006 ............................................ 177,000
Thereafter ...................................... -
Litigation and Contingencies
In 2001 the Company and the Partnership (see Note 3) were named in a
lawsuit filed in U.S. District Court in the District of Wyoming. The claim
asserts breach of contract, fraud and negligent misrepresentation by the Company
related to the responsibility for year 2000 ad valorem taxes on crude oil and
natural gas properties sold by the Company and the Partnership. In February
2002, a summary judgment was granted to the plaintiff in this matter and a final
judgment in the amount of $1.3 million was entered. The Company has filed an
appeal. The Company believes these charges are without merit. The Company has
established a reserve in the amount of $845,000, which represents the Company's
interest in the judgment.
In late 2000, the Company received a Final De Minimis Settlement Offer
from the United States Environmental Protection Agency concerning the Casmalia
Disposal Site, Santa Barbara County, California. The Company's liability for the
cleanup at the Superfund site is based on its acquisition of Bennett Petroleum
Corporation, which is alleged to have transported or arranged for the
transportation of oil field waste and drilling muds to the Superfund site. The
Company has engaged California counsel to evaluate the notice of proposed de
minimis settlement and its notice of potential strict liability under the
Comprehensive Environmental Response, Compensation and Liability Act. Defense of
the action is handled through a joint group of oil companies, all of which are
claiming a petroleum exclusion that limits the Company's liability. The
potential financial exposure and any settlement posture has yet not been
developed, but is considered by the Company to be immaterial.
Additionally, from time to time, the Company is involved in litigation
relating to claims arising out of its operations in the normal course of
business. At December 31, 2001, the Company was not engaged in any legal
proceedings that are expected, individually or in the aggregate, to have a
material adverse effect on the Company.
F-24
11. Earnings per Share
The following table sets forth the computation of basic and diluted
earnings per share:
1999 2000 2001
------------------ ----------------- ---------------
Numerator:
Numerator for basic and diluted earnings per share
- net income (loss) before extraordinary item $ (36,680,000) $ 6,676,000 $ (19,718,000)
Extraordinary item - 1,773,000 -
------------------ ----------------- ---------------
Numerator for basis and diluted earnings per share
- net income (loss) available to common
stockholders (36,680,000) 8,449,000 (19,718,000)
================== ================= ===============
Denominator:
Denominator for basic earnings per share -
weighted-average shares 6,783,633 22,615,777 25,788,571
Effect of dilutive securities:
Stock options, warrants and CVRs - 10,011,987 -
------------------ ----------------- ---------------
Dilutive potential common shares Denominator for
diluted earnings per share -
adjusted weighted-average shares and assumed
conversions 6,783,633 32,627,764 25,788,571
================== ================= ===============
Basic earnings (loss) per share:
Net income (loss) before extraordinary item $ (5.41) $ 0.29 $ (0.76)
Extraordinary item - 0.08 -
---------------- ----------------- ---------------
Net income (loss) per common share $ (5.41) $ 0.37 $ (0.76)
================== ================= ===============
Diluted earnings (loss) per share:
Net income (loss) before extraordinary item $ (5.41) $ 0.21 $ (0.76)
Extraordinary item - 0.05 -
------------------ ----------------- ---------------
Net income (loss) per common share - diluted $ (5.41) $ 0.26 $ (0.76)
================== ================= ===============
For the year ended December 31, 1999 and 2001 none of the shares
issuable in connection with stock options, warrants or CVRs are included in
diluted shares. Inclusion of these shares would be antidilutive due to losses
incurred in that year. Had a loss not been incurred, 68.2 million shares and 1.2
million shares would have been included for the year ended December 31, 1999 and
2001, respectively.
12. Quarterly Results of Operations (Unaudited)
Selected results of operations for each of the fiscal quarters during
the years ended December 31, 2000 and 2001 are as follows:
1st 2nd 3rd 4th
Quarter Quarter Quarter Quarter
--------- ---------- --------- ---------
(In thousands, except per share data)
Year Ended December 31, 2000
Net revenue ................... $ 16,717 $ 16,287 $ 16,377 $ 27,219
Operating income (loss) ....... 1,513 1,629 (963) 9,404
Net income (loss) before
extraordinary item .......... 27,156 (7,186) (13,586) 292
Net income (loss) ............. 27,156 (5,413) (13,586) 292
Net income (loss) before
extraordinary item per
common share- basic ......... $ 1.20 $ (0.32) $ (0.60) $ 0.01
Net income (loss) before
extraordinary item per common
share - diluted ............ $ 0.52 $ (0.32) $ (0.60) $ 0.01
F-25
Net income (loss) per common
share- basic ................ $ 1.20 $ (0.24) $ (0.60) $ 0.01
(0.60)
Net income (loss) per common
share- diluted .............. $ 0.52 $ (0.24) $ (0.60) $ 0.01
Year Ended December 31, 2001
Net revenue ................... $ 29,086 $ 21,116 $ 14,901 $ 12,140
Operating income (loss) ....... 12,112 9,002 2,113 (4,102)
Net income (loss) ............. 255 (1,274) (5,849) (12,850)
Net income (loss) per common
share- basic ................ $ 0.01 $ (0.05) $ (0.22) $ (0.43)
Net income (loss) per common
share- diluted .............. $ 0.01 $ (0.05) $ (0.22) $ (0.43)
During the first quarter of 2000, the Company recognized a gain of $34
million on the sale of its equity investment in the Partnership. In the second
quarter of 2000, the Company recognized an extraordinary gain on debt
extinguishment of $1.8 million.
During the fourth quarter of 2001, the Company incurred a ceiling
limitation write-down of $2.6 million, which was determined using realized
prices at March 22, 2002. Had year-end 2001 realized prices been used, the
write-down would have been $71.3 million.
13. Benefit Plans
The Company has a defined contribution plan (401(k)) covering all
eligible employees of the Company. The Company did not contribute to the plan in
2000 or 2001. The employee contribution limitations are determined by formulas,
which limit the upper one-third of the plan members from contributing amounts
that would cause the plan to be top-heavy. The employee contribution is limited
to the lesser of 20% of the employee's annual compensation or $11,000.
14. Guarantor Condensed Consolidation Financial Statements.
The following table presents condensed consolidating balance sheets of
Abraxas, as a parent company, and its significant subsidiaries, Canadian Abraxas
and Grey Wolf, as of December 31, 2000 and 2001 and the related consolidating
statements of operations for the years ended December 31, 1999, 2000 and 2001.
Canadian Abraxas (one of the Restricted Subsidiaries, see Note 5) is a guarantor
of the First Lien Notes ($63.5 million) and jointly and severally liable with
Abraxas for the Second Lien Notes ($190.2 million) and the Old Notes ($801,000).
Grey Wolf is a non-guarantor with respect to the First Lien Notes and the Old
Notes.
Condensed Consolidating Parent Company, Restricted Subsidiaries and Non-Guarantor Balance Sheet
December 31, 2001
(In thousands)
Abraxas Abraxas
Petroleum Restricted Reclassifi- Petroleum
Corporation Subsidiary Non-Guarantor cations Corporation
Inc. Parent (Canadian Subsidiary and and
Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries
-----------------------------------------------------------------------------
Assets:
Current assets:
Cash .................................... $ 3,593 $ 1,245 $ 2,767 $ - $ 7,605
Accounts receivable, less allowance for
doubtful accounts...................... 17,281 792 6,782 (16,808) 8,047
Equipment inventory ..................... 1,061 178 12 - 1,251
F-26
Other current assets .................... 250 99 94 - 443
-------------- --------------- ------------- ------------ --------------
Total current assets .................. 22,185 2,314 9,655 (16,808) 17,346
Property and equipment - net................ 116,462 122,486 42,946 - 281,894
Deferred financing fees, net .............. 2,779 1,042 107 - 3,928
Other assets ............................... 108,801 784 6,281 (115,321) 545
-------------- --------------- ------------- ------------ --------------
Total assets ............................ $ 250,227 $ 126,626 $ 58,989 $ (132,129) $ 303,713
============== =============== ============= ============ ==============
Liabilities and Stockholder's deficit:
Current liabilities:
Accounts payable ............................. $ 10,642 $ 17,009 $ 9,472 $ (22,985) $ 14,138
Accrued interest ............................. 5,000 1,009 4 - 6,013
Other accrued expenses ....................... 1,052 - 64 - 1,116
Hedge liability .............................. 438 220 - - 658
Current maturities of long-term debt ......... 415 - - - 415
-------------- --------------- ------------- ------------ --------------
Total current liabilities .................. 17,547 18,238 9,540 (22,985) 22,340
Long-term debt .................................. 209,611 52,629 22,944 - 285,184
Deferred income taxes ........................... - 17,718 2,903 - 20,621
Future site restoration ........................ - 3,399 657 - 4,056
-------------- --------------- ------------- ------------ --------------
227,158 91,984 36,044 (22,985) 332,201
Stockholders' equity (deficit)................... 23,069 34,642 22,945 (109,144) (28,488)
-------------- --------------- ------------- ------------ --------------
Total liabilities and stockholders' equity
(deficit)........................................ $ 250,227 $ 126,626 $ 58,989 $ (132,129) $ 303,713
============== =============== ============= ============ ==============
(1) Includes amounts for insignificant U.S. subsidiaries, Sandia and Wamsutter,
which are guarantors of the First and Second Lien Notes. Sandia is also a
guarantor of the Old Notes. Additionally, these subsidiaries are designated as
Restricted Subsidiaries along with Canadian Abraxas (see Note 5).
Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Balance Sheet
December 31, 2000
(In thousands)
Abraxas Abraxas
Petroleum Restricted Reclassifi- Petroleum
Corporation Subsidiary Non-Guarantor cations Corporation
Inc. Parent (Canadian Subsidiary and and
Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries
--------------- -------------- ------------------------------ -----------------
Assets:
Current assets:
Cash .................................... $ 326 $ 1,678 $ - $ - $ 2,004
Accounts receivable, less allowance for
doubtful accounts...................... 46,085 2,890 6,434 (34,691) 20,718
Equipment inventory ..................... 985 319 107 - 1,411
Other current assets .................... 179 - - - 179
--------------- -------------- ------------- ---------------- -----------------
Total current assets .................. 47,575 4,887 6,541 (34,691) 24,312
Property and equipment - net................ 119,349 148,585 36,850 - 304,784
Deferred financing fees, net .............. 4,116 1,440 - - 5,556
Other assets ............................... 96,666 832 - (96,590) 908
--------------- -------------- ------------- ---------------- -----------------
Total assets ............................ $ 267,706 $ 155,744 $ 43,391 $ (131,281) $ 335,560
=============== ============== ============= ================ =================
Liabilities and Stockholder's deficit:
Current liabilities:
Accounts payable ............................. $ 23,028 $31,437 $ 8,891 $ (34,354) $ 29,002
Accrued interest ............................. 5,057 1,009 13 - 6,079
Other accrued expenses ....................... 679 (349) 1,602 - 1,932
Current maturities of long-term debt ......... 1,128 - - - 1,128
--------------- -------------- ------------- ---------------- -----------------
Total current liabilities .................. 29,892 32,097 10,506 (34,354) 38,141
Long-term debt .................................. 205,953 52,629 7,859 - 266,441
Deferred income taxes ........................... - 18,881 2,198 - 21,079
Future site restoration ........................ - 3,706 599 - 4,305
F-27
Minority interest in foreign subsidiary ......... - - - 12,097 12,097
--------------- -------------- ------------- ---------------- -----------------
235,845 107,313 21,162 (22,257) 342,063
Stockholders' equity (deficit)................... 31,861 48,431 22,229 (109,024) (6,503)
--------------- -------------- ------------- ---------------- -----------------
Total liabilities and stockholders' equity
(deficit)........................................ $ 267,706 $ 155,744 $ 43,391 $(131,281) $ 335,560
=============== ============== ============= ================ =================
Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Statement of Operations
For the year ended December 31, 2001
(In thousands)
Abraxas Abraxas
Petroleum Restricted Reclassifi- Petroleum
Corporation Subsidiary Non-Guarantor cations Corporation
Inc. Parent (Canadian Subsidiary and and
Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries
--------------- -------------- ------------- --------------- ---------------
Revenues:
Oil and gas production revenues ............... $ 34,934 $ 24,308 $ 13,959 $ - $ 73,201
Gas processing revenues ....................... - 2,008 430 - 2,438
Rig revenues .................................. 756 - - - 756
Other ........................................ 85 471 292 - 848
--------------- -------------- ------------- --------------- ---------------
35,775 26,787 14,681 - 77,243
Operating costs and expenses:
Lease operating and production taxes .......... 9,302 6,836 2,478 - 18,616
Depreciation, depletion, and amortization ..... 12,336 14,707 5,441 - 32,484
Proved property impairment .................... - 2,638 - - 2,638
Rig operations ................................ 702 - - - 702
General and administrative .................... 3,742 1,720 983 - 6,445
General and administrative (Stock-based
Compensation)................................ (2,767) - - - (2,767)
--------------- -------------- ------------- --------------- ---------------
23,315 25,901 8,902 - 58,118
--------------- -------------- ------------- --------------- ---------------
Operating income (loss)........................... 12,460 886 5,779 - 19,125
Other (income) expense:
Interest income ............................... (1,242) - - 1,164 (78)
Amortization of deferred financing fees........ 1,907 361 - - 2,268
Interest expense............................... 25,086 7,117 484 (1,164) 31,523
Other ......................................... 1,052 - - - 1,052
--------------- -------------- ------------- --------------- ---------------
26,803 7,478 484 - 34,765
--------------- -------------- ------------- --------------- ---------------
Income (loss) from operations before income tax -
and extraordinary item......................... (14,343) (6,592) 5,295 (15,640)
Income tax expense (benefit)...................... 505 (80) 1,977 - 2,402
Minority interest in income of consolidated
foreign subsidiary ............................ - - - (1,676) (1,676)
--------------- -------------- ------------- --------------- ---------------
Net income (loss)................................ $ (14,848) $ (6,512) $ 3,318 $ (1,676) $ (19,718)
=============== =============- ============= =============== ================
Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Statement of Operations
For the year ended December 31, 2000
(In thousands)
Abraxas Abraxas
Petroleum Restricted Reclassifi- Petroleum
Corporation Subsidiary Non-Guarantor cations Corporation
Inc. Parent (Canadian Subsidiary and and
Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries
--------------- -------------- ------------- --------------- ---------------
Revenues:
Oil and gas production revenues ............... $ 32,165 $ 27,425 $ 13,383 $ - $ 72,973
F-28
Gas processing revenues ....................... - 2,271 446 - 2,717
Rig revenues .................................. 505 - - - 505
Other ........................................ 216 170 19 - 405
--------------- -------------- ------------- --------------- ---------------
32,886 29,866 13,848 - 76,600
Operating costs and expenses:
Lease operating and production taxes .......... 7,755 8,695 2,333 - 18,783
Depreciation, depletion, and amortization ..... 12,328 18,126 5,403 - 35,857
Rig operations ................................ 717 - - - 717
General and administrative .................... 4,115 1,484 934 - 6,533
General and administrative (Stock-based
Compensation)................................ 2,767 - - - 2,767
--------------- -------------- ------------- --------------- ---------------
27,682 28,305 8,670 - 64,657
--------------- -------------- ------------- --------------- ---------------
Operating income (loss)........................... 5,204 1,561 5,178 - 11,943
Other (income) expense:
Interest income ............................... (2,277) - - 1,747 (530)
Amortization of deferred financing fees........ 1,660 431 - - 2,091
Interest expense .............................. 24,594 7,582 711 (1,747) 31,140
Gain on sale of equity investment ............. (33,983) - - - (33,983)
Other ......................................... 1,116 447 - - 1,563
--------------- -------------- ------------- --------------- ---------------
(8,890) 8,460 711 - 281
--------------- -------------- ------------- --------------- ---------------
Income (loss) from operations before income tax
and extraordinary item......................... 14,094 (6,899) 4,467 - 11,662
Income tax expense (benefit)...................... 3,433 (1,658) 1,930 - 3,705
Minority interest in income of consolidated 112
foreign subsidiary ............................ - - - (1,281) (1,281)
--------------- -------------- ------------- --------------- ---------------
Income (loss) before extraordinary item........... 10,661 (5,241) 2,537 (1,281) 6,676
Extraordinary item:
Gain on debt extinguishment.................... 1,773 - - - 1,773
--------------- -------------- ------------- --------------- ---------------
Net income (loss)................................. $ 12,434 $ (5,241) $ 2,537 $ (1,281) $ 8,449
=============== ============= ============= =============== ===============
Condensed Consolidating Parent Company, Restricted Subsidiaries and Non-Guarantor Statement of Operations
For the year ended December 31, 1999
(In thousands)
Abraxas Abraxas
Petroleum Restricted Reclassifi- Petroleum
Corporation Subsidiary Non-Guarantor cations Corporation
Inc. Parent (Canadian Subsidiary and and
Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries
--------------- -------------- ------------- --------------- ---------------
Revenues:
Oil and gas production revenues ............... $ 21,1 $ 29,314 $ 8,380 $ - $ 59,025
Gas processing revenues ....................... - 3,827 417 - 4,244
Rig revenues .................................. 444 - - - 444
Other ........................................ 2,811 222 24 - 3,057
--------------- -------------- ------------- --------------- ---------------
24,586 33,363 8,821 66,770
Operating costs and expenses:
Lease operating and production taxes .......... 6,627 9,115 2,196 - 17,938
Depreciation, depletion, and amortization ..... 9,931 20,329 4,551 - 34,811
Proved property impairment .................... - 19,100 - - 19,100
Rig operations ................................ 624 - - - 624
General and administrative .................... 2,933 1,728 608 - 5,269
--------------- -------------- ------------- --------------- ---------------
20,115 50,272 7,355 - 77,742
--------------- -------------- ------------- --------------- ---------------
Operating income (loss)........................... 4,471 (16,909) 1,466 - (10,972)
F-29
Other (income) expense:
Interest income ............................... (1,590) (347) (28) 1,299 (666)
Amortization of deferred financing fees........ 1,484 431 - - 1,915
Interest expense............................... 28,036 9,662 416 (1,299) 36,815
--------------- -------------- ------------- --------------- ---------------
27,930 9,746 388 - 38,064
--------------- -------------- ------------- --------------- ---------------
Income (loss) from operations before income tax... (23,459) (26,655) 1,078 - (49,036)
Income tax expense (benefit)...................... - (13,177) 552 - (12,625)
Minority interest in income of consolidated
foreign subsidiary ............................ - - - (269) (269)
--------------- -------------- ------------- --------------- ---------------
Net income (loss) ............................... $ (23,459) $(13,478) $ 526 $ (269) $ (36,680)
=============== ============== ============= =============== ===============
Condensed Consolidating Partent, Restricted Subsidiary and Non-Guarantor Statement of Cash Flow
For the year ended December 31, 2001
(In thousands)
Abraxas Abraxas
Petroleum Restricted Reclassifi- Petroleum
Corporation Subsidiary Non-Guarantor cations Corporation
Inc. Parent (Canadian Subsidiary and and
Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries
--------------- -------------- ------------- --------------- ---------------
Operating ActivitiesOperating Activities
Net income (loss) ........................... $ (14,848) $ (6,512) $ 3,318 $ (1,676) $ (19,718)
Adjustments to reconcile net income (loss)
to net cash provided by operating
activities:
Minority interest in income of foreign
subsidiary ........................... - - - 1,676 1,676
Loss on sale of equity investment....... 845 - - - 845
Depreciation, depletion, and
amortization ......................... 12,336 14,707 5,441 - 32,484
Proved property impairment ............. - 2,638 - - 2,638
Deferred income tax (benefit) expense... - (80) 1,977 - 1,897
Amortization of deferred financing fees. 1,907 361 - - 2,268
Stock-based compensation ............... (2,767) - - - (2,767)
Changes in operating assets and
liabilities:
Accounts receivable ................ 28,804 (9,721) (6,390) - 12,693
Equipment inventory ................ (76) - - - (76)
Other ............................. (281) - 175 - (106)
Accounts payables and accrued
expenses ......................... (12,915) (2,254) (402) - (15,571)
--------------- -------------- ------------- --------------- ---------------
Net cash provided (used) by operating
activities ............................... 13,005 (861) 4,119 - 16,263
Investing Activities
Capital expenditures, including purchases
and development of properties ............ (19,126) (15,313) (22,617) - (57,056)
Proceeds from sale of oil and gas
properties................................ 9,677 15,882 3,379 - 28,938
Acquisition of minority interest ............ (2,679) - - - (2,679)
--------------- -------------- ------------- --------------- ---------------
Net cash provided (used) by investing
activities ............................... (12,128) 569 (19,238) - (30,797)
Financing Activities
Proceeds form issuance of common stock....... 16 - - - 16
