SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
AMENDMENT NO. 1
(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, 2002
[ ]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission File Number 0-19118
ABRAXAS PETROLEUM CORPORATION
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(Exact name of Registrant as specified in its charter)
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Nevada 74-2584033
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(State or Other Jurisdiction of (I.R.S. Employer Identification Number)
Incorporation or Organization)
500 N. Loop 1604 East, Suite 100
San Antonio, Texas 78232
(Address of principal executive offices)
Registrant's telephone number,
including area code (210) 490-4788
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Common Stock, par value $.01 per share
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No__
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ X ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act) [ ] Yes [X] No
The aggregate market value of the voting stock (which consists solely of
shares of common stock) held by nonaffiliates of the registrant as of June 30,
2002, based upon the closing per share price of $0.75, was approximately
$17,414,180 on such date.
The number of shares of the issuer's common stock, par value $.01 per
share, outstanding as of March 5, 2003 was 35,622,096 shares of which 28,328,651
shares were held by non-affiliates.
1
Documents Incorporated by Reference: Portions of the registrant's Proxy
Statement relating to the 2003 Annual Meeting of Shareholders to be held on May
29, 2003 have been incorporated by reference herein (Part III).
2
Explanatory Note
This amendment is being filed to reflect the restatement of the Company's
consolidated financial statements, as discussed in Note 20 thereto, and other
information related to such restated financial statements. Except for Items 1
and 2 of Part I, Items 6, 7 and 8 of Part II and Item 15 of Part IV, no other
information included in the original report on Form 10-K is amended by this Form
10-K/A.
3
ABRAXAS PETROLEUM CORPORATION
FORM 10-K/A
TABLE OF CONTENTS
PART I
Page
Item 1. Business.......................................................................................6
General.......................................................................................6
Recent Events.................................................................................7
Business Strategy ...........................................................................10
Markets and Customers........................................................................10
Risk Factors.................................................................................11
Regulation of Crude Oil and Natural Gas Activities...........................................16
Canadian Royalty Matters.....................................................................19
Environmental Matters ......................................................................20
Title to Properties..........................................................................22
Employees....................................................................................23
Item 2. Properties....................................................................................22
Primary Operating Areas......................................................................23
Exploratory and Developmental Acreage........................................................23
Productive Wells.............................................................................24
Reserves Information.........................................................................24
Crude Oil, Natural Gas Liquids and Natural Gas Production and Sales Price ...................26
Drilling Activities..........................................................................27
Office Facilities............................................................................28
Other Properties.............................................................................28
Item 3. Legal Proceedings.............................................................................28
Item 4. Submission of Matters to a Vote of Security Holders...........................................28
Item 4a. Executive Officers of Abraxas.................................................................28
PART II
Item 5. Market for Registrant's Common Equity
and Related Stockholder Matters............................................................30
Market Information...........................................................................30
Holders......................................................................................30
Dividends....................................................................................30
Recent Sales of Unregistered Securities......................................................30
Securities Authorized for Issuance Under Equity Compensation Plans...........................31
Item 6. Selected Financial Data.......................................................................31
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.........32
General......................................................................................32
Results of Operations........................................................................32
Liquidity and Capital Resources..............................................................37
Critical Accounting Policies..... ...........................................................44
New Accounting Pronouncements..... ..........................................................46
Item 7a. Quantitative and Qualitative Disclosures about Market Risk....................................48
4
Item 8. Financial Statements and Supplementary Data...................................................49
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure......................................................49
PART III
Item 10. Directors and Executive Officers of the Registrant .........................................49
Item 11. Executive Compensation.......................................................................50
Item 12. Security Ownership of Certain Beneficial Owners and Management...............................50
Item 13. Certain Relationships and Related Transactions...............................................50
Item 14. Controls and Procedures......................................................................50
PART IV
Item 15. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K...................................................................51
SIGNATURES..................................................................................56
5
FORWARD-LOOKING INFORMATION
We make forward-looking statements throughout this document. Whenever you
read a statement that is not simply a statement of historical fact (such as when
we describe what we "believe," "expect" or "anticipate" will occur or what we
"intend" to do, and other similar statements), you must remember that our
expectations may not be correct, even though we believe they are reasonable. The
forward-looking information contained in this document is generally located in
the material set forth under the headings "Risk Factors," "Business," and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" but may be found in other locations as well. These forward-looking
statements generally relate to our plans and objectives for future operations
and are based upon our management's reasonable estimates of future results or
trends. The factors that may affect our expectations regarding our operations
include, among others, the following:
o our high debt level;
o our ability to raise capital;
o our limited liquidity;
o economic and business conditions;
o price and availability of alternative fuels;
o political and economic conditions in oil producing countries,
especially those in the Middle East;
o our success in development, exploitation and exploration activities;
o planned capital expenditures;
o prices for crude oil and natural gas;
o declines in our production of crude oil and natural gas;
o our acquisition and divestiture activities;
o results of our hedging activities; and
o other factors discussed elsewhere in this document.
PART I
Item 1. Business
General
Abraxas Petroleum Corporation is an independent energy company engaged
primarily in the acquisition, exploration, exploitation and production of crude
oil and natural gas. Our principal means of growth has been through the
acquisition and subsequent development and exploitation of producing properties.
As a result of our historical acquisition activities, we believe that we have a
substantial inventory of low risk 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.
In January 2003, we completed the following transactions:
o The closing of the sale of the capital stock of our wholly owned
subsidiaries Canadian Abraxas Petroleum Limited, referred to herein as
Canadian Abraxas, and Grey Wolf Exploration Inc., referred to herein as
Old Grey Wolf, to a Canadian royalty trust for approximately $138
million.
o The closing of a new senior secured credit agreement consisting of a
term loan facility of $4.2 million and a revolving credit facility of
6
up to $50 million with an initial borrowing base of $49.9 million, of
which $42.5 million was used to fund the exchange offer described below
and the remaining availability will fund the continued development of
our existing crude oil and natural gas properties.
o The closing of an exchange offer, pursuant to which Abraxas paid $264
in cash and issued $610 principal amount of new 11 1/2 % Secured Notes
due 2007, Series A, referred to herein as New Notes, and 31.36 shares
of Abraxas common stock for each $1,000 in principal amount of the
outstanding 11 1/2 % Senior Secured Notes due 2004, Series A, and 11
1/2 % Senior Notes due 2004, Series D, issued by Abraxas and Canadian
Abraxas, which were tendered and accepted in the exchange offer. An
aggregate of approximately $179.9 million in principal amount of the
notes were tendered in the exchange offer and the remaining $11.1
million of notes not tendered were redeemed.
o The repayment of Abraxas' 12 7/8% Senior Secured Notes due 2003,
principal amount of $63.5 million, plus accrued interest.
o The repayment of Old Grey Wolf's senior secured credit facility with
Mirant Canada Energy Capital Ltd. (Mirant Canada Facility) in the
amount of approximately $46.3 million.
These transactions are more fully described below under the caption
"Recent Events."
Our principal areas of operation are Texas and western Canada. At December
31, 2002, we owned interests in 548,819 gross acres (422,874 net acres), and
operated properties accounting for approximately 88% of our PV-10, affording us
substantial control over the timing and incurrence of operating and capital
expenditures. At December 31, 2002 estimated total proved reserves were 166.5
Bcfe with an aggregate PV-10 of $254.9 million. Subsequent to the transactions
described in "Recent Events" our reserves were reduced by 54.0 Bcfe with an
aggregate PV-10 of $118.3 million.
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.
Recent Events
We recently completed a series of transactions designed to reduce our
indebtedness, improve our ability to meet our debt service obligations and
provide us with working capital necessary to develop our existing crude oil and
natural gas properties. As a result of these transactions, which we sometimes
refer to in this document as the financial restructuring, we have reduced the
principal amount of our overall outstanding long-term debt from approximately
$300 million at December 31, 2002 to approximately $156.4 million in principal
amount at January 23, 2003, and have reduced our annual cash interest payments
from approximately $34 million to approximately $4 million, assuming that, as
required under the new senior secured credit agreement, Abraxas issues
additional New Notes in lieu of cash interest payments. After giving effect to
the financial restructurings on January 23, 2003, the principal amount of our
outstanding New Notes and new senior secured credit agreement was approximately
$156.4 million ($109.7 million in New Notes and $46.7 related to the new senior
secured credit agreement). Due to the accounting treatment under accounting
principles generally accepted in the United States of America for financial
restructurings, the reported carrying value of the New Notes and new senior
secured credit agreement will be approximately $175 million ($128.6 million
related to the New Notes). The transactions comprising the financial
restructuring are summarized below.
See Notes 2 and 3 of Notes to Consolidated Financial Statements in Item 8
for further information regarding the sale of Canadian Abraxas and Old Grey Wolf
and the impact of the exchange offer on our outstanding notes at year end 2002.
7
Sale of Stock of Canadian Abraxas and Old Grey Wolf
On January 23, 2003, Abraxas completed the sale to a wholly owned
subsidiary of PrimeWest Energy Inc. of all of the outstanding capital stock of
two of Abraxas' former wholly-owned subsidiaries, Canadian Abraxas and Old Grey
Wolf, for approximately $138 million before net adjustments of $3.4 million.
Under the terms of the agreement with PrimeWest, we have retained certain oil
and gas properties formerly held by Canadian Abraxas and Old Grey Wolf,
including all of Canadian Abraxas' and Old Grey Wolf's undeveloped acreage
existing at the time of the sale, which includes all of our interests in
producing and undeveloped acreage in the Ladyfern area. These assets have been
contributed to a new wholly-owned subsidiary, Grey Wolf Exploration, Inc., which
we refer to herein as New Grey Wolf. Portions of this undeveloped acreage will
be developed by PrimeWest and New Grey Wolf under a farmout arrangement.
Abraxas used the proceeds from the sale of the capital stock of Canadian
Abraxas and Old Grey Wolf for the following purposes:
o to pay fees and expenses of the sale of Canadian Abraxas and Old Grey
Wolf of approximately $2.5 million;
o to redeem our 12 7/8% Senior Secured Notes, Series A, referred to
herein as first lien notes, at 100% of their principal amount, plus
accrued and unpaid interest, for approximately $66.4 million; and
o to pay approximately $19.4 million of the cash portion of the exchange
offer described below.
In addition, upon the closing of the sale, Old Grey Wolf repaid all of its
outstanding indebtedness of approximately $46.3 million, under the Mirant Canada
facility.
Exchange Offer
Contemporaneously with the closing of the sale of Canadian Abraxas and Old
Grey Wolf, Abraxas completed an exchange offer, pursuant to which it offered to
exchange cash and securities for all of the then outstanding 11 1/2% Senior
Secured Notes due 2004, Series A, referred to herein as second lien notes, and
11 1/2% Senior Notes due 2004, Series D, referred to herein as old notes, issued
by Abraxas and Canadian Abraxas ($52.6 million is carried on Canadian Abraxas).
In exchange for each $1,000 principal amount of notes tendered in the exchange
offer, tendering note holders received:
o cash in the amount of $264;
o an 11 1/2% Secured Note due 2007, Series A, with a principal amount
equal to $610; and
o 31.36 shares of Abraxas common stock.
At the time the exchange offer was made, there were approximately $190.2
million of the second lien notes and $801,000 of the old notes outstanding.
Holders of approximately 94% of the aggregate outstanding principal amount of
the second lien notes and old notes tendered their notes for exchange in the
offer. Pursuant to the procedures for redemption under the applicable historical
indenture provisions, the remaining 6% of the aggregate outstanding principal
amount of the second lien notes and old notes were redeemed at 100% of the
principal amount plus accrued and unpaid interest, for approximately $11.5
million ($11.1 million in principal and $0.4 million in interest) and the
indentures for the second lien notes and old notes were duly discharged. In
connection with the exchange offer, Abraxas made cash payments of approximately
$47.5 million and issued approximately $109.7 million in principal amount of New
Notes and 5,642,699 shares of Abraxas common stock. Fees and expenses incurred
in connection with the exchange offer were approximately $3.8 million, of which
$967,000 was charged to expense in 2002 and is included in financing cost in the
statement of operations and the balance will be charged to expense in 2003 as
the cost are incurred.
8
New Notes
The New Notes will accrue interest from the date of issuance, at a fixed
annual rate of 11 1/2%, payable in cash semi-annually on each May 1 and November
1, commencing May 1, 2003, provided that, if we fail, or are not permitted
pursuant to our new senior secured credit agreement or the intercreditor
agreement between the trustee under the indenture for the New Notes and the
lenders under the new senior secured credit agreement, to make such cash
interest payments in full, we will pay such unpaid interest in kind by the
issuance of additional notes with a principal amount equal to the amount of
accrued and unpaid cash interest on the notes plus an additional 1% accrued
interest for the applicable period. Upon an event of default, interest will
accrue at an annual rate of 16.5%. The New Notes are guaranteed by all of
Abraxas' current subsidiaries, Sandia Oil & Gas Corp., Sandia Operating Corp.,
Wamsutter Holdings, Inc., Western Associated Energy Corporation, Eastside Coal
Company, Inc., and New Grey Wolf, and will be guaranteed by all of Abraxas'
future subsidiaries. The New Notes are secured by a second lien or charge on all
of the Company's current and future assets, including, but not limited to, its
crude oil and natural gas properties. Under the terms of the New Notes, we are
required, to the extent permitted, to pay down debt under the new senior secured
credit agreement and, if permitted, the New Notes, with our cash flow which is
not required to pay our capital expenditures or make cash interest and tax
payments.
Redemption of First Lien Notes
On January 24, 2003, we completed the redemption of 100% of our outstanding
12 7/8% Senior Secured Notes, Series A, or first lien notes, with approximately
$66.4 million of the proceeds from the sale of Canadian Abraxas and Old Grey
Wolf utilized to retire $63.5 million of our first lien notes outstanding, plus
accrued interest of $2.9 million. Under the terms of the indenture for the first
lien notes, we had the right to redeem the first lien notes at 100% of the
outstanding principal amount of the notes, plus accrued and unpaid interest to
the date of redemption, and to discharge the indenture upon call of the first
lien notes for redemption and deposit of the redemption funds with the trustee.
We exercised these rights on January 23, 2003 and upon the discharge of the
indenture, the trustee released the collateral securing our obligations under
the first lien notes.
New Senior Secured Credit Agreement
Contemporaneously with the closing of the exchange offer and the sale of
Canadian Abraxas and Old Grey Wolf, Abraxas entered into a new senior secured
credit agreement providing a term loan facility and a revolving credit facility
as described below. Subject to earlier termination on the occurrence of events
of default or other events, the stated maturity date for both the term loan
facility and the revolving credit facility is January 22, 2006. Outstanding
amounts under both facilities bear interest at the prime rate announced by Wells
Fargo Bank, N.A. plus 4.5%. Any amounts in default under the term loan facility
will accrue interest at an additional 4%. At no time will the amounts
outstanding under the new senior secured credit agreement bear interest at a
rate less than 9%.
Term Loan Facility. Upon closing of the new senior secured credit
agreement, Abraxas borrowed $4.2 million pursuant to a term loan facility, all
of which was used to make cash payments in connection with the financial
restructuring. Accrued interest under the term loan facility will be capitalized
and added to the outstanding principal amount of the term loan facility until
maturity. As of March 5, 2003, Abraxas owed $4.2 million under the term loan
facility.
Revolving Credit Facility. Lenders under the new senior secured credit
agreement have provided a revolving credit facility to Abraxas with a maximum
borrowing base of up to $50 million. Our current borrowing base under the
revolving credit facility is $49.9 million, subject to adjustments based on
periodic calculations and mandatory prepayments under the senior secured credit
agreement. Portions of accrued interest under the revolving credit facility may
be capitalized and added to the principal amount of the revolving credit
facility. As of March 5, 2003, we had borrowed $42.5 million under the revolving
credit facility.
9
Business Strategy
Our primary business objectives are to increase reserves, production and
cash flow through the following:
o Low Cost Operations. We seek to maintain low lease operating and
general and administrative expenses ("G&A expenses") per Mcfe by
operating a majority of our producing properties and by maintaining a
high rate of production on a per well basis. As a result of this
strategy, we have achieved per unit lease operating and G&A expenses
that compare favorably with our peer companies.
o Exploitation of Existing Properties. We will continue to allocate a
portion of our operating cash flow to the exploitation of our proved
oil and natural gas 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. Abraxas' inventory of
development opportunities is considerable and growing, our ability to
exploit that inventory will depend on our ability to raise additional
capital and on our discretionary cash flow, which in turn is highly
dependent on future crude oil and natural gas prices.
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 hedging devices. To ensure a fixed price for future production, we
may sell a futures contract and thereafter either (i) make physical delivery of
crude oil or natural gas to comply with such contract or (ii) buy a matching
futures contract to unwind our futures position and sell our production to a
customer. These contracts may expose us to the risk of financial loss in certain
circumstances, including instances where production is less than expected, our
customers fail to purchase or deliver the contracted quantities of crude oil or
natural gas, or a sudden, unexpected event materially impacts crude oil or
natural gas prices. These contracts may also restrict our ability to benefit
from unexpected increases in crude oil and natural gas prices. You should read
the discussion under "Management's Discussion and Analysis of Financial
Condition And Results of Operations -- Liquidity and Capital Resources," and
"Quantitative and Qualitative Disclosures about Market Risk; Commodity Price
Risk" for more information regarding our historical hedging activities.
Substantially all of our crude oil and natural gas is sold at current
market prices under short-term arrangements , as is customary in the industry.
During the year ended December 31, 2002, three purchasers accounted for
approximately 77% of our United States crude oil and natural gas sales and one
customer accounted for approximately 80% of our crude oil and natural gas sales
in Canada. We believe that there are numerous other companies available to
purchase our crude oil and natural gas and that the loss of one or more of these
purchasers would not materially affect our ability to sell crude oil and natural
gas. The prices we realize for the sale of our crude oil and natural gas are
subject to our hedging activities. You should read the discussion under
"Management's Discussion and Analysis of Financial Condition And Results of
Operations -- Liquidity and Capital Resources" and "Quantitative and Qualitative
10
Disclosures about Market Risk; Commodity Price Risk" for more information
regarding our historical hedging activities.
Risk Factors
Our reduced operating cash flow resulting from the sale of Canadian Abraxas
and Old Grey Wolf may put significant strain on our liquidity and cash position.
Our reduced operating cash flow and resulting limited liquidity has caused us,
and the limitations imposed by the new senior secured credit agreement and the
New Notes will cause us, to reduce capital expenditures, including exploration,
exploitation and development projects. These reductions will limit our ability
to replenish our depleting reserves, which could negatively impact our cash flow
from operations and results of operations in the future. In addition, under the
terms of the New Notes, we are required, to the extent permitted, to pay down
debt under the new senior secured credit agreement and, if permitted, the New
Notes, with our cash flow which is not required to pay our capital expenditures
or make cash interest and tax payments.
The effects of our reduced operating cash flow will be exacerbated by our
high level of debt, which will affect our operations in several important ways,
including:
o A substantial amount of our cash flow from operations could be required
to make principal and interest payments on our outstanding indebtedness
and may not be available for other purposes, including developing our
properties;
o The covenants contained in the indenture governing the New Notes and in
the new senior secured credit agreement will limit our ability to
borrow additional funds or to dispose of assets or use the proceeds of
any asset sales and may affect our flexibility in planning for, and
reacting to, changes in our business; and
o Our debt level may impair our ability to obtain additional financing in
the future for working capital, capital expenditures, acquisitions,
interest payments, scheduled principal payments, general corporate
purposes or other purposes.
Our limited liquidity and restrictions on uses of cash dictated by both the
new senior secured credit agreement and the New Notes, combined with our high
debt levels, may hinder our ability to satisfy the substantial capital
requirements related to our operations. The success of our future operations
will require us to make substantial capital expenditures for the exploitation,
development, exploration and production of crude oil and natural gas.
Under the terms of the new senior secured credit agreement and the New
Notes, Abraxas is subject to cash and expenditures covenants including
limitations on capital expenditures. These limitations imposed on Abraxas by the
new senior secured credit agreement and the New Notes will have the effect of
limiting our ability to develop our crude oil and natural gas properties because
much of our cash flow may be used for debt service. As a result, our ability to
replace production may be limited. You should read the discussion under "Our
ability to replace production with new reserves is highly dependent on
acquisitions or successful development and exploration activities" for more
information regarding the risks associated with limitations on our ability to
develop our crude oil and natural gas properties.
Hedging transactions may limit our potential gains. Under the terms of the
new senior secured credit agreement, we are required to maintain commodity price
hedging positions on not less than 25% and not more than 75% of our estimated
production for a rolling six-month period. On January 23, 2003, we entered into
a collar option agreement with respect to 5,000 MMBtu per day, or approximately
25% of our production, at a call price of $6.25 per MMBtu and a put price of
$4.00 per MMBtu, for the calendar months of February through July 2003. In
February 2003, we entered into a second hedging agreement related to 5,000 MMBtu
which provides for a floor price of $4.50 per MMBtu for the calendar months of
March 2003 through February 2004.
We cannot assure you that our hedging transactions will reduce risk or
minimize the effect of any decline in crude oil or natural gas prices. Any
substantial or extended decline in crude oil or natural gas prices would have a
material adverse effect on our business and financial results. Hedging
activities may limit the risk of declines in prices, but such arrangements may
11
also limit, and have in the past limited, additional revenues from price
increases. In addition, such transactions may expose us to risks of financial
loss under certain circumstances, such as:
o production being less than expected; or
o price differences between delivery points for our production and those
in our hedging agreements increasing.
In 2000, 2001 and 2002, we experienced hedging losses of $20.2 million,
$12.1 million and $3.2 million, respectively.
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, exploitation and development activities or, through engineering
studies, identify additional behind-pipe zones or secondary recovery reserves.
Our future crude oil and natural gas production is therefore highly dependent
upon our level of success in acquiring or finding additional reserves. While we
have had some success in pursuing these activities, we have not been able to
fully replace the production volumes lost from natural field declines and
property sales. We have implemented a number of measures to conserve our cash
resources, including postponement of exploration and development projects.
However, while these measures will conserve our cash resources in the near term,
they will also limit our ability to replenish our depleting reserves, which
could negatively impact our cash flow from operations in the future. The terms
of our senior secured credit agreement and new secured notes limit our capital
expenditures which will further limit our ability to replenish our reserves and
replace production. Further, in addition to the effects of our limited
liquidity, our operations may be curtailed, delayed or cancelled by other
factors, such as title problems, weather, compliance with governmental
regulations, mechanical problems or shortages or delays in the delivery of
equipment. We cannot assure you that our exploration and development activities
will result in increases in reserves.
Use of our net operating loss carryforwards may be limited. At December 31,
2002, Abraxas had, subject to the limitation discussed below, $166.7 million of
net operating loss carryforwards for U.S. tax purposes. These loss carryforwards
will expire from 2003 through 2022 if not utilized. At December 31, 2002,
Abraxas had approximately $1.0 million of net operating loss carryforwards for
Canadian tax purposes. These carryforwards will expire from 2003 through 2009 if
not utilized. In connection with January 2003 transactions described in Note 2,
in Notes to Consolidated Financial Statements, Item 8, certain of the loss
carryforwards may be utilized.
As to a portion of the U.S. net operating loss carryforwards, the amount of
such carryforwards that we can use annually is limited under U.S. tax law.
Additionally, uncertainties exist as to the future utilization of the operating
loss carryforwards under the criteria set forth under FASB Statement No. 109.
Therefore, Abraxas has established a valuation allowance of $39.7 million and
$99.1 million for deferred tax assets at December 31, 2001 and 2002,
respectively.
Crude oil and natural gas prices and their volatility could adversely
affect our revenue, cash flows, profitability and growth. Our revenue, cash
flows, profitability and future rate of growth depend substantially upon
prevailing prices for crude oil and natural gas. Natural gas prices affect us
more than crude oil prices because most of our production and reserves are
natural gas. Prices also affect the amount of cash flow available for capital
expenditures and our ability to borrow money or raise additional capital. In
addition, we may have ceiling limitation write-downs when prices decline. During
the second quarter of 2002, we had a ceiling limitation write down of
approximately $116.0 million. Lower prices may also reduce the amount of crude
oil and natural gas that we can produce economically.
We cannot predict future crude oil and natural gas prices. Factors that can
cause price fluctuations include:
o changes in supply and demand for crude oil and natural gas;
12
o weather conditions;
o the price and availability of alternative fuels;
o political and economic conditions in oil producing countries,
especially those in the Middle East; and
o overall economic conditions.
In addition to decreasing our revenue and cash flow from operations, low or
declining crude oil and natural gas prices could have additional material
adverse effects on us, such as:
o reducing the overall volumes of crude oil and natural gas that we can
produce economically;
o causing a ceiling limitation write-down;
o increasing our dependence on external sources of capital to meet our
liquidity requirements; and
o impairing our ability to obtain needed equity capital.
Lower crude oil and natural gas prices increase the risk of ceiling
limitation write-downs. We use the full cost method to account for our crude oil
and natural gas operations. Accordingly, we capitalize the cost to acquire,
explore for and develop crude oil and natural gas properties. Under full cost
accounting rules, the net capitalized cost of crude oil and natural gas
properties may not exceed a "ceiling limit" which is based upon the present
value of estimated future net cash flows from proved reserves, discounted at
10%, plus the lower of cost or fair market value of unproved properties. If net
capitalized costs of crude oil and natural gas properties exceed the ceiling
limit, we must charge the amount of the excess to earnings. This is called a
"ceiling limitation write-down." This charge does not impact cash flow from
operating activities, but does reduce our stockholders' equity and earnings. The
risk that we will be required to write down the carrying value of crude oil and
natural gas properties increases when crude oil and natural gas prices are low.
In addition, write-downs may occur if we experience substantial downward
adjustments to our estimated proved reserves. An expense recorded in one period
may not be reversed in a subsequent period even though higher crude oil and
natural gas prices may have increased the ceiling applicable to the subsequent
period.
At June 30, 2002, our net capitalized costs of crude oil and natural gas
properties exceeded the present value of our estimated proved reserves by $138.7
million ($28.2 million on the U.S. properties and $110.5 million on the Canadian
properties). These amounts were calculated considering June 30, 2002 prices of
$26.12 per Bbl for crude oil and $2.16 per Mcf for natural gas as adjusted to
reflect the expected realized prices for each of the full cost pools. Subsequent
to June 30, 2002, commodity prices increased in Canada and we utilized these
increased prices in calculating the ceiling limitation write-down. The total
write-down was approximately $116.0 million. At December 31, 2002, our net
capitalized cost of crude oil and natural gas properties did not exceed the
present value of our estimated reserves, due to increased commodity prices
during the fourth quarter and, as such, no further write-down was recorded. We
cannot assure you that we will not experience additional ceiling limitation
write-downs in the future.
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.
13
You should not assume that the present value of future net revenues
referred to in this annual report is the current market value of our estimated
crude oil and natural gas reserves. In accordance with SEC requirements, the
estimated discounted future net cash flows from proved reserves are generally
based on prices and costs as of the end of the period of the estimate. Actual
future prices and costs may be materially higher or lower than the prices and
costs as of the end of the year of the estimate. Any changes in consumption by
natural gas purchasers or in governmental regulations or taxation will also
affect actual future net cash flows. The timing of both the production and the
expenses from the development and production of crude oil and natural gas
properties will affect the timing of actual future net cash flows from proved
reserves and their present value. In addition, the 10% discount factor, which is
required by the SEC to be used in calculating discounted future net cash flows
for reporting purposes, is not necessarily the most accurate discount factor.
The effective interest rate at various times and the risks associated with us or
the crude oil and natural gas industry in general will affect the accuracy of
the 10% discount factor.
The estimates of our reserves are based upon various assumptions about
future production levels, prices and costs that may not prove to be correct over
time. In particular, estimates of crude oil and natural gas reserves, future net
revenue from proved reserves and the PV-10 thereof for the crude oil and natural
gas properties described in this annual report are based on the assumption that
future crude oil and natural gas prices remain the same as crude oil and natural
gas prices at December 31, 2002. The sales prices as of such date used for
purposes of such estimates were $29.69 per Bbl of crude oil, $18.89 per Bbl of
NGLs and $3.79 per Mcf of natural gas. This compares with $18.26 per Bbl of
crude oil, $16.29 per Bbl of NGLs and $2.16 per Mcf of natural gas as of
December 31, 2001. These estimates also assume that we will make future capital
expenditures of approximately $59.5 million in the aggregate, which are
necessary to develop and realize the value of proved undeveloped reserves on our
properties. Any significant variance in actual results from these assumptions
could also materially affect the estimated quantity and value of reserves set
forth herein.
We have experienced recurring net losses. The following table shows the
losses we had in 1998, 1999, 2001 and 2002:
Years Ended December 31,
1998 1999 2001 2002
---- ---- ---- ----
Net (loss) $(84.0) $(36.7) $(19.7) $ (118.5)
While we had net income in 2000 of $8.4 million, if the significant gain on
the sale of an interest in a partnership were excluded, we would have
experienced a net loss for the year of $(25.5) million. We cannot assure you
that we will become profitable in the future.
The marketability of our production depends largely upon the availability,
proximity and capacity of natural gas gathering systems, pipelines and
processing facilities. The marketability of our production depends in part upon
processing facilities. Transportation space on such gathering systems and
pipelines is occasionally limited and at times unavailable due to repairs or
improvements being made to such facilities or due to such space being utilized
by other companies with priority transportation agreements. Our access to
transportation options can also be affected by U.S. federal and state and
Canadian regulation of crude oil and natural gas production and transportation,
general economic conditions, and changes in supply and demand. These factors and
the availability of markets are beyond our control. If market factors
dramatically change, the financial impact on us could be substantial and
adversely affect our ability to produce and market crude oil and natural gas.
Our Canadian operations are subject to the risks of currency fluctuations
and in some instances economic and political developments. We conduct operations
in Canada. The expenses of such operations are payable in Canadian dollars while
most of the revenue from crude oil and natural gas sales is based upon U.S.
dollar price indices. As a result, Canadian operations are subject to the risk
of fluctuations in the relative values of the Canadian and U.S. dollars. We are
also required to recognize foreign currency translation gains or losses related
to any debt issued by our Canadian subsidiary because the debt is denominated in
U.S. dollars and the functional currency of such subsidiary is the Canadian
dollar. Our foreign operations may also be adversely affected by local political
and economic developments, royalty and tax increases and other foreign laws or
policies, as well as U.S. policies affecting trade, taxation and investment in
other countries.
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We depend on our key personnel. We depend to a large extent on Robert L.G.
Watson, our Chairman of the Board, President and Chief Executive Officer, for
our management and business and financial contacts. The unavailability of Mr.
