PROSPECTUS
ABRAXAS PETROLEUM CORPORATION
CANADIAN ABRAXAS PETROLEUM LIMITED
OFFER TO EXCHANGE 11.5% SENIOR NOTES DUE 2004, SERIES B
FOR ANY AND ALL OUTSTANDING 11.5% SENIOR
NOTES DUE 2004, SERIES A
THE EXCHANGE OFFER WILL EXPIRE AT 5:00 P.M., NEW YORK CITY
TIME, ON MARCH 14, 1997, UNLESS EXTENDED.
Abraxas Petroleum Corporation, a Nevada corporation ("Abraxas"), and
Canadian Abraxas Petroleum Limited, a Canada corporation ("Canadian Abraxas"
and, together with Abraxas, the "Issuers"), hereby offer (the "Exchange Offer"),
upon the terms and conditions set forth in this Prospectus (the "Prospectus")
and the accompanying Letter of Transmittal (the "Letter of Transmittal"), to
exchange $1,000 principal amount of their 11.5% Senior Notes due 2004, Series B
(the "Exchange Notes"), which have been registered under the Securities Act of
1933, as amended (the "Securities Act"), pursuant to a Registration Statement of
which this Prospectus is a part, for each $1,000 principal amount of their
outstanding 11.5% Senior Notes due 2004, Series A (the "Series A Notes"), of
which $215,000,000 principal amount is outstanding. The form and terms of the
Exchange Notes are the same as the form and terms of the Series A Notes (which
they replace) except that (i) the Exchange Notes will bear a Series B
designation, (ii) the Exchange Notes will have been registered under the
Securities Act and, therefore, will not bear legends restricting their transfer
and will not be subject to certain provisions relating to an increase in the
interest rate which were applicable to the Series A Notes in certain
circumstances relating to the timing of the Exchange Offer and (iii) holders of
the Exchange Notes will not be entitled to certain rights of holders of the
Series A Notes under the Registration Rights Agreement (as defined herein),
which rights will terminate upon consummation of the Exchange Offer. The
Exchange Notes will evidence the same debt as the Series A Notes (which they
replace) and will be issued under and be entitled to the benefits of the
Indenture dated November 14, 1996 (the "Indenture") among the Issuers and IBJ
Schroder Bank & Trust Company governing the Series A Notes and the Exchange B
Notes. As used herein, the term "Notes" refers to both the Series A Notes and
the Exchange Notes. See "The Exchange Offer" and "Description of the Notes."
Interest on the Exchange Notes will be payable semi-annually in arrears
on May 1 and November 1 of each year, commencing on May 1, 1997, at the rate of
11.5% per annum. Interest will accrue from the date of issuance of the Series A
Notes (November 14, 1996). The Exchange Notes will be redeemable, in whole or in
part, at the option of the Issuers, on or after November 1, 2000, at the
redemption prices set forth herein, plus accrued and unpaid interest to the date
of redemption. In addition, at any time on or prior to November 1, 1999, the
Issuers may, at their option, redeem up to 35% of the aggregate principal amount
of the Notes originally issued with the net cash proceeds of one or more Equity
Offerings (as defined herein), at a redemption price equal to 111.5% of the
aggregate principal amount of the Exchange Notes to be redeemed, plus accrued
and unpaid interest to the date of redemption; provided, however, that, after
giving effect to any such redemption, at least $139.75 million aggregate
principal amount of Notes remains outstanding.
The Exchange Notes will be general unsecured obligations of the Issuers
and will rank pari passu in right of payment to all existing and future
unsubordinated indebtedness of the Issuers. The Exchange Notes will rank senior
in right of payment to all future subordinated indebtedness of the Issuers. The
Exchange Notes will, however, be effectively subordinated to secured
indebtedness of the Issuers to the extent of the value of the assets securing
such indebtedness. See "Description of the Notes."
The Exchange Notes will be unconditionally guaranteed, jointly and
severally, by certain of the Issuers' future subsidiaries (the "Subsidiary
Guarantors"). The Guarantees (as defined herein) will be general unsecured
obligations of the Subsidiary Guarantors and will rank pari passu in right of
payment to all unsubordinated indebtedness of the Subsidiary Guarantors and
senior in right of payment to all subordinated indebtedness of the Subsidiary
Guarantors. The Guarantees will be effectively subordinated to secured
indebtedness of the Subsidiary Guarantors to the extent of the value of the
assets securing such indebtedness. See "Description of the Notes." Upon
<PAGE>
consummation of the Offering, the Issuers and the Subsidiary Guarantors will
have no secured indebtedness outstanding.
Abraxas has entered into a credit facility (the "New Credit Facility")
with Bankers Trust Company ("BTCo") and ING (U.S.) Capital Corporation ("ING
Capital") which is secured by certain assets of Abraxas and guaranteed by
Canadian Abraxas. The New Credit Facility has an initial availability of $20.0
million. As of December 20, 1996, there were no borrowings under the New Credit
Facility outstanding.
Upon a Change of Control (as defined herein), each holder of the Notes
will have the right to require the Issuers to repurchase all or a portion of
such holder's Notes at a redemption price equal to 101% of the principal amount
thereof, plus accrued and unpaid interest to the date of repurchase. In
addition, the Issuers will be obligated to offer to repurchase the Notes at 100%
of the principal amount thereof plus accrued and unpaid interest to the date of
repurchase in the event of certain asset sales. See "Description of the Notes."
The Issuers will accept for exchange any and all Series A Notes validly
tendered and not withdrawn prior to 5:00 p.m., New York City time, on March 14,
1997, unless extended by the Issuers in their sole discretion (the "Expiration
Date"). Tenders of the Series A Notes may be withdrawn at any time prior to 5:00
p.m. on the Expiration Date. The Exchange Offer is subject to certain customary
conditions. The Series A Notes were sold by the Issuers on November 14, 1996 to
the Initial Purchasers (as defined herein) and were thereupon sold by the
Initial Purchasers in reliance upon Rule 144A under the Securities Act, to a
limited number of qualified institutional buyers that agreed to comply with
certain transfer restrictions and other conditions. Accordingly, the Series A
Notes may not be offered, resold or otherwise transferred in the United States
unless registered under the Securities Act or unless an applicable exemption
from the registration requirements of the Securities Act is available. The
Exchange Notes are being offered hereunder in order to satisfy the obligations
of the Issuers under the Registration Rights Agreement entered into by the
Issuers and the Initial Purchasers in connection with the offering of the Series
A Notes. See "The Exchange Offer."
Based on an interpretation by the staff of the Securities and Exchange
Commission (the "Commission") set forth in no-action letters issued to third
parties, the Issuers believe that the Exchange Notes issued pursuant to the
Exchange Offer may be offered for resale, resold and otherwise transferred by
any holder thereof (other than any such holder that is an "affiliate" of either
of the Issuers within the meaning of Rule 405 under the Securities Act or a
broker-dealer who purchased the Series A Notes directly from the Issuers for
resale pursuant to Rule 144A or another exemption from the Securities Act)
without compliance with the registration and prospectus delivery provisions of
the Securities Act, provided that such Exchange Notes are acquired in the
ordinary course of such holder's business and such holder has no arrangement or
understanding with any person to participate in the distribution of such
Exchange Notes. See "Purpose of the Exchange Offer" and " Resale of the Exchange
Notes." Each broker-dealer that receives the Exchange Notes for its own account
pursuant to the Exchange Offer (a "Participating Broker-Dealer") must
acknowledge that it will deliver a prospectus in connection with any resale of
such Exchange Notes. The Letter of Transmittal states that by so acknowledging
and by delivering a prospectus, a participating Broker-Dealer will not be deemed
to admit that it is an "underwriter" within the meaning of the Securities Act.