Proceeds from long-term borrowings .......... 11,700 - 18,295 - 29,995
F-30
Payments on long-term borrowings ............ (9,326) - - - (9,326)
--------------- -------------- ------------- --------------- ---------------
Net cash provided (used) by financing
activities.................................. 2,390 - 18,295 - 20,685
--------------- -------------- ------------- --------------- ---------------
3,267 (292) 3,176 - 6,151
Effect of exchange rate changes on cash ..... - (141) (409) - (550)
--------------- -------------- ------------- --------------- ---------------
Increase (decrease) in cash ................. 3,267 (433) 2,767 - 5,601
Cash at beginning of year ................... 326 1,678 - - 2,004
--------------- -------------- ------------- --------------- ---------------
Cash at end of year.......................... $ 3,593 $ 1,245 $ 2,767 $ - $ 7,605
=============== ============== ============= =============== ===============
Condensed Consolidating Partent, Restricted Subsidiary and Non-Guarantor Statement of Cash Flow
For the year ended December 31, 2000
(In thousands)
Abraxas Abraxas
Petroleum Restricted Reclassifi- Petroleum
Corporation Subsidiary Non-Guarantor cations Corporation
Inc. Parent (Canadian Subsidiary and and
Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries
--------------- -------------- ------------- --------------- ---------------
Operating Activities
Net income (loss) ........................... $ 12,434 $ (5,241) $ 2,537 $ (1,281) $ 8,449
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Minority interest in income of foreign
subsidiary ........................... - - - 1,281 1,281
Extraordinary gain on extinguishment
of debt............................... (1,773) - - - (1,773)
Gain on sale of equity investment....... (33,983) - - - (33,983)
Depreciation, depletion, and
amortization ......................... 12,329 18,126 5,402 - 35,857
Deferred income tax expense (bebefit)... 3,433 (153) 1,658 4,938
Amortization of deferred financing fees. 1,660 431 - - 2,091
Stock-based compensation ............... 2,767 - - - 2,767
Issuance of common stock and warrants
for compensation ..................... 265 - - - 265
Changes in operating assets and
liabilities:
Accounts receivable ................ 8 (3,461) (3,583) - (7,036)
Equipment inventory ................ (538) - - - (538)
Other ............................. (184) (1,618) (37) - (1,839)
Accounts payables and accrued 10,893
expenses ......................... 5,357 378 5,158 -
--------------- -------------- ------------- --------------- ---------------
Net cash provided by operating activities ... 1,775 8,462 11,135 - 21,372
Investing Activities
Capital expenditures, including purchases
and development of properties ............ (39,767) (15,649) (18,996) - (74,412)
Proceeds from sale of oil and gas
properties ............................... 5,542 7,393 8,222 - 21,157
Proceeds from sale of equity investment ..... 34,482 - - - 34,482
--------------- -------------- ------------- --------------- ---------------
Net cash provided (used) by investing
activities ............................... 257 (8,256) (10,774) - (18,773)
Financing Activities
Purchase of treasury stock, net ............. (78) - - - (78)
Proceeds from long-term borrowings .......... 6,400 - - - 6,400
Payments on long-term borrowings ............ (9,979) - (184) - (10,163)
Deferred financing fees ..................... 23 - - - 23
--------------- -------------- ------------- --------------- ---------------
F-31
Net cash provided (used) by financing
activities ............................... (3,634) - (184) - (3,818)
--------------- -------------- ------------- --------------- ---------------
(1,602) 206 177 - (1,219)
Effect of exchange rate changes on cash ..... - (399) (177) - (576)
--------------- -------------- ------------- --------------- ---------------
Increase (decrease) in cash ................. (1,602) (193) - - (1,795)
Cash at beginning of year ................... 1,928 1,871 - - 3,799
--------------- -------------- ------------- --------------- ---------------
Cash at end of year.......................... $ 326 $ 1,678 $ - $ - $ 2,004
=============== ============== ============= =============== ===============
Condensed Consolidating Partent, Restricted Subsidiary and Non-Guarantor Statement of Cash Flow
For the year ended December 31, 1999
(In thousands)
Abraxas Abraxas
Petroleum Restricted Reclassifi- Petroleum
Corporation Subsidiary Non-Guarantor cations Corporation
Inc. Parent (Canadian Subsidiary and and
Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries
--------------- -------------- ------------- --------------- ---------------
Operating Activities
Net income (loss) ........................... $ (23,459) $ (13,478) $ 526 $ (269) $ (36,680)
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Minority interest in income of foreign
subsidiary ........................... - - - 269 269
Depreciation, depletion, and
amortization ......................... 9,931 20,329 4,551 - 34,811
Proved property impairment ............. - 19,100 - - 19,100
Deferred income tax (benefit) expense... - (13,595) 479 - (13,116)
Amortization of deferred financing fees. 1,484 431 - - 1,915
Amortization of premium on long term
debt.................................. (579) - - - (579)
Issuance of common stock and warrants
for compensation ..................... 53 - - - 53
Changes in operating assets and
liabilities:
Accounts receivable ................ 3,724 (5,201) (1,315) 94 (2,698)
Equipment inventory ................ 57 - - - 57
Other ............................. 221 (177) 352 - 396
Accounts payables and accrued
expenses ......................... 7,816 (8,224) 762 - 354
Other................................... (83,656) 83,750 - (94) -
--------------- -------------- ------------- --------------- ---------------
Net cash provided (used) by operating
activities ............................... (84,408) 82,935 5,355 - 3,882
Investing Activities
Capital expenditures, including purchases
and development of properties ............ (19,132) (99,600) (9,976) - (128,708)
Proceeds from sale of oil and gas
properties and equipment inventory ....... 1,753 13,920 1,821 - 17,494
--------------- -------------- ------------- --------------- ---------------
Net cash used by investing activities ....... (17,379) (85,680) (8,155) - (111,214)
Financing Activities
Proceeds from long-term borrowings .......... 87,006 54 1,397 - 88,457
Payments on long-term borrowings ............ (35,747) - - - (35,747)
Deferred financing fees ..................... (3,586) - - - (3,586)
--------------- -------------- ------------- --------------- ---------------
Net cash provided by financing activities ... 47,673 54 1,397 - 49,124
--------------- -------------- ------------- --------------- ---------------
(54,114) (2,691) (1,403) - (58,208)
Effect of exchange rate changes on cash ..... - 392 225 - 617
--------------- -------------- ------------- --------------- ---------------
F-32
Increase (decrease) in cash ................. (54,114) (2,299) (1,178) - (57,591)
Cash at beginning of year ................... 56,042 4,170 1,178 - 61,390
--------------- -------------- ------------- --------------- ---------------
Cash at end of year.......................... $ 1,928 $ 1,871 $ - $ - $ 3,799
=============== =============- ============= =============== ===============
15. Business Segments
The Company conducts its operations through two geographic segments,
the United States and Canada, and is engaged in the acquisition, development,
and production of crude oil and natural gas and the processing of natural gas in
each country. The Company's significant operations are located in the Texas Gulf
Coast, the Permian Basin of western Texas, and Canada. Identifiable assets are
those assets used in the operations of the segment. Corporate assets consist
primarily of deferred financing fees and other property and equipment. The
Company's revenues are derived primarily from the sale of crude oil, condensate,
natural gas liquids, and natural gas to marketers and refiners and from
processing fees from the custom processing of natural gas. As a general policy,
collateral is not required for receivables; however, the credit of the Company's
customers is regularly assessed. The Company is not aware of any significant
credit risk relating to its customers and has not experienced significant credit
losses associated with such receivables.
In 2001, three customers accounted for approximately 41% of
consolidated oil and natural gas production revenue. Three customers accounted
for approximately 76% of United States revenue and five customers accounted for
approximately 78% of revenue in Canada. In 2000, two customers accounted for
approximately 26% of oil and natural gas production revenues. Three customers
accounted for approximately 59% of United States revenue and two customers
accounted for approximately 36% of revenue in Canada. In 1999, three customers
accounted for approximately 58% of oil and natural gas production revenues and
gas processing revenues.
Business segment information about the Company's 1999 operations in different
geographic areas is as follows:
U.S. Canada Total
------------------ ------------------ -------------------
(In thousands)
Revenues ................................... $ 24,586 $ 42,184 $ 66,770
================== ================== ===================
Operating profit (loss)..................... $ 7,765 $ (15,444) $ (7,679)
================== ==================
General corporate .......................... (3,293)
Net interest expense and amortization of
deferred financing fees ................. (38,064)
-------------------
Loss before income taxes ................ $ (49,036)
===================
Identifiable assets at December 31, 1999 ... $ 107,336 $ 206,474 $ 313,810
================== ==================
Corporate assets ........................... 8,474
-------------------
Total assets ............................ $ 322,284
===================
Business segment information about the Company's 2000 operations in different
geographic areas is as follows:
U.S. Canada Total
------------------ ------------------ -------------------
(In thousands)
Revenues ................................... $ 32,886 $ 43,714 $ 76,600
================== ================== ===================
Operating profit............................ $ 12,446 $ 6,739 $ 19,185
================== ==================
General corporate .......................... (7,602)
Net interest expense and amortization of
deferred financing fees ................. (32,701)
Other income (net).......................... 32,780
-------------------
Income before income taxes and
extraordinary items ................... $ 11,662
===================
Identifiable assets at December 31, 2000 ... $ 132,327 $ 197,229 $ 329,556
================== ==================
F-33
Corporate assets ........................... 6,004
-------------------
Total assets ............................ $ 335,560
===================
Business segment information about the Company's 2001 operations in different
geographic areas is as follows:
U.S. Canada Total
------------------ ------------------ -------------------
(In thousands)
Revenues ................................... $ 35,775 $ 41,468 $ 77,243
================== ================== ===================
Operating profit............................ $ 13,795 $ 6,665 $ 20,460
================== ==================
General corporate .......................... (1,335)
Net interest expense and amortization of
deferred financing fees ................. (33,713)
Other expense............................... (1,052)
-------------------
Loss before income taxes................. $ (15,640)
===================
Identifiable assets at December 31, 2001.... $ 124,993 $ 174,063 $ 299,056
================== ==================
Corporate assets ........................... 4,657
-------------------
Total assets ............................ $ 303,713
===================
16. Hedging Program and Derivatives
On January 1, 2001, the Company adopted SFAS 133 "Accounting for
Derivative Instruments and Hedging Activities" as amended and interpreted. Under
SFAS 133, all derivative instruments are recorded on the balance sheet at fair
value. If the derivative does not qualify as a hedge or is not designated as a
hedge, the gain or loss on the derivative is recognized currently in earnings.
To qualify for hedge accounting, the derivative must qualify either as a fair
value hedge, cash flow hedge or foreign currency hedge. Currently, the Company
uses only cash flow hedges and the remaining discussion will relate exclusively
to this type of derivative instrument. If the derivative qualifies for hedge
accounting, the gain or loss on the derivative is deferred in Other
Comprehensive Income (Loss), a component of Stockholders' Equity, to the extent
that the hedge is effective.