Watson could have a materially adverse effect on our business. Mr. Watson has a
three-year employment contract with Abraxas commencing on December 21, 1999,
which automatically renews thereafter for successive one-year periods unless
Abraxas gives 120 days notice prior to the expiration of the original term or
any extension thereof of its intention not to renew the employment agreement.
Our success is also dependent upon our ability to employ and retain skilled
technical personnel. While we have not experienced difficulties in employing or
retaining such personnel, our failure to do so in the future could adversely
affect our business.
Risks Related to Our Industry
Our operations are subject to numerous risks of crude oil and natural gas
drilling and production activities. Our crude oil and natural gas drilling and
production activities are subject to numerous risks, many of which are beyond
our control. These risks include the following:
o that no commercially productive crude oil or natural gas reservoirs
will be found;
o that crude oil and natural gas drilling and production activities may
be shortened, delayed or canceled; and
o that our ability to develop, produce and market our reserves may be
limited by:
o title problems,
o weather conditions,
o compliance with governmental requirements, and
o mechanical difficulties or shortages or delays in the delivery of
drilling rigs, work boats and other equipment.
In the past, we have had difficulty securing drilling equipment in certain
of our core areas. We cannot assure you that the new wells we drill will be
productive or that we will recover all or any portion of our investment.
Drilling for crude oil and natural gas may be unprofitable. Dry 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.
15
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.
Our crude oil and natural gas operations are subject to various U.S.
federal, state and local and Canadian federal and provincial governmental
regulations that materially affect our operations. Matters regulated include
discharge permits for drilling operations, drilling and abandonment bonds,
reports concerning operations, the spacing of wells and unitization and pooling
of properties and taxation. At various times, regulatory agencies have imposed
price controls and limitations on production. In order to conserve supplies of
crude oil and natural gas, these agencies have restricted the rates of flow of
crude oil and natural gas wells below actual production capacity. Federal,
state, provincial and local laws regulate production, handling, storage,
transportation and disposal of crude oil and natural gas, by-products from crude
oil and natural gas and other substances and materials produced or used in
connection with crude oil and natural gas operations. To date, our expenditures
related to complying with these laws and for remediation of existing
environmental contamination have not been significant. We believe that we are in
substantial compliance with all applicable laws and regulations. However, the
requirements of such laws and regulations are frequently changed. We cannot
predict the ultimate cost of compliance with these requirements or their effect
on our operations.
Regulation of Crude Oil and Natural Gas Activities
The exploration, production and transportation of all types of hydrocarbons
are subject to significant governmental regulations. Our operations are affected
from time to time in varying degrees by political developments and federal,
state, provincial and local laws and regulations. In particular, crude oil and
natural gas production operations and economics are, or in the past have been,
affected by industry specific price controls, taxes, conservation, safety,
environmental, and other laws relating to the petroleum industry, by changes in
such laws and by constantly changing administrative regulations.
Price Regulations
In the past, maximum selling prices for certain categories of crude oil,
natural gas, condensate and NGLs in the United States were subject to
significant federal regulation. At the present time, however, all sales of our
crude oil, natural gas, condensate and NGLs produced in the United States under
private contracts may be sold at market prices. Congress could, however, reenact
price controls in the future. If controls that limit prices to below market
rates are instituted, our revenue would be adversely affected.
Crude oil and natural gas exported from Canada is subject to regulation by
the National Energy Board ("NEB") and the government of Canada. Exporters are
free to negotiate prices and other terms with purchasers, provided that export
contracts in excess of two years must continue to meet certain criteria
prescribed by the NEB and the government of Canada. Crude oil and natural gas
exports for a term of less than two years must be made pursuant to an NEB order,
or, in the case of exports for a longer duration, pursuant to an NEB license and
Governor in Council approval.
The provincial governments of Alberta, British Columbia and Saskatchewan
also regulate the volume of natural gas that may be removed from these provinces
for consumption elsewhere based on such factors as reserve availability,
transportation arrangements and marketing considerations.
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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"
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).
17
(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
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
18
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
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 Alberta and British Columbia, the
provinces where almost all of New Grey Wolf's production is located, have
established incentive programs which have included royalty rate reductions,
royalty holidays and tax credits for the purpose of encouraging crude oil and
natural gas exploration or enhanced planning projects. All of New Grey Wolf's
production is from oil and gas rights which have been granted by the Provinces.
The Province of Alberta requires the payment from lessees of oil and gas
rights of annual rental payments as well as royalty payments. Regulations made
pursuant to the Mines and Minerals Act (Alberta) provide various incentives for
exploring and developing crude oil reserves in Alberta. Crude oil produced from
horizontal extensions commenced at least five years after the well was
originally spudded may qualify for a royalty reduction. An 8,000 cubic meters
exemption is available to production from a well that has not produced for a
12-month period prior to January 31, 1993 or 24 months following such date. In
addition, crude oil production from eligible new field and new pool wildcat
wells and deeper pool test wells spudded or deepened after September 30, 1992,
is entitled to a 12-month royalty exemption (to a maximum of CDN $1 million).
Crude oil produced from low productivity wells, enhanced recovery schemes (such
as injection wells) and experimental projects is also subject to royalty
reductions.
The Alberta government classifies conventional crude oil into three
categories, being Old Oil, New Oil and Third Tier Oil. Each have a base royalty
rate of 10%. The rate caps on the categories are 25% for oil from crude oil
pools discovered after September 30, 1992, being the Third Tier Oil, 30% for oil
19
from pools or pool extensions discovered after April 1, 1974, from wells drilled
or deepened after October 31, 1991 or from reactivated wells and which are not
Third Tier Oil, and 35% for Old Oil.
Effective January 1, 1994, the calculation and payment of natural gas
royalties became subject to a simplified process. The royalty reserved to the
Crown, subject to various incentives, is between 15% or 30%, in the case of new
natural gas, and between 15% and 35%, in the case of old natural gas, depending
upon a prescribed or corporate average reference price. Natural gas produced
from qualifying exploratory gas wells spudded or deepened after July 1, 1985 and
before June 1, 1988 are 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 meter and 35% for prices above CDN $210 per cubic
meter. The ARTC rate is currently applied to a maximum of CDN $2.0 million of
Alberta Crown royalties payable for each producer or associated group of
producers. Crown royalties on production from producing properties acquired from
corporations claiming maximum entitlement to ARTC will generally not be eligible
for ARTC. The rate is established quarterly based on average "par price", as
determined by the Alberta Department of Energy for the previous quarterly
period.
Producers of crude oil and natural gas in British Columbia are also
required to pay annual rental payments in respect of Crown leases and royalties
and freehold production taxes in respect of crude oil and natural gas produced
from Crown and freehold lands respectively. British Columbia also classifies
conventional crude oil into the three categories of Old Oil, New Oil and Third
Tier Oil. The amount payable as a royalty in respect of crude oil depends on the
vintage of the crude oil (whether it was produced from a pool discovered before
or after October 31, 1975) or a pool in which no well was completed on June 1,
1998), the quantity of crude oil produced in a month and the value of the crude
oil. Crude oil produced from a discovery well may be exempt from the payment of
a royalty for the first 36 months of production to a maximum production of
11,450 m3. The royalty payable on natural gas is determined by a sliding scale
based on a classification of the gas based on whether it is conservation gas
(gas associated with marketed oil production) and by drilling and land lease
date and on a reference price which is the greater of the amount obtained by the
producer and at prescribed minimum price. Conservation gas has a minimum royalty
of 8%. The royalty rate ranges from between 9% and 27% for wells drilled on
lands issued after May 31, 1998 and before January 1, 2003 and completed within
5 years of the date the lands were issued and between 12% and 27% for wells
spudded after May 31, 1998 on lands where rights had been issued as of May 31,
1998.
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
20
crude oil and natural gas industry in general, and thus we are unable to predict
the ultimate cost and effects of future changes in environmental laws and
regulations.
In the United States, the Comprehensive Environmental Response,
Compensation and Liability Act ("CERCLA"), also known as "Superfund," and
comparable state statutes impose strict, joint, and several liability on certain
classes of persons who are considered to have contributed to the release of a
"hazardous substance" into the environment. These persons include the owner or
operator of a disposal site or sites where a release occurred and companies that
generated, disposed or arranged for the disposal of the hazardous substances
released at the site. Under CERCLA such persons or companies may be
retroactively liable for the costs of cleaning up the hazardous substances that
have been released into the environment and for damages to natural resources,
and it is common for neighboring land owners and other third parties to file
claims for personal injury, property damage, and recovery of response costs
allegedly caused by the hazardous substances released into the environment. The
Resource Conservation and Recovery Act ("RCRA") and comparable state statutes
govern the disposal of "solid waste" and "hazardous waste" and authorize
imposition of substantial civil and criminal penalties for failing to prevent
surface and subsurface pollution, as well as to control the generation,
transportation, treatment, storage and disposal of hazardous waste generated by
crude oil and natural gas operations. Although CERCLA currently contains a
"petroleum exclusion" from the definition of "hazardous substance," state laws
affecting our operations impose cleanup liability relating to petroleum and
petroleum related products, including crude oil cleanups. In addition, although
RCRA regulations currently classify certain oilfield wastes which are uniquely
associated with field operations as "non-hazardous," such exploration,
development and production wastes could be reclassified by regulation as
hazardous wastes thereby administratively making such wastes subject to more
stringent handling and disposal requirements.
We currently own or lease, and have in the past owned or leased, numerous
properties that for many years have been used for the exploration and production
of crude oil and natural gas. Although we utilized standard industry operating
and disposal practices at the time, hydrocarbons or other wastes may have been
disposed of or released on or under the properties we owned or leased or on or
under other locations where such wastes have been taken for disposal. In
addition, many of these properties have been operated by third parties whose
treatment and disposal or release of hydrocarbons or other wastes was not under
our control. These properties and the wastes disposed thereon may be subject to
CERCLA, RCRA, and analogous state laws. Our operations are also impacted by
regulations governing the disposal of naturally occurring radioactive materials
("NORM"). We must comply with the Clean Air Act and comparable state statutes
which prohibit the emissions of air contaminants, although a majority of our
activities are exempted under a standard exemption. Moreover, owners, lessees
and operators of crude oil and natural gas properties are also subject to
increasing civil liability brought by surface owners and adjoining property
owners. Such claims are predicated on the damage to or contamination of land
resources occasioned by drilling and production operations and the products
derived there from, and are usually causes of action based on negligence,
trespass, nuisance, strict liability and fraud.
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.
21
Certain federal environmental laws that may affect us include the Canadian
Environmental Assessment Act which ensures that the environmental effects of
projects receive careful consideration prior to licenses or permits being
issued, to ensure that projects that are to be carried out in Canada or on
federal lands do not cause significant adverse environmental effects outside the
jurisdictions in which they are carried out, and to ensure that there is an
opportunity for public participation in the environmental assessment process;
the Canadian Environmental Protection Act ("CEPA") which is the most
comprehensive federal environmental statute in Canada, and which controls toxic
substances (broadly defined), includes standards relating to the discharge of
air, soil and water pollutants, provides for broad enforcement powers and
remedies and imposes significant penalties for violations; the National Energy
Board Act which can impose certain environmental protection conditions on
approvals issued under the Act; the Fisheries Act which prohibits the depositing
of a deleterious substance of any type in water frequented by fish or in any
place under any condition where such deleterious substance may enter any such
water and provides for significant penalties; the Navigable Waters Protection
Act which requires any work which is built in, on, over, under, through or
across any navigable water to be approved by the Minister of Transportation, and
which attracts severe penalties and remedies for non-compliance, including
removal of the work.
In Alberta, environmental compliance has been governed by the Alberta
Environmental Protection and Enhancement Act ("AEPEA") since September 1, 1993.
In addition to consolidating a variety of environmental statutes, the AEPEA also
imposes certain new environmental responsibilities on crude oil and natural gas
operators in Alberta. The AEPEA sets out environmental standards and compliance
for releases, clean-up and reporting. The Act provides for a broad range of
liabilities, enforcement actions and penalties.
We are not currently involved in any administrative, judicial or legal
proceedings arising under domestic or foreign federal, state, or local
environmental protection laws and regulations, or under federal or state common
law, which would have a material adverse effect on our financial position or
results of operations. Moreover, we maintain insurance against costs of clean-up
operations, but we are not fully insured against all such risks. A serious
incident of pollution may result in the suspension or cessation of operations in
the affected area.
We believe that we have obtained and are in compliance with all material
environmental permits, authorizations and approvals.
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 5, 2003, we had 48 full-time employees in the United States,
including 3 executive officers, 3 non-executive officers, 1 petroleum engineer,
1 geologist, 6 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 5, 2003, New Grey Wolf had 13 full-time employees, including 3
executive officers, 1 non-executive officer, 2 petroleum engineers, 2
geologists, 1 geophysicist and, 4 technical and clerical personnel in Canada.
22
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,
2002 located in those two regions. We operate 94% of our wells in Texas.
Operations in South Texas are concentrated along the Edwards trend in Live Oak
and Dewitt Counties, the Frio/Vicksburg trend in San Patricio County and the
Wilcox trend in Goliad County. In total in South Texas we own an average 88%
working interest in 44 wells with average daily production of 291 net Bbls of
crude oil and NGLs and 8,177 net Mcf of natural gas per day for the year ended
December 31, 2002. As of December 31, 2002 we had estimated net proved reserves
in South Texas of 31,103 Mmcfe (83% natural gas) with a PV-10 of $47.2 million,
70% 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 have entered
into a farmout agreement with EOG Resources Inc. whereby EOG earned a 75%
working interest in Abraxas' then existing Montoya acreage by paying Abraxas
$2.5 million and paying 100% of the cost of the first five wells, the last of
which came on line in December 2002. EOG remains under a continuous development
clause, however Abraxas will be responsible for its pro-rata share of the
drilling and development costs going forward. Two wells are planned for 2003. In
total in West Texas we own an average 75% working interest in 157 wells with
average daily production of 389net Bbls of crude oil and NGLs and 6,814 net Mcf
of natural gas per day for the year ended December 31, 2002. As of December 31,
2002, we had estimated net proved reserves in West Texas of 65,957 Mmcfe (80%
natural gas) with a PV-10 of $62.7 million, 39% of which was attributable to
proved developed reserves. During 2002, we drilled a total of 3 new wells (1.06
net) in Texas with a 67% success rate.
Wyoming
We currently hold over 60,000 contiguous acres in the Powder River Basin in
east central Wyoming. The Company has drilled and operates 5 wells in Converse
and Niobrara counties that were completed in the Turner and Niobrara formations.
We own a 100% working interest in these wells that produced an average of 43 net
barrels of crude oil per day in 2002. As of December 31, 2002 we had estimated
net proved producing reserves in Wyoming of 91,791 barrels of crude oil with a
PV-10 of $427,000.
Western Canada
We own properties in western Canada, consisting primarily of natural gas
reserves and undeveloped acreage in the provinces of Alberta and British
Columbia. Our Alberta properties are in two concentrated areas; the Caroline
field, 60 miles northwest of Calgary and the Peace River Arch area in
northwestern Alberta. We have entered into a farmout agreement with PrimeWest in
connection with the sale of Canadian Abraxas and Old Grey Wolf (See "Recent
Events") to jointly develop these areas in the future. Our other Canadian
operations are located in the Ladyfern area of northeast British Columbia. In
this area we participated in six wells being drilled during 2002 with a 50%
success rate. As of December 31, 2002 Canadian Abraxas and Grey Wolf had
estimated net proved reserves of 68.8 Bcfe (88% natural gas) with a PV-10 of
$144.5 million of which 93% was attributable to proved developed reserves. As of
December 31, 2002, giving effect to the transactions which occurred in January
2003, New Grey Wolf had estimated net proved reserves, of 14.9 Bcfe (91% natural
gas) with a PV-10 of $26.3 million, 61% of which was attributable to proved
developed reserves. For the year ended December 31, 2002, the Canadian
properties produced an average of approximately 740.5 net Bbls of crude oil and
NGLs per day and 27,345.6 net Mcf of natural gas per day. During 2002, we
drilled a total of 20 new wells (15.7 net) in Canada with a 90% 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, 2002:
23
Developed and Undeveloped Acreage
-------------------------------------------------------------------
As of December 31, 2002
-------------------------------------------------------------------
Developed Acreage (1) Undeveloped Acreage (2)
--------------------------------- -------------------------------
Gross Acres(3) Net Acres(4) Gross Acres (3) Net Acres (4)
--------------- -------------- ---------------- ---------------
Canada (5) 84,335 49,429 367,315 285,827
Texas 24,775 19,911 10,881 10,029
Wyoming 3,200 3,200 58,311 54,478
--------------- -------------- ---------------- ---------------
Total 112,310 72,540 436,507 350,334
=============== ============== =============== ==============
---------------
(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).
(5) Includes 73,840 gross (43,997 net) developed acres and 15,097 gross (8,288
net) undeveloped acres that were sold in connection with the sale of
Canadian Abraxas and Old Grey Wolf in January 2003, see Item 1. "Business -
Recent Events".
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, 2002:
Productive Wells (1)
---------------------------------------------------------------------
As of December 31, 2002
--------------------- ---------------------------------------------------------------------
State/Country Crude Oil Natural Gas
--------------------- -------------------------------- ----------------------------------
Gross(2) Net(3) Gross(2) Net(3)
----------------- ---------------- --------------- ----------------
Canada (4) 243.0 5.6 121.0 66.4
Texas 139.0 111.3 62.0 45.2
Wyoming 5.0 5.0 - -
--------------- -------------- --------------- ----------------
Total 387.0 121.9 183.0 111.6
=============== ============== =============== ================
------------
(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.
(4) Includes 228.0 gross (4.3 net) crude oil wells and 114.0 gross (65.0 net)
natural gas wells that were sold in connection with the sale of Canadian
Abraxas and Old Grey Wolf in January 2003, see Item 1. "Business - Recent
Events".
Reserves Information
The crude oil and natural gas reserves of the U.S. operations only have
been estimated as of January 1, 2003, January 1, 2002, and January 1, 2001, by
DeGolyer and MacNaughton, of Dallas, Texas. The reserves of the Canadian
operations as of January 1, 2002 and January 1, 2001 have been estimated by
McDaniel and Associates Consultants Ltd. of Calgary, Alberta. The January 1,
2003 reserves attributable to the Canadian operations were estimated internally.
Crude oil and natural gas reserves, and the estimates of the present value of
future net revenues there from, were determined based on then current prices and
costs. Reserve calculations involve the estimate of future net recoverable
reserves of crude oil and natural gas and the timing and amount of future net
revenues to be received there from. Such estimates are not precise and are based
on assumptions regarding a variety of factors, many of which are variable and
uncertain.
24
The following table sets forth certain information regarding estimates of
our crude oil, natural gas liquids and natural gas reserves as of January 1,
2001, January 1, 2002 and January 1, 2003:
Estimated Proved Reserves
----------------------------------------------
Proved Proved Total
Developed Undeveloped Proved
-------------- --------------- ---------------
As of January 1, 2001
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
As of January 1, 2003 (1)
Crude oil (MBbls) 1,782 1,317 3,099
NGLs (MBbls) 1,222 284 1,506
Natural gas (MMcf) 90,374 48,458 138,832
------------------
Reserves on a Mcf equivalent at December 31, 2002 were 146.5 Bcfe. Crude
oil and natural gas liquids are converted to a Mcf equivalent (Mcfe) on the
basis of 1 Bbl of crude oil and natural gas liquid equals 6 Mcf of natural
gas.
1. Reserves as of January 1, 2003 include 67 MBbls of crude oil, 1,079 MBbls
of NGLs, and 47,066 MMcf of natural gas that were sold in connection with
the sale of Canadian Abraxas and Old Grey Wolf in January 2003, see
"Business - Recent Events".
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 $38.9 million on U.S. properties. This amount was 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
25
reserves for its U.S. properties as determined using increased realized prices
on March 22, 2002 of $24.16 per Bbl for crude oil and $2.89 per Mcf for natural
gas.
At June 30, 2002, our net capitalized costs of crude oil and natural gas
properties exceeded the present value of our estimated proved reserves by $138.7
million ($28.2 million on the U.S. properties and $110.5 million on the Canadian
properties). These amounts were calculated considering June 30, 2002 prices of
$26.12 per Bbl for crude oil and $2.16 per Mcf for natural gas as adjusted to
reflect the expected realized prices for each of the full cost pools. Subsequent
to June 30, 2002, commodity prices increased in Canada and we utilized these
increased prices in calculating the ceiling limitation write-down. The total
write-down was approximately $116.0 million. At December 31, 2002, our net
capitalized cost of crude oil and natural gas properties did not exceed the
present value of our estimated reserves, due to increased commodity prices
during the fourth quarter and, as such, no further write-down was recorded. We
cannot assure you that we will not experience additional ceiling limitation
write-downs in the future.
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, 2002. The average sales prices as of such date used for
purposes of such estimates were $29.69 per Bbl of crude oil, $18.89 per Bbl of
NGLs and $3.79 per Mcf of natural gas. It is also assumed that we will make
future capital expenditures of approximately $59.5 million in the aggregate,
which are necessary to develop and realize the value of proved undeveloped
reserves on our properties. Any significant variance in actual results from
these assumptions could also materially affect the estimated quantity and value
of reserves set forth herein.
We file reports of our estimated crude oil and natural gas reserves with
the Department of Energy and the Bureau of the Census. The reserves reported to
these agencies are required to be reported on a gross operated basis and
therefore are not comparable to the reserve data reported herein.
Crude Oil, Natural Gas Liquids, and Natural Gas Production and Sales Prices
The following table presents our net crude oil, net natural gas liquids and
net natural gas production, the average sales price per Bbl of crude oil and
natural gas liquids and per Mcf of natural gas produced and the average cost of
production per BOE of production sold, for the three years ended December 31,
2002.
2000 2001 2002
------------ ---------- ------------
Crude oil production (Bbls)....... 636,734 454,063 292,264
Natural gas production (Mcf)...... 19,962,470 17,495,598 15,452,721
Natural gas liquids production
(Bbls)....................... 314,897 277,969 242,032
MMcfe............................. 25,672 21,888 18,658
Average sales price per Bbl of
crude oil.................... $ 18.69 $ 24.6 $ 24.34
Average sales price per MCF of
natural gas (1).............. $ 2.71 $ 3.20 $ 2.55
Average sales price per Bbl of
natural gas liquids.......... $ 22.42 $ 21.51 $ 17.94
Average sales price per Mcfe...... $ 2.82 $ 3.35 $ 2.72
Average cost of production per
Mcfe produced (2)............ $ 0.74 $ 0.85 $ 0.82
26
(1) Average sales prices are net of hedging activity.
(2) Crude oil and natural gas were combined by converting crude oil and natural
gas liquids to a Mcf equivalent ("Mcfe") on the basis of 1 Bbl of crude oil
and natural gas liquid equals 6 Mcf of natural gas. Production costs
include direct operating costs, ad valorem taxes and gross production
taxes.
Drilling Activities
The following table sets forth our gross and net working interests in
exploratory and development wells drilled during the three years ended December
31 2002.
2000 2001 2002
----------------------------- ----------------------------- -------------------------
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
------------ ---------- ------------ ---------- ---------- --------
Exploratory(3)
Productive(4)
Crude oil - - - - 1.0 1.0
Natural gas 3.0 2.5 2.0 1.0 3.0 0.5
Dry holes(5) 9.0 5.6 1.0 .5 3.0 1.5
------------ ---------- ------------ ---------- ---------- --------
Total 12.0 8.1 3.0 1.5 7.0 3.0
============ ========== ============ ========== ========== ========
Development(6)
Productive (4)
Crude oil 9.0 9.0 2.0 2.0 - -
Natural gas 16.0 12.2 13.0 11.0 14.0 11.8
Dry holes (5) 3.0 3.0 - - 1.0 1.0
------------ ---------- ------------ ---------- ---------- --------
Total 28.0 24.2 15.0 13.0 15.0 12.8
============ ========== ============ ========== ========== ========
------------------
(1) A gross well is a well in which we own an interest.
(2) The number of net wells represents the total percentage of working
interests held in all wells (e.g., total working interest of 50% is
equivalent to 0.5 net well. A total working interest of 100% is equivalent
to 1.0 net well).
(3) An exploratory well is a well drilled to find and produce crude oil or
natural gas in an unproved area, to find a new reservoir in a field
previously found to be producing crude oil or natural gas in another
reservoir, or to extend a known reservoir.
(4) A productive well is an exploratory or a development well that is not a dry
hole.
(5) A dry hole is an exploratory or development well found to be incapable of
producing either crude oil or natural gas in sufficient quantities to
justify completion as a crude oil or natural gas well.
(6) A development well is a well drilled within the proved area of a crude oil
or natural gas reservoir to the depth of stratigraphic horizon (rock layer
or formation) noted to be productive for the purpose of extracting proved
crude oil or natural gas reserves.
As of March 5, 2003, we had 6 wells in process of drilling and completing,
1 in the U.S. and 5 in Canada.
27
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.
New Grey Wolf leases 17,522 square feet of office space in Calgary, Alberta
pursuant to a lease, which expires in April 2003.
Other Properties
We own 10 acres of land, an office building, workshop, warehouse and house
in Sinton, Texas, 2.8 acres of land, an office building in Scurry County, Texas,
600 acres of fee land in Scurry County, Texas and 160 acres of land in Coke
County, Texas. All three properties are used for the storage of tubulars and
production equipment. We also own 19 vehicles which are used in the field by
employees. We own 2 workover rigs, which are used for servicing our wells.
Item 3. Legal Proceedings
In 2001, Abraxas and Abraxas Wamsutter L.P. were named as defendants in a
lawsuit filed in U.S. District Court in the District of Wyoming. The claim
asserts breach of contract, fraud and negligent misrepresentation by Abraxas and
Abraxas Wamsutter, L.P. related to the responsibility for year 2000 ad valorem
taxes on crude oil and natural gas properties sold by Abraxas and Abraxas
Wamsutter, L.P. In February 2002, a summary judgment was granted to the
plaintiff in this matter and a final judgment in the amount of $1.3 million was
entered. Abraxas has filed an appeal. We believe these charges are without
merit. We have established a reserve in the amount of $845,000, which represents
our estimated share of the judgment.
In late 2000, Abraxas received a Final De Minimis Settlement Offer from the
United States Environmental Protection Agency concerning the Casmalia Disposal
Site, Santa Barbara County, California. Abraxas' liability for the cleanup at
the Superfund site is based on a 1992 acquisition, which is alleged to have
transported or arranged for the transportation of oil field waste and drilling
muds to the Superfund site. Abraxas 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 crude
oil companies, all of which are claiming a petroleum exclusion that limits
Abraxas' liability. The potential financial exposure and any settlement posture
has yet not been developed, but is considered by Abraxas to be immaterial.
Additionally, from time to time, we are involved in litigation relating to
claims arising out of its operations in the normal course of business. At
December 31, 2002, we were not engaged in any legal proceedings that are
expected, individually or in the aggregate, to have a material adverse effect on
our operations.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted to a vote of our security holders during the fourth
quarter of the fiscal year ended December 31, 2002.
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 2003 annual meeting of
shareholders and until his successor is duly elected and qualified.
Robert L. G. Watson, age 52, 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,
28
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 51, 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 41, 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.
29
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
Market Information
Abraxas common stock began trading on the American Stock Exchange on August
18, 2000, under the symbol "ABP." The following table sets forth certain
information as to the high and low bid quotations quoted for Abraxas' common
stock on the American Stock Exchange.
Period High Low
------ ---- ---
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
2002
First Quarter $1.70 $0.89
Second Quarter 1.41 0.52
Third Quarter 0.98 0.42
Fourth Quarter 0.80 0.52
2003 First Quarter (Through March 5, 2003) $0.99 $0.55
Holders
As of March 5, 2003, we had 35,622,096 shares of common stock outstanding
and had approximately 1,606 stockholders of record.
Dividends
We have not paid any cash dividends on our common stock and it is not
presently determinable when, if ever, we will pay cash dividends in the future.
In addition, the indenture governing the New Notes and Senior Secured Credit
Agreement prohibits the payment of cash dividends and stock dividends on our
common stock. You should read the discussion under "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Liquidity and
Capital Resources" for more information regarding the restrictions on our
ability to pay dividends.
Recent Sales of Unregistered Securities
On January 23, 2003, we issued approximately $109.7 million in principal
amount of New Notes and 5,642,699 shares of Abraxas common stock in connection
with the exchange offer. These securities were issued pursuant to the exemption
from the registration requirements of the Securities Act of 1933, as amended,
under Regulation D. The securities were offered and sold only to accredited
investors and to no more than 35 non-accredited investors each of whom Abraxas
believed had such knowledge and experience in financial and business matters
that he or she was capable of evaluation of the merits and risks on the
investment in the New Notes and shares of Abraxas common stock.
30
Securities Authorized for Issuance Under Equity Compensation Plans
Equity Compensation Plan Information
Number of securities
remaining available for
future issuance under
Number of securities to Weighted-average equity compensation plans
be issued upon exercise exercise price of (excluding securities
of outstanding options, outstanding options, reflected in column (a))
warrants and rights warrants and rights (c)
Plan Category (a) (b)
Equity compensation plan
approved by security holders 3,003,340 $1.94 2,161,366
Equity compensation plans not
approved by security holders
1,252,000 $2.89 -
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" in Item 8.
Year Ended December 31,
----------------------------------------------------------------------------------
1998 1999 2000 2001 2002
---- ---- ---- ---- ----
(Dollars in thousands except per share data)
Total revenue (4) $ 60,084 $ 66,770 $ 76,600 $ 77,243 $ 54,320
Net income (loss) (4) $ (83,960) (3) $ (36,680) (3) $ 8,449 (2) $ (19,718) (5) $ (118,527) (1)
Net income (loss) per common share -
diluted (4) $ (13.26) $ (5.41) $ 0.26 $ (0.76) $ (3.95)
Weighted average shares outstanding -
diluted (in thousands) 6,331 6,784 22,616 25,789 29,979
Total assets $ 291,498 $ 322,284 $ 335,560 $ 303,616 $ 181,425
Long-term debt, excluding current
maturities (4) $ 299,698 $ 273,421 $ 266,441 $ 285,184 $ 236,943
Total stockholders' equity (deficit) $ (63,522) $ (9,505) $ (6,503) $ (28,585) $ (142,254)
(1) Includes ceiling limitation write-down of $116.0 million.
(2) Includes gain on sale of partnership interest of $34 million in 2000 and
the reclassification of an extraordinary gain on debt extinguishment in
2000 to other income (see Note 20 to the consolidated financial
statements).
(3) Includes ceiling limitation write-down of $61.2 million and $19.1 million
for 1998 and 1999, respectively. (4) These amounts have been restated (see
Note 20 to the consolidated financial statements). (5) Includes ceiling
test write-down of $2.6 million in 2001, based on subsequent (March
22, 2002) realized prices, related to our Canadian operations.