This Prospectus, as it may be amended or supplemented from time to time, may be
used by a Participating Broker-Dealer in connection with resales of the Exchange
Notes received in exchange for the Series A Notes where such Series A Notes were
acquired by such Participating Broker-Dealer as a result of market-making
activities or other trading activities. The Issuers agreed that they will make
this Prospectus available to any Participating Broker-Dealer for use in
connection with any such resale during the period required by the Securities
Act. See "Plan of Distribution."
There has not previously been any public market for the Series A Notes or
the Exchange Notes. The Issuers do not intend to list the Exchange Notes on any
securities exchange or to seek approval for quotation through any automated
quotation system. There can be no assurance that an active market for the
Exchange Notes will develop. See "Risk Factors -- Lack of Public Market."
Moreover, to the extent that the Series A Notes are tendered and accepted in the
Exchange Offer, the trading market for untendered and tendered but unaccepted
Series A Notes could be adversely affected.
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The Exchange Notes will be available initially only in book-entry form.
The Issuers expect that the Exchange Notes issued pursuant to the Exchange Offer
will be issued in the form of a Global Certificate (as defined herein), which
will be deposited with, or on behalf of, The Depository Trust Company (the
"Depositary" or "DTC") and registered in its name or in the name of Cede & Co.,
its nominee. Beneficial interests in the Global Certificate representing the
Exchange Notes will be shown on, and transfers thereof to qualified
institutional buyers will be affected through, records maintained by the
Depositary and its participants. After the initial issuance of the Global
Certificate, the Exchange Notes in certified form will be issued in exchange for
the Global Certificate only on the terms set forth in the Indenture. See
"Book-Entry; Delivery and Form."
Holders of the Series A Notes not tendered and accepted in the Exchange
Offer will continue to hold such Series A Notes and will be entitled to all of
the rights and benefits and will be subject to the limitations applicable
thereto under the Indenture and with respect to transfer under the Securities
Act. The Issuers will not receive any proceeds from the Exchange Offer. Pursuant
to the Registration Rights Agreement, the Issuers will pay all the expenses
incurred by them incident to the Exchange Offer. See "The Exchange Offer."
SEE "RISK FACTORS" ON P. 19 FOR A DESCRIPTION OF CERTAIN RISKS TO BE
CONSIDERED BY HOLDERS WHO TENDER THEIR SERIES A NOTES IN THE EXCHANGE OFFER.
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE
COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE ACCURACY OR
ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL
OFFENSE.
The date of this Prospectus is February 5, 1997.
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DISCLOSURE REGARDING FORWARD-LOOKING INFORMATION
This Prospectus includes "forward-looking statements" within the meaning
of Section 27A of the Securities Act and Section 21E of the Exchange Act. All
statements other than statements of historical facts included in this
Prospectus, including, without limitation, those regarding the Issuers'
financial position, business strategy, budgets, reserve estimates, development
and exploitation opportunities and projects, behind-pipe zones, classification
of reserves, projected costs, potential reserves and plans and objectives of
management for future operations, are forward-looking statements. Although the
Issuers believe that the expectations reflected in such forward-looking
statements are reasonable, they can give no assurance that such expectations
will prove to have been correct. Important factors that could cause actual
results to differ materially from the Issuers' expectations ("Cautionary
Statements") are disclosed under "Risk Factors" and elsewhere in this Prospectus
including, without limitation, in conjunction with the forward-looking
statements included in this Prospectus. All subsequent written and oral
forward-looking statements attributable to either of the Issuers, or persons
acting on behalf of either of them, are expressly qualified in their entirety by
the Cautionary Statements.
CURRENCY TRANSLATION
Certain information contained in this Prospectus relating to CGGS (as
defined herein) and Cascade (as defined herein) has been translated from
Canadian dollars into U.S. dollars. The statements of operations and other
similar information relating to CGGS have been translated into U.S. dollars at
the average exchange rates of $0.7321 and $0.7273 to one Canadian dollar for the
nine months ended September 30, 1996 and the fiscal year ended October 31, 1995,
respectively. The balance sheet of Canadian Abraxas as of September 30, 1996 has
been translated at the period-end exchange rate of $0.7458 to one Canadian
dollar. In addition, the financial statements of Canadian Abraxas have been
converted from Canadian generally accepted accounting principles to United
States generally accepted accounting principles.
NOTICE TO NEW HAMPSHIRE RESIDENTS
NEITHER THE FACT THAT A REGISTRATION STATEMENT OR AN APPLICATION FOR A
LICENSE HAS BEEN FILED UNDER THIS CHAPTER WITH THE STATE OF NEW HAMPSHIRE NOR
THE FACT THAT A SECURITY IS EFFECTIVELY REGISTERED OR A PERSON IS LICENSED IN
THE STATE OF NEW HAMPSHIRE CONSTITUTES A FINDING BY THE SECRETARY OF STATE THAT
ANY DOCUMENT FILED UNDER RSA 421-B IS TRUE, COMPLETE AND NOT MISLEADING. NEITHER
ANY SUCH FACT NOR THE FACT THAT AN EXEMPTION OR EXCEPTION IS AVAILABLE FOR A
SECURITY OR A TRANSACTION MEANS THAT THE SECRETARY OF STATE HAS PASSED IN ANY
WAY UPON THE MERITS OR QUALIFICATIONS OF, OR RECOMMENDED OR GIVEN APPROVAL TO,
ANY PERSON, SECURITY, OR TRANSACTION. IT IS UNLAWFUL TO MAKE, OR CAUSE TO BE
MADE, TO ANY PROSPECTIVE PURCHASER, CUSTOMER, OR CLIENT ANY REPRESENTATION
INCONSISTENT WITH THE PROVISIONS OF THIS PARAGRAPH.
NOTICE TO FLORIDA RESIDENTS
PURSUANT TO SECTION 517.011(1)(a)(5) OF THE FLORIDA SECURITIES ACT, YOU
HAVE THE RIGHT TO RESCIND YOUR SUBSCRIPTION (UNLESS YOU ARE AN INSTITUTIONAL
INVESTOR DESCRIBED IN SECTION 517.061(7) OF THE FLORIDA SECURITIES ACT) BY
GIVING NOTICE OF SUCH RESCISSION BY TELEPHONE, TELEGRAPH OR LETTER, WITHIN THREE
DAYS AFTER YOU FIRST TENDER CONSIDERATION, TO THE INITIAL PURCHASERS. IF NOTICE
IS NOT RECEIVED BY SUCH TIME, THE FOREGOING RIGHT OF RESCISSION SHALL BE NULL
AND VOID.
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SUMMARY
The following summary is qualified in its entirety by the more detailed
information and financial statements, including the notes thereto, appearing
elsewhere in this Prospectus. As used in this Prospectus, the term "Abraxas"
refers to Abraxas Petroleum Corporation, the term "Canadian Abraxas" refers to
Canadian Abraxas Petroleum Limited and the term "Company" refers to Abraxas and
all of its subsidiaries, including Canadian Abraxas, for the relevant time
periods. The term "CGGS" refers to CGGS Canadian Gas Gathering Systems Inc.
after giving effect to the sale by CGGS of the Nevis Gas Processing Plant and
related assets (the "Nevis Plant") to a third party. References herein to
"Fiscal 1995" with respect to CGGS shall mean CGGS' fiscal year ended October
31, 1995, references to the nine months ended September 30, 1996 with respect to
CGGS means the nine months ended October 31, 1996 and references to the balance
sheet as of September 30, 1996 means the CGGS balance sheet at October 31, 1996.