The relationship between the hedging instrument and the hedged item
must be highly effective in achieving the offset of changes in cash flows
attributable to the hedged risk both at the inception of the contract and on an
ongoing basis. Hedge accounting is discontinued prospectively when a hedge
instrument becomes ineffective. Gains and losses deferred in accumulated Other
Comprehensive Income (Loss) related to a cash flow hedge that becomes
ineffective remain unchanged until the related production is delivered. If the
Company determines that it is probable that a hedged transaction will not occur,
deferred gains or losses on the hedging instrument are recognized in earnings
immediately.
Gains and losses on hedging instruments related to accumulated Other
Comprehensive Income (Loss) and adjustments to carrying amounts on hedged
production are included in natural gas or crude oil production revenue in the
period that the related production is delivered.
The following table sets forth the Company's hedge position as of December
31, 2001.
Time Period Notional Quantities Price Fair Value
--------------------------------------- ------------------------------ ------------------------------ ----------------
January, 2002 - October 31, 2002 20,000 Mcf/day of natural Fixed price swap $2.60-$2.95 $ (658,000)
gas or 1,000 Bbl/day of natural gas or
crude oil $18.90 Crude oil
On January 1, 2001, in accordance with the transition provisions of
SFAS 133, the Company recorded $31.0 million, net of tax, in Other Comprehensive
Income (Loss) representing the cumulative effect of an accounting change to
recognize the fair value of cash flow derivatives. The Company recorded cash
flow hedge derivative liabilities of $38.2 million on that date and a deferred
tax asset of $7.2 million.
F-34
For the year ended December 31, 2001, losses before tax of $12.1
million were transferred from Other Comprehensive Income (Loss) to revenue and
the fair value of outstanding liabilities decreased by $25.5 million. The
ineffective portion of the cash flow hedges was not material at December 31,
2001.
For the year ended December 31, 2001, $566,000 of deferred net loss on
derivative instruments were recorded in Other Comprehensive Income (Loss). All
of the deferred net loss is expected to be reclassified to earnings during the
next twelve-month period.
All hedge transactions are subject to the Company's risk management
policy, approved by the Board of Directors. The Company formally documents all
relationships between hedging instruments and hedged items, as well as its risk
management objectives and strategy for undertaking the hedge. This process
includes specific identification of the hedging instrument and the hedged
transaction, the nature of the risk being hedged and how the hedging
instrument's effectiveness will be assessed. Both at the inception of the hedge
and on an ongoing basis, the Company assesses whether the derivatives that are
used in hedging transactions are highly effective in offsetting changes in cash
flows of hedged items.
The fair value of the hedging instrument was determined based on the
base price of the hedged item and NYMEX forward price quotes. As of December
2001, a commodity price increase of 10% would have resulted in an unfavorable
change in the fair market value of $1.2 million, and a commodity price decrease
of 10% would have resulted in a favorable change in fair market value of $0.9
million.
In November 1996, the Company assumed swap arrangements extending
through October 2001 with a counterparty involving various quantities and fixed
prices. These swap arrangements provided that the Company make payments to the
counterparty to the extent the market prices, determined based on the price for
crude oil on the NYMEX and the Inside FERC, Tennessee Gas Pipeline Co. Texas
(Zone O) price for natural gas, exceed certain fixed prices and for the
counterparty to make payments to the Company to the extent the market prices
were less than such fixed prices. The Company accounted for the related gains or
losses in crude oil and natural gas revenue in the period of the hedged
production. These swap arrangements terminated in January 1999 and the Company
was paid $750,000 by the counterparty for such termination. This amount is
included in Other Revenue in the accompanying financial statements.
In March 1998, the Company entered into a costless collar hedge
agreement with Enron Capital and Trade Resources Corp. for 2,000 Bbls of crude
oil per day with a floor price of $14.00 per Bbl and a ceiling price of $22.30
per Bbl for crude oil on the NYMEX. The agreement was effective April 1, 1998
and extended through March 31, 1999. Under the terms of the agreement the
Company was paid when the average monthly price for crude oil on the NYMEX was
below the floor price, and the Company paid the counterparty when the average
monthly price exceeded the ceiling price. For the year ended December 31, 1999
the Company realized a loss of $1.8 million on this agreement, which is
accounted for in Crude Oil and Natural Gas Revenue. The Company has also entered
into a costless collar hedge agreement with Barrett Resources Corporation
("Barrett") for the period November 1999 through October 2000. This agreement
consisted of a swap for 1,000 Bbls per day of crude oil with the Company being
paid $20.30 and paying NYMEX calendar month average, and an additional 1,000
Bbls of crude oil per day with a floor price of $18.00 per Bbl and a ceiling of
$22.00 per Bbl. The Company realized a loss from hedges of $20.2 million for the
year ended December 31, 2000, which is accounted for in Oil and Gas Production
Revenue. At year end 2001 Barrett has a swap call on either 1,000 Bbls of crude
oil or 20,000 MMBtu of natural gas per day at Barrett's option at fixed prices
($18.90 for crude oil or $2.60 to $2.95 for natural gas) through October 31,
2002. The Company realized a loss from hedges of $12.1 million for the year
ended December 31, 2001, which is accounted for in Oil and Gas Production
Revenue.
17. Comprehensive Income
Comprehensive income includes net income, losses and certain items
recorded directly to Stockholders' Equity and classified as Other Comprehensive
Income (Loss). The following table illustrates the calculation of comprehensive
income for the year ended December 31, 2001:
Accumulated Other
Comprehensive Comprehensive Income
Income (Loss) (Loss)
------------------- ------------------------
For the year
Ended As of
December 31, 2001 December 31, 2001
------------------- ------------------------
Accumulated other comprehensive loss at December 31, 2000 (a)...... $ (4,799)
F-35
Net loss........................................................ $ (19,718)
-------------------
Other Comprehensive income (loss):
Hedging derivatives (net of tax) - See Note 16
Cumulative effect of change in accounting principle January
1, 2001....................................................... (30,980)
Reclassification adjustment for settled hedge contracts....... 12,113
Change in fair market value of outstanding hedge positions.... 18,301
-------------------
(566)
Foreign currency translation adjustment......................... (8,196)
-------------------
Other comprehensive income (loss).................................. (8,762) (8,762)
-------------------
Comprehensive income (loss)........................................ $ ( 28,480)
=================== ---------------------
Accumulated other comprehensive loss at December 31, 2001.......... $ (13,561)
=====================
(a) Amount at December 31, 2000 due to foreign currency
translation adjustment.
18. Proved Property Impairment
In accordance with SEC requirements, the estimated discounted future
net cash flows from proved reserves are generally based on prices and costs as
of the end of the year, or alternatively, if prices subsequent to that date have
increased, a price near the periodic filing date of the Company's financial
statements. As of December 31, 2001, the Company's net capitalized costs of oil
and gas properties exceeded the present value of its estimated proved reserves
by $71.3 million ($38.9 million on the U.S. properties and $32.4 million on the
Canadian properties). These amounts were calculated considering 2001 year-end
prices of $19.84 per barrel for oil and $2.57 per Mcf for gas as adjusted to
reflect the expected realized prices for each of the full cost pools. The
Company did not adjust its capitalized costs for its U.S. properties because
subsequent to December 31, 2001, oil and gas prices increased such that
capitalized costs for its U.S. properties did not exceed the present value of
the estimated proved oil and gas reserves for its U.S. properties as determined
using increased realized prices on March 22, 2002 of $24.16 per Bbl for oil and
$2.89 per Mcf for gas. 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.
19. Subsequent Event
In March 2002, the Company's wholly-owned Canadian subsidiaries, Grey
Wolf and Canadian Abraxas, entered into a definitive purchase and sale agreement
related to the sale of their interest in a natural gas processing 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 $21.5 million.
F-36
20. Supplemental Oil and Gas Disclosures (Unaudited)
The accompanying table presents information concerning the Company's
crude oil and natural gas producing activities as required by Statement of
Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing
Activities." Capitalized costs relating to oil and gas producing activities are
as follows:
Years Ended December 31
------------------------------------------------------------------------------------------
2000 2001
---------------------------------------------- -------------------------------------------
Total U.S. Canada Total U.S. Canada
--------------- -------------- ------------ ------------- ------------- --------------
(In thousands)
Proved crude oil and natural
gas properties ............ $ 481,802 $ 274,939 $ 206,863 $ 486,098 $ 284,182 $ 201,916
Unproved properties ......... 12,831 - 12,831 10,626 - 10,626
--------------- -------------- ------------ ------------- ------------- --------------
Total .......................... 494,633 274,939 219,694 496,724 284,182 212,542
Accumulated depreciation,
depletion, and
amortization, and
impairment ................ (251,746) (156,148) (95,598) (280,280) (168,124) (112,156)
--------------- -------------- ------------ ------------- ------------- --------------
Net capitalized costs ... $ 242,887 118,791 $ 124,096 $ 216,444 $ 116,058 $ 100,386
=============== ============== ============ ============= ============= ==============
Cost incurred in oil and gas property acquisitions, exploration and
development activities are as follows:
Years Ended December 31
--------------------------------------------------------------------------------------------------
1999 2000 2001
---------------------------------------------------------------------------------------------------
Total U.S Canada Total U.S. Canada Total U.S. Canada
----------- ---------- ---------- --------- --------- ---------- ------------ ---------- ---------
(In thousands)
Property acquisition costs:
Proved ................... $ 89,743 $ - $ 89,743 $ 7,189 $ - $ 7,189 $ - $ - $ -
Unproved ................. - - - - - - - - -
----------- ---------- ---------- --------- --------- ---------- ------------ ---------- ---------
$ 89,743 $ - $ 89,743 $ 7,189 $ - $ 7,189 $ - $ - $ -
=========== ========== ========== ========= ========== ========== ============ ========== ========
Property development and
exploration costs ........ $ 37,344 $ 18,901 $ 18,443 $64,873 $ 39,631 $ 25,242 $ 56,694 $ 18,867 $ 37,827
=========== ========== ========== ========= ========== ========== ============ ========== ========
F-37
The results of operations for oil and gas producing activities are as
follows:
Years Ended December 31
--------------------------------------------------------------------------------------------------
1999 2000 2001
---------------------------------------------------------------------------------------------------
Total U.S Canada Total U.S. Canada Total U.S. Canada
----------- ---------- ---------- --------- --------- ---------- ------------ ---------- ---------
(In thousands)
Revenues ................... $ 59,025 $ 21,331 $ 37,694 $ 72,973 $ 32,165 $ 40,808 $ 73,201 $ 34,934 $ 38,267
Production costs ........... (17,938) (6,627) (11,311) (18,783) (7,755) (11,028) (18,616) (9,302) (9,314)
Depreciation, depletion,
and amortization ......... (34,452) (9,571) (24,881) (35,497) (11,968) (23,529) (32,124) (11,976) (20,148)
Proved property impairment . (19,100) - (19,100) - - - (2,638) - (2,638)
General and administrative . (1,317) (733) (584) (1,722) (1,118) (604) (1,565) (1,073) (492)
Income taxes (expense)
benefit................... 7,455 - 7,455 (339) - (339) (2,419) - (2,419)
----------- ---------- ---------- --------- --------- ---------- ------------ ---------- ---------
Results of operations from oil
and gas producing activities
(excluding corporate overhead
and interest costs) ....... $ (6,327) $ 4,400 $(10,727) $ 16,632 $ 11,324 $ 5,308 $ 15,839 $ 12,583 $ 3,256
=========== ========== ========== ========== ========= =========== ========== ========= =========
Depletion rate per barrel
of oil equivalent, before
impact of impairment .... $ 6.34 $ 4.91 $ 7.13 $ 8.30 $ 6.19 $ 10.02 $ 8.81 $ 6.96 $ 10.45
=========== ========== ========== ========== ========= =========== ========== ========= =========
F-38
Estimated Quantities of Proved Oil and Gas Reserves
The following table presents the Company's estimate of its net proved
crude oil and natural gas reserves as of December 31, 1999, 2000, and 2001. The
Company's management emphasizes that reserve estimates are inherently imprecise
and that estimates of new discoveries are more imprecise than those of producing
oil and gas properties. Accordingly, the estimates are expected to change as
future information becomes available. The estimates have been prepared by
independent petroleum reserve engineers.