31
Item 7. Management's Discussion And Analysis Of Financial Condition And Results
Of Operations
The following is a discussion of our consolidated financial condition,
results of operations, liquidity and capital resources. This discussion should
be read in conjunction with our Consolidated Financial Statements and the Notes
thereto. See "Financial Statements" in Item 8.
As discussed in Note 20 to the consolidated financial statements, the
Company's financial statements have been restated. The accompanying management's
discussion and analysis gives effect to that restatement.
General
We have incurred net losses in five of the last six 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. Crude oil and
natural gas prices increased substantially in 2000. During 2001, crude oil and
natural gas prices weakened substantially from the 2000 levels. During 2002,
prices began to increase. In addition, because our proved reserves will decline
as crude oil, natural gas and natural gas liquids are produced, unless we
acquire additional properties containing proved reserves or conduct successful
exploration and development activities, our reserves and production will
decrease. Our ability to acquire or find additional reserves in the near future
will be dependent, in part, upon the amount of available funds for acquisition,
exploitation, exploration and development projects. In order to provide us with
liquidity and capital resources, we have sold certain of our producing
properties. However, our production levels have declined as we have been unable
to replace the production represented by the properties we have sold with new
production from the producing properties we have invested in with the proceeds
of our property sales. In addition, under the terms of our new senior secured
credit agreement and our New Notes, we are subject to limitations on capital
expenditures. As a result, we will be limited in our ability to replace existing
production with new production and might suffer a decrease in the volume of
crude oil and natural gas we produce. If crude oil and natural gas prices return
to depressed levels or if our production levels continue to decrease, our
revenues, cash flow from operations and financial condition will be materially
adversely affected. For more information, see "Liquidity and Capital Resources -
Current Liquidity Requirements" and "Future Capital Resources."
Results of Operations
General. 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.
Commodity Prices. Our results of operations are significantly affected by
fluctuations in commodity prices. Price volatility in the natural gas market has
remained prevalent in the last few years. In the first quarter of 2002, we
experienced a decline in energy commodity prices from the prices that we
received in the first quarter of 2001. During the first quarter of 2001, we had
certain crude oil and natural gas hedges in place that prevented us from
realizing the full impact of a favorable 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 and the beginning of the first quarter of 2002, prices again became
depressed, primarily due to the economic downturn. Beginning in March 2002,
commodity prices began to increase and continued higher through December 2002.
Prices have continued to increase during the first part of 2003. As of March 5,
2003, the NYMEX price for natural gas was $7.02 per Mcf and $36.69 per Bbl for
crude oil.
32
The table below illustrates how natural gas prices fluctuated over the
course of 2001 and 2002. The table below contains the last three day average of
NYMEX traded contracts price and the prices we realized during each quarter for
2001 and 2002, including the impact of our hedging activities.
Natural Gas Prices by Quarter
(in $ per Mcf)
---------------------------------------------------------------------------------------------------
Quarter Ended
---------------------------------------------------------------------------------------------------
March 31, June 30, Sept. 30, Dec. 31, March 31, June 30, Sept. 30, Dec. 31,
2001 2001 2001 2001 2002 2002 2002 2002
------------ ---------- ----------- ------------- ------------- ----------- ----------- -----------
Index $7.27 $4.82 $2.98 $2.47 $2.38 $3.36 $3.28 $ 3.99
Realized 4.85 3.41 2.26 2.09 2.21 2.44 2.08 3.47
The NYMEX natural gas price on March 5, 2003 was $7.02 per Mcf.
Prices for crude oil have followed a similar path as the commodity market
fell throughout 2001 and the first quarter of 2002. The table below contains the
last three day average of NYMEX traded contracts price and the prices we
realized during each quarter for 2001 and 2002.
Crude Oil Prices by Quarter
(in $ per Bbl)
-------------------------------------------------------------------------------------------------------
Quarter Ended
-------------------------------------------------------------------------------------------------------
March 31, June 30, Sept. 30, Dec. 31, March 31, June 30, Sept. 30, Dec. 31,
2001 2001 2001 2001 2002 2002 2002 2002
----------- ---------- ------------- -------------- ------------- ---------- ------------- ------------
Index $ 29.86 $ 27.94 $ 26.50 $ 22.12 $ 19.48 $ 26.40 $ 27.50 $ 28.29
Realized 27.22 25.32 25.06 18.72 16.64 23.47 23.47 24.83
The NYMEX crude oil price on March 5, 2003 was $ 36.69 per Bbl.
Hedging Activities. We seek to reduce our exposure to price volatility by
hedging our production through swaps, options and other commodity derivative
instruments. In 2000, 2001 and 2002, we experienced hedging losses of $20.2
million, $12.1 million and $3.2 million, respectively. In October 2002, all of
these hedge agreements expired. Under the expired hedge agreements, we made
total payments over the term of these arrangements to various counterparties in
the amount of $35.1 million.
Under the terms of our new senior secured credit agreement, we are required
to maintain hedging positions with respect to not less than 25% nor more than
75% of our crude oil and natural gas production for a rolling six month period.
On January 23, 2003, we entered into a collar option agreement with respect to
5,000 MMBtu per day, or approximately 25% of our production, at a call price of
$6.25 per MMBtu and a put price of $4.00 per MMBtu agreement, for the calendar
months of February through July 2003. In February 2003, we entered into a second
hedge agreement for the calendar months of March 2003 through February 2004,
related to 5,000 MMBtu which provides for a floor price of $4.50 per MMBtu.
Selected Operating Data. The following table sets forth certain of our operating
data for the periods presented.
Years Ended December 31,
---------------------------------------------
(dollars in thousands, except per unit data)
2000 2001 2002
--------------- ------------- -------------
Operating revenue:*
Crude oil sales*............................ $ 11,899 $ 11,184 $ 7,114
NGLs sales ................................. 7,061 5,979 4,343
33
Natural gas sales*.......................... 54,013 56,038 39,405
Gas processing revenue...................... 2,717 2,438 2,420
Rig and other............................... 910 1,604 1,038
--------------- ------------- -------------
Total operating revenues ................... $ 76,600 $ 77,243 $ 54,320
=============== ============= =============
Operating income (loss)..................... $ 11,943 $ 19,125 $ (110,903)
Crude oil production (MBbls)................ 636.7 454.1 292.3
NGLs production (MBbls)..................... 314.9 278.0 242.0
Natural gas production (MMcf)............... 19,962.5 17,495.6 15,452.7
Average crude oil sales price (per Bbl)* $ 18.69 $ 24.63 $ 24.34
Average NGLs sales price (per Bbl) $ 22.42 $ 21.51 $ 17.94
Average natural gas sales price (per Mcf)* $ 2.71 $ 3.20 $ 2.55
*Revenue and average sales prices are net of hedging activities.
Comparison of Year Ended December 31, 2002 to Year Ended December 31, 2001:
Operating Revenue. During the year ended December 31, 2002, operating
revenue from crude oil, natural gas and natural gas liquids sales decreased by
$22.3 million from $73.2 million in 2001 to $50.9 million in 2002. This decrease
was primarily attributable to a decrease in production volumes and lower
commodity prices in 2002 as compared to 2001. Crude oil and natural gas revenue
was impacted by $11.5 million from a decline in commodity prices and $10.8
million from reduced production. The decline in production was due to the
disposition of certain properties in south Texas and natural field declines.
Natural gas liquids volumes declined from 278.0 MBbls in 2001 to 242.0
MBbls in 2002. Crude oil sales volumes declined from 454.1 MBbls in 2001 to
292.3 MBbls during 2002. Natural gas sales volumes decreased from 17.5 Bcf in
2001 to 15.5 Bcf in 2002. Production declines were primarily attributable to our
disposition of assets during 2002 and natural field declines.
Average sales prices in 2002 net of hedging losses were:
o $ 24.34 per Bbl of crude oil,
o $ 17.94 per Bbl of natural gas liquids, and
o $ 2.55 per Mcf of natural gas.
Average sales prices in 2001 net of hedging losses were:
o $24.63 per Bbl of crude oil,
o $21.51 per Bbl of natural gas liquids, and
o $ 3.20 per Mcf of natural gas.
Lease Operating Expense. Lease operating expense ("LOE") decreased from
$18.6 million in 2001 to $15.2 million in 2002. LOE on a per Mcfe basis for 2002
was $0.82 per Mcfe as compared to $0.83 per Mcfe in 2001. The decrease in the
per Mcfe cost is due to a reduced operating cost offset by the decline in
production volumes.
G&A Expense. General and administrative ("G&A") expense increased slightly
from $6.4 million in 2001 to $6.9 million in 2002. This increase was due
primarily to increased legal expenses related to ongoing litigation in 2002. Our
G&A expense on a per Mcfe basis increased from $0.30 in 2001 to $0.37 in 2002.
The increase in the per Mcfe cost was due primarily to lower production volumes
in 2002 as compared to 2001.
G&A - Stock-based Compensation Expense. Effective July 1, 2000, the
Financial Accounting Standards Board ("FASB") issued FIN 44, "Accounting for
Certain Transactions Involving Stock Compensation", an interpretation of
34
Accounting Principles Board Opinion No. ("APB") 25. Under the interpretation,
certain modifications to fixed stock option awards which were made subsequent to
December 15, 1998, and not exercised prior to July 1, 2000, require that the
awards be subject to variable accounting until they are exercised, forfeited, or
expired. In March 1999, we amended the exercise price to $2.06 on all options
with an existing exercise price greater than $2.06. We charged approximately
$2.8 million to stock-based compensation expense in 2000 compared to crediting
approximately $2.8 million in 2001. This was due to the decline in the market
price of our Common stock during 2001. During 2002, we did not recognize any
stock-based compensation due to the decline in the price of our common stock.
DD&A Expense. Depreciation, depletion and amortization ("DD&A") expense
decreased by $5.9 million from $32.4 million in 2001 to $26.5 million in 2002.
The decline in DD&A is due to reductions in our full cost pool resulting from
ceiling test write-downs, as well as lower production volumes. Our DD&A expense
on a per Mcfe basis for 2002 was $1.42 per Mcfe as compared to $1.74 per Mcfe in
2001.
Interest Expense. Interest expense increased from $31.5 million to $34.1
million for 2002 compared to 2001. The increase was the result of additional
sales pursuant to our production payment arrangement with Mirant Americas as
well as increased borrowings under Old Grey Wolf's credit facility in 2002. The
production payment was reacquired in June 2002 for approximately $6.8 million.
Ceiling Limitation Write-down. We record the carrying value of our crude
oil and natural gas properties using the full cost method of accounting. For
more information on the full cost method of accounting, you should read the
description under "Critical Accounting Policies-- Full Cost Method of Accounting
for Crude Oil and Natural Gas Activities". As of December 31, 2001, the
Company's net capitalized costs of crude oil and natural gas properties exceeded
the present value of its estimated proved reserves by $71.3 million. These
amounts were calculated considering 2001 year-end prices of $19.84 per Bbl for
crude oil and $2.57 per Mcf for natural gas as adjusted to reflect the expected
realized prices for each of the full cost pools. The Company did not adjust its
capitalized costs for its U.S. properties because subsequent to December 31,
2001, crude oil and natural gas prices increased such that capitalized costs for
its U.S. properties did not exceed the present value of the estimated proved
crude oil and natural gas reserves for its U.S. properties as determined using
increased realized prices on March 22, 2002 of $24.16 per Bbl for crude oil and
$2.89 per Mcf for natural gas.
At June 30, 2002, our net capitalized costs of crude oil and natural gas
properties exceeded the present value of our estimated proved reserves by $138.7
million ($28.2 million on the U.S. properties and $110.5 million on the Canadian
properties). These amounts were calculated considering June 30, 2002 prices of
$26.12 per Bbl for crude oil and $2.16 per Mcf for natural gas as adjusted to
reflect the expected realized prices for each of the full cost pools. Subsequent
to June 30, 2002, commodity prices increased in Canada and we utilized these
increased prices in calculating the ceiling limitation write-down. The total
write-down was approximately $116.0 million. At December 31, 2002 our net
capitalized cost of crude oil and natural gas properties did not exceed the
present value of our estimated reserves, due to increased commodity prices
during the fourth quarter and, as such, no further write-down was recorded. We
cannot assure you that we will not experience additional ceiling limitation
write-downs in the future.
The risk that we will be required to write-down the carrying value of our
crude oil and natural gas assets increases when crude oil and natural gas prices
are depressed or volatile. In addition, write-downs may occur if we have
substantial downward revisions in our estimated proved reserves or if purchasers
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.
Income taxes. Income tax expense decreased from an expense of $2.4 million
for the year ended December 31, 2001 to a benefit of $29.7 million for the year
ended December 31, 2002. The decrease was primarily due to the tax benefit
relating to the ceiling limitation write-down related to our Canadian
properties.
35
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 and natural field declines.
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
property disposition and natural field declines.
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.
Lease Operating Expense. Lease operating expense decreased 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 expense decreased from $6.5 million
in 2000 to $6.4 million in 2001. 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 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.
36
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. 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, ($38.9 million on the U.S.
properties and $32.4 million on the Canadian properties) million. These amounts
were calculated considering 2001 year-end prices of $19.84 per Bbl for crude oil
and $2.57 per Mcf for natural gas as adjusted to reflect the expected realized
prices for each of the full cost pools. The Company did not adjust its
capitalized costs for its U.S. properties because subsequent to December 31,
2001, crude oil and natural gas prices increased such that capitalized costs for
its U.S. properties did not exceed the present value of the estimated proved
crude oil and natural gas reserves for its U.S. properties as determined using
increased realized prices on March 22, 2002 of $24.16 per Bbl for crude oil and
$2.89 per Mcf for natural gas.
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.
Income taxes for the year ended December 31, 2000 related to deferred taxes on
the sale of the Wamsutter partnership.
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.
Liquidity and Capital Resources
General. The crude oil and natural gas industry is a highly capital
intensive and cyclical business. Our capital requirements are driven principally
by our obligations to service debt and to fund the following costs:
o the development of existing properties, including drilling and
completion costs of wells;
o acquisition of interests in crude oil and natural gas properties;
and
o production and transportation facilities.
The amount of capital available to us will affect our ability to service
our existing debt obligations and to continue to grow the business through the
development of existing properties and the acquisition of new properties.
Our sources of capital are primarily cash on hand, cash from operating
activities, funding under the new senior secured credit agreement and the sale
of properties. Our overall liquidity depends heavily on the prevailing prices of
crude oil and natural gas and our production volumes of crude oil and natural
gas. Significant downturns in commodity prices, such as that experienced in the
last nine months of 2001 and the first quarter of 2002, can reduce our cash from
operating activities. Although we have hedged a portion of our natural gas and
crude oil production and will continue this practice as required pursuant to the
new senior secured credit agreement, future crude oil and natural gas price
declines would have a material adverse effect on our overall results, and
therefore, our liquidity. Low crude oil and natural gas prices could also
negatively affect our ability to raise capital on terms favorable to us.
If the volume of crude oil and natural gas we produce decreases, our cash
flow from operations will decrease. Our production volumes will decline as
reserves are produced. In addition, due to sales of properties in 2002 and
January 2003, we now have significantly reduced reserves and production levels.
In the future we may sell additional properties, which could further reduce our
production volumes. To offset the loss in production volumes resulting from
natural field declines and sales of producing properties, we must conduct
successful exploration, exploitation and development activities, acquire
additional producing properties or identify additional behind-pipe zones or
secondary recovery reserves. While we have had some success in pursuing these
37
activities, historically, we have not been able to fully replace the production
volumes lost from natural field declines and property sales.
Working Capital. At December 31, 2002 our current liabilities of
approximately $82.8 million exceeded our current assets of $17.2 million.
However, as a result of the financial restructuring completed in January 2003
our current liabilities were reduced by $75.7 million to $7.1 million as of
January 23, 2003, which includes trade payables of $4.1 million and $1.6 million
of revenues due third parties. After giving effect to the scheduled principal
reductions required during 2003 under our senior secured credit agreement, we
will have cash interest expense of approximately $4.0 million. We do not expect
to make cash interest payments with respect to the outstanding New Notes, and
the issuance of additional New Notes in lieu of cash interest payments thereon
will not affect our working capital balance.
Capital Expenditures. Capital expenditures in 2000, 2001 and 2002 were
$74.4 million, $57.1 million and $38.7 million, respectively. The table below
sets forth the components of these capital expenditures for the three years
ended December 31, 2000, 2001 and 2002.
Year Ended December 31,
---------------------------------------------
2000 2001 2002
--------------- -------------- -------------
(dollars in thousands)
Expenditure category:
Property acquisitions $ 7,189 $ - $ -
Development 64,873 56,694 38,560
Facilities and other 2,350 362 154
--------------- -------------- -------------
Total $ 74,412 $ 57,056 $ 38,714
=============== ============== =============
During 2000, 2001 and 2002, capital expenditures were primarily for the
development of existing properties. For 2003, our capital expenditures are
subject to limitations imposed under the new senior secured credit agreement and
New Notes, including a maximum annual capital expenditure budget of $15 million
for 2003, and subject to reduction in the event of a reduction in our net
assets. We currently expect to have a capital expenditure budget of up to $8
million for the first quarter of 2003. Our capital expenditures could include
expenditures for acquisition of producing properties if such opportunities
arise, but we currently have no agreements, arrangements or undertakings
regarding any material acquisitions. We have no material long-term capital
commitments and are consequently able to adjust the level of our expenditures as
circumstances dictate. Additionally, the level of capital expenditures will vary
during future periods depending on market conditions and other related economic
factors. Should the prices of crude oil and natural gas decline from current
levels, our cash flows will decrease which may result in a reduction of the
capital expenditures budget. If we decrease our capital expenditures budget, we
may not be able to offset crude oil and natural gas production volumes decreases
caused by natural field declines and sales of producing properties.
Sources of Capital. The net funds provided by and/or used in each of the
operating, investing and financing activities are summarized in the following
table and discussed in further detail below:
2000 2001 2002
------------- ------------- -----------
(dollars in thousands)
Net cash (used in) provided by operating activities $ 21,372 $ 16,263 $ (8,336)
Net cash used in investing activities (18,773) (30,797) (5,036)
Net cash provided by (used in) financing activities (3,818) 20,685 10,836
-------------- ------------- ------------
Total $ (1,219) $ 6,151 $ (2,536)
============== ============= ============
Operating activities for the year ended December 31, 2002, used $8.4
million of cash. Investing activities used $5.0 million during 2002. Our
investing activities included the sale of properties which provided $33.9
million, and the use of $38.7 million primarily for the development of producing
38
properties. Financing activities provided us with $10.8 million during 2002,
relating primarily to advances on Old Grey Wolf's credit facility.
Operating activities for the year ended December 31, 2001 provided us $16.3
million of cash. Investing activities included the sale of properties which
provided $28.9 million, and the use of $57.1 million for the development of
producing properties and $2.7 million for the acquisition of the minority
interest in Grey Wolf. Financing activities provided $20.7 million during 2001,
including the provision of additional funding of $11.7 million under our
production payment arrangement with Mirant Americas, and the provision of $18.3
million under Old Grey Wolf's credit facility. Payments on long-term debt used
$9.3 million.
Future Capital Resources. We will have four principal sources of liquidity
going forward: (i) cash on hand, (ii) cash from operating activities, (iii)
funding under the revolving credit facility, and (iv) sales of producing
properties. However, covenants under the indenture for the outstanding New Notes
and the new senior secured credit agreement restrict our use of cash on hand,
cash from operating activities and any proceeds from asset sales. We may attempt
to raise additional capital through the issuance of additional debt or equity
securities, though the terms of the new note indenture and the new senior
secured credit agreement substantially restrict our ability to:
o incur additional indebtedness;
o incur liens;
o pay dividends or make certain other restricted payments;
o consummate certain asset sales;
o enter into certain transactions with affiliates;
o merge or consolidate with any other person; or
o sell, assign, transfer, lease, convey or otherwise dispose of all or
substantially all of our assets.
Our best opportunity for additional sources of liquidity and capital will
be through the issuance of equity securities or through the disposition of
assets, as allowed under the various financing arrangements.
Contractual Obligations
We are committed to making cash payments in the future on the following
types of agreements:
o Long-term debt
o Operating leases for office facilities
We have no off-balance sheet debt or unrecorded obligations and we have not
guaranteed the debt of any other party. Below is a schedule of the future
payments that we are obligated to make based on agreements in place as of
December 31, 2002.
Payments due in:
Contractual Obligations
(dollars in thousands)
----------------------------- --------------------------------------------------------------------------------------
Total 2003 2004 2005 2006 2007
----------------------------- ------------- -------------- ------------- ------------- ------------- ---------------
Long-Term Debt (1) $300,443 $ 63,500 $ 190,979 $ - $ - $ 45,964
Operating Leases (2) 985 336 236 236 177 -
(1) After the transactions described in Item 1 - "Recent Events," the amounts
would be $0 in each of the three years 2003, 2004 and 2005, $47,996 in 2006
and $184,000 for 2007. These amounts represent the balances outstanding
under the term loan facility, the revolving credit facility and the New
Notes. These repayments assume that interest will be capitalized under the
term loan facility and that periodic interest on the new senior secured
credit agreement will be paid on a monthly basis and that we will not draw
down additional funds there under.
39
(2) Office lease obligations. Leases for office space for Abraxas and New Grey
Wolf expire in April 2006 and April 2003, respectively.
Other obligations. We make and will continue to make substantial capital
expenditures for the acquisition, exploitation, development, exploration and
production of crude oil and natural gas. In the past, we have funded our
operations and capital expenditures primarily through cash flow from operations,
sales of properties, sales of production payments and borrowings under our bank
credit facilities and other sources. Given our high degree of operating control,
the timing and incurrence of operating and capital expenditures is largely
within our discretion.
Long-Term Indebtedness. The recently completed financial restructuring
resulted in the retirement of our first lien notes, second lien notes and old
notes, together with the Old Grey Wolf credit facility. As of March 5, 2003, our
long-term indebtedness consists of the senior credit facility and the notes
issued in connection with the financial restructuring. The following table sets
forth our long-term indebtedness as of December 31, 2002, and proforma
information reflecting the consummation of the restructuring transactions.
Long Term Indebtedness
Pro forma
December 31,
2002 (a)
After
December 31 Restructuring
-----------------------------------------------
2001 2002
------------------- -------------- -----------
(In thousands)
12 7/8% Senior Secured Notes due 2003 (first lien notes).............. $ 63,500 $ 63,500 $ -
11 1/2% Senior Secured Notes due 2004 (second lien notes)............. 190,178 190,178 -
11 1/2% Senior Notes due 2004 (old lien notes)........................ 801 801 -
9 1/2% Senior Credit Facility ("Grey Wolf Facility") providing for
borrowings up to approximately US $96 million (CDN $150
million). Secured by the assets of Old Grey Wolf and
non-recourse to Abraxas....................................... 22,944 45,964 -
Production Payment ............................................... 8,176 - -
11 1/2% Secured Notes due 2007 (New Notes) - January 2003.......... - - 128,600
New Senior Secured Credit Agreement - January 2003................. - - 46,700
------------------ -------------- -----------
285,599 300,443 175,300
Less current maturities ........................................... 415 63,500 -
------------------ -------------- -----------
$ 285,184 $ 236,943 $ 175,300
================== ============== ===========
(a) After the transactions described in Note 2, for financial reporting
purposes, the New Notes will be reflected at the carrying value of the Second
Lien Notes and Old Notes prior to the exchange of $191.0 million, net of the
cash offered in the exchange of $47.5 million and net of the fair market value
related to equity of $3.8 million offered in the exchange. In conjunction with
the financial restructuring transaction, Abraxas paid cash of $11.5 million
($11.1 in principal and $0.4 million in interest) to redeem certain of the
outstanding old debt and accrued interest. The result of all of these items will
be a remaining carrying value of the New Notes of $128.6 million. The face
amount of the New Notes is $109.7 million. See Note 2 of Notes to Consolidated
Financial Statements in Item 8 for terms and conditions of the New Notes and the
New Senior Secured Credit Agreement.
New Notes - 11 1/2% Secured Notes. In connection with the financial
restructuring, Abraxas issued $109.7 million in principal amount of it's 11 1/2%
Secured Notes due 2007, Series A, in exchange for the second lien notes and old
notes tendered in the exchange offer. The New Notes were issued under an
indenture with U.S. Bank, N. A.
40
The New Notes accrue interest from the date of issuance, at a fixed annual
rate of 11 1/2%, payable in cash semi-annually on each May 1 and November 1,
commencing May 1, 2003, provided that, if we fail, or are not permitted pursuant
to our new senior secured credit agreement or the intercreditor agreement
between the trustee under the indenture for the New Notes and the lenders under
the new senior secured credit agreement, to make such cash interest payments in
full, we will pay such unpaid interest in kind by the issuance of additional New
Notes with a principal amount equal to the amount of accrued and unpaid cash
interest on the New Notes plus an additional 1% accrued interest for the
applicable period. Upon an event of default, the New Notes accrue interest at an
annual rate of 16.5%.
The New Notes are secured by a second lien or charge on all of our current
and future assets, including, but not limited to, all of our crude oil and
natural gas properties. All of Abraxas' current subsidiaries, Sandia Oil & Gas,
Sandia Operating (a wholly-owned subsidiary of Sandia Oil & Gas), Wamsutter, New
Grey Wolf, Western Associated Energy and Eastside Coal, are guarantors of the
New Notes, and all of Abraxas' future subsidiaries will guarantee the New Notes.
If Abraxas cannot make payments on the New Notes when they are due, the
guarantors must make them instead.
The New Notes and related guarantees
o are subordinated to the indebtedness under the new senior secured
credit agreement;
o rank equally with all of Abraxas' current and future senior
indebtedness; and
o rank senior to all of Abraxas' current and future subordinated
indebtedness, in each case, if any.
The New Notes are subordinated to amounts outstanding under the new senior
secured credit agreement both in right of payment and with respect to lien
priority and are subject to an intercreditor agreement.
Abraxas may redeem the New Notes, at its option, in whole at any time or in
part from time to time, at redemption prices expressed as percentages of the
principal amount set forth below. If Abraxas redeems all or any New Notes, it
must also pay all interest accrued and unpaid to the applicable redemption date.
The redemption prices for the New Notes during the indicated time periods are as
follows:
Period Percentage
From January 24, 2003 to June 23, 2003.......................80.0429%
From June 24, 2003 to January 23, 2004.......................91.4592%
From January 24, 2004 to June 23, 2004.......................97.1674%
From June 24, 2004 to January 23, 2005.......................98.5837%
Thereafter...................................................100.0000%
Under the indenture, we are subject to customary covenants which, among
other things, restrict our ability to:
o borrow money or issue preferred stock;
o pay dividends on stock or purchase stock;
o make other asset transfers;
o transact business with affiliates;
o sell stock of subsidiaries;
o engage in any new line of business;
o impair the security interest in any collateral for the notes;
o use assets as security in other transactions; and
41
o sell certain assets or merge with or into other companies.
In addition, we are subject to certain financial covenants including
covenants limiting our selling, general and administrative expenses and capital
expenditures, a covenant requiring Abraxas to maintain a specified ratio of
consolidated EBITDA, as defined in the agreements, to cash interest and a
covenant requiring Abraxas to permanently, to the extent permitted, pay down
debt under the new senior secured credit agreement and, to the extent permitted
by the new senior secured credit agreement, the New Notes or, if not permitted,
paying indebtedness under the new senior secured credit agreement.
The indenture contains customary events of default, including nonpayment of
principal or interest, violations of covenants, inaccuracy of representations or
warranties in any material respect, cross default and cross acceleration to
certain other indebtedness, bankruptcy, material judgments and liabilities,
change of control and any material adverse change in our financial condition.
New Senior Secured Credit Agreement. In connection with the financial
restructuring, Abraxas entered into a new senior secured credit agreement
providing a term loan facility and a revolving credit facility as described
below. Subject to earlier termination on the occurrence of events of default or
other events, the stated maturity date for both the term loan facility and the
revolving credit facility is January 22, 2006. In the event of an early
termination, we will be required to pay a prepayment premium, except in the
limited circumstances described in the new senior secured credit agreement.
Outstanding amounts under both facilities bear interest at the prime rate
announced by Wells Fargo Bank, N.A. plus 4.5%. Any amounts in default under the
term loan facility will accrue interest at an additional 4%. At no time will the
amounts outstanding under the new senior secured credit agreement bear interest
at a rate less than 9%.
Term Loan Facility. Abraxas has borrowed $4.2 million pursuant to a term
loan facility at January 23, 2003, all of which was used to make cash payments
in connection with the financial restructuring. Accrued interest under the term
loan facility will be capitalized and added to the principal amount of the term
loan facility until maturity.
Revolving Credit Facility. Lenders under the new senior secured credit
agreement have provided a revolving credit facility to Abraxas with a maximum
borrowing base of up to $50 million. Our current borrowing base under the
revolving credit facility is $49.9 million, subject to adjustments based on
periodic calculations and mandatory prepayments under the senior secured credit
agreement. Portions of accrued interest under the revolving credit facility may
be capitalized and added to the principal amount of the revolving credit
facility. At January 23, 2003, we have borrowed $42.5 million under the
revolving credit facility, all of which was used to make cash payments in
connection with the financial restructuring. We plan to use the remaining
borrowing availability under the new senior secured credit agreement to fund our
operations, including capital expenditures.
Covenants. Under the new senior secured credit agreement, Abraxas is
subject to customary covenants and reporting requirements. Certain financial
covenants require Abraxas to maintain minimum levels of consolidated EBITDA (as
defined in the new senior secured credit agreement), minimum ratios of
consolidated EBITDA to cash interest expense and a limitation on annual capital
expenditures. In addition, at the end of each fiscal quarter, if the aggregate
amount of our cash and cash equivalents exceeds $2.0 million, we are required to
repay the loans under the new senior secured credit agreement in an amount equal
to such excess. The new senior secured credit agreement also requires us to
enter into hedging agreements on not less than 25% or more than 75% of our
projected oil and gas production. We are also required to establish deposit
accounts at financial institutions acceptable to the lenders and we are required
to direct our customers to make all payments into these accounts. The amounts in
these accounts will be transferred to the lenders upon the occurrence and during
the continuance of an event of default under the new senior secured credit
agreement.
In addition to the foregoing and other customary covenants, the new senior
secured credit agreement contains a number of covenants that, among other
things, restrict our ability to:
o incur additional indebtedness;
o create or permit to be created any liens on any of our properties;
o enter into any change of control transactions;
42
o dispose of our assets;
o change our name or the nature of our business;
o make any guarantees with respect to the obligations of third parties;
o enter into any forward sales contracts;
o make any payments in connection with distributions, dividends or
redemptions relating to our outstanding securities, or
o make investments or incur liabilities.