Except as otherwise noted, the reserve data for Abraxas reported in this
Prospectus are based on the reserve estimates of Abraxas' independent petroleum
engineers and the reserve data for CGGS reported in this Prospectus are based on
reserve estimates of CGGS' independent petroleum engineers. Except as otherwise
indicated herein, each reference herein to "on a pro forma basis" shall mean
that the results for the stated period or other information have been adjusted
to reflect the consummation of the Transactions (as defined herein). See
"Glossary of Terms" for definitions of certain terms used in this Prospectus.
The Company
The Company is an independent energy company engaged primarily in the
acquisition, exploration, development and production of crude oil and natural
gas. Since January 1, 1991, the Company's principal means of growth has been
through the acquisition and subsequent development and exploitation of producing
properties and related assets. The Company utilizes a disciplined acquisition
strategy, focusing its efforts on producing properties and related assets
possessing the following characteristics: a concentration of operations;
significant, quantifiable development potential; historically low operating
expenses; and the potential to reduce G&A expenses per BOE. The Company seeks to
complement its acquisition and development activities by selectively
participating in exploration projects with experienced industry partners. After
giving effect to the Recent Acquisitions, the Company's principal areas of
operation are Texas, western Canada and southwestern Wyoming. The Company owns
interests in 225,290 gross acres (126,845 net acres) and 507 gross wells (325.8
net wells), 352 of which are operated by the Company, and varying interests in
13 natural gas processing plants or compression facilities. On a pro forma
basis, at June 30, 1996, the Company would have had total proved reserves of
45,647 MBOE (64.9% natural gas), of which 81.7% would have been proved
developed. On a pro forma basis, for the nine months ended September 30, 1996,
the Company's EBITDA would have been $28.4 million.
The Company's acquisition, development, exploitation and exploration
activities have substantially increased the Company's proved reserve base,
average daily production and natural gas processing plant throughput while
decreasing its total operating and G&A expenses per BOE. After consummation of
the Recent Acquisitions, the Company has completed 16 acquisitions of producing
properties totaling 46,009 MBOE of proved reserves at an average net acquisition
cost of $3.83 per BOE since January 1, 1991. From January 1, 1991, on an
historical basis, to June 30, 1996, on a pro forma basis, the Company's total
proved reserves would have increased from 889 MBOE to 45,647 MBOE and aggregate
PV-10 would have increased from $11.9 million to $218.3 million. From January 1,
1991, on an historical basis, to the nine months ended September 30, 1996, on a
pro forma basis, average net daily production would have increased from 0.141
MBOE per day to 14.1 MBOE per day. On a pro forma basis, the Company would have
had net natural gas processing capacity of 128.1 MMcf per day as of September
30, 1996. In addition, on a pro forma basis, for the nine months ended September
30, 1996, average net daily natural gas processing plant throughput would have
been 87.4 MMcf per day, of which 27.3 MMcf would have been processed for third
parties, and net operating revenue from processing natural gas of third parties
at the Canadian Abraxas Plants (as defined herein) would have been $1.9 million.
From the year ended December 31, 1991, on an historical basis, to the nine
months ended September 30, 1996, on a pro forma basis, the Company's direct
operating expenses per BOE would have decreased from $6.30 per BOE to $2.81 per
BOE and G&A expenses per BOE would have decreased from $5.39 per BOE to $0.66
per BOE. As a result of the Company's successful acquisition strategy and its
ability to decrease its direct operating and G&A expenses per BOE, the Company's
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EBITDA (excluding interest income) has increased from $6.66 per BOE, for the
year ended December 31, 1991, to, on a pro forma basis, $7.24 per BOE, for the
nine months ended September 30, 1996.
The Company was founded in 1977 by Robert L.G. Watson, the Company's
Chairman of the Board, President and Chief Executive Officer. Canadian Abraxas
was formed by the Company in 1996 to acquire CGGS. The Company's principal
offices are located at 500 North Loop 1604 East, Suite 100, San Antonio, Texas
78232 and its telephone number is (210) 490-4788. Canadian Abraxas' principal
offices are located at 630 - 6th Avenue, S.W., Suite 303, Calgary, Alberta and
its telephone number is (403) 262-1949.
Business Strategy
The Company's primary business objectives are to: increase its
recoverable reserves, production and cash flow from operations through strategic
acquisitions; exploit and develop its producing properties; maintain low cost
operations; and pursue a focused exploration strategy. The Company seeks to
achieve its business objectives through the use of the following strategies:
o Disciplined Acquisition Strategy. The Company utilizes a disciplined
acquisition strategy, focusing its acquisition efforts on producing properties
and related assets possessing the following characteristics: a concentration of
operations; significant, quantifiable development potential; historically low
operating expenses; and the potential to reduce G&A expenses per BOE. The
success of the Company's acquisition strategy is illustrated by the following
table:
<TABLE>
<CAPTION>
Purchase Purchase Cummulative Cummulative June 30, 1996
Property Date Price(1) CapEx (2) Cash Flow (3) PV-10 IRR (4)
- ------------------------ -------- -------- ----------- ------------ ------------- --------
(dollars in millions)
<S> <C> <C> <C> <C> <C> <C>
Delaware Properties (5) 7/1/94 $ 25.0 $ 6.8 $ 6.0 $ 37.6 19.3%
Sinton Properties (6) 1/1/93 19.6 13.4 12.1(7) 43.0 21.4%
Sharon-Ridge/Westbrook 9/1/92 4.4 0.4 2.0 5.2 13.1%
Spraberry 7/1/94 3.2 3.0 0.9 7.1 18.5%
Happy 8/12/92 2.2 0.1 2.6(7) 2.0 31.0%
</TABLE>
- ----------------
(1) Purchase price is net of accrual of net revenue from the effective date
of acquisition to purchase date.
(2) Consists of capital expenditures on a cumulative basis from date of
purchase through June 30, 1996 (undiscounted).
(3) Consists of operating revenue less LOE on a cumulative basis from date
of purchase through June 30, 1996 (undiscounted).
(4) Internal rate of return ("IRR") was calculated assuming that the
purchase price for each property was paid on the purchase date and that
the cumulative capital expenditures and cumulative cash flow occurred
in equal monthly amounts over the time periods presented.
(5) Consist of the Company's interests in Cherry Canyon and the Delaware
Area (each as defined herein).
(6) Consist of the Company's interests in Portilla, East White Point and
Stedman Island (each as defined herein). Does not include the 50%
overriding royalty interest in Portilla, East White Point and Stedman
Island previously owned by the Pension Fund (as defined herein).
(7) Does not include results of operations of the Partnership (as defined
herein) from March 21, 1996 to June 30, 1996 or proceeds from the Acco
Sale (as defined herein).