Total United States Canada
------------------------- ------------------------- -------------------------
Liquid Natural Liquid Natural Liquid Natural
Hydrocarbons Gas Hydrocarbons Gas Hydrocarbons Gas
------------ ------------ ------------ ------------ ------------ -----------
Barrels) (Mcf) (Barrels) (Mcf) (Barrels) (Mcf)
(In Thousands)
Proved developed and undeveloped reserves:
Balance at December 31, 1998 ........... 7,695 197,478 5,751 110,239 1,944 (1) 87,239 (2)
Revisions of previous estimates ...... (167) (80,592) 1,153 (45,697) (1,320) (34,895)
Extensions and discoveries ........... 354 30,305 196 24,686 158 5,619
Purchase of minerals in place ........ 3,246 58,354 - - 3,246 58,354
Production ........................... (1,154) (25,698) (584) (8,190) (570) (17,508)
Sale of minerals in place ............ (125) (15,542) (95) (621) (30) (14,921)
------------ -------------- ------------ ------------ ------------ -----------
Balance at December 31, 1999 (3) ....... 9,849 164,305 6,421 80,417 3,428 (1) 83,888 (2)
Revisions of previous estimates ...... (216) (21,342) 54 (13,441) (270) (7,901)
Extensions and discoveries ........... 791 72,498 315 57,371 476 15,127
Purchase of minerals in place ........ 254 6,822 - - 254 6,822
Production ........................... (952) (19,963) (539) (8,364) (413) (11,599)
Sale of minerals in place ............ (882) (10,993) (170) (1,075) (712) (9,918)
------------ -------------- ------------ ------------ ------------ -----------
Balance at December 31, 2000............ 8,844 191,327 6,081 114,908 2,763 (1) 76,419 (2)
Revisions of previous estimates ...... (627) 2,944 (688) 3,318 60 (374)
Extensions and discoveries ........... 1,063 26,329 354 4,886 710 21,443
Production ........................... (732) (17,495) (416) (7,823) (316) (9,672)
Sale of minerals in place ............ (1,746) (14,348) (924) (6,821) (822) (7,527)
------------ -------------- ------------ ------------ ------------ -----------
Balance at December 31, 2001............ 6,802 188,757 4,407 108,468 2,395 80,289
============ =====================================================================
(1) Includes 269,000 and 732,000 barrels of liquid hydrocarbon reserves owned by
Grey Wolf of which approximately 138,000 and 376,000 barrels are applicable
to the minority interest's share of these reserves at December 31, 1999 and
2000, respectively. As of December 31, 2001 Abraxas owned 100% of Grey Wolf.
(2) Includes 21,710 and 21,389 MMcf of natural gas reserves owned by Grey Wolf
of which 11,140 and 10,975 MMcf are applicable to the minority interest's
share of these reserves at December 31, 1999 and 2000, respectively. As of
December 31, 2001 Abraxas owned 100% of Grey Wolf.
(3) At year end 1999 amounts exclude the Company's proportional interest in
Partnership proved reserves, accounted for by the equity method, of 2.8
Mbbls of liquid hydrocarbons and 25.8 MMcf of natural gas.
F-39
Estimated Quantities of Proved Oil and Gas Reserves (continued)
Total United States Canada
------------------------- ------------------------- -------------------------
Liquid Natural Liquid Natural Liquid Natural
Hydrocarbons Gas Hydrocarbons Gas Hydrocarbons Gas
------------ ------------ ------------ ------------ ------------ -----------
Barrels) (Mcf) (Barrels) (Mcf) (Barrels) (Mcf)
(In Thousands)
Proved developed reserves:
December 31, 1999....................... 7,700 128,587 4,492 53,275 3,208 75,312
=========== =========== ============ =========== ============= ============
December 31, 2000 ...................... 7,001 119,737 4,309 48,177 2,692 71,560
=========== =========== ============ =========== ============= ============
December 31, 2001....................... 5,047 111,243 2,892 40,514 2,155 70,729
=========== =========== ============ =========== ============= ============
F-40
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves
The following disclosures concerning the standardized measure of future
cash flows from proved crude oil and natural gas reserves are presented in
accordance with SFAS No. 69. The standardized measure does not purport to
represent the fair market value of the Company's proved crude oil and natural
gas reserves. An estimate of fair market value would also take into account,
among other factors, the recovery of reserves not classified as proved,
anticipated future changes in prices and costs, and a discount factor more
representative of the time value of money and the risks inherent in reserve
estimates.
Under the standardized measure, future cash inflows were estimated by
applying period-end prices at December 31, 2001 adjusted for fixed and
determinable escalations, to the estimated future production of year-end proved
reserves. Future cash inflows were reduced by estimated future production and
development costs based on year-end costs to determine pre-tax cash inflows.
Future income taxes were computed by applying the statutory tax rate to the
excess of pre-tax cash inflows over the tax basis of the properties. Operating
loss carryforwards, tax credits, and permanent differences to the extent
estimated to be available in the future were also considered in the future
income tax calculations, thereby reducing the expected tax expense.
Future net cash inflows after income taxes were discounted using a 10%
annual discount rate to arrive at the Standardized Measure.
F-41
Set forth below is the Standardized Measure relating to proved oil and
gas reserves for:
Years Ended December 31
----------------------------------------------------------------------------------------------------
1999 2000 2001
----------------------------------- ----------------------------------- -----------------------------
Total U.S. Canada (1) Total U.S. Canada (1) Total U.S. Canada
----------------------------------- ----------------------------------- -----------------------------
(In thousands)
Future cash inflows........ $ 577,407 $ 309,609 $ 267,798 $ 2,046,039 $ 1,274,871 $ 771,168 $ 607,375 $313,640 $ 293,735
Future production and
development costs........ (181,109) (96,302) (84,807) (318,130) (254,667) (63,463) (220,613) (138,296) (82,317)
Future income tax expense.. (6,319) - (6,319) (230,987) (65,421) (165,566) - - -
------------ ---------- ---------- ------------ ------------ ---------- ----------- --------- ---------
Future net cash flows...... 389,979 213,307 176,672 1,496,922 954,783 542,139 386,762 175,344 211,418
Discount................... (151,528) (90,024) (61,504) (721,388) (468,663) (252,725) (177,096) (98,157) (78,939)
------------ ---------- ---------- ------------ ------------ ---------- ----------- --------- ---------
Standardized Measure of
discounted future net
cash relating to proved
reserves................. $ 238,451 $ 123,283 $ 115,168 $ 775,534 $ 486,120 $ 289,414 $ 209,666 $ 77,187 $ 132,479
============ ========== ========= =========== ============ ========== ========== ======== ===========
At year end 1999 amounts exclude the Partnership, accounted for by the equity
method, which was sold in 2000.
(1) The Standardized Measure of discounted future net cash flows relating
to proved reserves includes approximately $12,400 and $43,700 as of
December 31, 1999 and 2000, respectively, relating to minority
interest. As of December 31, 2001, Abraxas owns 100% of Grey Wolf.
F-42
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserves
The following is an analysis of the changes in the Standardized
Measure:
Year Ended December 31
----------------------------------------------------------
1999 2000 2001
------------------- ------------------- ------------------
(In thousands)
Standardized Measure, beginning
of year ................................. $ 181,581 $ 238,451 $ 775,534
Sales and transfers of oil and gas
produced, net of production costs ....... (41,086) (54,190) (54,585)
Net changes in prices and development
and production costs from prior year .... 77,060 707,755 (613,325)
Extensions, discoveries, and improved
recovery, less related costs ............ 34,445 290,283 39,982
Purchases of minerals in place ............ 90,510 33,586 -
Sales of minerals in place ................ (18,797) (75,391) (96,096)
Revision of previous quantity estimates ... (90,030) (95,757) (2,474)
Change in future income tax expense ....... (6,319) (224,668) 230,987
Other ..................................... (7,071) (68,380) (147,910)
Accretion of discount ..................... 18,158 23,845 77,553
------------------- ------------------- ------------------
Standardized Measure, end of year ....... $ 238,451 $ 775,534 $ 209,666
=================== =================== ==================
F-43
FINANCIAL STATEMENTS
GREY WOLF EXPLORATION INC.
December 31, 2001
F-44
AUDITORS' REPORT
To the Directors of
Grey Wolf Exploration Inc.
We have audited the balance sheets of Grey Wolf Exploration Inc. as at December
31, 2001 and 2000 and the statements of earnings and retained earnings and of
cash flows for the years then ended. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
With respect to the financial statements for each of the years in the two year
period ended December 31, 2001, we conducted our audits in accordance with
Canadian generally accepted auditing standards and auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform an audit to obtain reasonable assurance whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, these financial statements present fairly, in all material
respects, the financial position of the Company as at December 31, 2001 and 2000
and the results of its operations and its cash flows for the years then ended in
accordance with Canadian generally accepted accounting principles.
On February 23, 2001, we reported separately to the shareholders of the Company
on financial statements for the year ended December 31, 2000, prepared in
accordance with the Canadian generally accepted accounting principles, which
excluded Note 10 on differences between Canadian and United States generally
accepted accounting principles.