Guarantees. The obligations of Abraxas under the new senior secured credit
agreement are guaranteed by Sandia Oil & Gas, Sandia Operating, Wamsutter, New
Grey Wolf, Western Associated Energy and Eastside Coal. Obligations under the
new senior secured credit agreement are secured by a first lien security
interest in substantially all of Abraxas' and the guarantors' assets, including
all crude oil and natural gas properties.
Events of Default. The new senior credit 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 our financial condition.
Hedging Activities
Our results of operations are significantly affected by fluctuations in
commodity prices and we seek to reduce our exposure to price volatility by
hedging our production through swaps, options and other commodity derivative
instruments. Under the new senior secured credit agreement, we are required
maintain hedge positions on not less than 25% or more than 75% of our projected
oil and gas production for a six month rolling period. On January 23, 2003, we
entered into a collar option agreement with respect to 5,000 MMBtu per day, or
approximately 25% of our production, at a call price of $6.25 per MMBtu and a
put price of $4.00 per MMBtu, for the calendar months of February through July
2003. In February 2003, we entered into a second hedge agreement related to
5,000 MMBtu for the calendar months of March 2003 through February 2004 which
provides for a floor price of $4.50 per MMBtu. See "Item 7A--Quantitative and
Qualitative Disclosures about Market Risk--Hedging Sensitivity" for further
information.
Net Operating Loss Carryforwards
At December 31, 2002, the Company had, subject to the limitation discussed
below, $166.7 million of net operating loss carryforwards for U.S. tax purposes.
These loss carryforwards will expire from 2003 through 2022 if not utilized. At
December 31, 2002, the Company had approximately $1.0 million of net operating
loss carryforwards for Canadian tax purposes. These carryforwards will expire
from 2003 through 2009 if not utilized. In connection with January 2003
transactions described in Note 2, in Notes to Consolidated Financial Statements,
Item 8, certain of the loss carryforwards may be 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.
43
An ownership change under Section 382 occurred in December 1999, following
the issuance of additional shares, as described in Note 6. 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 $39.7 million and $99.1 million for deferred tax assets
at December 31, 2001 and 2002, respectively.
Related Party Transactions
Accounts receivable - Other in the consolidated balances sheets includes
approximately $48,365 and $51,211 as of December 31, 2001 and 2002,
respectively, representing amounts due from officers and stockholders relating
to advances made to employees.
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 the Company from time
to time. The Company paid Wind River a total of approximately $336,000, $314,000
and $345,000 in 2000, 2001 and 2002 respectively, for Wind River's operating
costs associated with the Company's use of the plane.
Critical Accounting Policies
The preparation of financial statements in conformity with generally
accepted accounting principles requires that management apply accounting
policies and make estimates and assumptions that affect results of operations
and the reported amounts of assets and liabilities in the financial statements.
The following represents those policies that management believes are
particularly important to the financial statements and that require the use of
estimates and assumptions to describe matters that are inherently uncertain.
Full Cost Method of Accounting for Crude Oil and Natural Gas Activities.
SEC Regulation S-X defines the financial accounting and reporting standards for
companies engaged in crude oil and natural gas activities. Two methods are
prescribed: the successful efforts method and the full cost method. Abraxas has
chosen to follow the full cost method under which all costs associated with
property acquisition, exploration and development are capitalized. We also
capitalize internal costs that can be directly identified with our acquisition,
exploration and development activities and do not include any costs related to
production, general corporate overhead or similar activities. Under the
successful efforts method, geological and geophysical costs and costs of
carrying and retaining undeveloped properties are charged to expense as
incurred. Costs of drilling exploratory wells that do not result in proved
reserves are charged to expense. Depreciation, depletion, amortization and
impairment of crude oil and natural gas properties are generally calculated on a
well by well or lease or field basis versus the "full cost" pool basis.
Additionally, gain or loss is generally recognized on all sales of crude oil and
natural gas properties under the successful efforts method. As a result our
financial statements will differ from companies that apply the successful
efforts method since we will generally reflect a higher level of capitalized
costs as well as a higher depreciation, depletion and amortization date on our
crude oil and natural gas properties.
At the time it was adopted, management believed that the full cost method
would be preferable, as earnings tend to be less volatile than under the
successful efforts method. However, the full cost method makes us susceptible to
significant non-cash charges during times of volatile commodity prices because
the full cost pool may be impaired when prices are low. These charges are not
44
recoverable when prices return to higher levels. The Company has experienced
this situation several times over the years, most recently in 2002. Our crude
oil and natural gas reserves have a relatively long life. However, temporary
drops in commodity prices can have a material impact on our business including
impact from the full cost method of accounting.
Under full cost accounting rules, the net capitalized cost of crude oil and
natural gas properties may not exceed a "ceiling limit" which is based upon the
present value of estimated future net cash flows from proved reserves,
discounted at 10%, plus the lower of cost or fair market value of unproved
properties. If net capitalized costs of crude oil and natural gas properties
exceed the ceiling limit, we must charge the amount of the excess to earnings.
This is called a "ceiling limitation write-down." This charge does not impact
cash flow from operating activities, but does reduce our stockholders' equity
and reported earnings. The risk that we will be required to write down the
carrying value of crude oil and natural gas properties increases when crude oil
and natural gas prices are depressed or volatile. In addition, write-downs may
occur if we experience substantial downward adjustments to our estimated proved
reserves or if purchasers cancel long-term contracts for our natural gas
production. An expense recorded in one period may not be reversed in a
subsequent period even though higher crude oil and natural gas prices may have
increased the ceiling applicable to the subsequent period.
For the year ended December 31, 2002, we recorded a write-down of $116.0
million. The write-down in 2002 was due to low commodity prices. We cannot
assure you that we will not experience additional write-downs in the future.
Should commodity prices decline, a further write-down of the carrying value of
our crude oil and natural gas properties may be required.
Estimates of our proved reserves included in this report are prepared in
accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a
function of:
o the quality and quantity of available data;
o the interpretation of that data;
o the accuracy of various mandated economic assumptions;
o and the judgment of the persons preparing the estimate.
The Company's proved reserve information included in this Report was based
on evaluations prepared by independent petroleum engineers. Estimates prepared
by other third parties may be higher or lower than those included herein.
Because these estimates depend on many assumptions, all of which may
substantially differ from future actual results, reserve estimates will be
different from the quantities of oil and gas that are ultimately recovered. In
addition, results of drilling, testing and production after the date of an
estimate may justify material revisions to the estimate.
You should not assume that the present value of future net cash flows is
the current market value of our estimated proved reserves. In accordance with
SEC requirements, the Company based the estimated discounted future net cash
flows from proved reserves on prices and costs on the date of the estimate.
Actual future prices and costs may be materially higher or lower than the prices
and costs as of the date of the estimate.
The estimates of proved reserves materially impact DD&A expense. If the
estimates of proved reserves decline, the rate at which the Company records DD&A
expense will increase, reducing future net income. Such a decline may result
from lower market prices, which may make it uneconomic to drill for and produce
higher cost fields.
Hedge Accounting. From time to time, we use commodity price hedges to limit
our exposure to fluctuations in crude oil and natural gas prices. Results of
those hedging transactions are reflected in crude oil and natural gas sales.
Statement of Financial Accounting Standards, ("SFAS") No. 133, "Accounting
for Derivative Instruments and Hedging Activities," was effective for the
Company on January 1, 2001. SFAS 133, as amended and interpreted, establishes
45
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities.
Under this statement, all derivatives, whether designated in hedging
relationships or not, are required to be recorded at fair value on our balance
sheet. The accounting for changes in the fair value of a derivative instrument
depends on the intended use of the derivative and the resulting designation,
which is established at the inception of a derivative. Special accounting for
qualifying hedges allows a derivative's gains and losses to offset related
results of the hedged item in the consolidated statement of operations. For
derivative instruments designated as cash flow hedges, changes in fair value, to
the extent the hedge is effective, are recognized in other comprehensive income
until the hedged item is recognized in earnings. For derivative instruments
designated as fair value hedges, changes in fair value, to the extent the hedge
is effective, are recognized as an increase or decrease to the value of the
hedged item until the hedged item is recognized in earnings. Hedge effectiveness
is measured at least quarterly based on the relative changes in fair value
between the derivative contract and the hedged item over time. Any change in the
fair value resulting from ineffectiveness, as defined by SFAS 133, is recognized
immediately in earnings. Changes in fair value of contracts that do not meet the
SFAS 133 definition of a cash flow or fair value hedge are also recognized in
earnings through risk management income. All amounts initially recorded in this
caption are ultimately reversed within the same caption and included in oil and
gas sales or interest expense, as applicable, over the respective contract
terms.
One of the primary factors that can have an impact on our results of
operations is the method used to value our derivatives. We have established the
fair value of all derivative instruments using estimates determined by our
counterparties and subsequently evaluated internally using established index
prices and other sources. These values are based upon, among other things,
futures prices, volatility, time to maturity and credit risk. The values we
report in our financial statements change as these estimates are revised to
reflect actual results, changes in market conditions or other factors, many of
which are beyond our control.
Another factor that can impact our results of operations each period is our
ability to estimate the level of correlation between future changes in the fair
value of the hedge instruments and the transactions being hedged, both at the
inception and on an ongoing basis. This correlation is complicated because
energy commodity prices, the primary risk we hedge, have quality and location
differences that can be difficult to hedge effectively. The factors underlying
our estimates of fair value and our assessment of correlation of our hedging
derivatives are impacted by actual results and changes in conditions that affect
these factors, many of which are beyond our control.
Due to the volatility of crude oil and natural gas prices and, to a lesser
extent, interest rates, our financial condition and results of operations can be
significantly impacted by changes in the market value of our derivative
instruments. As of December 31, 2001 the net market value of our derivatives was
a liability of $658,000. As of December 31, 2002 we did not have any outstanding
derivatives.
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.
SFAS No. 141 and 142 clarify that more assets should be distinguished and
classified between tangible and intangible. The Company did not change or
reclassify contractual mineral rights included in oil and gas properties on the
balance sheet upon adoption of SFAS No. 142. The Company believes the treatment
of such mineral rights as tangible assets under the full cost method of
accounting for crude oil and natural gas properties is appropriate. An issue has
arisen regarding whether contractual mineral rights should be classified as
intangible rather that tangible assets. If it is determined that
reclassification is necessary, the Company's oil and gas properties would be
reduced by $868,000 million and $3.1 and intangible assets would have increased
by a like amount at December 31, 2001 and 2002, respectively, representing cost
incurred from the effective date of June 30, 2001. The provisions of SFAS No.
141 and 142 impact only the balance sheet and associated footnote disclosure,
and reclassifications necessary would not impact the Company's cash flows or
results of operations.
46
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 addresses accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. SFAS No. 143 is effective for us January 1,
2003. SFAS No. 143 requires that the fair value of a liability for an asset's
retirement obligation be recorded in the period in which it is incurred and the
corresponding cost capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its then present value each
period, and the capitalized cost is depreciated over the useful life of the
related asset. If the liability is settled for an amount other than the recorded
amount, a gain or loss is recognized. For all periods presented, we have
included estimated future costs of abandonment and dismantlement in our full
cost amortization base and amortize these costs as a component of our depletion
expense.
We have completed our assessment of SFAS No. 143 and based on our
estimates, we do not expect the statement to have a material effect on our
financial position, results of operations and cash flows for future periods. At
January 1, 2003, we estimate that the present value of our future Asset
Retirement Obligation ("ARO") for natural gas and oil property and related
equipment is approximately $657,000. We estimate that the cumulative effect to
the adoption of SFAS No. 143 and the change in the accounting principle will be
a loss of $285,000, which will be recorded in the first quarter of 2003. The
impact on each of the prior years was not material.
Effective January 1, 2002, we adopted SFAS No. 144 " Accounting for the
Impairment or 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 discontinued operations be recognized in the period that the losses
are incurred rather than as of the measurement date. This new standard had no
impact on the consolidated financial statements for the year ended December 31,
2002.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB No. 4, 44,
and 64, Amendments of FASB Statement No. 13 and Technical Corrections." SFAS No.
145 clarifies guidance related to the reporting of gains and losses from
extinguishment of debt and resolves inconsistencies related to the required
accounting treatment of certain lease modifications. SFAS No. 145 also amends
other existing pronouncements to make various technical corrections, clarify
meanings or describe their applicability under changed conditions. The
provisions relating to the reporting of gains and losses from extinguishment of
debt become effective for us beginning January 1, 2003. All other provisions of
this standard were effective for us as of May 15, 2002 and did not have an
impact on our financial condition or results of operations. Upon issuance of our
restated financial statements included in this Form 10-K/A we have reclassified
the gain on the early extinguishment of debt in 2000 from an extraordinary item
to other income - see Note 20. This reclassification did not affect net income
for the year ended December 31, 2000.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS No. 146 requires costs
associated with exit of disposal activities to be recognized when they are
incurred rather than at the date of commitment to an exit or disposal plan. SFAS
No. 146 is effective for us beginning January 1, 2003. We are currently
evaluating the impact the standard will have on our results of operations and
financial condition.
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-based
Compensation--Transition and Disclosure, an amendment of FASB Statement No.
123," which amends SFAS No. 123 to provide alternative methods of transition for
a voluntary change to the fair value based method of accounting for stock-based
employee compensation. It also amends the disclosure provisions of SFAS No. 123
to require prominent disclosure in both annual and interim financial statements
about the method of accounting for stock-based employee compensation and the
effect of the method used on reported results. The provisions of SFAS No. 148
are effective for annual financial statements for fiscal years ending after
December 15, 2002, and for financial reports containing condensed financial
statements for interim periods beginning after December 15, 2002. The Company
will continue to use APB No. 25 to account for stock based compensation while
providing the disclosures required by SFAS No. 123 as amended by SFAS No. 148.
47
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Commodity Price Risk
As an independent crude oil and natural gas producer, our revenue, cash
flow from operations, other income and equity earnings and profitability,
reserve values, access to capital and future rate of growth are substantially
dependent upon the prevailing prices of crude oil, natural gas and natural gas
liquids. Declines in commodity prices will materially adversely affect our
financial condition, liquidity, ability to obtain financing and operating
results. Lower commodity prices may reduce the amount of crude oil and natural
gas that we can produce economically. Prevailing prices for such commodities are
subject to wide fluctuation in response to relatively minor changes in supply
and demand and a variety of additional factors beyond our control, such as
global political and economic conditions. Historically, prices received for
crude oil and natural gas production have been volatile and unpredictable, and
such volatility is expected to continue. Most of our production is sold at
market prices. Generally, if the commodity indexes fall, the price that we
receive for our production will also decline. Therefore, the amount of revenue
that we realize is partially determined by factors beyond our control. Assuming
the production levels we attained during the year ended December 31, 2002, 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 $5.1
million for the year.
Hedging Sensitivity
On January 1, 2001, we adopted SFAS 133 "Accounting for Derivative
Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138. Under
SFAS 133, all derivative instruments are recorded on the balance sheet at fair
value. If the derivative does not qualify as a hedge or is not designated as a
hedge, the gain or loss on the derivative is recognized currently in earnings.
To qualify for hedge accounting, the derivative must qualify either as a fair
value hedge, cash flow hedge or foreign currency hedge. Currently, we use 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 we determine that
it is probable that a hedged transaction will not occur, deferred gains or
losses on the hedging instrument are recognized in earnings immediately.
Gains and losses on hedging instruments related to accumulated Other
Comprehensive Income and adjustments to carrying amounts on hedged production
are included in natural gas or crude oil production revenue in the period that
the related production is delivered.
In 2000, 2001 and 2002, we experienced hedging losses of $20.2 million,
$12.1 million and $3.2 million, respectively. In October 2002, all of these
hedge agreements expired. Under the expired hedge agreements, we made total
payments to various counterparties in the amount of $35.1 million.
Under the terms of the new senior secured credit agreement, we are required
to maintain hedging positions with respect to not less than 25% nor more than
75% of our crude oil and natural gas production for a rolling six month period.
As of January 23, 2003, we have entered into a collar option agreement with
respect to 5,000 MMBtu per day, or approximately 25% of our production, at a
call price of $6.25 per MMBtu and a put price of $4.00 per MMBtu. In February of
2003 we entered into an additional hedge agreement for 5,000 MMBtu per day with
a floor of $4.50 per MMBtu. As of March 5, 2003, the fair market value of our
hedge positions is not material. For Abraxas, the fair value of the hedging
instrument was determined based on the base price of the hedged item and NYMEX
forward price quotes.
48
The following table sets forth our hedging position as of March 5, 2003.
Time Period Notional Quantities Price Fair Value
---------------------------------------- ------------------------------ ------------------------------ ----------------
February 1, 2003--July 31, 2003 5,000 MMBtu of production Collar with floor of $4.00 $ -
per day and ceiling of $6.25
March 1, 2003 - February 29, 2004 5,000 MMBtu of production Floor of $4.50 $ 368,500
per day
All hedge transactions are subject to our risk management policy, which has
been approved by the Board of Directors. We formally document all relationships
between hedging instruments and hedged items, as well as our 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, we assess whether the derivatives that are used in hedging
transactions are highly effective in offsetting changes in cash flows of hedged
items.
Interest rate risk
At December 31, 2002, 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 Old Grey Wolf's long-term debt was at a fixed interest rate of
9.5%.
As a result of the financial restructuring that occurred in January 2003,
we will have approximately $46.7 million in outstanding indebtedness under the
new senior secured credit agreement, accruing interest at a rate of prime plus
4.5%, subject to a minimum interest rate of 9.0%. In the event that the prime
rate (currently 1.5%) rises above 4.5% the interest rate applicable to our
outstanding indebtedness under the new senior secured credit agreement will rise
accordingly. For every percentage point that the prime rate rises above 4.5%,
our interest expense would increase by approximately $467,000 on an annual
basis. Our New Notes accrue interest at fixed rates and is accordingly not
subject to fluctuations in market rates.
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 $63.4 million for the year ended December
31, 2002. It is estimated that a 5% change in the value of the U.S. dollar to
the Canadian dollar would have changed our net loss by approximately $3.2
million. 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
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 2003 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.
49
Item 11. Executive Compensation
There is incorporated in this Item 11 by reference that portion of our
definitive proxy statement for the 2003 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 2003 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 2003 Annual Meeting of Stockholders which
appears therein under the caption "Certain Transactions."
Item 14. Controls and Procedures
Within the 90 days prior to the filing date of this report, we carried out
an evaluation, under the supervision and with the participation of our
management, including the Chief Executive Officer and Chief Financial Officer,
of the effectiveness of the design and operation of our disclosure controls and
procedures pursuant to Rule 13a-14 of the Securities Exchange Act of 1934, as
amended (the "Exchange Act"). Based upon that evaluation, the Chief Executive
Officer and Chief Financial Officer concluded that our disclosure controls and
procedures are effective in alerting them on a timely basis to material
information relating to the Company required to be included in our periodic
filings under the Exchange Act. Subsequent to the date of this evaluation, there
have been no significant changes in our internal controls or in other factors
that could significantly affect internal controls, nor were any corrective
actions required with regard to significant deficiencies or material weaknesses.
Subsequent to the issuance of our consolidated financial statements for the
year ended December 31, 2002, our management determined that the wholly owned
Canadian subsidiaries should not have been presented as discontinued operations.
As a result, the accompanying consolidated balance sheets as of December 31,
2002 and 2001, and the related consolidated statements of operations, and cash
flows for each of the three years in the period ended December 31, 2002 have
been restated to present the assets and liabilities, results of operations, and
cash flows as components of continuing operations. This restatement relates to
the inappropriate initial implementation of SFAS No. 144. In the future, we will
monitor all new standards to determine the appropriate approach of
implementation given our industry's method of accounting.
50
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a)1. Consolidated Financial Statements Page
Report of Independent Auditors.....................................F-2
Consolidated Balance Sheets,
December 31, 2001 and 2002 (Restated).............................F-3
Consolidated Statements of Operations,
Years Ended December 31, 2000, 2001 and 2002 (Restated)...........F-5
Consolidated Statements of Stockholders' Equity (Deficit)
Years Ended December 31, 2000, 2001 and 2002.....................F-6
Consolidated Statements of Cash Flows
Years Ended December 31, 2000, 2001 and 2002 (Restated)...........F-8
Notes to Consolidated Financial Statements.........................F-10
Grey Wolf Exploration, Inc.
Report of Independent Auditors...........................F-45
Balance Sheets at December 31, 2002 and 2001..............F-46
Statements of Earnings and Retained Earnings
Years ended December 31, 2002, 2001 and 2000............F-48
Statements of Cash Flows
Years ended December 31, 2002, 2001 and 2000............F-49
Notes to Financial Statements.............................F-50
(a)2. Financial Statement Schedules
All schedules have been omitted because they are not applicable, not
required under the instructions or the information requested is set forth in the
consolidated financial statements or related notes thereto.
(a)3.Exhibits
The following Exhibits have previously been filed by the Registrant
or are included following the Index to Exhibits.
Exhibit Number. Description
3.1 Articles of Incorporation of Abraxas. (Filed as Exhibit 3.1 to Abraxas'
Registration Statement on Form S-4, No. 33-36565 (the "S-4 Registration
Statement")).
3.2 Articles of Amendment to the Articles of Incorporation of Abraxas dated
October 22, 1990. (Filed as Exhibit 3.3 to the S-4 Registration
Statement).
3.3 Articles of Amendment to the Articles of Incorporation of Abraxas dated
December 18, 1990. (Filed as Exhibit 3.4 to the S-4 Registration
Statement).
51
3.4 Articles of Amendment to the Articles of Incorporation of Abraxas dated
June 8, 1995. (Filed as Exhibit 3.4 to Abraxas' Registration Statement on
Form S-3, No. 333-00398 (the "S-3 Registration Statement")).
3.5 Articles of Amendment to the Articles of Incorporation of Abraxas dated
as of August 12, 2000 (Filed as Exhibit 3.5 to Abraxas' Annual Report of
Form 10-K filed April 2, 2001).
3.6 Amended and Restated Bylaws of Abraxas. (Filed as Exhibit 3.6 to Abraxas'
Annual Report on Form 10-K filed April 5, 2002).
4.1 Specimen Common Stock Certificate of Abraxas. (Filed as Exhibit 4.1 to
the S-4 Registration Statement).
4.2 Specimen Preferred Stock Certificate of Abraxas. (Filed as Exhibit 4.2 to
Abraxas' Annual Report on Form 10-K filed on March 31, 1995).
4.3 Rights Agreement dated as of December 6, 1994 between Abraxas and First
Union National Bank of North Carolina ("FUNB"). (Filed as Exhibit 4.1 to
Abraxas' Registration Statement on Form 8-A filed on December 6, 1994).
4.4 Amendment to Rights Agreement dated as of July 14, 1997 by and between
Abraxas and American Stock Transfer & Trust Company. (Filed as Exhibit 1
to Amendment No. 1 to Abraxas' Registration Statement on Form 8-A filed
on August 20, 1997).
4.5 Second Amendment to Rights Agreement as of May 22, 1998, by and between
Abraxas and American Stock Transfer & Trust Company. (Filed as Exhibit 1
to Amendment No. 2 to Abraxas' Registration Statement on Form 8-A filed
on August 24, 1998).
4.6 Indenture dated January 23, 2003, by and among Abraxas, as Issuer; the
subsidiary Guarantors party thereto and U.S. Bank, N.A., as Trustee,
relating to Abraxas' 11-1/2 % Secured Notes Due 2007. (filed as Exhibit
4.1 to Abraxas' Current Report on Form 8-K dated February 6, 2003).
4.7 Form of 111/2% Secured Notes due 2007. (Filed as Exhibit A to Exhibit
4.6).
*10.1 Abraxas Petroleum Corporation 1984 Non-Qualified Stock Option Plan, as
amended and restated. (Filed as Exhibit 10.7 to Abraxas' Annual Report on
Form 10-K filed April 14, 1993).
*10.2 Abraxas Petroleum Corporation 1984 Incentive Stock Option Plan, as
amended and restated. (Filed as Exhibit 10.8 to Abraxas' Annual Report on
Form 10-K filed April 14, 1993).
*10.3 Abraxas Petroleum Corporation 1993 Key Contributor Stock Option Plan.
(Filed as Exhibit 10.9 to Abraxas' Annual Report on Form 10-K filed April
14, 1993).
*10.4 Abraxas Petroleum Corporation 401(k) Profit Sharing Plan. (Filed as
Exhibit 10.4 to Abraxas' Registration Statement on Form S-4, No.
333-18673, (the "1996 Exchange Offer Registration Statement")).
*10.5 Abraxas Petroleum Corporation Director Stock Option Plan. (Filed as
Exhibit 10.5 to the 1996 Exchange Offer Registration Statement).
*10.6 Abraxas Petroleum Corporation Restricted Share Plan for Directors. (Filed
as Exhibit 10.20 to Abraxas' Annual Report on Form 10-K filed on April
12, 1994).
*10.7 Abraxas Petroleum Corporation 1994 Long Term Incentive Plan. (Filed as
Exhibit 10.21 to Abraxas' Annual Report on Form 10-K filed on April 12,
1994).
52
*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 Abraxas'
Registration statement on Form S-1, Registration No. 33-66446, (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.
10.16 Common Stock Purchase Warrant dated September 1, 2000 between Jessup &
Lamont Holdings (Filed as Exhibit 10.16 to Abraxas Annual Report on Form
10-K filed on April 2, 2001).
10.17 Common Stock Purchase Warrant dated August 1, 2000 between Abraxas and
TNC, Inc. (Filed as Exhibit 10.17 to Abraxas Annual Report on Form 10-K
filed on April 2, 2001).
10.18 Common Stock Purchase Warrant dated August 1, 2000 between Abraxas and
Charles K. Butler (Filed as Exhibit 10.17 to Abraxas Annual Report on
Form 10-K filed on April 2, 2001).
10.19 Agreement of Limited Partnership of Abraxas Wamsutter L.P. dated as of
November 12, 1999 by and between Wamsutter Holdings, Inc. and TIFD III-X
Inc. (Filed as Exhibit 10.2 to Abraxas' Current Report on Form 8-K filed
November 30,1999).
10.20 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).
10.21 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).
10.22 Purchase and Sale Agreement dated November 21, 2002, by and among
Abraxas, as Seller, Primewest Gas Inc., as Purchaser, Primewest Energy
Inc., as Guarantor, Canadian Abraxas and Grey Wolf Exploration Inc., as
the Companies (Filed as Exhibit 10.1 to Abraxas' Current Report on Form
8-K/A filed December 9, 2002).
10.23 Farmout Agreement between Grey Wolf Exploration Limited and PrimeWest
Energy, Inc. (Previously filed as Exhibit 10.2 to Abraxas' Current Report
on Form 8-K/A filed on December 9, 2002).
10.24 Farmout Agreement between Grey Wolf Exploration Limited and PrimeWest
Energy, Inc. (Previously filed as Exhibit 10.3 to Abraxas' Current Report
on Form 8-K/A filed on December 9, 2002).
10.25 Loan And Security Agreement dated as of January 22, 2003, by and among
Abraxas, as Borrower, the Subsidiaries of Abraxas that are Signatories
thereto, as Guarantors, the Lenders that are Signatories thereto, as
Lenders, and Foothill Capital Corporation, as the Arranger and
Administrative Agent (Filed as Exhibit 10.5 to Abraxas' Current Report on
Form 8-K filed February 6, 2003).
10.26 Intercreditor and Subordination Agreement dated as of January 23, 2003,
by and among Foothill, in its capacity as agent (in such capacity,
together with any successor in such capacity, the "Senior Agent") for the
lenders who are from time to time parties to the Loan Agreement (the
"Senior Lenders"), U.S. Bank, N.A., a national banking association in its
capacity as trustee (in such capacity, together with any successor in
such capacity, the "Trustee") for the holders of the 11 1/2% Secured
Notes Due 2007, issued under the Indenture. (Filed as Exhibit 10.6 to
Abraxas' Current Report on Form 8-K filed February 6, 2003).
53
16.1 Letter addressing change in certifying accountant (Filed on Abraxas' Form
8-K filed on August 22, 2001).
21.1 Subsidiaries of Abraxas. (Filed as Exhibit 21.1 to Abraxas, Grey Wolf
Exploration Inc., Sandia Oil & Gas Corporation, Sandia Operating Corp.,
Wamsutter Holdings, Inc., Western Associated Energy Corporation and
Eastside Coal Company, Inc.'s Registration Statement on Form S-1, No.
333-103027).
23.1 Consent of Deloitte & Touche LLP (filed herewith).
23.2 Consent of Deloitte & Touche LLP Chartered Accountants (filed herewith).
23.3 Consent of DeGolyer and MacNaughton. (filed herewith).
23.4 Consent of McDaniel & Associates Consultants, Ltd. (filed herewith).
99.1 Certification by Chief Executive Officer pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002 (filed herewith).
99.2 Certification by Chief Financial Officer pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002 (filed herewith).
* Management Compensatory Plan or Agreement.
(b) Reports on Form 8-K
1. Current Report on Form 8-K on November 26, 2002. Other Events,
including a press release relating to Purchase and Sale agreement
relating to the sale of Canadian properties.
2. Current Report on Form 8-K/A on December 9, 2002. Other Events,
including Purchase and Sale agreement and Farmout agreements relating
to the sale of Canadian properties.
3. Current Report on Form 8-K on December 10, 2002. Other Events,
including a press release announcing exchange offer.
4. Current Report on Form 8-K on December 10, 2002. Other Events,
including a press release announcing commitment for new credit
facility.
5. Current Report on Form 8-K on December 12, 2002. Other Events,
including an amended press release announcing exchange offer.
6. Current Report on Form 8-K on January 8, 2003. Other Events, including
a press release extending exchange offer.
7. Current Report on Form 8-K on January 9, 2003. Other Events, including
a press release extending exchange offer.
8. Current Report on Form 8-K on January 10, 2003. Other Events, including
a press release extending exchange offer.
9. Current Report on Form 8-K on January 13, 2003. Other Events, including
a press release extending exchange offer.
54
10. Current Report on Form 8-K on January 14, 2003. Other Events, including
a press release extending exchange offer.
11. Current Report on Form 8-K on January 15, 2003. Other Events, including
a press release extending exchange offer.
12. Current Report on Form 8-K on January 24, 2003. Other Events, including
a press release announcing the closing of Canadian Asset Sale, New
Secured Credit Facility and completion of exchange offer and redemption
of debt.
13. Current Report on Form 8-K on February 6, 2003, Disposition of Assets
announcing the completion of the sale of the common stock of Canadian
Abraxas and Grey Wolf Exploration, Inc.; Other Event, completion of
exchange offer, new credit facility and redemption of notes; Financial
Statements and exhibits, including pro forma financial statements
giving effect of the sale of Canadian properties, exchange offer, new
credit facility and redemption of notes.