In connection with the acquisition of the Sinton Properties, the Company
also acquired interests in two natural gas processing plants, one of which was
subsequently sold in the Acco Sale. See "-- Recent Acquisitions -- Portilla and
Happy." Since being acquired by the Company, the average net daily natural gas
processing throughput of these plants has increased by an average of 7.3% per
year, revenue has increased by an average of 24.5% per year and operating
expenses as a percentage of revenue have decreased by an average of 13.7% per
year.
o Exploitation Of Existing Properties. The Company allocates a significant
amount of its non-acquisition capital budget to the exploitation of its
producing properties. As of June 30, 1996, on a pro forma basis, approximately
18.3% (8,373 MBOE) of the Company's total proved reserves would have been
classified as proved undeveloped. Management believes that the proximity of
these undeveloped reserves to existing production makes development of these
properties less risky and more cost-effective than other drilling opportunities
available to the Company. The Company has identified 276 potential exploitation
opportunities on the Company's existing properties including those acquired in
the Recent Acquisitions. The Company drilled 38 wells during 1996 (including
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seven in western Canada) at a total cost of $13.2 million with a success rate of
90%. In addition, the Company performed 42 workovers or recompletions during
1996 at an estimated cost of $3.3 million and plans to drill 113 wells and
perform 48 workovers or recompletions during 1997 at an estimated cost of $33.3
million.
o Low Cost Operations. The Company seeks to maintain low operating and G&A
expenses per BOE by operating a majority of its producing properties and related
assets and by using contract personnel to assist with the development or
evaluation of producing properties and related assets. As a result of this
strategy, the Company's EBITDA Margin has consistently improved since 1991, even
in years with depressed commodity prices. From the year ended December 31, 1991
to, on a pro forma basis, the nine months ended September 30, 1996, the
Company's direct operating and G&A expenses per BOE have decreased by 55.4% and
87.8%, respectively, resulting in an improvement in EBITDA Margin as illustrated
below:
<TABLE>
<CAPTION>
Nine Months Ended
Year Ended December 31, September 30,
------------------------------------------------------ ------------------
Pro Pro
Forma Forma
(per BOE) (1) 1991 1992 1993 1994 1995 1995 1996 1996
----------- -------- -------- -------- -------- ------- --------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Total operating revenue(2) $ 18.35 $ 16.03 $ 15.98 $ 13.08 $ 12.15 $ 8.61(5) $ 14.08 $ 10.71(5)
Direct operating
operating expenses (3) 6.30 6.23 6.39 4.41 3.92 2.5(5) 4.21 2.81(5)
G&A 5.39 4.59 1.09 0.93 0.92 0.49 1.54 0.66
----------- -------- -------- -------- -------- ------- --------- --------
EBITDA (4) $ 6.66 $ 5.21 $ 8.50 $ 7.74 $ 7.31 $ 5.62(5) $ 8.33 $ 7.24(5)
EBITDA Margin 36.3% 32.5% 53.2% 59.2% 60.2% 65.3%(5) 59.2% 67.6%(5)
</TABLE>
- --------------------
(1) Amounts are calculated on the basis of dollars per BOE of production.
Production data does not include third-party natural gas processing
volumes.
(2) Consists of crude oil and natural gas production sales, revenue from
rig operations and processing of natural gas of third parties as well
as other miscellaneous revenue. Both historical and pro forma total
operating revenue for the nine months ended September 30, 1996 are
presented net of a loss from hedging activities incurred during such
period.
(3) Consists of lease operating expenses, production taxes, abandoned
projects, rig operating expenses and processing expenses.
(4) Does not include interest income.
(5) Includes results from the Hoole Area. See "--Recent Acquisitions
CGGS."
o Focused Exploration Activity. The Company allocates a portion of its capital
budget to the drilling of exploratory wells which have high reserve potential.
The Company believes that by devoting a relatively small amount of capital to
high impact, high risk projects while reserving the majority of its available
capital for development projects, it can reduce its risk profile while still
benefiting from the potential for significant reserve additions. See "Business
- -- Primary Operating Areas -- Exploration Opportunities."
Recent Acquisitions
The Company has recently acquired CGGS, the Wyoming Properties, Portilla
and Happy, East White Point and Stedman Island for an aggregate purchase price
of approximately $176.2 million (the "Recent Acquisitions"). The Company
believes that each of the Recent Acquisitions is consistent with the Company's
acquisition strategy.
CGGS
In November 1996, Canadian Abraxas acquired 100% of the outstanding
capital stock of CGGS, after the consummation of the sale of the Nevis Plant,
for CDN$126.4 million, or approximately U.S.$94.8 million, including
approximately $8.3 million for CGGS' working capital.
Canadian Abraxas owns producing properties in western Canada consisting
primarily of natural gas reserves (the "Canadian Abraxas Properties") and
interests ranging from 10% to 100% in 197 miles of natural gas gathering systems
and 11 natural gas processing plants or compression facilities (the "Canadian
Abraxas Plants"), four of which are operated by Canadian Abraxas. The Canadian
Abraxas Properties consist of 154,968 gross acres (86,327 net acres) and 120
gross wells (68.8 net wells), 48 of which are operated by Canadian Abraxas. As
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of September 1, 1996, the Canadian Abraxas Properties had total proved reserves
of 10,821 MBOE (91.8% natural gas) with an aggregate PV-10 of $46.4 million,
86.3% of which was attributable to proved developed reserves. The Canadian
Abraxas Plants had aggregate net natural gas processing capacity of 98.3 MMcf
per day at September 1, 1996. For the nine months ended September 30, 1996, the
Canadian Abraxas Plants processed an average of 182.8 gross MMcf (65.7 net MMcf)
of natural gas per day, of which 19.6% (39.7% net) was custom processed for
third parties. For the nine months ended September 30, 1996, the Canadian
Abraxas Properties and the Canadian Abraxas Plants would have contributed $10.3
million of EBITDA to the Company on a pro forma basis.
In January 1997, Canadian Abraxas entered into a letter of intent to sell
its interest in the Hoole Area for approximately $9.3 million. The Hoole Area
consists of 9,728 gross acres (3,311 net acres) and 6.4 gross wells (3.2 net
wells), none of which are operated by Canadian Abraxas. As of September 1, 1996,
the Hoole Area natural gas properties had total proved reserves of 1,477.0 MBOE
with an aggregate PV-10 of $6.3 million, 89.3% of which was attributable to
proved developed reserves. The Hoole Area natural gas processing plant had
aggregate net natural gas processing capacity of 32.0 MMcf per day at September
1, 1996. For the nine months ended September 30, 1996, the Hoole Area natural
gas processing plant processed an average of 18.9 gross MMcf (9.5 net MMcf) of
natural gas per day, of which 4.4% (2.2% net) was custom processed for third
parties. For the nine months ended September 30, 1996, the Hoole Area properties
and natural gas processing plants contributed $2.4 million of revenue to CGGS.
The Company believes that the Canadian Abraxas Properties have
significant, quantifiable development potential which can be realized through
exploitation and development. The Company believes that processing volumes at
the Canadian Abraxas Plants can be increased due to unutilized gross natural gas
processing throughput capacity at the plants of approximately 62.7 MMcf (32.4
net MMcf) of natural gas per day. The Company intends to utilize this excess
capacity by seeking to process additional natural gas volumes from third parties
and from increased production from the Canadian Abraxas Properties. In addition,
the Company believes that increases in the demand for natural gas from, Alberta,
Canada will help to reduce the existence of basis differentials in the pricing
of natural gas produced in this area. The Company believes that its ownership of
the Canadian Abraxas Properties and the Canadian Abraxas Plants will afford it a
competitive advantage relative to other area operators due to the Company's
preferential access to the natural gas processing capacity at these facilities.