Calgary, Canada /s/ Deloitte & Touche LLP
March 28, 2002 Chartered Accountants
F-45
COMMENTS BY AUDITORS FOR U.S. READERS ON
CANADA - U.S. REPORTING DIFFERENCES
In the United States, reporting standards for auditors require the addition of
an explanatory paragraph (following the opinion paragraph) outlining changes in
accounting principles that have been implemented in the financial statements. As
discussed in Note 7 to the financial statements, in 2001 the Company changed its
method of computing diluted earnings per share to conform to the new Canadian
Institute of Chartered Accountants Handbook recommendations section 3500. In
addition, as discussed in Note 6 to the financial statements, in 2000 the
Company changed its method of accounting for income taxes to conform to the new
Canadian Institute of Chartered Accounts Handbook recommendations section 3465.
Calgary, Canada /s/ Deloitte & Touche LLP
March 28, 2002 Chartered Accountants
F-46
AUDITORS' REPORT
To the Directors of
Grey Wolf Exploration Inc.
We have audited the statements of earnings and retained earnings and cash flows
of Grey Wolf Exploration Inc. for the year ended December 31, 1999. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audit.
We conducted our audit in accordance with Canadian generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
In our opinion, these financial statements present fairly, in all material
respects, the results of the Company's operations and cash flows for the year
ended December 31, 1999 in accordance with Canadian generally accepted
accounting principles.
Calgary, Canada /s/ Ernst & Young LLP
March 10, 2000 Chartered Accountants
F-47
GREY WOLF EXPLORATION INC.
Balance Sheets
As At December 31
(thousands of dollars)
2001 2000
$ $
-------------------------------------------
ASSETS
Current
Cash (Note 4) 4,405 -
Accounts receivable (Note 9) 9,980 9,815
-------------------------------------------
14,385 9,815
Long-term receivable (Note 9) 10,000 -
Property and equipment (Note 3) 71,879 54,782
Deferred financing fees (Note 4) 170 -
-------------------------------------------
96,434 64,597
-------------------------------------------
Liabilities
Current
Accounts payable and accrued liabilities (Note 9) 15,183 15,764
Long-term debt (Note 4) 36,526 11,793
Future site restoration 1,050 898
Future income taxes (Note 6) 6,359 3,297
-------------------------------------------
59,118 31,752
-------------------------------------------
SHAREHOLDERS' EQUITY
Share capital (Note 5) 27,891 27,555
Retained earnings 9,425 5,290
-------------------------------------------
37,316 32,845
-------------------------------------------
96,434 64,597
-------------------------------------------
See accompanying notes
F-48
GREY WOLF EXPLORATION INC.
Statements of Earnings and Retained Earnings
Years Ended December 31
(thousands of dollars, except for share amounts)
2001 2000 1999
$ $ $
---------------------------------------------------
Revenue
Petroleum and natural gas sales 30,268 26,009 15,427
Royalties, net of Alberta Royalty Tax Credit (7,615) (5,380) (2,363)
---------------------------------------------------
22,653 20,629 13,064
---------------------------------------------------
Expenses
Operating 3,844 3,462 3,236
General and administrative 1,278 1,384 903
Interest and finance charges 1,827 1,126 576
Depletion, depreciation and site restoration 8,364 7,924 6,663
---------------------------------------------------
15,313 13,896 11,378
---------------------------------------------------
Earnings before taxes 7,340 6,733 1,686
---------------------------------------------------
Provision for taxes (Note 6)
Capital tax 144 61 110
Income taxes 3,061 2,732 229
---------------------------------------------------
3,205 2,793 339
---------------------------------------------------
Net earnings 4,135 3,940 1,347
Retained earnings, beginning of year 5,290 1,912 565
Adoption of income tax accounting standard change (Note 6) - (562) -
---------------------------------------------------
Retained earnings, end of year 9,425 5,290 1,912
---------------------------------------------------
Basic and diluted earnings per share (Note 7) 0.32 0.31 0.11
---------------------------------------------------
---------------------------------------------------
Weighted average number of shares
Basic 12,776,407 12,660,528 12,695,313
Diluted 12,776,407 12,732,251 12,707,805
---------------------------------------------------
See accompanying notes
F-49
GREY WOLF EXPLORATION INC.
Statements of Cash Flows
Years Ended December 31
(thousands of dollars, except for share amounts)
2001 2000 1999
$ $ $
---------------------------------------------------
Operating Activities
Net earnings 4,135 3,940 1,347
Depletion, depreciation and site restoration 8,364 7,924 6,663
Future income taxes 3,061 2,732 229
---------------------------------------------------
Cash flow from operations 15,560 14,596 8,239
Changes in non-cash working capital items (Note 8) (746) 1,936 (289)
---------------------------------------------------
14,814 16,532 7,950
---------------------------------------------------
Financing Activities
Increase (decrease) in long-term debt 28,334 (273) 2,094
Increase in long-term receivable (10,000) - -
Issue (repurchase) of common shares 336 3 (78)
---------------------------------------------------
18,670 (270) 2,016
---------------------------------------------------
Total cash resources provided 33,484 16,262 9,966
---------------------------------------------------
Investing Activities
Property and equipment received under property swap agreement - 10,779 -
Disposal of property and equipment under property swap agreement - (12,332) -
---------------------------------------------------
Net cash proceeds - (1,553) -
Other acquisitions (Note 9) 1,071 13 3,662
Expenditures for property and equipment 36,800 17,941 10,737
Sale of property and equipment (8,838) (342) (2,629)
Site restoration 46 203 -
---------------------------------------------------
29,079 16,262 11,770
---------------------------------------------------
Increase (decrease) in cash and cash equivalents 4,405 - (1,804)
Cash and cash equivalents, beginning of year - - 1,804
---------------------------------------------------
Cash and cash equivalents, end of year 4,405 - -
---------------------------------------------------
Cash flow from operations per share (Note 7)
Basic and diluted 1.22 1.15 0.65
---------------------------------------------------
---------------------------------------------------
Cash interest paid 1,840 1,123 614
Cash taxes paid 82 72 104
---------------------------------------------------
See accompanying notes
F-50
Grey Wolf Exploratioin, Inc.
Notes to Financial Statements
Years Ended December 31, 2001 and 2000
(tabular amounts in thousands of dollars, except for share amounts)
1. DESCRIPTION OF BUSINESs
Grey Wolf Exploration Inc. ("Grey Wolf" or "the Company") was incorporated
under the laws of the Province of Alberta on December 23, 1986. The
Company's primary business is the exploration, development and production
of crude oil and natural gas in western Canada. As at December 31, 2001,
the Company is a wholly-owned subsidiary of Abraxas Petroleum Corporation
("Abraxas").
2. SIGNIFICANT ACCOUNTING POLICIES
The financial statements have been prepared in accordance with Canadian
generally accepted accounting principles and are expressed in Canadian
dollars. Differences between Canadian and U.S. GAAP are outlined in Note 10
to the financial statements.
Petroleum and natural gas properties
The Company follows the full cost method of accounting in accordance with
the guideline issued by the Canadian Institute of Chartered Accountants
("CICA") whereby all costs associated with the exploration for and
development of petroleum and natural gas reserves, whether productive or
unproductive, are capitalized in a Canadian cost centre and charged to
income as set out below. Such costs include acquisition, drilling,
geological and geophysical costs related to exploration and development
activities. Costs of acquiring and evaluating unproved properties are
excluded from the depletion base until it is determined whether or not
proved reserves are attributable to the properties or impairment occurs.
Gains or losses are not recognized upon disposition of petroleum and
natural gas properties unless crediting the proceeds against accumulated
costs would result in a change in the rate of depletion of 20% or more.
Depletion of petroleum and natural gas properties and depreciation of
production equipment, except for gas plants and related facilities, is
provided on accumulated costs using the unit-of-production method based on
estimated proved petroleum and natural gas reserves, before royalties, as
determined by independent engineers. For purposes of the depletion
calculation, proven petroleum and natural gas reserves are converted to a
common unit of measure on the basis of one barrel of oil or liquids being
equal to six thousand cubic feet of natural gas. Depreciation of gas plants
and related facilities is calculated on a straight-line basis over an
average 18-year term.
The depletion and depreciation cost base includes capitalized costs, less
costs of unproved properties, plus provision for future development costs
of proved undeveloped reserves.
F-51
2. SIGNIFICANT ACCOUNTING POLICIES (Continued)
The net carrying value of the Company's petroleum and natural gas
properties is limited to an ultimate recoverable amount. This amount is the
aggregate of estimated future net revenues from proved reserves and the
costs of unproved properties, net of impairment allowances, less future
estimated production costs, general and administration costs, financing
costs, site restoration and abandonment costs, and income taxes. Future net
revenues are estimated using prices and costs without escalation or
discounting, and the income tax and Alberta Royalty Tax Credit legislation
in effect at year end.
Future abandonment and site restoration costs
The estimated cost of future abandonment and site restoration is based on
the current cost and the anticipated method and extent of site restoration
in accordance with existing legislation and industry practice. The annual
charge is provided for on a unit-of-production basis for all properties
except for gas plants for which the annual charge is calculated on a
straight-line basis over the estimated remaining life of the plants. Actual
site restoration expenditures are charged to the accumulated liability
account as incurred.
Other assets
Furniture, leasehold improvements, computer hardware, software and office
equipment are carried at cost and are depreciated over the estimated useful
life of the assets at rates varying between 20 percent and 30 percent, on a
declining-balance basis.
Use of estimates
The amounts recorded for depletion and depreciation of property and
equipment and the provision for abandonment and site restoration are based
on estimates. The ceiling test calculation is based on estimates of proved
reserves, production rates, oil and natural gas prices, future costs and
other relevant assumptions. By their nature, these estimates are subject to
uncertainty and the effect on the financial statements of changes in such
estimates could be significant.
Joint operations
Substantially all of the Company's exploration and development activities
are conducted jointly with others, and accordingly, the financial
statements reflect only the Company's proportionate interest in such
activities.
Revenue recognition
Petroleum and natural gas sales are recognized when the commodities are
delivered to purchasers.
F-52
2. SIGNIFICANT ACCOUNTING POLICIES (Continued)
Future income taxes
The Company has adopted, on a retroactive basis without restatement of the
1999 financial statements, the CICA new accounting recommendation, "Income
Taxes". Under this standard, future income tax assets and liabilities are
measured based upon temporary differences between the carrying values of
assets and liabilities and their tax basis. Income tax expense (recovery)
is computed based on the change during the year in the future tax assets
and liabilities. Effects of changes in tax laws and tax rates are
recognized when substantially enacted.
Financial instruments
Financial instruments of the Company consist of accounts receivable,
long-term receivable, accounts payable and accrued liabilities, and
long-term debt. As at December 31, 2001 and 2000, there were no significant
differences between the carrying amounts of these financial instruments
reported on the balance sheets and their estimated fair values.
The Company also from time to time employs financial instruments to manage
its exposure to commodity prices. These instruments are not used for
speculative trading purposes. Gains and losses on commodity price hedges
are included in revenues upon the sale of the related production provided
there is reasonable assurance that the hedge is and will continue to be
effective.