14. Current Report on Form 8-K on February 24, 2003, Regulation FD,
including press release announcing 2003 capital budget, hedge
agreements and resignation of director.
55
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: July 22, 2003
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 July 22, 2003
/s/ Chris E. Williford Exec. Vice President and
---------------------------- Treasurer (Principal Financial
Chris Williford and Accounting Officer) July 22, 2003
/s/ Craig S. Bartlett, Jr. Director July 22, 2003
----------------------------
Craig S. Bartlett, Jr.
/s/ Franklin Burke Director July 22, 2003
----------------------------
Franklin Burke
/s/ Ralph F. Cox Director July 22, 2003
----------------------------
Ralph F. Cox
/s/ James C. Phelps Director July 22, 2003
----------------------------
James C. Phelps
/s/ Joseph A. Wagda Director July 22, 2003
----------------------------
Joseph A. Wagda
56
CERTIFICATIONS
I, Robert L. G. Watson, certify that:
1. I have reviewed this annual report on Form 10-K/A of Abraxas Petroleum
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of the registrant's board of directors (or persons
performing the equivalent functions):
(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses
Date: July 22, 2003
/s/ Robert L.G. Watson
Robert L.G. Watson
Chairman of the Board, President and
Principal Executive Officer
CERTIFICATIONS
I, Chris Williford, certify that:
1. I have reviewed this annual report on Form 10-K/A of Abraxas Petroleum
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of the registrant's board of directors (or persons
performing the equivalent functions):
(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses
Date: July 22, 2003
/s/ Chris Williford
Chris Williford
Executive Vice President and
Principal Accounting Officer
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 10, 2003,
July 18, 2003, as to Note 20 and the first paragraph of "New Accounting
Pronouncements" in Note 1, (which report expresses an unqualified opinion and
includes two explanatory paragraphs referring to the subsequent events described
in Note 2 and the restatement described in Note 20), appearing in this Annual
Report on Form 10-K/A of Abraxas Petroleum Corporation for the year ended
December 31, 2002.
/s/ Deloitte & Touche LLP
San Antonio, Texas
July 18, 2003
Exhibit 23.2
Independent Auditors' Consent
We consent to the incorporation by reference in the Registration Statements No.
33-48932, 33-48934, 33-72268, 33-81416, 33-81418, 333-17375, and 333-17377 of
Abraxas Petroleum Corporation on Form S-8 of our report dated March 10, 2003 on
the financial statements of Grey Wolf Exploration Inc. (which report expresses
an unqualified opinion and includes an explanatory paragraph relating to our
previously issued report on the financial statements of Grey Wolf Exploration
Inc. which excluded differences between Canadian and United States generally
accepted accounting principles as set out in Note 12, and for U.S. readers has a
Canada-U.S. reporting difference which would require an explanatory paragraph
relating to the Company's changes in accounting policies and significant
subsequent events that have been disclosed in the financial statements),
appearing in this Annual Report on Form 10-K/A of Abraxas Petroleum Corporation
for the year ended December 31, 2002.
Calgary, Canada /s/ Deloitte & Touche LLP
July 18, 2003 Chartered Accountants
Exhibit 23.3
Consent of DeGolyer and MacNaughton
We hereby consent to the incorporation in your Annual Report on Form 10-K/A
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, 2002 on Certain Interests owned by Abraxas Petroleum
Corporation," Appraisal Report as of December 31,2001 on Certain Interest owned
by Abraxas Petroleum Corporation," and "Appraisal Report as of December 31,
2000, 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
July 22, 2003
Exhibit 23.4
Consent of McDaniel and Associates Consultants LTD.
We consent to the incorporation in your Annual Report on Form 10-K/A of the
references to McDaniel and Associates Consultants Ltd. in the "Reserves
Information" section and to the use by reference of information contained in our
Evaluation Report "Canadian Abraxas Petroleum Ltd., Evaluation of Oil & Gas
Reserves, As of January 1, 2002", dated April 3, 2002.
McDaniel & Associates Consultants LTD
Calgary, Alberta
April 3, 2002
Exhibit 99.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the amendment to the Annual Report of Abraxas Petroleum
Corporation (the "Company") on Form 10-K/A for the year ended December 31, 2002
as filed with the Securities and Exchange Commission on the date hereof (the
"Report"), I, Robert L.G. Watson, Chairman of the Board, President and Chief
Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350,
as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of
the Securities Act of 1934; and (2) The information contained in the Report
fairly presents, in all material respects, the financial condition and results
of operations of the Company.
/s/ Robert L.G. Watson
Robert L.G. Watson
Chairman of the Board, President
and Chief Executive Officer
July 22, 2003
This certification accompanies the Report pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the
Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of ss.18
of the Securities Exchange Act of 1964, as amended.
A signed original of this written statement required by Section 906 has been
provided to the Company and will be retained by the Company and furnished to the
Securities and Exchange Commission or its staff upon request.
Exhibit 99.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the amendment to the Annual Report of Abraxas Petroleum
Corporation (the "Company") on Form 10-K/A for the year ended December 31, 2002
as filed with the Securities and Exchange Commission on the date hereof (the
"Report"), I, Chris E, Williford, Executive Vice President and Chief Financial
Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of
the Securities Act of 1934; and (2) The information contained in the Report
fairly presents, in all material respects, the financial condition and results
of operations of the Company.
/s/ Chris E. Williford
Chris E. Williford
Executive Vice President and
Chief Financial Officer
July 22, 2003
This certification accompanies the Report pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the
Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of ss.18
of the Securities Exchange Act of 1964, as amended.
A signed original of this written statement required by Section 906 has been
provided to the Company and will be retained by the Company and furnished to the
Securities and Exchange Commission or its staff upon request.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Abraxas Petroleum Corporation and Subsidiaries
Independent Auditors' Reports for the years ended December 31, 2000,
2001 and 2002.............................................................F-2
Consolidated Balance Sheets at December 31, 2001 and 2002 (Restated)........F-3
Consolidated Statements of Operations for the years ended
December 31, 2000, 2001 and 2002 (Restated)...............................F-5
Consolidated Statements of Stockholders' Equity (Deficit) for the
years ended December 31, 2000, 2001 and 2002...............................F-6
Consolidated Statements of Cash Flows for the years ended
December 31, 2000, 2001 and 2002(Restated) ...............................F-8
Notes to Consolidated Financial Statements ...... ..........................F-10
Grey Wolf Exploration Inc.
Auditors' Reports for the years ended December 31, 2000,
2001 and 2002............................................................F-45
Comments by Auditors' for US readers on Canada - US reporting differences...F-46
Balance Sheets at December 31, 2002 and 2001................................F-47
Statements of Earnings and Retained Earnings for the years ended
December 31, 2002, 2001 and 2000..........................................F-48
Statements of Cash Flows for the years ended December 31, 2002,
2001 and 2000.............................................................F-49
Notes to Financial Statements...............................................F-50
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, 2002
and 2001, and the related consolidated statements of operations, stockholders'
equity (deficit), and cash flows for each of the three years in the period ended
December 31, 2002. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of the Company at December 31, 2002
and 2001, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2002 in conformity with accounting
principles generally accepted in the United States of America.
As discussed in Note 2 to the financial statements, on January 23, 2003, the
Company sold all of the outstanding common stock of two wholly owned
subsidiaries, Canadian Abraxas Petroleum Limited and Grey Wolf Exploration,
Inc., repaid certain debt, and also entered into an agreement to exchange cash,
new debt and common stock of the Company for certain other debt.
As discussed in Note 20 to the financial statements, the accompanying 2000, 2001
and 2002 financial statements have been restated.
/s/DELOITTE & TOUCHE LLP
San Antonio, Texas
March 10, 2003 (July 18, 2003, as to Note 20 and the first paragraph of "New
Accounting Pronouncements" in Note 1)
F-2
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
(As Restated, see Note 20)
--------------------------------------
December 31
--------------------------------------
2001 2002
------------------ -------------------
(Dollars in thousands)
Current assets:
Cash ................................................... $ 7,605 $ 4,882
Accounts receivable:
Joint owners ....................................... 2,785 2,215
Oil and gas production sales ....................... 4,758 7,466
Other .............................................. 504 364
------------------ -------------------
8,047 10,045
Equipment inventory .................................... 1,251 1,014
Other current assets ................................... 443 1,240
------------------ -------------------
Total current assets.................................. 17,346 17,181
Property and equipment:
Oil and gas properties, full cost method of accounting:
Proved ............................................. 486,098 521,995
Unproved, not subject to amortization .............. 10,626 7,052
Other property and equipment ......................... 67,632 44,189
------------------ -------------------
Total .......................................... 564,356 573,236
Less accumulated depreciation, depletion, and
amortization ....................................... 282,462 422,842
------------------ -------------------
Total property and equipment - net ................. 281,894 150,394
Deferred financing fees, net of accumulated amortization
of $8,668 and $10,763 at December 31, 2001 and 2002,
respectively ........................................... 3,928 5,671
Deferred income taxes...................................... - 7,820
Other assets .............................................. 448 359
------------------ -------------------
Total assets ........................................... $ 303,616 $ 181,425
================== ===================
See accompanying Notes to Consolidated Financial Statements
F-3
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (CONTINUED)
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
(As Restated, see Note 20)
--------------------------------------
December 31
--------------------------------------
2001 2002
------------------ -------------------
(Dollars in thousands)
Current liabilities:
Accounts payable .......................................... $ 10,542 $ 9,687
Joint interest oil and gas production payable ............. 3,596 2,432
Accrued interest .......................................... 6,013 6,009
Other accrued expenses .................................... 1,116 1,162
Hedge liability............................................ 658 -
Current maturities of long-term debt ...................... 415 63,500
------------------ -------------------
Total current liabilities................................ 22,340 82,790
Long-term debt ............................................... 285,184 236,943
Deferred income taxes......................................... 20,621 -
Future site restoration ..................................... 4,056 3,946
Commitments and contingencies
Stockholders' equity (deficit):
Common stock, par value $.01 per share - authorized
200,000,000 shares; issued 30,145,280 at
December 31, 2001 and 2002 ............................. 301 301
Additional paid-in capital ................................ 136,830 136,830
Receivables from stock sale................................ (97) (97)
Accumulated deficit ....................................... (151,094) (269,621)
Treasury stock, at cost, 165,883 shares.................... (964) (964)
Accumulated other comprehensive income (loss).............. (13,561) (8,703)
------------------ -------------------
Total stockholders' equity (deficit)......................... (28,585) (142,254)
------------------ -------------------
Total liabilities and stockholders' equity (deficit)...... $ 303,616 $ 181,425
================== ===================
See accompanying Notes to Consolidated Financial Statements
F-4
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(As Restated, see Note 20)
----------------------------------------------------------
Year Ended December 31
----------------------------------------------------------
2000 2001 2002
----------------------------------------------------------
(In thousands except per share data)
Revenues:
Oil and gas production revenues ......................... $ 72,973 $ 73,201 $ 50,862
Gas processing revenues.................................. 2,717 2,438 2,420
Rig revenues ............................................ 505 756 635
Other .................................................. 405 848 403
--------------------------------------------------------
76,600 77,243 54,320
Operating costs and expenses:
Lease operating and production taxes .................... 18,783 18,616 15,240
Depreciation, depletion, and amortization ............... 35,857 32,484 26,539
Proved property impairment .............................. - 2,638 115,993
Rig operations .......................................... 717 702 567
General and administrative .............................. 6,533 6,445 6,884
General and administrative (Stock-based compensation).... 2,767 (2,767) -
--------------------------------------------------------
64,657 58,118 165,223
--------------------------------------------------------
Operating income (loss)..................................... 11,943 19,125 (110,903)
Other (income) expense:
Interest income ......................................... (530) (78) (92)
Amortization of deferred financing fees ................. 2,091 2,268 2,095
Interest expense ........................................ 31,140 31,523 34,150
Financing costs.......................................... - - 967
(Gain) loss on sale of equity investment ................ (33,983) 845 -
Gain on debt extinguishment ............................. (1,773) - -
Other ................................................... 1,563 207 201
--------------------------------------------------------
(1,492) 34,765 37,321
--------------------------------------------------------
Income (loss) before income tax............................. 13,435 (15,640) (148,224)
Income tax expense (benefit):
Current ................................................. (1,233) 505 -
Deferred ................................................ 4,938 1,897 (29,697)
Minority interest in income of foreign subsidiary (2001
prior to purchase)....................................... 1,281 1,676 -
--------------------------------------------------------
Net income (loss)........................................ $ 8,449 $ (19,718) $ (118,527)
========================================================
Net income (loss) per common share - basic .............. $ 0.37 $ (0.76) $ (3.95)
=======================================================
Net income (loss) per common share - diluted............ $ 0.26 $ (0.76) $ (3.95)
========================================================
See Accompanying Notes to Consolidated Financial Statements
F-5
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)
(In thousands except share amounts)
Accumulated
Common Stock Treasury Stock Additional Other Receivables
------------------------------------ Paid-In Accumulated Comprehensive From
Shares Amount Shares Amount Capital Deficit Income (Loss) Stock Sale Total
---------------------------------------------------------------------------------------------------
Balance at January 1, 2000.. 22,747,099 $ 227 152,083 $ (1,071) $ 127,562 $ (139,825) $ 3,602 $ (97) $(9,602)
Comprehensive income
(loss):
Net income............... - - - - - 8,449 - - 8,449
Other comprehensive
income:
Foreign currency
translation
adjustment ........ - - - - - (8,401) - (8,401)
------------
Comprehensive income (loss) - - - - - - - - 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) $ (97) $(6,600)
Comprehensive income
(loss):
Net loss................. - - - - - (19,718) - - (19,718)
Other comprehensive
income:
Hedge loss........... - - - - - - (566) - (566)
Foreign currency
translation
adjustment ........ - - - - - - (8,196) - (8,196)
------------
Comprehensive income (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
Old 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) $ (97) $(28,585)
----------------------------------------------------------------------------------------------------
(continued)
F-6
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)(continued)
(In thousands except share amounts)
Accumulated
Common Stock Treasury Stock Additional Other Receivables
------------------------------------ Paid-In Accumulated Comprehensive From
Shares Amount Shares Amount Capital Deficit Income (Loss) Stock Sale Total
---------------------------------------------------------------------------------------------------
Balance at January 1, 2001.. 30,145,280 $301 165,883 $ (964) $ 136,830 $ (151,094) $(13,561) $ (97) $(28,585)
Comprehensive income
(loss):
Net loss................. - - - - - (118,527) - - (118,527)
Other comprehensive
income:
Hedge income......... - - - - - - 566 566
Foreign currency
translation
adjustment ........ - - - - - - 4,292 - 4,292
------------
Comprehensive income (loss) - - - - - - - - (113,669)
---------------------------------------------------------------------------------------------------
Balance at December 31, 2002 30,145,280 $ 301 165,883 $ (964) $ 136,830 $ (269,621) $ (8,703) (97) $(142,254)
===================================================================================================
See accompanying Notes to Consolidated Financial Statements.
F-7
ABRAXAS PETROLEUM CORPORATOIN AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(As Restated, see Note 20)
----------------------------------------------------------
Year Ended December 31
----------------------------------------------------------
2000 2001 2002
------------------ ------------------ -------------------
(In thousands)
Operating Activities
Net income (loss) ........................ $ 8,449 $ (19,718) $ (118,527)
Adjustments to reconcile net income
(loss) to net cash provided by operating activities:
Minority interest in income of
foreign subsidiary................. 1,281 1,676 -
Gain on extinguishment of debt.... (1,773) - -
(Gain) loss on sale of equity
investment......................... (33,983) 845 -
Depreciation, depletion, and
amortization ...................... 35,857 32,484 26,539
Proved property impairment .......... - 2,638 115,993
Deferred income tax expense.......... 4,938 1,897 (29,697)
Amortization of deferred financing
fees............................... 2,091 2,268 2,095
Stock-based compensation ............ 2,767 (2,767) -
Issuance of common stock and
warrants for compensation ......... 265 - -
Changes in operating assets and
liabilities:
Accounts receivable ............. (7,036) 12,693 (2,247)
Equipment inventory ............. (538) (76) 201
Other .......................... (1,839) (106) 126
Accounts payable ................ 11,318 (14,848) (2,775)
Accrued expenses ................ (425) (723) (44)
------------------ ------------------ -------------------
Net cash provided by (used) in operations. 21,372 16,263 (8,336)
Investing Activities
Capital expenditures, including purchases
and development of properties ......... (74,412) (57,056) (38,912)
Proceeds from sale of oil and gas
properties............................. 21,157 28,938 33,876
Acquisition of minority interest.......... - (2,679) -
Proceeds from sale of equity investment .. 34,482 - -
------------------ ------------------ -------------------
Net cash used in investing activities..... (18,773) (30,797) (5,036)
F-8
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
Year Ended December 31
----------------------------------------------------------
2000 2001 2002
------------------ ------------------ ------------------
(In thousands)
Financing Activities
Purchase of treasury stock, net ............ $ (78) $ - $ -
Proceeds from issuance of common stock..... - 16 -
Proceeds from long-term borrowings ......... 6,400 29,995 20,551
Payments on long-term borrowings ........... (10,163) (9,326) (8,176)
Deferred financing fees .................... 23 - (1,539)
------------------ ------------------ -------------------
Net cash (used) provided by financing
activities............................... (3,818) 20,685 10,836
------------------ ------------------- -------------------
Increase (decrease) in cash ................ (1,219) 6,151 (2,536)
------------------ -------------------- -------------------
Effect of exchange rate changes on cash..... (576) (550) (187)
------------------ -------------------- -------------------
Increase (decrease) in cash ................ (1,795) 5,601 (2,723)
Cash at beginning of year .................. 3,799 2,004 7,605
------------------ -------------------- -------------------
Cash at end of year......................... $ 2,004 $ 7,605 $ 4,882
================== ==================== ===================
Supplemental Disclosures
Supplemental disclosures of cash flow
information:
Interest paid ......................... $ 33,004 $ 31,752 $ 34,154
================== ================== ===================
Taxes paid............................. $ - $ 505 $ -
================== ================== ===================
Supplemental schedule of noncash investing and financing activities:
In May 2001 the Company issued 3,386,488 shares of common
stock upon the expiration of the CVRs issued in connection
with the December 1999 exchange. 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 Old Grey Wolf. See Note 4.
Decrease in oil and gas properties and other assets... $ (2,925)
=====================
Decrease in deferred income tax liability............. $ 1,091
=====================
Increase in stockholders equity....................... $ (9,246)
=====================
Decrease in minority interest in foreign subsidiary... $ 13,759
=====================
See accompanying Notes to Consolidated Financial Statements.
F-9
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2000, 2001 and 2002
1. Organization and Significant Accounting Policies
Nature of Operations
Abraxas Petroleum Corporation (the "Company" or "Abraxas") is an
independent energy company engaged in the exploration for and the acquisition,
development, and production of crude oil and natural gas primarily along the
Texas Gulf Coast, in the Permian Basin of western Texas and in western Canada.
The consolidated financial statements include the accounts of the Company and
its wholly owned subsidiaries. All intercompany accounts and transactions have
been eliminated in consolidation.
The consolidated financial statements include the accounts of the Company,
and its wholly owned foreign 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.
In January 2003, the Company sold all of the common stock of Canadian
Abraxas and Grey Wolf. Certain oil and gas properties were retained and
transferred into a new wholly owned subsidiary that retained the name Grey Wolf
Exploration, Inc. ("New Grey Wolf").
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 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
F-10
of cost or estimated fair value of unproved properties included in the costs
being amortized, if any, less related income taxes. Excess costs are charged to
proved property impairment expense. No gain or loss is recognized upon sale or
disposition of crude oil and natural gas properties, except in unusual
circumstances.
Unproved properties represent costs associated with properties on which the
Company is performing exploration activities or intends to commence such
activities. These costs are reviewed periodically for possible impairments or
reduction in value based on geological and geophysical data. If a reduction in
value has occurred, costs being amortized are increased. The Company believes
that the unproved properties will be substantially evaluated in six to
thirty-six months and it will begin to amortize these costs at such time. During
2000, 2001 and 2002 the Company capitalized $589,000, $164,000 and $152,000 of
interest expense respectively, based on the cost of major development projects
in progress.
Other Property and Equipment
Other property and equipment are recorded on the basis of cost.
Depreciation of other property and equipment is provided over the estimated
useful lives using the straight-line method. Major renewals and betterments are
recorded as additions to the property and equipment accounts. Repairs that do
not improve or extend the useful lives of assets are expensed.
Hedging
The Company periodically enters into agreements to hedge the risk of future
crude oil and natural gas price fluctuations. Such agreements, 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.
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
F-11
the following weighted-average assumptions for 2000, 2001 and 2002, risk-free
interest rates of 6.25%, 3.50% and 1.5%, respectively; dividend yields of -0-%;
volatility factors of the expected market price of the Company's common stock of
..916, .35 and .35, respectively; and a weighted-average expected life of the
option of ten years.
The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions including the expected stock price
volatility. Because the Company's employee stock options have characteristics
significantly different from those of traded options, and because changes in the
subjective input assumptions can materially affect the fair value estimate, in
management's opinion, the existing models do not necessarily provide a reliable
single measure of the fair value of its employee stock options.
For purposes of pro forma disclosures, the estimated fair value of the
options is amortized to expense over the options' vesting period. The Company's
pro forma information follows:
Year Ended December 31
-------------------------------------------------
2000 2001 2002
-------------- -------------- -------------
Net income (loss) as reported $ 8,449 $ (19,718) $ (118,527)
Add: Stock-based employee compensation expense
included in reported net income, net of
related tax effects 2,767 (2,767) -
Deduct: Total stock-based employee compensation
expense determined under fair value based
method for all awards, net of related tax
effects (1,127) (1,284) (670)
-------------- -------------- ------------
Pro forma net income (loss) $ 10,089 $ (23,769) $ (119,197)
============== ============== ============
Earnings (loss) per share:
Basic - as reported $ 0.37 $ (0.76) $ (3.95)
============== ============== ============
Basic - pro forma $ 0.45 $ (0.92) $ (3.98)
============== ============== ============
Diluted - as reported $ 0.26 $ (0.76) $ (3.95)
============== ============== ============
Diluted - pro forma $ 0.31 $ (0.92) $ (3.98)
============== ============== ============
Foreign Currency Translation
The functional currency for Canadian Abraxas and Grey Wolf (Old and New) is
the Canadian dollar ($CDN). The Company translates the functional currency into
U.S. dollars ($US) based on the current exchange rate at the end of the period
for the balance sheet and a weighted average rate for the period on the
statement of operations. Translation adjustments are reflected as Accumulated
Other Comprehensive Income (Loss) in Stockholders' Equity (Deficit). See Note 2
for Canadian subsidiaries sold in 2003. A portion of the translation account
will be eliminated at the closing of the sale in 2003.
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 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.
F-12
Revenue Recognition
The Company recognizes crude oil and natural gas revenue from its interest
in producing wells as crude oil and natural gas is sold from those wells, net of
royalties. Revenue from the processing of natural gas is recognized in the
period the service is performed. The Company utilizes the sales method to
account for gas production volume imbalances. Under this method, income is
recorded based on the Company's net revenue interest in production taken for
delivery. The Company had no material gas imbalances.
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.
SFAS No. 141 and 142 clarify that more assets should be distinguished and
classified between tangible and intangible. The Company did not change or
reclassify contractual mineral rights included in oil and gas properties on the
balance sheet upon adoption of SFAS No. 142. The Company believes the treatment
of such mineral rights as tangible assets under the full cost method of
accounting for crude oil and natural gas properties is appropriate. An issue has
arisen regarding whether contractual mineral rights should be classified as
intangible rather that tangible assets. If it is determined that
reclassification is necessary, the Company's oil and gas properties would be
reduced by $868,000 and $3.1 million and intangible assets would have increased
by a like amount at December 31, 2001 and 2002, respectively, representing cost
incurred from the effective date of June 30, 2001. The provisions of SFAS No.
141 and 142 impact only the balance sheet and associated footnote disclosure,
and reclassifications necessary would not impact the Company's cash flows or
results of operations.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 addresses accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. SFAS No. 143 is effective for us January 1,
2003. SFAS No. 143 requires that the fair value of a liability for an asset's
retirement obligation be recorded in the period in which it is incurred and the
corresponding cost capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its then present value each
period, and the capitalized cost is depreciated over the useful life of the
related asset. If the liability is settled for an amount other than the recorded
amount, a gain or loss is recognized. For all periods presented, we have
included estimated future costs of abandonment and dismantlement in our full
cost amortization base and amortize these costs as a component of our depletion
expense.
We have completed our assessment of SFAS No. 143 and based on our
estimates, we do not expect the statement to have a material effect on our
financial position, results of operations and cash flows for future periods. At
January 1, 2003 , we estimate that the present value of our future Asset
Retirement Obligation ("ARO") for natural gas and oil property and related
equipment is approximately $657,000. We estimate that the cumulative effect to
the adoption of SFAS No. 143 and the change in the accounting principal will be
a loss of $285,000, which will be recorded in the first quarter of 2003. The
impact on each of the prior periods was not material.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Asset." Effective January 1, 2002, the
Company adopted SFAS No. 144. SFAS No. 144 retains the requirement to recognize
F-13
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 discontinued
operations be recognized in the period that the losses are incurred rather than
as of the measurement date. This new standard had no impact on the Company's
consolidated financial statements for the year ended December 31, 2002.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB No. 4, 44,
and 64, Amendments of FASB Statement No. 13 and Technical Corrections." SFAS No.
145 clarifies guidance related to the reporting of gains and losses from
extinguishment of debt and resolves inconsistencies related to the required
accounting treatment of certain lease modifications. SFAS No. 145 also amends
other existing pronouncements to make various technical corrections, clarify
meanings or describe their applicability under changed conditions. The
provisions relating to the reporting of gains and losses from extinguishment of
debt become effective for us beginning January 1, 2003. All other provisions of
this standard were effective for the Company as of May 15, 2002 and did not have
an impact on the Company's financial condition or results of operations. Upon
issuance of our restated financial statements, see Note 20, the Company has
reclassified the gain on the early extinguishment of debt in 2000 from an
extraordinary item to other income. This reclassification did not affect net
income for the year ended December 31, 2000.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS No. 146 requires costs
associated with exit of disposal activities to be recognized when they are
incurred rather than at the date of commitment to an exit or disposal plan. SFAS
No. 146 is effective for us beginning January 1, 2003. The Company is currently
evaluating the impact the standard will have on its results of operations and
financial condition.
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-based
Compensation--Transition and Disclosure, an amendment of FASB Statement No.
123," which amends SFAS No. 123 to provide alternative methods of transition for
a voluntary change to the fair value based method of accounting for stock-based
employee compensation. It also amends the disclosure provisions of SFAS No. 123
to require prominent disclosure in both annual and interim financial statements
about the method of accounting for stock-based employee compensation and the
effect of the method used on reported results. The provisions of SFAS No. 148
are effective for annual financial statements for fiscal years ending after
December 15, 2002, and for financial reports containing condensed financial
statements for interim periods beginning after December 15, 2002. The Company
will continue to use APB No. 25 to account for stock based compensation, while
providing the disclosures required by SFAS 123 as amended by SFAS 148.
Reclassifications
Certain prior years balances have been reclassified for comparative
purposes.
2. Recent Events
Exchange Offer. On January 23, 2003, the Company completed an exchange
offer, pursuant to which it offered to exchange cash and securities for all of
the outstanding 11 1/2% Senior Secured Notes due 2004, Series A ("Second Lien
Notes") and 11 1/2% Senior Notes due 2004, Series D, ("Old Notes") issued by
Abraxas and Canadian Abraxas. In exchange for each $1,000 principal amount of
such notes tendered in the exchange offer, tendering note holders received:
o cash in the amount of $264;
o an 11 1/2% Secured Note due 2007, Series A, ("New Notes") with a
principal amount equal to $610; and
o 31.36 shares of Abraxas common stock.
At the time the exchange offer was made, there were approximately $190.2
million of the Second Lien Notes and $801,000 of the Old Notes outstanding - see
Note 3. Holders of approximately 94% of the aggregate outstanding principal
amount of the Second Lien Notes and Old Notes tendered their notes for exchange
in the offer. Pursuant to the procedures for redemption under the applicable
indenture provisions, the remaining 6% of the aggregate outstanding principal
amount of the Second Lien Notes and Old Notes were redeemed at 100% of the
principal amount plus accrued and unpaid interest, for approximately $11.5
million ($11.1 million in principal and $0.4 million in interest). The
indentures for the Second Lien Notes and Old Notes have been duly discharged. In
connection with the exchange offer, Abraxas made cash payments of approximately
$47.5 million and issued approximately $109.7 million in principal amount of New
Notes and 5,642,699 shares of Abraxas common stock. Fees and expenses incurred
in connection with the exchange offer were approximately $3.8 million ($967,000
was charged to expense in 2002 and is included in financing costs in the
accompanying statement of operations). The balance will be charged to expense in
2003 as the cost are incurred.
F-14
New Notes. The new notes will accrue interest from the date of issuance, at
a fixed annual rate of 11 1/2%, payable in cash semi-annually on each May 1 and
November 1, commencing May 1, 2003, provided that, if the Company fails, or are
not permitted pursuant to the new senior secured credit agreement or the
intercreditor agreement between the trustee under the indenture for the New
Notes and the lenders under the new senior secured credit agreement, to make
such cash interest payments in full, the Company will pay such unpaid interest
in kind by the issuance of additional notes with a principal amount equal to the
amount of accrued and unpaid cash interest on the notes plus an additional 1%
accrued interest for the applicable period. Upon an event of default, interest
will accrue at an annual rate of 16.5%. The New Notes are guaranteed by all of
Abraxas' current subsidiaries, Sandia Oil & Gas Corp., Sandia Operating Corp.,
Wamsutter Holdings, Inc., Western Associated Energy Corporation, Eastside Coal
Company, Inc., and New Grey Wolf, and will be guaranteed by all of Abraxas'
future subsidiaries. The New Notes are secured by a second lien or charge on all
of the Company's current and future assets, including, but not limited to, its
crude oil and natural gas properties.
Redemption of First Lien Notes. On January 24, 2003, the Company completed
the redemption of 100% of our outstanding 12?% Senior Secured Notes, Series A,
("First Lien Notes") - see Note 4, with approximately $66.4 million of the
proceeds from the sale of Canadian Abraxas and Old Grey Wolf. Prior to the
redemption, the Company had $63.5 million of its First Lien Notes outstanding.
Under the terms of the indenture for the First Lien Notes the Company had the
right to redeem the First Lien Notes at 100% of the outstanding principal amount
of the notes, plus accrued and unpaid interest to the date of redemption, and to
discharge the indenture upon call of the First Lien Notes for redemption and
deposit of the redemption funds with the trustee. The Company exercised these
rights on January 23, 2003 and upon the discharge of the indenture, the trustee
released the collateral securing the Company's obligations under the First Lien
Notes.