Immediately after the acquisition of CGGS, the Company amalgamated CGGS
with Canadian Abraxas, and Canadian Abraxas, being the name of the surviving
entity, used the net proceeds from the sale of the Nevis Plant to retire the
outstanding debentures of CGGS. In addition, Canadian Abraxas intends to sell a
10% working interest in the Canadian Abraxas Properties and the Canadian Abraxas
Plants to Cascade, in connection with the Company's plan to integrate the
operations of the Canadian Abraxas Properties and the Canadian Abraxas Plants
into the existing operations of Cascade Oil & Gas Ltd., one of the Company's
Canadian subsidiaries ("Cascade"). The Company has identified potential cost
savings through anticipated decreases in the G&A expenses of CGGS, which would
have amounted to approximately $380,000 for the nine months ended September 30,
1996, on a pro forma basis. See the unaudited Pro Forma Financial Information
and the notes thereto included elsewhere in this Prospectus.
The Wyoming Properties
On September 30, 1996, the Company acquired producing properties with
total proved reserves of 9,935 MBOE (68.5% natural gas) as of June 30, 1996, in
the Wamsutter area of southwestern Wyoming (the "Wyoming Properties") for $47.5
million in cash, before adjustment for accrual of net revenue and interest from
April 1, 1996 to September 30, 1996. The Wyoming Properties consist of 19,587
gross acres (14,091 net acres) and 25 gross wells (20.4 net wells), 22 of which
are operated by the Company. In addition, the Company acquired various
overriding royalty interests in four wells. As of June 30, 1996, the aggregate
PV-10 of the Wyoming Properties was $30.3 million (based, in part, on an assumed
natural gas price of $1.07 per Mcf), 97.3% of which was attributable to proved
developed reserves. For the nine months ended September 30, 1996, the Wyoming
Properties would have contributed $5.4 million of EBITDA to the Company on a pro
forma basis. As of September 30, 1996, the Company had recorded the preliminary
net purchase price of $45.9 million to its crude oil and natural gas properties.
8
<PAGE>
Management believes that the Wyoming Properties have significant
development potential which will enable the Company to increase its cash flow
from operations and reserve base without significant capital expenditures. The
Company intends to exploit this development potential through the more efficient
use of compression and gathering facilities, low cost recompletions of various
behind-pipe zones and drilling of infill development wells on closer spacing.
The Company has drilled two wells on the Wyoming Properties since September 30,
1996. Additionally, the Company has identified potential exploitation and
development opportunities which it believes may have up to 15,400 MBOE of
additional reserves. The Wyoming Properties are geographically concentrated,
thereby enabling the Company to operate the properties without incurring
additional G&A expenses. In addition, the Company believes that expected
improvements in the transportation infrastructure and an increase in the demand
for natural gas from southwestern Wyoming will help to reduce the existence of
basis differentials in the pricing of natural gas produced in the area.
Portilla and Happy
In November 1996, the Company acquired a 75% partnership interest (the
"Partnership Interest") in Portilla-1996, L.P. (the "Partnership") for $27.6
million, including the repayment of certain indebtedness and before adjustment
for the accrual of net revenue to the closing date. The Company previously owned
the remaining 25% interest in the Partnership. The Partnership owned a 100%
working interest in the Portilla Field, located in the Texas Gulf Coast region
(the "Portilla Field"), a 100% interest in a natural gas processing plant
located at the Portilla Field (the "Portilla Plant" and, together with the
Portilla Field, "Portilla") and a 12% working interest in the Happy Field,
located in the Permian Basin of west Texas ("Happy"). Portilla and Happy consist
of 1,405 gross acres (1,115 net acres) and 78 gross wells (52 net wells), 61 of
which are operated by the Company. As of June 30, 1996, Portilla and Happy had
total proved reserves of 4,314 MBOE (18.4% natural gas) with an aggregate PV-10
of $30.2 million, 99.8% of which was attributable to proved developed reserves.
The Portilla Plant had natural gas processing capacity of approximately 20.0
MMcf per day at September 30, 1996. During the nine months ended September 30,
1996, the Portilla Plant processed an average of 18.2 MMcf of natural gas per
day. For the nine months ended September 30, 1996, Portilla and Happy would have
contributed an additional $3.8 million of EBITDA to the Company on a pro forma
basis.
The Company previously owned a 50% interest in Portilla and a 12% working
interest in Happy. In March 1996, the Company sold its interests in Portilla and
Happy to Acco, LLC ("Acco") for net consideration of $15.6 million (the "Acco
Sale"). Acco subsequently obtained the release of a 50% overriding royalty
interest in Portilla previously owned by the Commingled Pension Trust Fund
(Pension II), the trustee of which is Morgan Guaranty Trust Company of New York
(the "Pension Fund"), and Acco then contributed its interests in Portilla and
Happy to the Partnership in return for the Partnership Interest. The Company
continued to operate Portilla subsequent to the Acco Sale. See "Business Recent
Acquisitions -- Portilla and Happy."
East White Point and Stedman Island
In November 1996, the Company obtained the release of the 50%
overriding royalty interests in the East White Point Field, San Patricio
Country, Texas ("East White Point") and the Stedman Island Field, Nueces County,
Texas ("Stedman Island") from the Pension Fund for $9.3 million, before
adjustment for accrual of net revenue from August 1, 1996 to November 27, 1996.
The Pension Fund's interest in East White Point and Stedman Island consisted of
3,723 gross acres (1,256 net acres) and 25 gross wells (6.5 net wells), 15 of
which are operated by the Company. As of June 30, 1996, East White Point and
Stedman Island had total proved reserves of 5,304 MBOE (62.5% natural gas) with
an aggregate PV-10 of $29.4 million, 71.7% of which was attributable to proved
developed reserves. The East White Point natural gas processing plant, a modern
cyrogenic plant with capacity of approximately 25.0 MMcf of natural gas per day,
extracted approximately 679 Bbls of NGLs per day for the nine months ended
September 30, 1996.
9
<PAGE>
The Transactions
The initial offering of the Notes (the "Offering"), the execution of the
New Credit Facility, the repayment of the indebtedness under the Company's $85.0
million revolving credit and term loan facility with BTCo. and ING Capital (the
"Bridge Facility") and the consummation of the Recent Acquisitions are
collectively referred to herein as the "Transactions."
Risk Factors
See "Risk Factors" for a discussion of certain factors that should be
considered in evaluating an investment in the Notes.
10
<PAGE>
PURPOSE OF THE EXCHANGE OFFER
The Exchange Offer provides holders of the Series A Notes with
the Exchange Notes which will generally be freely transferable by the holders
thereof without registration or any prospectus delivery requirement under the
Securities Act. The Issuers' purpose in engaging in the Exchange Offer is to
provide holders of the Series A Notes with freely transferable securities and to
comply with the provisions of the Registration Rights Agreement which require,
subject to certain conditions, that the Exchange Offer be made. See "Purpose of
the Exchange Offer".
THE EXCHANGE OFFER
Exchange Ratio Each Series A Note is exchangeable
for a like principal amount of Exchange
Notes.
Expiration Date 5:00 p.m., New York City time, on
March 14, 1997 unless extended, in which
case the term "Expiration Date" means
the latest date and time to which the
Exchange Offer shall have been extended.
Principal Amount of Notes Subject to the terms and conditions of
the Exchange Offer, any and all Series A
Notes will be accepted if duly tendered
and not withdrawn prior to acceptance
thereof. The Exchange Offer is not
conditioned upon any minimum principal
amount of the Series A Notes being
tendered. The Indenture limits the
aggregate amount of the Notes, including
the Series A Notes and the Exchange
Notes, which may be outstanding to
$215.0 million principal amount, all of
which is currently in the form of the
Series A Notes.