Stock options
The Company has a stock option plan as described in Note 5. No compensation
expense is recognized when the stock options are issued. Consideration
received on exercise of stock options is credited to share capital.
Earnings per share
Basic earnings per share is calculated using the weighted average number of
common shares outstanding during the year. Diluted earnings per share is
calculated on the basis of the weighted average number of shares
outstanding during the year plus the additional common shares that would
have been outstanding if potentially dilutive common shares had been issued
using the "treasury stock" method.
Effective January 1, 2001, the Company retroactively adopted, with
restatement of prior periods, the recommendations of new CICA Handbook
Section 3500 for calculating earning per share. Under the revised standard,
the treasury stock method is used for determining the dilutive effect of
options issued. Prior to the adoption of the new recommendations, diluted
per share amounts were determined using the imputed earnings method.
F-53
3. PROPERTY AND EQUIPMENT
2001
---------------------------------------------------------
Accumulated
Depletion and Net Book
Cost Depreciation Value
$ $ $
---------------------------------------------------------
Petroleum and natural gas properties 89,516 (25,901) 63,615
Gas plants and related production facilities 11,010 (2,845) 8,165
Other assets 597 (498) 99
---------------------------------------------------------
Net property and equipment 101,123 (29,244) 71,879
---------------------------------------------------------
2000
---------------------------------------------------------
Accumulated
Depletion and Net Book
Cost Depreciation Value
$ $ $
---------------------------------------------------------
Petroleum and natural gas properties 69,543 (19,384) 50,159
Gas plants and related production facilities 5,786 (1,326) 4,460
Other assets 531 (368) 163
---------------------------------------------------------
Net property and equipment 75,860 (21,078) 54,782
---------------------------------------------------------
Undeveloped property costs of $6,065,907 at December 31, 2001 (2000 -
$6,441,705, 1999 - $7,365,579) have been excluded from the depletion base.
F-54
4. LONG-TERM DEBT
At December 31, 2001, the Company had a credit facility with Mirant Canada
Energy Capital Ltd., (the "Mirant Facility") with a maximum available limit
of $150,000,000. At December 31, 2001, $40,127,000 was drawn down against
this facility. Of the $40,127,000 drawn, $10,000,000 was advanced to
Canaxas (Note 9). Under the Mirant Facility, the Company is required to pay
an amount equal to monthly net cash flow from operations less interest
payments, general and administrative expenses and approved capital
expenditures. It is anticipated the Company will be a net borrower due to a
number of planned capital projects over the next several years.
Accordingly, the outstanding balance has been classified as long-term on
the balance sheet. The facility matures in December 2007.
Under the facility, loan advances bear interest at 9.5%, plus a 5%
overriding royalty which will decrease to 2 1/2% when certain conditions
are met. The overriding royalty granted to Mirant was treated as a
disposition of petroleum and natural gas properties, with a corresponding
deferred financing charge recorded of $3,600,000 based on the fair value at
the date of disposition. This deferred charge was netted against the
outstanding loan balance and will be amortized over a 6-year period ended
in 2007. Loan advances are supported by a first charge demand debenture in
the amount of $200,000,000 covering all the assets of the Company.
The Mirant credit facility was used to extinguish the previous revolving
term credit facility. As at December 31, 2001, all of the previous
revolving term credit facility had been repaid except for a bankers
acceptance for $5,000,000. As at December 31, 2001, equivalent cash had
been placed in trust to cover the $5,000,000 repayment, and accordingly was
netted against the loan for financial statement purposes. The remaining
$5,000,000 was repaid in January 2002.
At December 31, 2000, the Company had a revolving term credit facility with
a Canadian chartered bank with a maximum limit of $20,000,000. At December
31, 2000, $11,792,690 was drawn down against this facility. Under the
facility, loan advances bore interest at bank prime plus 1/8%, or if
bankers acceptances were utilized, the then current bankers acceptances
rate plus 1 1/8%. Loan advances were supported by a first floating charge
demand debenture in the amount of $25,000,000 covering all the assets of
the Company. During May 2001, the maximum limit under the revolving term
credit facility was increased to $27,000,000 and remained at this level
replaced by the Mirant Facility in December 2001.
F-55
5. SHARE CAPITAL
Authorized
Unlimited number of common shares without nominal or par value.
Issued
Number of Amount
Shares $
--------------------------------------
Balance, December 31, 1998 12,704,341 27,630
Issuer bid (44,600) (78)
--------------------------------------
Balance, December 31, 1999 12,659,741 27,552
Exercise of stock options 1,800 3
--------------------------------------
Balance, December 31, 2000 12,661,541 27,555
Exercise of stock options 179,786 336
--------------------------------------
Balance, December 31, 2001 12,841,327 27,891
--------------------------------------
On May 20, 1999, the Company's shareholders approved the consolidation of
the share capital of the Company on the basis of one common share for each
ten common shares outstanding. All common share and per share amounts have
been reflected on a post consolidation basis.
Stock options
A maximum of 1,270,000 options to purchase common shares have been
authorized for issuance under the Company's stock option plan. The options
were exercisable on a cumulative basis at 25% per year commencing one year
after grant date and expire five years from the date of grant. During the
year ended December 31, 2001, all options outstanding in the Company were
cancelled and new options were issued by Abraxas.
Number Weighted Average
of Options Option Price
----------------------------------------------
Balance, December 31, 1998 897,816 3.20
Issued 328,470 1.91
Cancelled (192,571) 2.83
----------------------------------------------
Balance, December 31, 1999 1,033,715 2.84
Issued 398,376 1.60
Exercised (1,800) 1.60
Cancelled (420,262) 2.53
----------------------------------------------
F-56
Balance, December 31, 2000 1,010,029 2.30
----------------------------------------------
Cancelled 1,010,029 2.30
----------------------------------------------
Balance December 31, 2001 - -
----------------------------------------------
6. PROVISION FOR TAXES
The Company accounts for future income taxes using the liability method.
Future income tax assets and liabilities are measured based upon temporary
differences between the carrying values of assets and liabilities and their
tax bases. Income tax expense (recovery) is computed based on the change
during the year in the future tax assets and liabilities. Future income tax
liabilities or assets are calculated using tax rates anticipated to apply
in the periods that the temporary differences are expected to reverse.
Effects of changes in tax laws and tax rates are recognized when
substantially enacted.
The provision for taxes recorded on the statements of earnings and retained
earnings differs from the tax calculated by applying the combined statutory
Canadian corporate and provincial income tax rate as follows:
2001 2000 1999
$ $ $
--------------------------------------------------------
Calculated income tax expense at 42.62%, (2000 and 1999
- 44.62%) 3,128 3,004 752
Increase (decrease) in tax resulting from:
Non-deductible crown royalties and other charges 2,950 2,254 2,147
Resource allowance and related items (2,757) (2,066) (1,174)
Alberta Royalty Tax Credit (177) (231) (1,392)
Non-deductible depletion and depreciation - - 43
Benefit of losses not previously recognized - - (147)
Large Corporation Tax 144 61 110
Tax rate adjustment (151) - -
Other 68 (229) -
--------------------------------------------------------
Provision for taxes 3,205 2,793 339
--------------------------------------------------------
The major components of future income tax liability at December 31, 2001
and 2000 are related to the following accounts:
2001 2000
$ $
------------------- ------------------
Property and equipment 7,672 4,767
Future site restoration (447) (401)
Share issue costs (117) (94)
Non-capital losses carried forward - (557)
Attributed royalty income carried forward (511) (144)
Resource allowance (310) (274)
Deferred financing costs 72 -
------------------- ------------------
Balance, December 31 6,359 3,297
------------------- ------------------
F-57
6. PROVISION FOR TAXES (Continued)
Upon adoption of the new accounting recommendation of the CICA, the Company
recorded a future income tax liability of $562,000 and decreased the
Company's retained earnings by $562,000. Had the new method not been
adopted, 2000 net earnings would have been increased by $88,000.
As at December 31, 2001 and 2000, the Company has exploration and
development costs, undepreciated capital costs, non-capital losses and
unamortized share issue costs available for deduction against future
taxable income in the following approximate amounts:
2001 2000
$ $
-----------------------------------
Canadian oil and gas property expense 14,816 21,158
Canadian development expense 18,526 9,838
Canadian exploration expense 11,245 5,735
Undepreciated capital cost 9,290 7,097
Non-capital losses - 1,249
Unamortized share issue costs 276 210
-----------------------------------
54,153 45,287
-----------------------------------
The Company's non-capital losses are available to be carried forward to
offset taxable income in future years and expire between 2002 and 2004.
7. EARNINGS PER SHARE
The treasury method of calculating earnings per share was adopted
retroactively effective January 1, 2001, with restatement of prior periods.
If the imputed earnings method was utilized for 2000, diluted net earnings
per share would be $0.31 per share (1999 - $0.11) and diluted cash flow
from operations per share would be $1.11 (1999 - $0.62).
There is no impact on 2001 diluted per share figures as a result of
adopting the new treasury method.
8. SUPPLEMENTARY CASH FLOW INFORMATION
2001 2000 1999
$ $ $
--------------------------------------------------------
Accounts receivable (165) (5,712) (1,390)
Accounts payable and accrued liabilities (581) 7,648 1,101
--------------------------------------------------------
Changes in non-cash working capital items (746) 1,936 (289)
--------------------------------------------------------
F-58
9. RELATED PARTY TRANSACTIONS
The Company manages the assets and operations of Canadian Abraxas Petroleum
Limited ("Canaxas") pursuant to a Management Agreement dated November 12,
1996. Canaxas is a wholly-owned subsidiary of Abraxas. As at December 31,
2001, Abraxas owned 97.3% (2000 - 46.0%) of the common shares of the
Company and Canaxas owned 2.7% (2000 - 2.7%) of the common shares of the
Company. The aggregate common costs of operations and administration of the
Canaxas and Grey Wolf assets are shared on a pro-rata basis, based on
revenue.
Amounts due to and from these related parties with respect to the
Management Agreement are $3,741,000 at December 31, 2001 (2000 -
$3,823,000). Abraxas also charged the Company a corporate service charge of
$849,000 in 2001 (2000 and 1999 - $Nil) of which $589,000 was charged out
to Canaxas. The amounts are non-interest earning, are not collateralized
and are due on demand. In addition, at December 31, 2001, the Company had a
long-term receivable from Canaxas in the amount of $10,000,000 (Note 4)
(2000 - $Nil). The balance bears interest at 9.65% and has no fixed terms
of repayment.