New Senior Secured Credit Agreement. Contemporaneously with the closing of
the exchange offer and the sale of Canadian Abraxas and Old Grey Wolf, on
January 23, 2003, Abraxas entered into a new senior secured credit agreement
providing a term loan facility of $4.2 million and a revolving credit facility
with a maximum borrowing base of up to $50 million. Subject to earlier
termination on the occurrence of events of default or other events, the stated
maturity date for both the term loan facility and the revolving credit facility
is January 22, 2006. In the event of an early termination, we will be required
to pay a prepayment premium, except in the limited circumstances described in
the new senior secured credit agreement. Outstanding amounts under both
facilities bear interest at the prime rate announced by Wells Fargo Bank, N.A.
plus 4.5%. Any amounts in default under the term loan facility will accrue
interest at an additional 4%. At no time will the amounts outstanding under the
new senior secured credit agreement bear interest at a rate less than 9%.
Term Loan Facility. Abraxas has borrowed $4.2 million pursuant to a term
loan facility at January 23, 2003, all of which was used to make cash payments
in connection with the financial restructuring. Accrued interest under the term
loan facility will be capitalized and added to the principal amount of the term
loan facility until maturity.
Revolving Credit Facility. Lenders under the new senior secured credit
agreement have provided a revolving credit facility to Abraxas with a maximum
borrowing base of up to $50 million. Our current borrowing base under the
revolving credit facility is $49.9 million, subject to adjustments based on
periodic calculations and mandatory prepayments under the senior secured credit
agreement. Portions of accrued interest under the revolving credit facility may
be capitalized and added to the principal amount of the revolving credit
facility. At January 23, 2003, the Company has borrowed $42.5 million under the
revolving credit facility, all of which was used to make cash payments in
connection with the financial restructuring. The Company plans to use the
remaining borrowing availability under the new senior secured credit agreement
to fund its operations, including capital expenditures.
Covenants. Under the new senior secured credit agreement, Abraxas is
subject to customary covenants and reporting requirements. Certain financial
covenants require Abraxas to maintain minimum levels of consolidated EBITDA (as
defined in the new senior secured credit agreement), minimum ratios of
consolidated EBITDA to cash interest expense and a limitation on annual capital
expenditures. In addition, at the end of each fiscal quarter, if the aggregate
amount of our cash and cash equivalents exceeds $2.0 million, the Company is
required to repay the loans under the new senior secured credit agreement in an
amount equal to such excess. The new senior secured credit agreement also
requires the Company to enter into hedging agreements on not less than 25% or
more than 75% of our projected oil and gas production. We are also required to
establish deposit accounts at financial institutions acceptable to the lenders
and we are required to direct our customers to make all payments into these
accounts. The amounts in these accounts will be transferred to the lenders upon
the occurrence and during the continuance of an event of default under the new
senior secured credit agreement.
In addition to the foregoing and other customary covenants, the new senior
secured credit agreement contains a number of covenants that, among other
things, restrict the Company's ability to:
o incur additional indebtedness;
o create or permit to be created any liens on any of our properties;
F-15
o enter into any change of control transactions;
o dispose of our assets;
o change our name or the nature of our business;
o make any guarantees with respect to the obligations of third
parties;
o enter into any forward sales contracts;
o make any payments in connection with distributions, dividends or
redemptions relating to our outstanding securities, or
o make investments or incur liabilities.
Guarantees. The obligations of Abraxas under the new senior secured credit
agreement are guaranteed by Sandia Oil & Gas, Sandia Operating, Wamsutter, New
Grey Wolf, Western Associated Energy and Eastside Coal. Obligations under the
new senior secured credit agreement are secured by a first lien security
interest in substantially all of Abraxas' and the guarantors' assets, including
all crude oil and natural gas properties.
Events of Default. The new senior credit 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 our financial condition.
Sale of Stock of Canadian Abraxas and Old Grey Wolf. Contemporaneously with
the closing of the exchange offer, on January 23, 2003, Abraxas completed the
sale to a wholly owned subsidiary of PrimeWest Energy Inc. of all of the
outstanding capital stock of Canadian Abraxas and Old Grey Wolf for
approximately $138 million before net adjustments of $3.4 million. The aggregate
sales price for the shares was as follows:
Number of Shares Sales Price
------------------------- --------------------------
Canadian Abraxas 5,751 common shares $68 million
Old Grey Wolf 12,804,628 common shares $70 million
--------------------------
Total Sales Price: $138 million
==========================
After sales price adjustments and related costs and expenses of
approximately $5.9 million were made, the sales price realized for the sale of
Canadian Abraxas and Old Grey Wolf was $132.1 .million. Upon consummation of the
sale, Old Grey Wolf repaid the then current outstanding indebtedness under its
credit agreement with Mirant Canada Energy Capital, Ltd. ("Grey Wolf Facility")
in the amount of $46.3 million - see Note 3, which reduced the net proceeds from
the sale by a corresponding amount. The net cash proceeds from the sale were
$85.8 million, all of which has been utilized in connection with the financial
restructuring. The Company estimates a gain on the sale of Canadian Abraxas and
Old Grey Wolf of approximately $69 million at the time of closing in 2003.
Under the terms of the agreement with PrimeWest, Abraxas has retained
certain oil and gas properties formerly held by Canadian Abraxas and Old Grey
Wolf, including all of Canadian Abraxas' and Old Grey Wolf's undeveloped acreage
existing at the time of the sale, which includes all of our interests in the
Ladyfern area. These assets have been contributed to New Grey Wolf. Portions of
this undeveloped acreage will be developed by PrimeWest and New Grey Wolf under
a farmout arrangement. Under the farmout arrangements, PrimeWest has agreed to
participate in the development of certain lands of New Grey Wolf in the Caroline
and Pouce Coupe areas of Alberta. PrimeWest has the right to earn a 60% interest
in certain wells if it bears 100% of the expense of drilling such wells. In
addition, New Grey Wolf and PrimeWest will have an area of mutual interest in
respect of the lands surrounding the Caroline area where each party will be
entitled to participate in the acquisition of the other, with New Grey Wolf
participating with a 40% interest and PrimeWest participating with a 60%
interest.
The following presents the summarized results of operations for the years
ended December 31, 2000, 2001, and 2002, for the Canadian properties which were
not retained after the transaction in January 2003.
F-16
Year ended December 31,
2000 2001 2002
-------- -------- --------
Total revenue .............................. $ 43,714 $ 41,468 $ 32,013
======== ======== ========
Loss from operations before income tax ..... (1,707) (102) (87,378)
Income tax expense (benefit) ............... 272 1,897 (29,697)
Minority interest in income ................ (1,281) (1,676) --
-------- -------- --------
Loss from operations ....................... $ (3,260) $ (3,675) $(57,681)
======== ======== ========
Assets and liabilities related to the Canadian properties which were
not retained after the January 2003 transaction:
December 31,
2002
-------------
Assets:
Cash........................................ $ 4,325
Accounts receivable......................... 4,016
Net property and equipment.................. 54,468
Other....................................... 11,438
------------
$ 74,247
============
Liabilities:
Accounts payable and accrued liabilities.... $ 7,320
Long-tern debt.............................. 45,964
Other....................................... 3,413
------------
$ 56,697
============
Included in the loss from operations shown above are interest expense of
$8.3 million, $7.6 million, and $9.5 million, and general and administrative
expense of $1.7 million, $1.5 million, and $1.7 million for the years ended
December 31, 2000, 2001 and 2002, respectively. The interest expense represents
the amounts relating to an Old Grey Wolf senior credit facility which was repaid
in conjunction with the transactions described above and the amounts related to
the balance of certain noted (approximately $52.6 million) which had
historically been reflected by Canadian Abraxas. At the time of the subsidiary
sale, the balance of the outstanding notes were transferred to the parent and
subject to the financial restructuring described in Note 3. The general and
administrative expense of the Canadian subsidiaries above were determined by
considering the on-going general and administrative cost associated with the
Canadian properties retained by the Company.
3. Long-Term Debt
As described in Note 2, the First Lien Notes were redeemed in January 2003.
The Old Notes and the Second Lien Notes were either redeemed or exchanged for
cash, common stock and New Notes in January 2003. Additionally, the 9.5% Mirant
Canada Energy Capital, Ltd. credit facility, with a balance outstanding at
December 31, 2002 of $45.9 million, was repaid in connection with the sale of
the common stock of Old Grey Wolf in January 2003.
The following is a brief description of the Company's debt as of December
31, 2002. The pro forma unaudited information reflects the impact of the
financial restructuring transactions - see Note 2.
Long-term debt consists of the following:
Pro forma
December 31,
2002 (a)
December 31 (unaudited)
-------------------------------------------------
2001 2002
-------------------------------------------------
(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 -
F-17
11.5% Second Lien Notes due 2004 ("Second Lien Notes")............. 190,178 190,178 -
9.5% Senior Credit Facility ("Grey Wolf Facility") providing for
borrowings up to approximately US $96 million (CDN $150
million). Secured by the assets of Old Grey Wolf and
non-recourse to Abraxas....................................... 22,944 45,964 -
11.5% Secured Notes due 2007 ("New Notes") - January 2003.......... - - 128,600
New Senior Secured Credit Agreement - January 2003................. - - 46,700
Production Payment ............................................... 8,176 - -
-------------------------------------------------
285,599 300,443 175,300
Less current maturities ........................................... 415 63,500 -
-------------------------------------------------
$ 285,184 $ 236,943 $ 175,300
=================================================
(a) After transactions described in Note 2, for financial reporting purposes,
the New Notes will be reflected at the carrying value of the Second Lien Notes
and Old Notes prior to the exchange of $191.0 million, net of the cash offered
in the exchange of $47.5 million and net of the fair market value related to
equity of $3.8 million offered in the exchange. In conjunction with the
financial restructuring transaction, Abraxas paid cash of $11.5 million ($11.1
million in principal and $0.4 million in interest) to redeem certain of the
outstanding old debt and accrued interest. The result of all of these items will
be a remaining carrying value of the New Notes of $128.6 million. The face
amount of the New Notes is $109.7 million. See Note 2 for terms and conditions
of the New Notes and the New Senior Secured Credit Agreement.
Old Notes. 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.
First Lien Notes. Interest on the First Lien Notes is payable semi-annually
in arrears on March 15 and September 15 of each year at the rate of 12.875% per
annum.
Second Lien Notes. Interest on the Second Lien Notes is payable
semi-annually in arrears on May 1 and November 1, commencing May 1, 2000.
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 had an aggregate total availability of up to $50 million at
15% interest. The Production Payment related to a portion of the production from
several natural gas wells in South Texas. The Company reacquired the Production
Payment in June 2002, for approximately $6.8 million.
Early Debt Extinguishment
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 initially
reflected as a gain. Upon reissuance of our financial statements, see Note 20,
the Company has reclassified this gain from an extraordinary item to other
income. This reclassification did not affect net income for the year ended
December 31, 2000.
4. Acquisitions and Divestitures
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 $112,700 for the year ended December 31, 2000.
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
F-18
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.
Acquisition of Minority Interest in Old Grey Wolf
In September 2001, the Company completed a tender offer for the minority
interest in Old Grey Wolf, acquiring the approximately 52% of capital stock that
was not previously owned by the Company. The Company issued 3,990,565 common
shares and 588,916 stock options, valued together at approximately $9.2 million.
Additionally, the Company incurred direct costs of approximately $2.7 million
related to the acquisition. The elimination of the minority interest through an
acquisition at a purchase price less than Old Grey Wolf's book value in the
Company's consolidated financial statements had the effect of reducing the
property and other assets balances by $2.9 million and deferred income taxes by
$1.1 million.
The Company sold all of the common stock in Old Grey Wolf in January 2003 -
see Note 2.
5. Property and Equipment
The major components of property and equipment, at cost, are as
follows:
Estimated
Useful December 31,
Life 2001 2002
-------- -------- ---------
Years (In thousands)
Land, buildings, and improvements .......... 15 $ 318 $ 331
Crude oil and natural gas properties ....... - 496,724 529,047
Natural Gas Processing ..................... 18 63,964 38,735
Equipment and other ........................ 7 3,350 5,123
-------- --------
$564,356 $573,236
======== ========
6. Stockholders' Equity
Common Stock
See Note 2 - Recent Events for common stock issued in January 2003 as part
of an exchange offer.
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 an 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, 2001 and 2002, the Company did
not purchase any shares of its common stock for treasury stock.
F-19
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 Old Grey Wolf option holders in connection with the
acquisition of the minority interest in Old Grey Wolf in September 2001 (see
Note 5), and for the re-issuance of outstanding options granted under the
Abraxas Petroleum Corporation 2000 Long Term Incentive Plan, which was
terminated in 2001. The options were re-issued at the same exercise price and
term as the original issuances.
The Company's various stock option plans have authorized the grant of
options to management, employees and directors for up to approximately 5.7
million shares of the Company's common stock. All options granted have ten year
terms and vest and become fully exercisable over three to four years of
continued service at 25% to 33% on each anniversary date. At December 31, 2002
approximately 2.2 million options remain available for grant.
A summary of the Company's stock option activity, and related
information for the years ended December 31, follows:
----------------------------- ------------------------------------------------------------
Weighted-Average Weighted-Average Weighted-Average
Options Exercise Price Options Exercise Price Options Exercise Price
(000s) (000s) (1) (000s)
---------- ------------------ ---------- ------------------ --------- ------------------
Outstanding-beginning of
year ................... 1,890 $ 1.82 4,042 $ 3.37 4,942 $ 3.28
Granted ................... 2,240 4.62 918 2.81 521 0.68
Exercised ................. - - (8) 1.95 - -
Forfeited/Expired ......... (88) 1.89 (10) 1.79 (2,158) 4.84
---------- ---------- ---------
Outstanding-end of year ... 4,042 $ 3.37 4,942 $ 3.28 3,305 $ 1.85
========== ========== =========
Exercisable at end of year 1,067 $ 1.99 2,259 $ 2.65 2,136 $ 1.91
========== ========== =========
Weighted-average fair
value of options
granted during the year $ 1.21 $ 1.19 $ 0.63
(1) In September 2001, the Abraxas Petroleum Corporation 2000 Long Term
Incentive Plan was terminated, and options granted under the plan were
reissued under the Abraxas Petroleum Corporation 1994 Long Term
Incentive Plan at the same option price and term.
The following table represents the range of option prices and the weighted
average remaining life of outstanding options as of December 31, 2002:
Options outstanding Exercisable
----------------------------------------------- --------------------------------------
Weighted Weighted
average average
Number remaining exercise Number Weighted average
Exercise price outstanding life price exercisable exercise price
--------------------- ------------------ --------------- ------------ ---------------- ---------------------
$0.50 - 0.97 795,000 8.8 $ 0.77 300,000 $ 0.97
$1.22 - 1.85 688,996 6.9 1.46 336,895 1.43
$2.01 - 2.21 1,507,494 4.5 2.08 1,394,107 2.07
$3.00 - 3.71 79,812 6.5 3.11 43,609 3.17
$4.13 - 4.83 234,035 8.1 4.82 61,538 4.78
F-20
Stock Awards
In addition to stock options granted under the plans described above, the
1994 Long-Term Incentive Plan also provides for the right to receive
compensation in cash, awards of common stock, or a combination thereof. There
were no awards in 2000, 2001 or 2002.
The Company also has adopted the Restricted Share Plan for Directors which
provides for awards of common stock to non-employee directors of the Company who
did not, within the year immediately preceding the determination of the
director's eligibility, receive any award under any other plan of the Company.
In 2000, the Company made direct awards of common stock of 12,753 shares, at
weighted average fair value $0.94 per share. The Company recorded compensation
expense of $11,900 for the year ended December 31, 2000. There were no direct
awards of common stock in 2001 or 2002.
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, 2002, the Company has approximately 6.4 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
--------------------------
2001 2002
------------- ------------
(In thousands)
Deferred tax liabilities:
U.S. full cost pool ..................................................... $ 2,714 $ -
Canadian full cost pool.................................................. 24,809 -
------------- ------------
Total deferred tax liabilities ............................................ 27,523 -
Deferred tax assets:
U.S. full cost pool...................................................... - 2,168
Canadian full cost pool.................................................. - 9,787
Depletion ............................................................... 2,035 2,778
Net operating losses ("NOL")............................................ 42,264 58,811
Investment in foreign subsidiaries....................................... - 32,038
Other ................................................................... 2,273 1,364
------------- ------------
Total deferred tax assets ................................................. 46,572 106,946
Valuation allowance for deferred tax assets ............................... (39,670) (99,126)
------------- ------------
Net deferred tax assets ................................................... 6,902 7,820
------------- ------------
Net deferred tax liabilities (assets) ..................................... $ 20,621 $ (7,820)
============= ============
F-21
Significant components of the provision (benefit) for income taxes are
as follows:
2000 2001 2002
------------ ----------- ----------
Current:
Federal..........................................................$ - $ 505 $ -
Foreign ......................................................... (1,233) - -
------------ ----------- ----------
$ (1,233) $ 505 $ -
============ =========== ==========
Deferred:
Federal .........................................................$ 3,433 $ - $ -
Foreign ......................................................... 1,505 1,897 29,697
------------ ----------- ----------
$ 4,938 $ 1,897 $ 29,697
============ =========== ==========
At December 31, 2002 the Company had, subject to the limitation discussed
below, $166.7 million of net operating loss carryforwards for U.S. tax purposes.
These loss carryforwards will expire from 2003 through 2022 if not utilized. At
December 31, 2002, the Company had approximately US $1.0 million of net
operating loss carryforwards for Canadian tax purposes. These carryforwards will
expire from 2003 through 2009 if not utilized. In connection with the January
2003 transactions described in Note 2, certain of the loss carryforward may be
utilized.
At December 31, 2002, the Company was no longer permanently reinvested with
respect to its foreign subsidiaries, see Note 2. As a result, the Company
recorded net deferred tax assets of $32.0 million related to its investment in
foreign subsidiaries, offset by an equivalent valuation allowance due to
uncertainties as to the future utilization of these amounts.
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 $3.2 million 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 $6.6 million 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 4. 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 $31.0
million.
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 $39.7 million and $99.1 million for deferred tax assets
at December 31, 2001 and 2002, respectively.
The reconciliation of income tax computed at the U.S. federal statutory tax
rates to income tax expense is:
December 31
---------------- -----------------------------------
2000 2001 2002
---------------- ----------------- -----------------
(In thousands)
Tax (expense) benefit at U.S.
statutory rates (35%) .............. $ (3,965) $ 5,318 $ 51,878
F-22
(Increase) decrease in deferred tax
asset valuation allowance .......... 1,371 (4,907) (59,456)
NOL utilization - gain on debt........ (603) - -
Write-down of non-tax basis assets.... - (2,194) (7,009)
Higher effective rate of foreign 7,349
operations.......................... (1,098) (136)
Percentage depletion ................. 363 596 683
Investment in foreign subsidiaries .. - - 35,604
Other ................................ 227 (1,079) 648
---------------- -----------------------------------
$ (3,705) $ (2,402) $ 29,697
================ ===================================
9. Related Party Transactions
Accounts receivable - Other includes approximately $48,365 and $51,211 as
of December 31, 2001 and 2002, respectively, representing amounts due from
officers and stockholders relating to advances made to employees.
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 the Company from time
to time. The Company paid Wind River a total of $336,000, $314,000 and $345,000
in 2000, 2001 and 2002 respectively, for Wind River's operating cost associated
with the Company's use of the plane.
10. Commitments and Contingencies
Operating Leases
During the years ended December 31, 2000, 2001 and 2002, the Company
incurred rent expense related to leasing office facilities of approximately
$465,000, $519,000 and $236,000, respectively. Future minimum rental payments
are as follows at December 31, 2002.
2003 .........................................................$ 336,000
2004 ......................................................... 236,000
2005 ......................................................... 236,000
2006 ......................................................... 177,000
Thereafter ................................................... -
Litigation and Contingencies
In 2001 the Company and the Partnership (see Note 4) were named in a
lawsuit filed in U.S. District Court in the District of Wyoming. The claim
asserts breach of contract, fraud and negligent misrepresentation by the Company
related to the responsibility for year 2000 ad valorem taxes on crude oil and
natural gas properties sold by the Company and the Partnership. In February
2002, a summary judgment was granted to the plaintiff in this matter and a final
judgment in the amount of $1.3 million was entered. The Company has filed an
appeal. The Company believes these charges are without merit. The Company has
established a reserve in the amount of $845,000, which represents the Company's
interest in the judgment. In 2002 the Company recorded $201,000 in other expense
representing its share of the ongoing legal cost related to this matter.
In 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 a 1992 acquisition, 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, 2002, 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-23
11. Earnings per Share
The following table sets forth the computation of basic and diluted
earnings per share:
2000 2001 2002
------------------ ----------------- ------------------
Numerator:
Numerator for basic and diluted earnings per
share - net income (loss) available to common
stockholders ................................... $ 8,449,000 $ (19,718,000) $ (118,527,000)
================== ================= ==================
Denominator:
Denominator for basic earnings per share -
weighted-average shares ........................ 22,615,777 25,788,571 29,979,397
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..................................... 32,627,764 25,788,571 29,979,397
================== ================= ==================
Basic earnings (loss) per share:
Net income (loss) per common share.......... $ 0.37 $ (0.76) $ (3.95)
================== ================= ==================
Diluted earnings (loss) per share:
Net income (loss) per common share - diluted. $ 0.26 $ (0.76) $ (3.95)
================== ================= ==================
For the year ended December 31, 2000, 2001 and 2002, 3.0 million shares,
4.3 million shares and 5.9 million shares respectively, were excluded from the
calculation of diluted earnings per share since their inclusion would have been
anti-dilutive.
12 Quarterly Results of Operations (Unaudited)
The operating results for each of the quarters in the two year period
ended December 31, 2002 have been restated to give effect to the restatement
related to amounts previously reported as discontinued operations being
reflected as continuing operations, as discussed in Note 20.
Selected results of operations for each of the fiscal quarters during
the years ended December 31, 2001 and 2002 are as follows:
1st 2nd 3rd 4th
Quarter Quarter Quarter Quarter
---------------- ---------------- --------------- ----------------
(In thousands, except per share data)
Year Ended December 31, 2001
Net revenue - as reported ........... $ 13,217 $ 9,818 $ 7,777 $ 4,963
Net revenue - as restated............ 29,086 21,116 14,901 12,140
Operating income (loss) - as reported. 4,709 5,565 2,284 (1,293)
Operating income (loss) - as restated. 12,112 9,002 2,113 (4,102)
Net income (loss) - as reported...... 255 (1,274) (5,849) (12,850)
Net income (loss) - as restated...... 255 (1,274) (5,849) (12,850)
Net income (loss) per common share -
basic and diluted - as reported..... $ 0.01 $ (0.05) $ (0.22) $ (0.43)
Net income (loss) per common share -
basic and diluted - as restated..... $ 0.01 $ (0.05) $ (0.22) $ (0.43)
F-24
Year Ended December 31, 2002
Net revenue - as reported............. $ 4,616 $ 5,759 $ 5,012 $ 6,920
Net revenue - as restated............ 11,807 14,235 11,061 17,217
Operating income (loss) - as reported. (741) (33,282) (560) 827
Operating income (loss) - as restated (735) (115,879) 490 5,221
Net income (loss) - as reported....... (8,699) (95,690) (8,438) (5,700)
Net income (loss) - as restated....... (8,699) (95,690) (8,438) (5,700)
Net income (loss) per common share -
basic and diluted - as reported..... $ (0.29) $ (3.19) $ (0.28) $ (0.19
Net income (loss) per common share-
basic and diluted - as restated..... $ (0.29) $ (3.19) $ (0.28) $ (0.19)
During the second quarter of 2002, the Company incurred a ceiling
limitation write-down of $116.0 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 2001 or
2002. 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 Old Grey Wolf, as of December 31, 2001 and 2002 and the related
consolidating statements of operations and cash flows for the years ended
December 31, 2000, 2001 and 2002. Canadian Abraxas 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). Old Grey Wolf
is a non-guarantor with respect to the First Lien Notes and the Old Notes. The
following condensed financial statements have been restated - see Note 20.
Condensed Consolidating Parent Company, Restricted Subsidiaries and Non-Guarantor Balance Sheet
December 31, 2002
(In thousands)
Abraxas Non- Abraxas
Petroleum Restricted Guarantor Reclassifi- Petroleum
Corporation Subsidiary Subsidiary cations Corporation
Inc. Parent (Canadian (Old Grey and and
Company(1) Abraxas) Wolf) eliminations Subsidiaries
--------------------------------------------------------------------------------
Assets:
Current assets:
Cash .................................... $ 557 $ 2,188 $ 2,137 $ - $ 4,882
Accounts receivable, less allowance for
doubtful accounts...................... 4,482 4,782 11,938 (11,157) 10,045
Equipment inventory ..................... 860 142 12 - 1,014
Other current assets .................... 316 682 242 - 1,240
-----------------------------------------------------------------------------
Total current assets.............. 6,215 7,794 14,329 (11,157) 17,181
Property and equipment - net................ 74,435 38,858 37,101 - 150,394
Deferred financing fees, net .............. 2,970 688 2,013 - 5,671
Deferred income taxes and other assets ..... 108,558 7,820 (108,199) 8,179
----------------------------------------------------------------------------
Total assets .......................... .. $ 192,178 $ 47,340 $ 61,263 $ (119,356) $ 181,425
============================================================================
F-25
Liabilities and Stockholders' deficit:
Current liabilities:
Accounts payable ............................. $ 15,928 $ 766 $ 6,398 $ (10,973) $ 12,119
Accrued interest ............................. 5,000 1,009 - - 6,009
Other accrued expenses ....................... 1,162 - - - 1,162
Current maturities of long-term debt ......... 63,500 - - - 63,500
-----------------------------------------------------------------------------
Total current liabilities................... 85,590 1,775 6,398 (10,973) 82,790
Long-term debt .................................. 138,350 52,629 45,964 - 236,943
Future site restoration ........................ - 3,171 775 - 3,946
-----------------------------------------------------------------------------
223,940 57,575 53,137 (10,973) 323,679
Stockholders' equity (deficit)................... (31,762) (10,235) 8,126 (108,383) (142,254)
-----------------------------------------------------------------------------
Total liabilities and stockholders' equity
(deficit)........................................ $ 192,178 $ 47,340 $ 61,263 $ (119,356) $ 181,425
============================== ==============================================
(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.