Trading and Market Price The Series A Notes are currently
eligible for quotation through the
National Association of Securities
Dealers, Inc.'s PORTAL system. Prior to
the date hereof, there has been only a
private institutional trading market for
the Series A Notes. It is anticipated
that a similar trading market will exist
for the Exchange Notes following the
Exchange Offer. BT Securities
Corporation, Jefferies & Company, Inc.
and ING Baring (U.S.) Securities
Corporation (the "Initial Purchasers")
have advised the Issuers that they
intend to act as market makers for the
Exchange Notes; however, they are not
obligated to do so and may discontinue
market making activities with respect to
the Exchange Notes at any time. See
"Risk Factors -- Lack of Public Market."
Conditions of the Exchange Offer The Issuers' obligation to consummate
the Exchange Offer is subject to certain
conditions. See "The Exchange Offer --
Conditions." Tenders of the Series A
Notes may be withdrawn at any time prior
to the Expiration Date. See "The
Exchange Offer -- Withdrawal Rights."
11
<PAGE>
How to Tender Tendering holders of the Series A Notes
must either (i) complete and sign a
Letter of Transmittal, have their
signatures guaranteed if required,
forward the Letter of Transmittal and
any other required documents to the
Exchange Agent at the address set forth
under the caption "Exchange Agent", and
either deliver the Series A Notes to the
Exchange Agent or tender such Series A
Notes pursuant to the procedures for
book-entry transfer or (ii) request a
broker, dealer, bank, trust company or
other nominee to effect the transaction
for them. Beneficial owners of the
Series A Notes registered in the name of
a broker, dealer, bank, trust company or
other nominee must contact such
institution to tender their Series A
Notes. The Series A Notes may be
physically delivered, but physical
delivery is not required if a
confirmation of a book-entry transfer of
such Series A Notes to the Exchange
Agent's account at DTC is delivered in a
timely fashion. Certain provisions have
also been made for holders whose Series
A Notes are not readily available or who
cannot comply with the procedure for
book-entry transfer on a timely basis.
Questions regarding how to tender and
requests for information should be
directed to the Exchange Agent. See "The
Exchange Offer -- How to Tender."
Acceptance of Tenders Subject to the terms and conditions of
the Exchange Offer, including the
reservation of certain rights by the
Issuers, the Series A Notes validly
tendered prior to the Expiration Date
will be accepted promptly after such
Expiration Date. Subject to such terms
and conditions, the Exchange Notes to be
issued in exchange for validly tendered
Series A Notes will be mailed by the
Exchange Agent promptly after acceptance
of the tendered Series A Notes or
credited to the holder's account in
accordance with appropriate book-entry
procedures. Although the Issuers do not
currently intend to do so, if they
modify the terms of the Exchange Offer
prior to the Expiration Date, such
modified terms will be available to all
holders of the Series A Notes, whether
or not their Series A Notes have been
tendered prior to such modification. Any
material modification will be disclosed
in accordance with the applicable rules
of the Commission and, if required, the
Exchange Offer will be extended to
permit holders of the Series A Notes
adequate time to consider such
modification. See "The Exchange Offer --
Acceptance of Tenders."
Exchange Agent IBJ Schroder Bank & Trust Company, One
State Street, New York, New York 10004,
Attention: Reorganization Operations
Department
Securities Offered $215,000,000 aggregate principal amount
11.5% Senior Notes due 2004.
12
<PAGE>
Issuers Abraxas Petroleum Corporation and
Canadian Abraxas Petroleum Limited, as
joint and several obligors.
Maturity Date November 1, 2004.
Interest Payment Dates Interest on the Notes will
accrue from the Issue Date and will be
payable semi-annually on each May 1 and
November 1, commencing May 1, 1997.
Ranking The Notes will be general unsecured
obligations of the Issuers and will rank
pari passu to all existing and future
unsubordinated indebtedness of the
Issuers and senior to all future
subordinated indebtedness of the
Issuers. The Notes will be effectively
subordinated in right of payment to all
existing and future secured indebtedness
of the Issuers.
Optional Redemption The Notes will be redeemable, in whole
or in part, at the option of the Issuers
on or after November 1, 2000, at the
redemption prices set forth herein, plus
accrued and unpaid interest to the date
of redemption. In addition, at any time
on or prior to November 1, 1999, the
Issuers may, at their option, redeem up
to 35% of the aggregate principal amount
of the Notes with the net cash proceeds
of one or more Equity Offerings at a
redemption price equal to 111.5% of the
aggregate principal amount of the Notes
to be redeemed, plus accrued and unpaid
interest to the date of redemption;
provided, however, that, after giving
effect to any such redemption, at least
$139.75 million aggregate principal
amount of the Notes remains outstanding.
Change of Control Upon a Change of Control, each holder
will have the right to require the
Issuers to repurchase such holder's
Notes at a redemption price equal to
101% of the principal amount thereof
plus accrued and unpaid interest to the
date of repurchase. In addition, the
Issuers will be obligated to offer to
repurchase the Notes at 100% of the
principal amount thereof plus accrued
and unpaid interest to the date of
redemption in the event of certain asset
sales.
Guarantees The Notes will be guaranteed (the
"Guarantees") on a senior basis by each
of the Subsidiary Guarantors. The
Guarantees will be general unsecured
obligations of the Subsidiary Guarantors
and will rank pari passu to all
unsubordinated indebtedness of the
Subsidiary Guarantors. The Guarantees
will be effectively subordinated in
right of payment to secured indebtedness
of the Subsidiary Guarantors.
13
<PAGE>
Certain Covenants The Indenture governing the Notes (the
"Indenture") will contain certain
covenants that limit the ability of the
Issuers and their Restricted
Subsidiaries (as defined herein) to,
among other things, incur additional
indebtedness, pay dividends or make
certain other restricted payments,
consummate certain asset sales, enter
into certain transactions with
affiliates, incur liens, and imposes
restrictions on the ability of a
Restricted Subsidiary to pay dividends
or make certain payments to the Issuers
and their Restricted Subsidiaries, merge
or consolidate with any other person or
sell, assign, transfer, lease, convey or
otherwise dispose of all or
substantially all of the assets of
either of the Issuers.
For additional information regarding the Exchange Notes, see "Description
of the Notes."
14
<PAGE>
EXCHANGE OFFER; REGISTRATION RIGHTS; ADDITIONAL INTEREST
In the Registration Rights Agreement, the Issuers agreed (i) to file
within 45 days after the Issue Date, and to cause to become effective within 120
days after the Issue Date, a registration statement with respect to the Exchange
Offer, and (ii) upon the Exchange Offer Registration Statement's being declared
effective, to offer the Exchange Notes in exchange for surrender of the Series A
Notes. If the Issuers do not comply with their registration obligations in a
timely manner, they will be required to pay additional interest (in addition to
the scheduled payment of interest) during the first 90 day period of such
default in an amount equal to 0.50% per annum at the end of such 90 day period.
The amount of the additional interest will increase by an additional 0.50% per
annum for each subsequent 90 day period until such obligations are complied
with, up to a maximum amount of additional interest of 2.00% per annum. In the
event that applicable interpretations of the staff of the Commission do not
permit the Issuers to effect the Exchange Offer, or if for any other reason the
Exchange Offer is not consummated within 150 days of the Issue Date, or if
certain holders of the Series A Notes are not permitted to receive the benefit
of the Exchange Offer, the Issuers will use their best efforts to cause to
become effective a shelf registration statement with respect to the resale of
the Series A Notes and to keep such shelf registration statement effective until
the earlier of three years after its effective date and such time as all of the
Series A Notes have been sold thereunder.