2001 2000
$ $
----------------------------------
Receivable from Canaxas 4,330 3,823
Long-term receivable from Canaxas 10,000 -
Payable to Abraxas 849 -
In July 1999, the Company purchased undeveloped property from a wholly-owed
subsidiary of Canaxas for a total cost of $3,421,000. As a result of this
acquisition, the Company was committed to spend $6,000,000 prior to June 30,
2002 pursuant to the terms of a farm-in agreement between the Company and
the wholly-owned subsidiary of Canaxas.
10. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES
Reconciliation of Financial Statements to United States Generally Accepted
Accounting Principles
The financial statements of the Company have been prepared in accordance
with Canadian generally accepted accounting principles ("Canadian GAAP"),
which in most respects, conform to accounting principles generally accepted
in the United States of America ("U.S. GAAP"). Differences from U.S. GAAP
having a significant effect on the Company's balance sheets and statements
of earnings and retained earnings and of cash flows are described and
quantified below for the years indicated:
F-59
10. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES (Continued)
(a) Tnder U.S. GAAP, interest costs associated with certain capital
expenditures are required to be capitalized as part of the historical
cost of the oil and gas assets. Under Canadian GAAP, the calculation of
interest costs eligible for capitalization differs from the calculation
under U.S. GAAP in certain respects and is optional at the discretion
of the entity. Accordingly, no amounts have been capitalized with
respect to the Canadian GAAP financial statements. The impact of
recording capitalized interest under U.S. GAAP would be to increase the
carrying value of property and equipment by $119,000 in 2001 and
$69,000 in 2000 with a corresponding decrease in interest expense in
the respective periods.
(b) Under U.S. GAAP, deferred taxes are recorded based upon the liability
method. When a business combination occurs, deferred taxes are
recognized for the tax effect of timing differences, with a
corresponding increase in property and equipment. Under Canadian GAAP,
prior to the adoption of the new CICA accounting recommendation,
"Future Income Taxes" effective January 1, 2000, the Company followed
the deferral method of accounting for income taxes. The impact of the
difference in 1999 is an additional deferred tax expense under U.S.
GAAP of $480,000. Upon adoption of the new recommendation for Canadian
GAAP, companies were permitted to record the impact of differences in
accounting and tax bases related to prior business combinations to
retained earnings as a one-time transition adjustment. Accordingly,
property and equipment is higher under U.S. GAAP by $682,000 for 2001
and 2000 before the impact of depletion. The impact of the additional
depletion expense related to the increased property and equipment for
U.S. GAAP purposes is to decrease net income by $62,000 in 2001,
$88,000 in 2000, and $77,000 in 1999. The cumulative impact of the
depletion expense relating to years prior to 1999 is $78,000.
(c) In September 2001, Abraxas acquired the remaining non-controlling
interest of the Company. Consideration was comprised of 0.6 common
shares of Abraxas, in exchange for each common share of the Company.
Under U.S. GAAP, the costs assigned to assets and liabilities by the
acquiring company under a business combination are considered to
constitute a new basis of accounting. Accordingly, the historical
carrying values of assets and liabilities of the subsidiary are
comprehensively revalued based on the purchase price assigned for
consolidation purposes at the time it becomes wholly owned ("push down
accounting"). Under Canadian GAAP, comprehensive revaluation of assets
and liabilities in the financial statements of a subsidiary based on a
purchase transaction involving acquisition of all of the equity
interests is permitted, but not required. Had the consolidation entries
of Abraxas related to the acquisition been applied in the Company's
financial statements using "push down accounting", property and
equipment and future income tax liability would be reduced by
$4,074,000 and $1,736,000, respectively, accounts receivable would be
increased and interest and finance charges decreased by $984,000
(relating to certain costs of the transaction paid by the Company),
with the remaining amount of $2,338,000 recorded as a revaluation
adjustment within shareholders'equity.
F-60
10. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES (Continued)
(d) Prior to 2001, Canadian GAAP required the use of the imputed earnings
method for purposes of the calculation of fully diluted earnings per
share. For fiscal periods beginning on or after January 1, 2001,
retroactive application of the treasury stock method with restatement
of prior periods is required, which is substantially the same as No.
SFAS 128 under U.S. GAAP. Accordingly, no adjustments are required to
conform the diluted earnings per share figures to U.S. GAAP, except for
the net income effect of the above-noted Canadian - U.S. GAAP
differences identified.
(Tabular amounts are in thousands of Canadian dollars, except per share
amounts)
STATEMENTS OF EARNINGS
The application of U.S. GAAP would have the following effect on the
Statements of Earnings:
Years Ended December 31,
-------------------------------------------------
2001 2000 1999
$ $ $
--------------- ----------------- ---------------
Net earnings, as reported 4,135 3,940 1,347
Capitalized interest (a) 119 69 -
Depreciation, depletion and amortization (b) (62) (88) (77)
Deferred income tax expense benefit (b) - - (480)
Interest and finance charges (c) 984 - -
--------------- ----------------- ---------------
Net earnings, U.S. GAAP 5,176 3,921 790
--------------- ----------------- ---------------
Basic earnings per share, as reported 0.32 0.31 0.11
Effect of increase (decrease) in net earnings
under U.S. GAAP (d) 0.09 - (0.05)
--------------- ----------------- ---------------
Basic earnings per share, U.S. GAAP 0.41 0.31 0.06
--------------- ----------------- ---------------
Diluted earnings per share, as reported 0.32 0.31 0.11
Effect of increase (decrease) in net earnings
under U.S. GAAP (d) 0.09 - (0.05)
--------------- ----------------- ---------------
Diluted earnings per share, U.S. GAAP 0.41 0.31 0.06
--------------- ----------------- ---------------
F-61
10. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES (Continued)
BALANCE SHEETS
The application of U.S. GAAP would have the following effect on the Balance
Sheets:
As At December 31, 2001 As At December 31, 2000
------------------------------------------ -------------------------------------------
Cumulative
As Increase U.S. As Increase U.S.
Reported (Decrease) GAAP Reported (Decrease) GAAP
-------------- --------------- ----------- ------------- ---------------- ------------
ASSETS
Accounts receivable (c) 9,980 984 10,964 9,815 - 9,815
Property and equipment (a) (b) (c) 71,879 (3,509) 68,370 54,782 510 55,292
LIABILITIES
Deferred income taxes (c) 6,359 (1,736) 4,623 3,297 - 3,297
SHAREHOLDERS'
EQUITY
Revaluation adjustment (c) - (2,338) (2,338) - - -
Retained earnings (a) (b) 9,425 1,549 10,974 5,290 510 5,800
F-62
10. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES (Continued)
STATEMENTS OF CASH FLOWS
The application of U.S. GAAP would have the following effect on the
Statements of Cash Flows:
Years Ended December 31,
--------------------------------------------
2001 2000 1999
$ $ $
------------- --------------- --------------
OPERATING ACTIVITIES
Cash flow from operating activities, as reported 14,814 16,532 7,950
Increase (decrease) in:
Net earnings (loss) 1,041 (19) (557)
Depletion, depreciation and amortization (b) 62 88 77
Deferred income taxes (b) - - 480
Changes in non-cash working capital items (c) (984) - -
------------- --------------- --------------
Cash flow from operating activities, U.S. GAAP 14,933 16,601 7,950
------------- --------------- --------------
INVESTING ACTIVITIES
Net cash (used) provided by investing activities, as reported (29,079) (16,262) (11,770)
Increase in capital expenditures (a) (119) (69) -
------------- --------------- --------------
Net cash (used) provided by investing activities,
U.S. GAAP (29,198) (16,331) (11,770)
------------- --------------- --------------
Statements of Cash Flows
The investing activities portion of the statement of cash flows for 2000
prepared under Canadian GAAP discloses the aggregate costs related to a
property swap arrangement, with adjustments to arrive at the cash
component of the transaction. Under U.S. GAAP only the net cash amount
would be presented on the statement of cash flows.
F-63
10. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES (Continued)
Under Canadian GAAP, corporations are permitted to present a sub-total
prior to changes in non-cash working capital within operating activities.
This information is perceived to be useful information for various users of
the financial statements and is commonly presented by Canadian public
corporations. Under U.S. GAAP, this sub-total is not permitted to be shown
and would be removed in the statements of cash flows for all periods
presented. In addition, cash flow from operations per share figures would
not be presented under U.S. GAAP.
Recent Developments in U.S. Accounting
The Financial Accounting Standards Board recently issued Statement No. 141,
"Business Combinations" (FAS No. 141) and Statement No. 142 "Goodwill and
Other Intangible Assets" (FAS No. 142). FAS No. 141 requires the purchase
method of accounting to be used for all business combinations after July 1,
2001. FAS No. 142 requires that goodwill and intangible assets with an
indefinite useful life no longer be amortized, but instead tested for
impairment at least annually. Enterprises are required to adopt FAS No. 142
for fiscal years beginning after December 15, 2001. FAS No. 141 has been
applied with respect to the acquisition by Abraxas of the remaining
non-controlling interest in Grey Wolf. The Company currently has no
goodwill or other intangible assets that will be impacted by the adoption
of FAS No. 142.
Statement No. 143, "Accounting for Asset Retirement Obligations" (FAS No.
143) was released by the Financial Accounting Standards Board in June 2001.
FAS No. 143 requires liability recognition for retirement obligations
associated with tangible long-lived assets. The initial market of the asset
retirement obligation is to be at fair value. The asset retirement cost
equal to the fair value of the retirement obligation is to be capitalized
as part of the cost of the related long-lived asset and amortized to
expense over the useful life of the asset. Enterprises are required to
adopt FAS No. 143 for fiscal years beginning after June 15, 2002. The
Company is currently assessing the impact that adoption of this standard
would have on its financial position and results of operations.
F-64
10. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES (Continued)
The Financial Accounting Standards Board also recently issued Statement No.
144, "Accounting for the Impairment of Disposal of Long-Lived Assets" (FAS
No. 144). FAS No. 144 will replace previous Untied States generally
accepted accounting principles regarding accounting for impairment of
long-lived assets and accounting and reporting for discontinued operations.
FAS No. 144 retains the fundamental provisions of the prior standard for
recognizing and measuring impairment losses on long-lived assets. FAS No.
144 retains the basic provisions of the prior standard for presentation of
discontinued operations in the income statement, but broadens that
presentation to include a component of an entity rather than a segment of a
business. Enterprises are required to adopt FAS No. 144 for fiscal years
beginning after December 15, 2001. The Company has adopted the accounting
standard effective January 1, 2002 which is not expected to have a
significant impact on the Company's financial position and results of
operations.
11. SUBSEQUENT EVENT
Subsequent to December 31, 2001, the Company entered into an agreement to
dispose of its non-operated interest in the Quirk Creek gas processing
facilities and related petroleum and natural gas rights, for proceeds of
$3,450,000. The agreement is expected to close during the second quarter of
2002.
F-65