Condensed Consolidating Parent Company, Restricted Subsidiaries and Non-Guarantor Balance Sheet
December 31, 2001
(In thousands)
Abraxas Non- Abraxas
Petroleum Restricted Guarantor Reclassifi- Petroleum
Corporation Subsidiary Subsidiary cations Corporation
Inc. Parent (Canadian (Old Grey and and
Company(1) Abraxas) Wolf) eliminations Subsidiaries
--------------------------------------------------------------------------------
Assets:
Current assets:
Cash .................................... $ 3,593 $ 1,245 $ 2,767 $ - $ 7,605
Accounts receivable, less allowance for
doubtful accounts...................... 17,184 792 6,782 (16,711) 8,047
Equipment inventory ..................... 1,061 178 12 - 1,251
Other current assets .................... 250 99 94 - 443
-----------------------------------------------------------------------------
Total current assets................... 22,088 2,314 9,655 (16,711) 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 (115,418) 448
-----------------------------------------------------------------------------
Total assets ............................ $ 250,130 $ 126,626 $ 58,989 $ (132,129) $ 303,616
=============================================================================
Liabilities and Stockholders' 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)................... 22,972 34,642 22,945 (109,144) (28,585)
-----------------------------------------------------------------------------
Total liabilities and stockholders' equity
(deficit)........................................ $ 250,130 $ 126,626 $ 58,989 $ (132,129) $ 303,616
=============================================================================
F-26
Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Statement of Operations
For the year ended December 31, 2002
(In thousands)
Abraxas Non- Abraxas
Petroleum Restricted Guarantor Reclassifi- Petroleum
Corporation Subsidiary Subsidiary cations Corporation
Inc. Parent (Canadian (Old Grey and and
Company(1) Abraxas) Wolf) eliminations Subsidiaries
--------------------------------------------------------------------------------
Revenues:
Oil and gas production revenues ............... $ 20,835 $ 14,726 $15,301 $ - $ 50,862
Gas processing revenues........................ - 1,955 465 2,420
Rig revenues .................................. 635 - - - 635
Other ........................................ 71 152 180 - 403
---------------------------------------------------------------------------
21,541 16,833 15,946 - 54,320
Operating costs and expenses:
Lease operating and production taxes .......... 7,639 3,751 3,850 - 15,240
Depreciation, depletion, and amortization ..... 9,194 10,633 6,712 - 26,539
Proved property impairment .................... 28,178 60,501 27,314 - 115,993
Rig operations ................................ 567 - - - 567
General and administrative .................... 4,045 1,312 1,527 - 6,884
---------------------------------------------------------------------------
49,623 76,197 39,403 - 165,223
---------------------------------------------------------------------------
Operating income (loss)........................... (28,082) (59,364) (23,457) - (110,903)
Other (income) expense:
Interest income ............................... (92) - - - (92)
Amortization of deferred financing fees........ 1,325 366 404 - 2,095
Interest expense............................... 24,689 6,665 2,796 - 34,150
Other ......................................... 1,168 - - - 1,168
---------------------------------------------------------------------------
27,090 7,031 3,200 - 37,321
---------------------------------------------------------------------------
Income (loss) before income tax .................. (55,172) (66,395) (26,657) - (148,224)
Income tax expense (benefit)...................... - (18,522) (11,175) - (29,697)
---------------------------------------------------------------------------
Net income (loss)................................ $ (55,172) $ (47,873) $(15,482) $ - $ (118,527)
===========================================================================
Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Statement of Operations
For the year ended December 31, 2001
(In thousands)
Abraxas Non- Abraxas
Petroleum Restricted Guarantor Reclassifi- Petroleum
Corporation Subsidiary Subsidiary cations Corporation
Inc. Parent (Canadian (Old Grey and and
Company(1) Abraxas) Wolf) eliminations Subsidiaries
---------------------------------------------------------------------------------
Revenues:
Oil and gas production revenues ............... $ 34,934 $ 24,308 $ 13,959 $ - $ 73,201
Gas processing revenues ....................... - 2,008 430 - 2,438
Rig revenues .................................. 756 - - - 756
Other ........................................ 85 471 292 - 848
---------------------------------------------------------------------------------
35,775 26,787 14,681 - 77,243
Operating costs and expenses:
Lease operating and production taxes .......... 9,302 6,836 2,478 - 18,616
Depreciation, depletion, and amortization ..... 12,336 14,707 5,441 - 32,484
Proved property impairment..................... - 2,638 - - 2,638
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
F-27
Other (income) expense:
Interest income ............................... (1,242) - - 1,164 (78)
Amortization of deferred financing fees........ 1,907 361 - - 2,268
Interest expense............................... 25,086 7,117 484 (1,164) 31,523
Other ......................................... 1,052 - - - 1,052
-----------------------------------------------------------------------------
26,803 7,478 484 - 34,765
-----------------------------------------------------------------------------
Income (loss) before income tax .................. (14,343) (6,592) 5,295 - (15,640)
Income tax expense (benefit)...................... 505 (80) 1,977 - 2,402
Minority interest in income of consolidated
foreign subsidiary............................. - - 1,676 - 1,676
-----------------------------------------------------------------------------
Net income (loss)................................ $ (14,848) $ (6,512) $ 1,642 $ - $ (19,718)
=============================================================================
Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Statement of Operations
For the year ended December 31, 2000
(In thousands)
Abraxas Non- Abraxas
Petroleum Restricted Guarantor Reclassifi- Petroleum
Corporation Subsidiary Subsidiary cations Corporation
Inc. Parent (Canadian (Old Grey and and
Company(1) Abraxas) Wolf) eliminations Subsidiaries
---------------------------------------------------------------------------------
Revenues:
Oil and gas production revenues ............... $ 32,165 $ 27,425 $ 13,383 $ - $ 72,973
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)
Gain on debt extinguishment.................... (1,773) - - - (1,773)
Other ......................................... 1,116 447 - - 1,563
-------------------------------------------------------------------------------
(10,663) 8,460 711 - (1,492)
-------------------------------------------------------------------------------
Income (loss) before income tax .................. 15,867 (6,899) 4,467 - 13,435
Income tax expense (benefit)...................... 3,433 (1,658) 1,930 3,705
Minority interest in income of consolidated
foreign subsidiary............................. - - 1,281 1,281
-------------------------------------------------------------------------------
Net income (loss)................................. $ 12,434 $ (5,241) $ 1,256 $ - $ 8,449
===============================================================================
F-28
Condensed Consolidating Parent, Restricted Subsidiary and Non-Guarantor Statement of Cash Flow
For the year ended December 31, 2002
(In thousands)
Abraxas Non- Abraxas
Petroleum Restricted Guarantor Reclassifi- Petroleum
Corporation Subsidiary Subsidiary cations Corporation
Inc. Parent (Canadian (Old Grey and and
Company(1) Abraxas) Wolf) eliminations Subsidiaries
---------------------------------------------------------------------------------
Operating Activities
Net income (loss) ........................... $ (55,172) $ (47,873) $(15,482) $ - $ (118,527)
Adjustments to reconcile net income (loss)
to net cash provided by operating
activities:
Depreciation, depletion, and
amortization ......................... 9,194 10,633 6,712 - 26,539
Proved property impairment ............. 28,178 60,501 27,314 - 115,993
Deferred income tax (benefit) expense... - (18,522) (11,175) - (29,697)
Amortization of deferred financing fees. 1,325 366 404 - 2,095
Changes in operating assets and
liabilities:
Accounts receivable ................ 18,088 (3,187) 1,114 (18,262) (2,247)
Equipment inventory ................ 201 - - - 201
Other ............................. 381 (177) (78) - 126
Accounts payables and accrued
expenses ......................... (47) 479 (3,251) - (2,819)
------------------------------------------------------------------------------
Net cash provided by (used in)operations..... 2,148 2,220 5,558 (18,262) (8,336)
Investing Activities
Capital expenditures, including purchases
and development of properties ............ (5,070) (4,926) (28,916) - (38,912)
Proceeds from sale of oil and gas
properties................................ 9,725 21,789 2,362 - 33,876
------------------------------------------------------------------------------
Net cash provided (used) by investing
activities................................ 4,655 16,863 (26,554) - (5,036)
Financing Activities
Proceeds from long-term borrowings........... - - 20,551 - 20,551
Payments on long-term borrowings ............ (8,176) (18,262) - 18,262 (8,176)
Deferred financing fees...................... (1,663) 146 (22) - (1,539)
------------------------------------------------------------------------------
Net cash provided (used) by financing
activities................................ (9,839) (18,116) 20,529 18,262 10,836
------------------------------------------------------------------------------
Effect of exchange rate changes on cash ..... - (24) (163) - (187)
------------------------------------------------------------------------------
Increase (decrease) in cash ................. (3,036) 943 (630) - (2,723)
Cash at beginning of year ................... 3,593 1,245 2,767 - 7,605
------------------------------------------------------------------------------
Cash at end of year.......................... $ 557 $ 2,188 $ 2,137 $ - $ 4,882
==============================================================================
Condensed Consolidating Parent, Restricted Subsidiary and Non-Guarantor Statement of Cash Flow
For the year ended December 31, 2001
(In thousands)
Abraxas Non- Abraxas
Petroleum Restricted Guarantor Reclassifi- Petroleum
Corporation Subsidiary Subsidiary cations Corporation
Inc. Parent (Canadian (Old Grey and and
Company(1) Abraxas) Wolf) eliminations Subsidiaries
---------------------------------------------------------------------------------
Operating Activities
Net income (loss) ........................... $ (14,848) $ (6,512) $ 1,642 $ - $ (19,718)
Adjustments to reconcile net income (loss)
to net cash provided by operating
activities:
Minority interest in income of foreign
subsidiary............................ - - 1,676 - 1,676
Loss on sale of equity investment....... 845 - - - 845
F-29
Depreciation, depletion, and
amortization ......................... 12,336 14,707 5,441 - 32,484
Proved property impairment.............. - 2,638 - 2,638
Deferred income tax (benefit) expense... - (80) 1,977 - 1,897
Amortization of deferred financing fees. 1,907 361 - - 2,268
Stock-based compensation ............... (2,767) - - - (2,767)
Changes in operating assets and
liabilities:
Accounts receivable ................ 28,804 (9,721) (6,390) - 12,693
Equipment inventory ................ (76) - - - (76)
Other ............................. (281) - 175 - (106)
Accounts payables and accrued
expenses ......................... (12,915) (2,254) (402) - (15,571)
------------------------------------------------------------------------------
Net cash provided (used) by operating
activities ............................... 13,005 (861) 4,119 - 16,263
Investing Activities
Capital expenditures, including purchases
and development of properties ............ (19,126) (15,313) (22,617) - (57,056)
Proceeds from sale of oil and gas
properties................................ 9,677 15,882 3,379 - 28,938
Acquisition of minority interest ............ (2,679) - - - (2,679)
------------------------------------------------------------------------------
Net cash provided (used) by investing
activities................................ (12,128) 569 (19,238) - (30,797)
------------------------------------------------------------------------------
Financing Activities
Proceeds form issuance of common stock....... 16 - - - 16
Proceeds from long-term borrowings .......... 11,700 - 18,295 - 29,995
Payments on long-term borrowings ............ (9,326) - - - (9,326)
------------------------------------------------------------------------------
Net cash provided (used) by financing
activities................................ 2,390 - 18,295 - 20,685
------------------------------------------------------------------------------
3,267 (292) 3,176 - 6,151
Effect of exchange rate changes on cash ..... - (141) (409) - (550)
------------------------------------------------------------------------------
Increase (decrease) in cash ................. 3,267 (433) 2,767 - 5,601
Cash at beginning of year ................... 326 1,678 - - 2,004
------------------------------------------------------------------------------
Cash at end of year.......................... $ 3,593 $ 1,245 $ 2,767 $ - $ 7,605
============================== ===============================================
Condensed Consolidating Parent, Restricted Subsidiary and Non-Guarantor Statement of Cash Flow
For the year ended December 31, 2000
(In thousands)
Abraxas Non- Abraxas
Petroleum Restricted Guarantor Reclassifi- Petroleum
Corporation Subsidiary Subsidiary cations Corporation
Inc. Parent (Canadian (Old Grey and and
Company(1) Abraxas) Wolf) eliminations Subsidiaries
---------------------------------------------------------------------------------
Operating Activities
Net income (loss) ........................... $ 12,434 $ (5,241) $ 1,256 $ - $ 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
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 (benefit)... 3,433 (153) 1,658 - 4,938
Amortization of deferred financing fees. 1,660 431 - - 2,091
Stock-based compensation ............... 2,767 - - - 2,767
F-30
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
expenses ......................... 5,357 378 5,158 - 10,893
-----------------------------------------------------------------------------
Net cash provided (used) by operations....... 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
-----------------------------------------------------------------------------
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
=============================================================================
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 2002, four customers accounted for approximately 79% of consolidated oil
and natural gas production revenue. Three customers accounted for approximately
77% of United States revenue and one customer accounted for approximately 80% of
revenue in Canada. In 2001, three customers accounted for approximately 41% of
oil and natural gas production revenues. Three customers accounted for
approximately 76% of United States revenue and five customers accounted for
approximately 76% of revenue in Canada. In 2000, two customers accounted for
approximately 26% of oil and natural gas production revenues and gas processing
revenues.
F-31
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).......................... 34,553
-------------------
Income before income taxes .............. $ 13,435
===================
Identifiable assets at December 31, 2000 ... $ 132,327 $ 197,229 $ 329,556
================== ==================
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 ........................... 4,560
-------------------
Total assets ............................ $ 303,616
===================
Business segment information about the Company's 2002 operations in
different geographic areas is as follows:
U.S. Canada Total
------------------ ------------------ -------------------
(In thousands)
Revenues ................................... $ 21,541 $ 32,779 $ 54,320
================== ================== ===================
Operating loss.............................. $ (23,677) $ (82,821) $ (106,498)
================== ==================
General corporate .......................... (4,405)
Net interest expense and amortization of
deferred financing fees ................. (36,153)
Other expense............................... (1,168)
-------------------
Loss before income taxes................. $ (148,224)
===================
Identifiable assets at December 31, 2002.... $ 81,025 $ 94,059 $ 175,084
================== ==================
Corporate assets ........................... 6,341
-------------------
Total assets ............................ $ 181,425
===================
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,
F-32
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.
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.
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 was 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 Company 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 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 $2.60 to $2.95 for
natural gas) through October 31, 2002. The Company realized a loss from hedges
of $12.1 million and $3.2 million for the years ended December 31, 2001 and 2002
respectively, which is accounted for in Oil and Gas Production Revenue.
Under the terms of the New Senior Secured Credit Agreement, (see Note 2)
the Company is required to maintain hedging agreements with respect to not less
than 25% nor more than 75% of it crude oil and natural gas production for a
rolling six month period. As of January 23, 2003, the Company has entered into a
collar option agreement with respect to 5,000 MMBtu per day, or approximately
25% of the Company's production, at a call price of $6.25 per MMBtu and a put
price of $4.00 per MMBtu, for the calendar months of February through July 2003.
In February 2003 the Company entered into an additional hedge agreement for
5,000 MMbtu per day with a floor of $4.50 per MMBtu for the calendar months of
March 2003 through February 2004.
F-33
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, 2002:
Accumulated Other
Comprehensive Comprehensive Income
Income (Loss) (Loss)
------------------- ------------------------
For the year
Ended As of
December 31, 2002 December 31,2002
------------------- ------------------------
Accumulated other comprehensive loss at December 31, 2001 ......... $ (13,561)
Net loss........................................................ $ (118,527)
-------------------
Other Comprehensive income (loss):
Hedging derivatives (net of tax) - See Note 16
Reclassification adjustment for settled hedge contracts, net
of taxes of ($596)............................................ 2,556
Change in fair market value of outstanding hedge positions
net of taxes of $504.......................................... (1,990)
-------------------
566
Foreign currency translation adjustment......................... 4,292
-------------------
Other comprehensive income (loss).................................. 4,858 4,858
-------------------
Comprehensive income (loss)........................................ $ (113,669)
=================== ---------------------
Accumulated other comprehensive loss at December 31, 2002.......... $ (8,703)
=====================
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. During the second quarter of 2002, the Company had a
ceiling limitation write-down of $116.0 million.
F-34
19. 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
-----------------------------------------------------------------------------------------
2001 2002
-------------------------------------------- -------------------------------------------
Total U.S. Canada Total U.S Canada
-------------- ------------- -------------- ------------- -------------- --------------
(In thousands)
Proved crude oil and natural
gas properties ............ $ 486,098 $ 284,182 $ 201,916 $ 521,309 $ 279,401 $ 241,908
Unproved properties ......... 10,626 - 10,626 7,052 - 7,052
-------------- ------------- -------------- ------------- -------------- --------------
Total .......................... 496,724 284,182 212,542 528,361 279,401 248,960
Accumulated depreciation,
depletion, and
amortization, and
impairment ................ (280,280) (168,124) (112,156) (420,344) (205,181) (215,163)
-------------- ------------- -------------- ------------- -------------- --------------
Net capitalized costs ... $ 216,444 $ 116,058 $ 100,386 $ 108,017 $ 74,220 $ 33,797
============== ============= ============== ============= ============== ==============
Cost incurred in oil and gas property acquisitions, exploration and
development activities are as follows:
Years Ended December 31
---------------------------------------------------------------------------------------------------
2000 2001 2002
---------------------------------------------------------------------------------------------------
Total U.S. Canada Total U.S. Canada Total U.S. Canada (1)
--------- -------- ------------ -------- ------------ ----------- ---------- --------- ----------
(In thousands)
Property acquisition costs:
Proved ...................$ 7,189 $ - $ 7,189 $ - $ - $ - $ - $ - $ -
Unproved ................. - - - - - - - - -
--------- -------- ------------ -------- ------------ ----------- ---------- --------- ----------
$ 7,189 $ - $ 7,189 $ - $ - $ - $ - $ - $ -
========= ======== ============ ======== ============ =========== ========== ========= ==========
Property development and
exploration costs ........$ 64,873 $ 39,631 $ 25,242 $ 56,694 $ 18,867 $ 37,827 $ 38,560 $ 4,944 $ 33,616
======== ======== ==================== ============ =========== ========== ============ ==========
(1) Canadian costs in 2002 were primarily for exploratory purposes.
F-35
The results of operations for oil and gas producing activities are as
follows:
Years Ended December 31
-----------------------------------------------------------------------------------------------
2000 2001 2002
----------------------------- ------------------------------- -------------------------------
Total U.S. Canada Total U.S. Canada Total U.S. Canada
---------- --------- ----------- --------- --------- --------- ----------- --------- --------
(In thousands)
Revenues ................... $ 72,973 $ 32,165 $ 40,808 $ 73,201 $ 34,934 $ 38,267 $ 50,862 $ 20,835 $ 30,027
Production costs ........... (18,783) (7,755) (11,028) (18,616) (9,302) (9,314) (15,240) (7,639) (7,601)
Depreciation, depletion,
and amortization ......... (35,497) (11,968) (23,529) (32,124) (11,976) (20,148) (26,224) (8,879) (17,345)
Proved property impairment . - - - (2,638) - (2,638) (115,993) (28,178) (87,815)
General and administrative . (1,722) (1,118) (604) (1,565) (1,073) (492) (1,836) (1,011) (825)
Income taxes (expense)
benefit................... (339) - (339) (2,419) - (2,419) - - -
--------- ---------- ------------ --------- ---------- --------- ----------------------- --------
Results of operations from oil
and gas producing activities
(excluding corporate overhead
and interest costs) ..........$ 16,632 $ 11,324 $ 5,308 $ 15,839 $ 12,583 $ 3,256 $(108,431) $ (24,872) $(83,559)
========= ========== ============ ========= ========== ========= ========== ========== =========
Depletion rate per barrel
of oil equivalent, before
impact of impairment ..... $ 8.30 $ 6.19 $ 10.02 $ 8.81 $ 6.96 $ 10.45 $ 8.52 $ 7.55 $ 8.94
========= ========== ============ ========= ========== ========== ========== ========== =========
F-36
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, 2000, 2001, and 2002. The
Company's management emphasizes that reserve estimates are inherently imprecise
and that estimates of new discoveries are more imprecise than those of producing
oil and gas properties. Accordingly, the estimates are expected to change as
future information becomes available. The estimates have been prepared by
independent petroleum reserve engineers.
Total United States Canada
----------------------- ------------------------- ------------------------
Liquid Natural Liquid Natural Liquid Natural
Hydrocarbons Gas Hydrocarbons Gas Hydrocarbons Gas
------------ ---------- ------------ ----------- -------------- -----------
(Barrels) (Mcf) (Barrels) (Mcf) (Barrels) (Mcf)
(In Thousands)
Proved developed and undeveloped reserves:
Balance at January 1, 2000 (1) ........... 9,849 164,305 6,421 80,417 3,428 83,888
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 76,419
Revisions of previous estimates ........ (628) 2,944 (688) 3,318 60 (374)
Extensions and discoveries ............. 1,064 26,329 354 4,886 710 21,443
Production ............................. (732) (17,495) (416) (7,823) (316) (9,672)
Sale of minerals in place .............. (1,746) (14,348) (924) (6,821) (822) (7,527)
---------- ----------- ---------- -------------- ------------- -----------
Balance at December 31, 2001.............. 6,802 188,757 4,407 108,468 2,395 80,289
Revisions of previous estimates ........ (798) (29,701) (63) (15,248) (735) (14,453)
Extensions and discoveries ............. 522 19,166 - - 522 19,166
Production ............................. (534) (15,453) (264) (5,472) (270) (9,981)
Sale of minerals in place .............. (1,387) (23,937) (843) (9,553) (544) (14,384)
---------- ----------- ---------- -------------- ------------- -----------
Balance at December 31, 2002 (2).......... 4,605 138,832 3,237 78,195 1,368 60,637
========== =========== ========== ============== ============= ===========
(1) The beginning of year 2000 amounts exclude the Company's proportion
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.
(2) Includes 1,146 Bbl of liquid hydrocarbons and 47,066 Mcf of natural gas
applicable to Canadian Abraxas and Old Grey Wolf that were sold in January
2003.
F-37
AGE>
Estimated Quantities of Proved Oil and Gas Reserves (continued)
----------------------- ------------------------- ------------------------
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, 2000..................... 7,001 119,737 4,609 48,177 2,392 71,560
========== =========== ========== ============== ============ ===========
December 31, 2001 .................... 5,047 111,243 2,892 40,514 2,155 70,729
========== =========== ========== ============== ============ ===========
December 31, 2002..................... 3,004 90,374 1,754 34,776 1,250 55,598
========== =========== ========== ============== ============ ===========
F-38
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves
The following disclosures concerning the standardized measure of future
cash flows from proved crude oil and natural gas are presented in accordance
with SFAS No. 69. The standardized measure does not purport to represent the
fair market value of the Company's proved crude oil and natural gas reserves. An
estimate of fair market value would also take into account, among other factors,
the recovery of reserves not classified as proved, anticipated future changes in
prices and costs, and a discount factor more representative of the time value of
money and the risks inherent in reserve estimates.
Under the standardized measure, future cash inflows were estimated by
applying period-end prices at December 31, 2002 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-39
Set forth below is the Standardized Measure relating to proved oil and
gas reserves for:
Years Ended December 31
-----------------------------------------------------------------------------------------------------
2000 2001 2002
-----------------------------------------------------------------------------------------------------
Total U.S. Canada Total U.S. Canada Total U.S. Canada
-----------------------------------------------------------------------------------------------------
(In thousands)
Future cash inflows ....... $ 2,046,039 $ 1,274,871 $ 771,168 $ 607,375 $ 313,640 $ 293,735 $ 686,055 $ 389,061 $ 296,994
Future production and
development costs ....... (318,130) (254,667) (63,463) (220,613) (138,296) (82,317) (225,068) (158,507) (66,561)
Future income tax expense . (230,987) (65,421) (165,566) - - - - - -
-----------------------------------------------------------------------------------------------------
Future net cash flows ..... 1,496,922 954,783 542,139 386,762 175,344 211,418 460,987 230,554 230,433
Discount .................. (721,388) (468,663) (252,725) (177,096) (98,157) (78,939) (206,134) (120,238) (85,896)
-----------------------------------------------------------------------------------------------------
Standardized Measure of
discounted future net
cash relating to proved
reserves ................ $ 775,534 $ 486,120 $ 289,414 $ 209,666 $ 77,187 $ 132,479 $ 254,853 $ 110,316 $ 144,537
=====================================================================================================
F-40
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
----------------------------------------------------------
2000 2001 2002
------------------- ------------------- ------------------
(In thousands)
Standardized Measure, beginning
of year ................................. $ 238,451 $ 775,534 $ 209,666
Sales and transfers of oil and gas
produced, net of production costs ....... (54,190) (54,585) (35,622)
Net changes in prices and development
and production costs from prior year .... 707,755 (613,325) 111,087
Extensions, discoveries, and improved
recovery, less related costs ............ 290,283 39,982 46,803
Purchases of minerals in place ............ 33,586 - -
Sales of minerals in place ................ (75,391) (96,096) (33,808)
Revision of previous quantity estimates ... (95,757) (2,474) (36,007)
Change in future income tax expense ....... (224,668) 230,987 -
Other ..................................... (68,380) (147,910) (28,232)
Accretion of discount ..................... 23,845 77,553 20,966
------------------- ------------------- ------------------
Standardized Measure, end of year ....... $ 775,534 $ 209,666 $ 254,853
=================== =================== ==================
F-41
20. Restatement
In January 2003, the Company sold its wholly owned Canadian subsidiaries,
Old Grey Wolf and Canadian Abraxas as part of a series of transactions related
to a financial restructuring - see Note 2 for additional information regarding
an exchange offer, redemption of certain notes and a new credit agreement.
Subsequent to the issuance of its consolidated financial statements for the year
ended December 31, 2002, the Company's management determined that the wholly
owned Canadian subsidiaries should not have been presented as discontinued
operations. As a result, the accompanying consolidated balance sheets as of
December 31, 2002 and 2001, and the related consolidated statements of
operations, and cash flows for each of the three years in the period ended
December 31, 2002 have been restated to present the assets and liabilities,
results of operations, and cash flows as components of continuing operations.
A summary of the significant effects of the restatement is as follows (In
thousands):
For the year ended December 31,
2000 2001 2002
--------------------------------------------------------------- -------------------------
As As As
Previously As Previously As Previously As
Reported Restated Reported Restated Reported Restated
------------ ------------ ------------- ------------ ---------- -----------
Revenues:
Oil and gas production revenue $ 32,165 $ 72,973 $ 34,934 $ 73,201 $ 21,601 $ 50,862
Gas processing revenue - 2,717 - 2,438 - 2,420
Rig revenue 505 505 756 756 635 635
Other 216 405 85 848 71 403
----------- ---------- ------------- ------------- ---------- ------------
32,886 76,600 35,775 77,243 22,307 54,320
Operating costs and expenses:
Lease operating and
production taxes 7,755 18,783 9,302 18,616 7,910 15,240
Depreciation, depletion and
amortization 12,328 35,857 12,336 32,484 9,654 26,539
Proved property impairment - - - 2,638 32,850 115,993
Rig operations 717 717 702 702 567 567
General and administrative 4,840 6,533 4,937 6,445 5,082 6,884
General and administrative
(Stock-based
compensation) 2,767 2,767 (2,767) (2,767) - -
----------- ---------- ------------- ------------- ---------- ------------
28,407 64,657 24,510 58,118 56,063 165,223
----------- ---------- ------------- ------------- ---------- ------------
Operating income (loss) 4,479 11,943 11,265 19,125 (33,756) (110,903)
Other (income) expense:
Interest income (530) (530) (78) (78) (92) (92)
Amortization of deferred
financing fees 1,660 2,091 1,907 2,268 1,325 2,095
Interest expense 22,847 31,140 23,922 31,523 24,689 34,150
Financing costs - - - - 967 967
(Gain) loss on sale of equity
investment (33,983) (33,983) 845 845 - -
Gain on debt extinguishment (1) - (1,773) - - - -
Other (b) 1,116 1,563 207 207 201 201
----------- ---------- ------------- ------------- ---------- ------------
(8,890) (1,492) 26,803 34,765 27,090 37,321
----------- ---------- ------------- ------------- ---------- ------------
Income (loss) before income tax 13,369 13,435 (15,538) (15,640) (60,846) (148,224)
Income tax expense (benefit):
Current - (1,233) 505 505 - -
Deferred 3,433 4,938 - 1,897 - (29,697)
Minority interest in income of
consolidated foreign
subsidiary - 1,281 - 1,676 - -
Loss from discontinued operations (3,260) - (3,675) - (57,681) -
Extraordinary item: gain on debt
extinguishment (1) 1,773 - - - - -
----------- ---------- ------------- ------------- ---------- -------------
Net income (loss) $ 8,449 $ 8,449 $ (19,718) $ (19,718) $(118,527) $ (118,527)
=========== ========== ============= ============= ========== =============
(1) As required by SFAS No. 145, the Company has reclassified the gain on
the early extinguishment of debt in 2000 originally reported as an
extraordinary item to other income. See Note 1.
F-42
December 31
--------------------------------------------------------------------------
2001 2002
-------------------------------------- -------------------------------
As Previously As As Previously As
Reported Restated Reported Restated
-------------------- ---------------- --------------- --------------
Current Assets:
Cash $ 3,593 $ 7,605 $ 557 $ 4,882
Accounts receivable:
Joint owners 938 2,785 516 2,215
Oil and gas production sales 2,988 4,758 5,292 7,466
Other 135 504 221 364
-------------------- ---------------- ------------ ---------------
4,061 8,047 6,029 10,045
Equipment inventory 1,061 1,251 1,021 1,014
Other current assets 250 443 316 1,240
-------------------- ---------------- ------------ --------------
8,965 17,346 7,923 17,181
Assets held for sale 163,902 - 74,247 -
-------------------- ---------------- ------------ ---------------
Total current assets 172,867 17,346 82,170 17,181
Property and equipment:
Oil and gas properties:
Proved 290,635 486,098 298,972 521,995
Unproved 4,571 10,626 7,052 7,052
Other property and equipment 2,587 67,632 2,713 44,189
-------------------- ---------------- ------------ ---------------
Total 297,793 564,356 308,737 573,236
Less accumulated depreciation, depletion
and amortization 170,307 282,462 212,811 422,842
-------------------- ---------------- ------------ ---------------
Total property and equipment - net 127,486 281,894 95,926 150,394
Deferred financing fees 2,779 3,928 2,970 5,671
Deferred income taxes - - - 7,820
Other 484 448 359 359
-------------------- ---------------- ------------ ---------------
Total assets $ 303,616 $ 303,616 $ 181,425 $ 181,425
==================== ================ ============ ==============
Current Liabilities:
Accounts payable $(a) 3,862 $ 10,542 $ 4,171 $ 9,687
Joint interest oil and gas production payable 1,180 3,596 1,637 2,432
Accrued interest 5,000 6,013 5,000 6,009
Other accrued expenses 1,052 1,116 1,162 1,162
Hedge liability 438 658 - -
Current maturities of long-term debt 415 415 63,500 63,500
-------------------- ---------------- ------------ ---------------
11,947 22,340 75,470 82,790
Liabilities related to assets held for sale 57,552 - 56,697 -
-------------------- ---------------- ------------ ---------------
Total current liabilities 69,499 22,340 132,167 82,790
Long-term debt 262,240 285,184 190,979 236,943
Deferred income taxes - 20,621 - -
Future site restoration 462 4,056 533 3,946
Stockholders' equity (deficit) (28,585) (28,585) (142,254) (142,254)
-------------------- ---------------- ------------ ---------------
Total liabilities and stockholders' deficit $ 303,616 $ 303,616 $ 181,425 $ 181,425
==================== ================ ============ ===============
(a) Previously reported as $5,042 due to clerical error. Amount has been
corrected.
(b) Previously reported as $1,016 due to clerical error. Amount has been
corrected.
F-43
FINANCIAL STATEMENTS
GREY WOLF EXPLORATION INC.
December 31, 2002
F-44
Deloitte & Touche LLP
3000, 700 Second Street SW
Calgary AB Canada T2P 0S7
Telephone +1 403-267-1700
Facsimile +1 403-264-2871
AUDITORS' REPORT
To the Directors of
Grey Wolf Exploration Inc.
We have audited the balance sheets of Grey Wolf Exploration Inc. as at December
31, 2002 and 2001 and the statements of earnings (loss) and retained earnings
(deficit) and of cash flows for each of the years in the three year period ended
December 31, 2002. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
With respect to the financial statements for each of the years in the three-year
period ended December 31, 2002, we conducted our audits in accordance with
Canadian generally accepted auditing standards and auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform an audit to obtain reasonable assurance whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, these financial statements present fairly, in all material
respects, the financial position of the Company as at December 31, 2002 and 2001
and the results of its operations and its cash flows for each of the years in
the three year period ended December 31, 2002 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 12 on differences between Canadian and United States generally
accepted accounting principles.
Calgary, Canada /s/ Deloitte & Touche LLP
March 10, 2003 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 recommendation 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 Accountants Handbook recommendation section
3465.
In the United States, reporting standards for auditors require the addition of
an explanatory paragraph (following the opinion paragraph) outlining significant
subsequent events that have been disclosed in the financial statements. We have
not audited any financial statements of the Company for any period subsequent to
December 31, 2002. However, as discussed in Note 13, the Company's parent
company sold all of the outstanding common shares of the Company on January 23,
2003.
Calgary, Canada /s/ Deloitte & Touche LLP
March 10, 2003 Chartered Accountants
F-46
GREY WOLF EXPLORATION INC.
Balance Sheets
As At December 31
(Thousands of Canadian dollars)
2002 2001
$ $
-------------------------------------------
ASSETS
Current
Cash (Note 4) 3,365 4,405
Accounts receivable (Note 10) 8,230 9,980
-------------------------------------------
11,595 14,385
Long-term receivable (Note 10) 10,000 10,000
Property and equipment (Note 3) 23,401 71,879
Future income taxes (Note 6) 25,233 -
-------------------------------------------
70,229 96,264
-------------------------------------------
Liabilities
Current
Accounts payable and accrued liabilities (Note 10) 10,078 15,183
Long-term debt (Note 4) 69,227 36,356
Future site restoration and abandonment 1,221 1,050
Future income taxes (Note 6) - 6,359
-------------------------------------------
80,526 58,948
-------------------------------------------
CONTINGENCIES (Note 11)
SHAREHOLDERS' EQUITY (DEFICIENCY)
Share capital (Note 5) 27,891 27,891
Retained earnings (deficit) (38,188) 9,425
-------------------------------------------
(10,297) 37,316
-------------------------------------------
70,229 96,264
-------------------------------------------
See accompanying notes
F-47
GREY WOLF EXPLORATION INC.