15
<PAGE>
Summary Historical and Pro Forma Financial Information
The following table presents summary historical consolidated financial
data of the Company for the five years ended December 31, 1995, and as of and
for the nine months ended September 30, 1995 and 1996, which have been derived
from the Company's consolidated financial statements and unaudited historical
and pro forma financial data. The pro forma data give effect to the consummation
of the Transactions. The unaudited Pro Forma Condensed Balance Sheet reflects
such adjustments as if the Transactions had occurred at September 30, 1996, and
the unaudited Pro Forma Statements of Operations for the year ended December 31,
1995 and for the nine months ended September 30, 1996 reflect such adjustments
as if the Transactions had occurred on January 1, 1995 and January 1, 1996,
respectively. The historical consolidated financial data of the Company as of
and for the nine months ended September 30, 1995 and 1996 have been derived from
the Company's interim consolidated financial statements which, in the opinion of
management of the Company, have been prepared on the same basis as the audited
consolidated financial statements and include all adjustments (consisting of
only normal recurring adjustments) necessary for a fair presentation of the
financial data for such periods. The statement of operations data for the nine
months ended September 30, 1996 is not necessarily indicative of results for a
full year. The information in this table should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations," "Selected Consolidated Financial Data," the Consolidated Financial
Statements and the notes thereto and the unaudited Pro Forma Financial
Information and the notes thereto included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
Nine Months Ended
Year Ended December 31, September 30,
------------------------------------------------------------------- ------------------------------
Pro Pro
Forma Forma
1991 1992 1993 1994 1995 1995 (1)(2) 1995 1996 1996(2)
-------- --------- --------- -------- -------- ------------ ------- --------- ---------
(dollars in thousands, except ratios)
Consolidated Statement of
Operations Data:
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Total operating revenue (3) .. $ 1,150 $ 2,691 $ 7,494 $ 11,349 $ 13,817 $ 45,696 $ 9,929 $ 11,909 $ 42,251
Operating expense (4) ........ 322 1,075 2,964 3,826 4,458 13,283 3,278 3,408 10,855
DD&A expense ................. 361 957 2,373 3,790 5,434 21,092 3,541 4,145 17,664
G&A expense .................. 338 770 510 810 1,042 2,592 769 1,250 2,545
Interest expense ............. 132 906 2,531 2,359 3,911 24,276 2,915 2,142 18,151
Amortization of deferred
financing fee ............... -- -- 649 400 214 1,025 120 192 769
Income (loss) from continuing
operations before
extraordinary items ......... (15) (1,072) (1,580) 113 (1,208) (15,917) (685) 122 (8,034)
Preferred stock dividends .... (249) (249) (186) (183) (366) (366) (274) (274) (274)
Net income (loss)applicable
to common stock ............. $ (264) $ (4,204) $ (2,619) $ (2,577) $ (1,574) $(16,283) $ (959) $ (520) $ (8,308)
Other Data:
EBITDA (5) ................... $ 168 $ 760 $ 4,049 $ 6,728 $ 8,351 $ 29,893 $ 5,892 $ 6,894 $ 28,403
Capital expenditures ......... $ 2,940 $ 7,866 $ 26,234 $ 40,906 $ 12,256 $ 22,842 $ 9,223 $ 58,040 $ 66,036
Ratio of EBITDA to fixed
charges (6) (7) ............. 1.27x -- 1.27x 2.44x 2.02x 1.18.x 1.94x 2.95x 1.50x
Ratio (deficiency) of earnings
to fixed charges(8)(9) ...... -- -- -- 1.04x -- -- -- 1.05x --
Ratio (deficiency) of
earnings to combined
fixed charges and preferred
stock dividends (10)(11) ... -- -- -- -- -- -- -- -- --
September 30, 1996(2)
-----------------------
Historical Pro Forma
---------- -----------
Consolidated Balance Sheet Data: (dollars in thousands)
Cash and cash equivalents $ 9,993 $ 11,486
Total assets 130,440 291,824
Total debt (12) 85,123 215,124
Shareholders' equity (11) 36,421 36,197
ACNTA (13) 293,761
Ratio of ACNTA to total debt (14) 1.37x
- --------------
</TABLE>
(1) The results of operations of CGGS for 1995 included herein reflect CGGS'
results of operations for its fiscal year ended October 31, 1995.
(2) Includes results from the Hoole Area. See " - Recent Acquisitions -
CGGS."
(3) Consists of crude oil and natural gas production sales, revenue from rig
operations and processing facilities and other miscellaneous revenue.
(4) Consists of lease operating and production taxes, rig operating expenses
and processing expenses.
16
<PAGE>
(5) EBITDA is defined as income (loss) from continuing operations before
income taxes, interest expense, DD&A, amortization of deferred financing
fee and other non-cash charges. The Company believes that the
presentation of EBITDA facilitates an investor's understanding of a
company's ability to service and/or incur indebtedness. EBITDA should not
be considered by an investor as an alternative to net income as an
indicator of the Company's operating performance or to cash flows as a
measure of liquidity.
(6) Fixed charges consist of interest expense and amortization of deferred
financing fees.
(7) The Company's EBITDA was inadequate to cover fixed charges in 1992 by
$146,000.
(8) Earnings consist of income (loss) from continuing operations before
income taxes plus fixed charges. Fixed charges consist of interest
expense and amortization of deferred financing fees.
(9) The Company's earnings were inadequate to cover fixed charges in 1991,
1992, 1993, and 1995 by $15,000, $1,072,000, $1,393,000, and $1,208,000,
respectively, for pro forma 1995 by $16,500,000, for the nine months
ended September 30, 1995 by $684,000, and for the pro forma nine months
ended September 30, 1996 by $8,474,000.
(10) Earnings consist of income (loss) from continuing operations before
income tax plus interest expense and amortization of deferred financing
fees. Fixed charges and preferred stock dividends consist of interest
expense, amortization of deferred financing fees and preferred stock
dividends.
(11) The Company's earnings were inadequate to cover fixed charges and
preferred stock dividends in 1991, 1992, 1993, 1994 and 1995 by $264,000,
$1,321,000, $1,579,000, $70,000 and $1,574,000, respectively, for the pro
forma 1995 by $16,866,000, for the nine months ended September 30, 1995
and 1996 by $958,000 and $152,000, respectively, and for the pro forma
nine months ended September 30, 1996 by $8,748,000.
(12) Consists of long-term debt, including capital lease obligations.
(13) Consists of 5,804,812 shares of the Company's Common Stock, par value
$.01 per share, of which 70,711 are treasury shares, and 45,741 shares of
the Company's Series 1995-B Preferred Stock, par value $.01 per share
("Series 1995-B Preferred"). Each share of Series 1995-B Preferred Stock
has a liquidation preference of $100, is entitled to cumulative annual
dividends of $8.00 per share payable quarterly and is convertible into
11.11 shares of Common Stock.
(14) Adjusted Consolidated Net Tangible Assets ("ACNTA"). Pro Forma ACNTA
includes: $218,292,000 of PV-10, $12,104,000 of working capital,
$32,660,000 of book value for the processing plants, $28,628,000 of book
value for unproved properties, $3,372,000 of book value for other
properties and equipment, $858,000 of book value for other tangible
assets less $2,153,000 of book value for minority interest.