Statements of Earnings (Loss) and Retained Earnings (Deficit)
Years Ended December 31
(thousands of Canadian dollars, except for share amounts)
2002 2001 2000
$ $ $
---------------------------------------------------
Revenue
Petroleum and natural gas sales 33,245 30,268 26,009
Royalties, net of Alberta Royalty Tax Credit (8,237) (7,615) (5,380)
---------------------------------------------------
25,008 22,653 20,629
---------------------------------------------------
Expenses
Operating 6,032 3,844 3,462
General and administrative (Note 3) 2,367 1,278 1,384
Interest and finance charges (Note 10) 4,518 1,827 1,126
Depletion, depreciation and site restoration (Note 3) 8,003 8,364 7,924
Write down of petroleum and natural gas properties
and facilities 82,635 - -
Amortization of deferred financing fees (Note 4) 634 - -
---------------------------------------------------
104,189 15,313 13,896
---------------------------------------------------
Earnings (loss) before taxes (79,181) 7,340 6,733
---------------------------------------------------
Provision for (recovery of) taxes (Note 6)
Current 24 144 61
Future (31,592) 3,061 2,732
---------------------------------------------------
(31,568) 3,205 2,793
---------------------------------------------------
Net earnings (loss) (47,613) 4,135 3,940
Retained earnings, beginning of year 9,425 5,290 1,912
Adoption of income tax accounting standard change (Note 6) - - (562)
---------------------------------------------------
Retained earnings (deficit), end of year (38,188) 9,425 5,290
---------------------------------------------------
Basic and diluted earnings (loss) per share (Note 7) (3.71) 0.32 0.31
---------------------------------------------------
Weighted average number of shares
Basic 12,841,327 12,776,407 12,660,528
Diluted 12,841,327 12,776,407 12,732,251
---------------------------------------------------
See accompanying notes
F-48
GREY WOLF EXPLORATION INC.
Statements of Cash Flows
Years Ended December 31
(Thousands of Canadian dollars, except for share amounts)
2002 2001 2000
$ $ $
---------------------------------------------------
Operating Activities
Net earnings (loss) (47,613) 4,135 3,940
Depletion, depreciation and site restoration 8,003 8,364 7,924
Write down of petroleum and natural gas properties
and facilities 82,635 - -
Future income tax expense (recovery) (31,592) 3,061 2,732
Amortization of deferred financing fees 634 - -
---------------------------------------------------
Cash flow from operations 12,067 15,560 14,596
Changes in non-cash working capital items (Note 9) (3,355) (746) 1,936
---------------------------------------------------
8,712 14,814 16,532
---------------------------------------------------
Financing Activities
Increase in long-term debt 67,994 28,334 (273)
Repayments of long-term debt (35,723) - -
Increase in long-term receivable - (10,000) -
Issuance of common shares - 336 3
---------------------------------------------------
32,271 18,670 (270)
---------------------------------------------------
Total cash resources provided 40,983 33,484 16,262
---------------------------------------------------
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 - 1,071 13
Expenditures for property and equipment 45,558 36,800 17,941
Dispositions of property and equipment (3,657) (8,838) (342)
Site restoration 122 46 203
---------------------------------------------------
42,023 29,079 16,262
---------------------------------------------------
Increase (decrease) in cash (1,040) 4,405 -
Cash, beginning of year 4,405 - -
---------------------------------------------------
Cash, end of year 3,365 4,405 -
---------------------------------------------------
Basic and diluted cash flow from operations
per share (Note 7) 0.94 1.22 1.15
---------------------------------------------------
Cash interest paid 5,483 1,840 1,123
Cash taxes paid 88 82 72
---------------------------------------------------
See accompanying notes
F-49
GREY WOLF EXPLORATION INC.
Notes to the Financial Statements
Years Ended December 31, 2002, 2001 and 2000
-------------------------------------------------------------------------------
(Tabular amounts in thousands of Canadian dollars, except for share amounts)
1. DESCRIPTION OF BUSINESS
Grey Wolf Exploration Inc. ("Grey Wolf" or "the Company") was incorporated
under the laws of the Province of Alberta on December 23, 1986. The
Company's primary business is the exploration, development and production
of crude oil and natural gas in western Canada. As at December 31, 2002 and
2001 the Company was a wholly-owned subsidiary of Abraxas Petroleum
Corporation ("Abraxas").
2. SIGNIFICANT ACCOUNTING POLICIES
These financial statements have been prepared in accordance with Canadian
generally accepted accounting principles. Differences between Canadian and
U.S. GAAP are outlined in Note 12 to the financial statements.
Cash
Cash includes amounts held in short-term deposits with original maturities
of 90 days or less.
Property and equipment
The Company follows the full cost method of accounting in accordance with
the guideline issued by the Canadian Institute of Chartered Accountants
("CICA") whereby all costs associated with the exploration for and
development of petroleum and natural gas reserves, whether productive or
unproductive, are capitalized in a Canadian cost centre and charged to
income as set out below. Such costs include acquisition, drilling,
geological and geophysical costs related to exploration and development
activities. Costs of acquiring and evaluating unproved properties are
excluded from the depletion base until it is determined whether or not
proved reserves are attributable to the properties or impairment occurs.
Gains or losses are not recognized upon disposition of petroleum and
natural gas properties unless crediting the proceeds against accumulated
costs would result in a change in the rate of depletion of 20% or more.
Depletion of petroleum and natural gas properties and depreciation of
production equipment, except for gas plants and related facilities, is
provided on accumulated costs using the unit-of-production method based on
estimated proved petroleum and natural gas reserves, before royalties, as
determined by independent engineers. For purposes of the depletion
calculation, proven petroleum and natural gas reserves are converted to a
common unit of measure on the basis of one barrel of oil or liquids being
equal to six thousand cubic feet of natural gas. Depreciation of gas plants
and related production facilities is calculated on a straight-line basis
over an average 18-year term.
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-50
2. SIGNIFICANT ACCOUNTING POLICIES (Continued)
Petroleum and natural gas properties (Continued)
The net carrying value of the Company's petroleum and natural gas
properties is limited to an ultimate recoverable amount (the "ceiling
test"). This amount is the aggregate of estimated future net revenues from
proved reserves and the costs of unproved properties, net of impairment
allowances, less future estimated production costs, general and
administration costs, financing costs, site restoration and abandonment
costs, and income taxes. Future net revenues are estimated using period end
prices and costs without escalation or discounting, and the income tax and
Alberta Royalty Tax Credit legislation substantially enacted at the balance
sheet date.
Furniture, leasehold improvements, computer hardware, software and office
equipment are carried at cost and are depreciated over the estimated useful
life of the assets at rates varying between 20 percent and 30 percent, on a
declining-balance basis.
Future site restoration and abandonment costs
The estimated cost of future site restoration is based on the current cost
and the anticipated method and extent of site restoration in accordance
with existing legislation and industry practice. The annual charge is
provided for on a unit-of-production basis for all properties except for
gas plants for which the annual charge is calculated on a straight-line
basis over the estimated remaining life of the plants. Actual site
restoration expenditures are charged to the accumulated liability account
as incurred.
Use of estimates
The amounts recorded for depletion and depreciation of property and
equipment and the provision for site restoration are based on estimates of
proved reserves and production rates. The ceiling test calculation is based
on estimates of proved reserves, production rates, oil and natural gas
prices, future costs and other relevant assumptions. By their nature, these
estimates are subject to uncertainty and the effect on the financial
statements of changes in such estimates could be significant.
F-51
2. SIGNIFICANT ACCOUNTING POLICIES (Continued)
Joint operations
Substantially all of the Company's exploration and development activities
are conducted jointly with others, and accordingly, the financial
statements reflect only the Company's proportionate interest in such
activities.
Revenue recognition
Petroleum and natural gas sales are recognized when the commodities are
delivered to purchasers.
Future income taxes
Effective January 1, 2000, the Company adopted, on a retroactive basis
without restatement of prior periods, the new Canadian Institute of
Chartered Accountants ("CICA") 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. Prior to January 1, 2000, the Company followed
the deferral method of accounting for income taxes.
Stock options
Prior to December 31, 2001, the Company had a stock option plan as
described in Note 5. No compensation expense was recognized when the stock
options were issued. Consideration received on exercise of stock options
was credited to share capital.
Per share figures
Basic per share figures are calculated using the weighted average number of
common shares outstanding during the year.
Effective January 1, 2001, the Company retroactively adopted, with
restatement of prior periods, the new recommendations of CICA Handbook
Section 3500. Under the revised standard, diluted per share figures are
calculated based on the weighted average number of shares outstanding
during the year plus the additional common shares that would have been
outstanding if potentially dilutive common shares had been issued using the
treasury stock method. Prior to the adoption of the new recommendations,
diluted per share amounts were determined using the imputed earnings
method.
F-52
2. SIGNIFICANT ACCOUNTING POLICIES (Continued)
Comparative figures
Certain of the prior years' comparative figures have been reclassified to
conform to the current year's presentation.
3. PROPERTY AND EQUIPMENT
2002
--------------------------------------------------------
Accumulated
Depletion and Net Book
Cost Depreciation Value
$ $ $
--------------------------------------------------------
Petroleum and natural gas properties 120,727 (102,708) 18,019
Gas plants and related production facilities 21,641 (16,314) 5,327
Other assets 621 (566) 55
--------------------------------------------------------
Net property and equipment 142,989 (119,588) 23,401
--------------------------------------------------------
2001
--------------------------------------------------------
Accumulated
Depletion and Net Book
Cost Depreciation Value
$ $ $
--------------------------------------------------------
Petroleum and natural gas properties 89,516 (25,649) 63,867
Gas plants and related production facilities 11,010 (3,097) 7,913
Other assets 597 (498) 99
--------------------------------------------------------
Net property and equipment 101,123 (29,244) 71,879
--------------------------------------------------------
For the year ended December 31, 2002, $701,000 of general and
administrative expenses were capitalized as part of property and equipment
related directly to the Company's exploration and development activities
(2001 - $402,000 and 2000 - $380,000).
As a result of the quarterly ceiling test calculation at June 30, 2002, the
Company recorded a write-down of its petroleum and natural gas properties
and facilities in the amount of $82,635,000 ($49,649,000 net of related tax
recovery). The impairment was primarily due to lower gas prices and reserve
revisions subsequent to December 31, 2001, and higher future estimated
interest costs relating to the Mirant Facility (Note 4).
F-53
3. PROPERTY AND EQUIPMENT (Continued)
Undeveloped property costs of $4,961,511 were excluded from the depletion
base for the year ended December 31, 2002 (2001 - $6,065,907 and 2000 -
$6,441,705).
Future site restoration and abandonment charges of $294,029 are included in
depletion, depreciation and site restoration expense for the year ended
December 31, 2002 (2001 - $197,987 and 2000 - $210,486).
4. LONG-TERM DEBT
Long-term debt is comprised of the following:
2002 2001
$ $
------------------ ----------------
Mirant Facility 72,398 40,127
Revolving term credit facility - 5,000
Cash held in trust - (5,000)
Unamortized deferred financing charges (3,171) (3,771)
------------------ ----------------
69,227 36,356
------------------ ----------------
At December 31, 2002 and 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, 2002, $72,398,000 was
drawn on this facility (2001 - $40,127,000). Of the $72,398,000 drawn,
$10,000,000 was advanced to Canaxas (2001 - $10,000,000) (Note 10). The
Company is required to pay an amount equal to monthly net cash flow from
operations less interest payments, general and administrative expenses and
approved capital expenditures. Loan advances are supported by a first
charge demand debenture in the amount of $200,000,000 together with a
debenture pledge agreement providing a first priority lien on all the
assets of the Company.
Under the Mirant Facility, loan advances bear interest at 9.5%, plus a 5%
overriding royalty which will decrease to 2.5% when certain conditions are
met. The overriding royalty granted to Mirant was treated as a disposition
of petroleum and natural gas properties in the amount of $3,600,000, with a
corresponding deferred financing charge recorded of $3,600,000, based on
the fair value at the date of disposition. This deferred charge plus
additional fees paid in 2001 and 2002 to secure the facility have been
netted against the outstanding loan balance and are being amortized over a
6-year period ending in 2007.
F-54
4. LONG-TERM DEBT (Continued)
The Mirant 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 banker's 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 the then
current bankers' acceptances rate plus 1 1/8%. Loan advances were supported
by a first floating charge demand debenture in the amount of $25,000,000
covering all the assets of the Company. During May 2001, the maximum limit
under the revolving term credit facility was increased to $27,000,000 and
remained at this level until replaced by the Mirant Facility in December
2001.
Effective January 1, 2002, the Emerging Issues Committee of the CICA issued
Abstract No. 122, which requires callable debt obligations to be presented
with current liabilities on the balance sheet. The maximum available amount
under the Mirant Facility may be terminated or reduced below the
outstanding amount only upon certain unanticipated events of default, and
therefore is not classified as a callable debt obligation. In addition, it
is anticipated the Company will be a net borrower due to a number of
planned capital projects over the next several years. Accordingly, the
outstanding balance has been classified as a long-term liability on the
balance sheet. The facility matures in December 2007.
Interest and financing charges for the year ended December 31, 2002
includes $5,483,000 of interest expense relating to long-term debt (2001 -
$843,000 and 2000 - $1,126,000).
F-55
5. SHARE CAPITAL
Authorized
Unlimited number of common shares without nominal or par value.
Issued
Number of Amount
Shares $
---------------------------------------------
Balance, January 1, 2000 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 and 2002 12,841,327 27,891
---------------------------------------------
Stock options
Prior to December 31, 2001, a maximum of 1,270,000 options to purchase
common shares were authorized for issuance under the Company's stock option
plan. The options were exercisable on a cumulative basis at 25% per year
commencing one year after the grant date and expiring in five years from
the date of grant. During the year ended December 31, 2001, all options
outstanding in the Company were cancelled and new options were issued by
Abraxas.
Number Weighted Average
of Options Option Price
----------------------------------------------
Balance, January 1, 2000 1,033,715 2.84
Issued 398,376 1.60
Exercised (1,800) 1.60
Cancelled (420,262) 2.53
------------------------
Balance, December 31, 2000 1,010,029 2.30
Exercised (179,786) 1.87
Cancelled (830,243) 2.39
------------------------
Balance December 31, 2001 and 2002 -
------------------------
F-56
6. PROVISION FOR TAXES
Effective January 1, 2000, the Company accounts for future income taxes
using the liability method. Prior to January 1, 2000, the Company followed
the deferral method of accounting for income taxes.
Upon adoption of the new accounting recommendation of the CICA effective
January 1, 2000, 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.
The total provision for taxes recorded differs from the tax calculated by
applying the combined statutory Canadian corporate and provincial income
tax rates as follows:
2002 2001 2000
$ $ $
--------------------------------------------------------
Calculated income tax (recovery) expense at
42.12% (2001 - 42.62% and 2000 - 44.62%) (33,351) 3,128 3,004
Increase (decrease) in tax resulting from:
Non-deductible crown royalties and other charges 2,511 2,950 2,254
Resource allowance and related items (583) (2,757) (2,066)
Alberta Royalty Tax Credit (105) (177) (231)
Large Corporation Tax 24 144 61
Tax rate adjustment (62) (151) -
Other (2) 68 (229)
--------------------------------------------------------
Provision for (recovery of) taxes (31,568) 3,205 2,793
--------------------------------------------------------
The major components of future income tax asset (liability) at December 31,
2002 and 2001 are as follows:
2002 2001
$ $
--------------- ----------------
Property and equipment 25,522 (7,672)
Future site restoration 514 447
Share issue costs 19 117
Attributed royalty income carried forward 607 511
Resource allowance (1,357) 310
Deferred financing costs (72) (72)
--------------- ----------------
25,233 (6,359)
--------------- ----------------
No valuation allowance has been recorded with respect to the future income
tax asset balance at December 31, 2002 based on management's assessment
that the amount is more likely than not to be realized.
F-57
7. PER SHARE figures
The treasury method of calculating per share figures was adopted
retroactively effective January 1, 2001, with restatement of prior periods.
If the imputed earnings method was utilized for the year ended December 31,
2000, diluted net earnings per share would have been $0.31 per share and
diluted cash flow from operations per share would have been $1.11. There
was no impact on 2001 diluted per share figures as a result of adopting the
new treasury method.
8. FINANCIAL INSTRUMENTS
Financial instruments of the Company consist of accounts receivable,
long-term receivable, accounts payable and accrued liabilities, and
long-term debt. As at December 31, 2002 and 2001, there were no significant
differences between the carrying amounts of these financial instruments
reported on the balance sheets and their estimated fair values.
Credit risk
The majority of the Company's accounts receivable are in respect of oil and
gas operations. The Company generally extends unsecured credit to these
customers, and therefore, the collection of accounts receivable may be
affected by changes in economic or other conditions. Management believes
the risk is mitigated by the size and reputation of the companies to which
they extend credit. The Company has not previously experienced any material
credit loss in the collection of receivables.
Interest rate risk
The Company's long-term debt bears interest at a floating market rate plus
1/8%. Accordingly, the Company is subject to interest rate risk, as the
required cash flow to service the debt will fluctuate as a result of
changes in market rates.
Commodity price risk
The nature of the Company's operations results in exposure to fluctuations
in commodity prices. The Company from time to time employs financial
instruments to manage its exposure to commodity prices. These instruments
are not used for speculative trading purposes. Gains and losses on
commodity price hedges are included in revenues upon the sale of the
related production. The Company had not entered into any contracts as at
December 31, 2002 and 2001.
F-58
9. SUPPLEMENTARY CASH FLOW INFORMATION
2002 2001 2000
$ $ $
--------------------------------------------------------
Accounts receivable 1,750 (165) (5,712)
Accounts payable and accrued liabilities (5,105) (581) 7,648
--------------------------------------------------------
Changes in non-cash working capital items (3,355) (746) 1,936
--------------------------------------------------------
10. RELATED PARTY TRANSACTIONS
The Company manages the assets and operations of Canadian Abraxas Petroleum
Limited ("Canaxas") pursuant to a Management Agreement dated November 12,
1996. Canaxas is a wholly-owned subsidiary of Abraxas. As at December 31,
2002 and 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.
During the year ended December 31, 2002, $2,967,200 was charged to Canaxas
with respect to the Management Agreement (2001 - $2,633,716 and 2000 -
$3,456,023). Abraxas also charged the Company a corporate service charge of
$885,000 for the year ended December 31, 2002 of which $480,000 was charged
out to Canaxas. For the year ended December 31, 2001, the Abraxas corporate
service charge was $849,000 (2000 - $Nil) of which $589,000 (2000 - $Nil)
was charged out to Canaxas. All amounts relating to the Abraxas corporate
service charge and the Management Agreement with Canaxas are non-interest
bearing, are not collateralized and are due on demand.
At December 31, 2002 and 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. Interest and
financing charges of $4,518,000 for the year ended December 31, 2002 are
net of $965,000 interest income accrued ($Nil for comparative periods
presented) related to the long-term receivable from Canaxas.
Following is a summary of amounts included in accounts receivable,
long-term receivable and accounts payable that are due from (to) related
parties as at December 31, 2002 and 2001:
F-59
10. RELATED PARTY TRANSACTIONS (Continued)
2002 2001
$ $
-----------------------------
Short-term receivable from Canaxas 1,236 4,330
Long-term receivable from Canaxas 10,000 10,000
Short-term payable to Abraxas - (849)
11. CONTINGENCIES
The Company is subject to various claims arising from its operations in the
normal course of business, none of which are expected, individually or in
the aggregate, to have a material adverse impact on the Company's
operations or financial position.
12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES
Reconciliation to United States Generally Accepted Accounting Principles
The financial statements of the Company have been prepared in accordance
with Canadian generally accepted accounting principles ("Canadian GAAP"),
which in most respects, conform to accounting principles generally accepted
in the United States of America ("U.S. GAAP"). Differences from U.S. GAAP
having a significant effect on the Company's balance sheets and statements
of earnings (loss) and retained earnings (deficit) and of cash flows are
described and quantified below for the years indicated:
(a)Under U.S. GAAP, interest costs associated with certain capital
expenditures are required to be capitalized as part of the historical
cost of the oil and gas assets. Under Canadian GAAP, the calculation of
interest costs eligible for capitalization differs from the calculation
under U.S. GAAP in certain respects and is optional at the discretion of
the entity. Accordingly, no amounts have been capitalized with respect
to the Canadian GAAP financial statements. The impact of recording
capitalized interest under U.S. GAAP would be to increase the carrying
value of property and equipment by $168,000 in 2002, $119,000 in 2001
and $69,000 in 2000 with a corresponding decrease in interest expense in
the respective periods. There was no cumulative adjustment under U.S.
GAAP for years prior to 2000.
F-60
12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES (Continued)
(b)In September 2001, Abraxas acquired the remaining non-controlling
interest of the Company. Consideration was comprised of 0.6 common
shares of Abraxas, in exchange for each common share of the Company.
Under U.S. GAAP, the costs assigned to assets and liabilities by the
acquiring company under a business combination are considered to
constitute a new basis of accounting. Accordingly, the historical
carrying values of assets and liabilities of the subsidiary are
comprehensively revalued based on the purchase price assigned for
consolidation purposes at the time it becomes wholly owned ("push down
accounting"). Under Canadian GAAP, comprehensive revaluation of assets
and liabilities in the financial statements of a subsidiary based on a
purchase transaction involving acquisition of all of the equity
interests is permitted, but not required. Had the consolidation entries
of Abraxas related to the acquisition been applied in the Company's
financial statements using "push down accounting", property and
equipment and future income tax liability would be reduced by $4,074,000
and $1,736,000, respectively, accounts receivable would be increased and
interest and financing charges decreased by $984,000 (relating to
certain costs of the transaction paid by the Company), with the
remaining amount of $2,338,000 recorded as a revaluation adjustment
within shareholders' equity.
(c)Under U.S. GAAP, the carrying value of petroleum and natural gas
properties and related facilities at the balance sheet date, net of
deferred income taxes and accumulated site restoration and abandonment
liability, is limited to the present value of after-tax future net
revenue from proven reserves, discounted at 10 percent, plus the lower
of cost and fair value of unproved oil and gas properties. Under
Canadian GAAP, the "ceiling test" calculation is performed using
undiscounted after-tax net revenues, less future estimated general and
administrative and financing costs plus the lower of cost and fair value
of unproved oil and gas properties. Had the ceiling test been applied in
accordance with U.S. GAAP, the write-down recorded for the year ended
December 31, 2002 would have been lower by $41,155,000 ($25,464,000
after-tax). There were no differences between the application of the
Canadian and U.S. GAAP ceiling tests in 2001 and 2000, or for years
prior to 2000.
F-61
12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES (Continued)
(d)Prior to 2000, Canadian GAAP required the use of the deferral method of
accounting for income taxes. For fiscal periods beginning on or after
January 1, 2000, retroactive adoption of the liability method of
accounting for income taxes was required, which is substantially the
same as Financial Accounting Standards Board Statement No. 109 under
U.S. GAAP. However, upon adoption of the new recommendation for Canadian
GAAP, companies were permitted to record the impact of differences in
accounting and tax bases to retained earnings as a one-time transition
adjustment. Accordingly, property and equipment would have been higher
under U.S. GAAP by $682,000 for 2002 and 2001 before the impact of
depletion. In addition, future income tax expense of $480,000 would have
been recorded for 1999 under U.S. GAAP.
(e)As a result of the Canadian - U.S. GAAP differences in capitalization
of interest, "push down accounting", ceiling test write-down and
adoption of the deferral method of accounting for incomes taxes as
outlined in (a), (b), (c) and (d), respectively, depletion and
depreciation expense and property and equipment under U.S. GAAP have
been adjusted for each of the years ended December 31, 2002, 2001 and
2000. The cumulative increase in depletion and depreciation expense for
years prior to 2000 was $158,000.
(f)Future income taxes have been adjusted for the year ended December 31,
2002 for the tax impact of the Canadian - U.S. GAAP differences outlined
in (a) through (e). Except for the impact on future tax expense for 1999
as noted in (d), the cumulative impact on future income taxes for years
prior to 2002 was not significant.
(g)Prior to 2001, Canadian GAAP required the use of the imputed earnings
method for purposes of the calculation of fully diluted earnings per
share. For fiscal periods beginning on or after January 1, 2001,
retroactive application of the treasury stock method with restatement of
prior periods is required, which is substantially the same as Financial
Accounting Standards Board Statement No. 128 under U.S. GAAP.
Accordingly, no adjustments are required to conform the diluted earnings
(loss) per share figures to U.S. GAAP, except for the net income (loss)
effect of the above-noted Canadian - U.S. GAAP differences identified.
F-62
12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES (Continued)
The application of U.S. GAAP would have the following effect on the
Statements of Earnings (Loss):
Years Ended December 31,
---------------------------------------------------
2002 2001 2000
$ $ $
----------------- ----------------- ---------------
Net earnings (loss), as reported (47,613) 4,135 3,940
Capitalized interest (a) 168 119 69
Depreciation, depletion and site restoration (e) (2,401) (62) (88)
Write-down of petroleum and natural gas properties
and facilities (c) 41,155 - -
Interest and financing charges (b) - 984 -
Future income tax expense (recovery) (f) (14,495) - -
----------------- ----------------- ---------------
Net earnings (loss), U.S. GAAP (23,186) 5,176 3,921
----------------- ----------------- ---------------
Basic and diluted earnings (loss) per share, as reported (3.71) 0.32 0.31
Effect of increase (decrease) in net earnings
(loss) under U.S. GAAP 1.90 0.09 -
----------------- ----------------- ---------------
Basic and diluted earnings (loss) per share, U.S. GAAP (g) (1.81) 0.41 0.31
----------------- ----------------- ---------------
F-63
12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES (Continued)
The application of U.S. GAAP would have the following effect on the Balance
Sheets:
As At December 31, 2002 As At December 31, 2001
-------------------------------------------- -----------------------------------------
Cumulative Cumulative
As Increase U.S. As Increase U.S.
Reported (Decrease) GAAP Reported (Decrease) GAAP
-------------- ---------------- ------------ -------------- --------------- ---------
ASSETS
Accounts receivable (b) 8,230 984 9,214 9,980 984 10,964
Property and equipment (a)(b)(c)(d)(e) 23,401 35,414 58,815 71,879 (3,509) 68,370
Future income taxes (f) 25,233 (12,759) 12,474 - - -
LIABILITIES
Future income taxes (d)(f) - - - 6,359 (1,736) 4,623
SHAREHOLDERS'
EQUITY (DEFICIENCY)
Revaluation adjustment (b) - (2,338) (2,338) - (2,338) (2,338)
Retained earnings (deficit)
(a)(b)(c)(d)(e)(f) (38,188) 25,977 (15,255) 9,425 1,549 10,974
F-64
12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES (Continued)
The application of U.S. GAAP would have the following effect on the
Statements of Cash Flows:
Years Ended December 31,
--------------------------------------------
2002 2001 2000
$ $ $
------------- -------------- ---------------
OPERATING ACTIVITIES
Cash flow from operating activities, as reported 8,712 14,814 16,532
Increase (decrease) in:
Net earnings (loss) 24,427 1,041 (19)
Depletion, depreciation and site restoration (e) 2,401 62 88
Write-down of petroleum and natural gas properties
and facilities (c) (41,155) - -
Future income tax expense (recovery) (f) 14,495 - -
Changes in non-cash working capital items (b) - (984) -
------------- -------------- ---------------
Cash flow from operating activities, U.S. GAAP 8,880 14,933 16,601
------------- -------------- ---------------
INVESTING ACTIVITIES
Net cash (used) provided by investing activities, as reported (42,023) (29,079) (16,262)
Increase in capital expenditures (a) (168) (119) (69)
------------- -------------- ---------------
Net cash (used) provided by investing activities,
U.S. GAAP (42,191) (29,198) (16,331)
------------- -------------- ---------------
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-65
12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES (Continued)
Under Canadian GAAP, companies are permitted to present a sub-total prior
to changes in non-cash working capital within operating activities. This
information is perceived to be useful information for various users of the
financial statements and is commonly presented by Canadian public
companies. Under U.S. GAAP, this sub-total is not permitted to be shown and
would be removed in the statements of cash flows for all periods presented.
In addition, cash flow from operations per share figures would not be
presented under U.S. GAAP.
Recent U.S. Accounting Developments
Statement No. 143, "Accounting for Asset Retirement Obligations" (FAS 143)
was released by the Financial Accounting Standards Board in June 2001. FAS
143 requires liability recognition for retirement obligations associated
with tangible long-lived assets. The initial amount of the asset retirement
obligation is to be recorded at fair value. The asset retirement cost equal
to the fair value of the retirement obligation is to be capitalized as part
of the cost of the related long-lived asset and amortized to expense over
the useful life of the asset. Enterprises are required to adopt FAS 143 for
fiscal years beginning after June 15, 2002. The Company is currently
assessing the impact that adoption of this standard would have on its
financial position and results of operations, in conjunction with the
January 23, 2003 transaction as described in Note 13.
The Financial Accounting Standards Board also recently issued Statement No.
144, "Accounting for the Impairment of Disposal of Long-Lived Assets" (FAS
144). FAS 144 will replace previous United States generally accepted
accounting principles regarding accounting for impairment of long-lived
assets and accounting and reporting for discontinued operations. FAS 144
retains the fundamental provisions of the prior standard for recognizing
and measuring impairment losses on long-lived assets. FAS 144 retains the
basic provisions of the prior standard for presentation of discontinued
operations in the income statement, but broadens that presentation to
include a component of an entity rather than a segment of a business.
Enterprises are required to adopt FAS 144 for fiscal years beginning after
December 15, 2001. The Company has adopted the accounting standard
effective January 1, 2002. The standard is not expected to have a
significant future impact on the Company's financial position and results
of operations.
F-66
12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES (Continued)
The Financial Accounting Standards Board also recently issued Statement No.
146, "Accounting for Costs Associated With Exit or Disposal Activities"
(FAS 146). FAS 146 addresses financial accounting and reporting for costs
associated with exit or disposal activities and nullifies Emerging Issues
Task Force (EITF) Issue No. 94-3, "Liability Recognition for Certain
Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring)." The provisions of
this Statement are effective for exit or disposal activities that are
initiated after December 31, 2002, with early application encouraged. The
standard is not expected to have a significant impact on the Company's
financial position or results of operations.
13. SUBSEQUENT EVENTS
On January 23, 2003, Abraxas completed the sale of all of the outstanding
common shares of the Company to an unrelated third party (the "Purchaser")
for gross cash proceeds of approximately $110,790,000, subject to closing
adjustments. Upon closing of the sale, the Company was required to repay
the outstanding indebtedness including accrued interest under the Mirant
Facility, totaling $72,847,000. Prior to the sale, certain petroleum and
natural gas assets of the Company with a net book value of $8,871,000 were
transferred to a related newly-formed subsidiary of Abraxas, a portion of
which will be developed jointly under farmout arrangements with the
Purchaser.
F-67