17
<PAGE>
Summary Historical and Pro Forma Reserve and Operating Data
The following table sets forth summary information with respect
to the Company's estimated proved crude oil, NGLs and natural gas reserves and
certain summary information with respect to the Company's operations for the
periods indicated. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations," the Company's Consolidated Financial
Statements and the notes thereto and the unaudited Pro Forma Financial
Information and the notes thereto included elsewhere in this Prospectus. The pro
forma reserve data at December 31, 1995 and June 30, 1996 give effect to the
Transactions as if they had occurred on December 31, 1995 and June 30, 1996,
respectively, and the pro forma operations data for the year ended December 31,
1995 and the nine months ended September 30, 1996 give effect to the
Transactions as if they had occurred on January 1, 1995 and January 1, 1996,
respectively.
<TABLE>
<CAPTION>
Six Months Ended June 30,
---------------------------
Historical Pro Historical Pro
------------------------ Forma ------------------ Forma
1993 1994 1995 1995(1) 1995 1996 1996(2)
------- ------- ------ ------- -------- -------- --------
Estimated Proved
Reserves (period-end):
- --------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Crude oil and NGLs (MBbls) 4,086 9,156 8,267 16,547 n/a(3) 6,513 16,039
Natural gas (MMcf) 16,591 67,579 54,569 191,593 n/a(3) 52,566 177,651
Crude oil equivalents
(MBOE) 6,851 20,420 17,362 48,479 n/a(3) 15,274 45,647
% Proved developed 87.7% 67.9% 76.8% 80.8% n/a(3) 76.9% 81.7%
Estimated future net
revenue before income
taxes (in thousands) $64,257 $153,476 $164,058 $402,445(4) n/a(3) $157,153 $414,497(4)
PV-10 (in thousands) 41,095 78,868 89,992 223,790(4) n/a(3) 81,925 218,292(4)
%Proved developed 89.9% 76.7% 78.4% 90.2% n/a(3) 79.7% 85.3%
Reserve Life (years):(5) 14.6 23.5 15.3 9.2 n/a(3) 13.8(6) 8.7(6)
Reserve Replacement
Rate:(7) 1,017% 1,664% (116%) 640% n/a(3) 207% 1,075%
<CAPTION>
Nine Months Ended
September 30,
-------------------------------
Historical Pro Forma
------------------ -----------
1995 1996 1996 (1)
-------- -------- -----------
Average Net Daily Production:
<S> <C> <C> <C> <C> <C> <C> <C>
Crude oil and NGLs (Bbls) 835 1,285 1,493 3,668 1,423 1,358 4,071
Natural gas (Mcf) 2,700 6,556 9,733 65,275 9,654 9,582 60,340
Average Sales Price:
Crude oil (per Bbl) $ 15.54 $15.47 $ 17.16 $ 17.18 $ 17.24 $ 19.94 $ 20.04
NGLs (per Bbl) 14.75 10.54 10.83 7.82 10.94 12.73 10.89
Natural gas (per Mcf) 2.60 1.85 1.47 1.01 1.41 1.95 1.30
Natural Gas Processing
Plants:
Net plant capacity
(MMcfpd) (period end) 25 25 25 123 25 25 128
(period-end)
Percentage utilization 52.6% 58.3% 62.4% 60.7% 62.1% 64.1% 68.2%
Percentage of throughput
attributable to
third-party processing 7.9% 5.3% 9.3% 35.3% 9.1% 11.0% 31.2%
</TABLE>
- ----------------
(1) The operations data of CGGS for 1995 included herein reflect CGGS'
operations data (including the Hoole Area) for its fiscal year ended
October 31, 1995. CGGS' operations data for the nine months ended
September 30, 1996 included herein reflect CGGS' operations data
(including the Hoole Area) for the nine months ended October 31, 1996.
(2) Includes reserve information for the Company, the Wyoming Properties,
Portilla and Happy and East White Point and Stedman Island at June 30,
1996 and the Canadian Abraxas Properties (including the Hoole Area) at
September 1, 1996. Does not include reserves of Cascade.
(3) Not available. Reserve information for 1995 was prepared by the Company's
independent petroleum engineers as of January 1, 1996 only.
(4) Does not include the present value of future net cash flow from
processing natural gas of third parties at the Canadian Abraxas Plants.
(5) Except as otherwise noted, Reserve Life is calculated as proved reserves
divided by annual production, both on a BOE basis.
(6) Based on reserve data as of June 30, 1996 (and September 1, 1996 with
respect to the CGGS reserve data included in the pro forma calculation
which includes the reserve data for the Hoole Area), and production for
the six months ended June 30, 1996, annualized to derive estimated annual
production.
(7) Reserve replacement rate is calculated as reserve additions in the period
divided by production for the period, both on a BOE basis.
18
<PAGE>
RISK FACTORS
Prospective investors should carefully consider the following factors in
addition to the other information in this Prospectus before making an investment
in the Notes offered hereby.
High Degree of Leverage
As adjusted for the consummation of the Transactions, the Company's total
debt and stockholders' equity would have been approximately $215.1 million and
$36.2 million, respectively, as of September 30, 1996. See "Capitalization." In
addition, the Company has entered into the New Credit Facility, under which the
Company's borrowing capacity is an initial maximum of up to $20.0 million. For
the year ended December 31, 1995 and the nine months ended September 30, 1996,
on a pro forma basis, the Company's ratio of EBITDA to fixed charges would have
been 1.18x and 1.50x, respectively, and its ratio of earnings to fixed charges
and preferred stock dividends would have been inadequate to cover fixed charges
by $16.9 million and $8.7 million, respectively. The Company intends to incur
additional indebtedness in the future in connection with acquiring, developing
and exploiting producing properties, although the Company's ability to incur
additional indebtedness may be limited by the terms of the Indenture and the New
Credit Facility. See "Description of the Notes," "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Liquidity and
Capital Resources" and the unaudited Pro Forma Financial Information and the
notes thereto included elsewhere in this Prospectus
The Company's level of indebtedness will have several important effects
on its future operations including (i) a substantial portion of the Company's
cash flow from operations will be dedicated to the payment of interest on its
indebtedness and will not be available for other purposes; (ii) covenants
contained in the Company's debt obligations will require the Company to meet
certain financial tests and other restrictions which will limit its ability to
borrow additional funds or to dispose of assets and may affect the Company's
flexibility in planning for, and reacting to, changes in its business, including
possibly limiting acquisition activities; and (iii) the Company's 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 may be limited. See "Description of
the Notes -- Certain Covenants -- Limitation on Incurrence of Additional
Indebtedness" and "Management's Discussion and Analysis of Financial Condition
and Results of Operations - Liquidity and Capital Resources."
The Company's ability to meet its debt service obligations and to reduce
its total indebtedness will be dependent upon the Company's future performance,
which will be subject to general economic conditions and to financial, business
and other factors affecting the operations of the Company, many of which are
beyond its control. Based upon the current level of operations and the
historical production of the producing properties and related assets currently
owned by the Company, the Company believes that its cash flow from operations as
well as borrowing capabilities will be adequate to meet its anticipated
requirements for working capital, capital expenditures, interest payments,
scheduled principal payments and general corporate or other purposes for the
foreseeable future. See the unaudited Pro Forma Financial Information and the
notes thereto included elsewhere in this Prospectus, the Company's Consolidated
Financial Statements and the notes thereto included elsewhere in this Prospectus
and "Management's Discussion and Analysis of Financial Condition and Results of
Operations -Liquidity and Capital Resources." No assurance can be given,
however, that the Company's business will continue to generate cash flow from
operations at or above current levels or that the historical production of the
producing properties and related assets currently owned by the Company can be
sustained in the future. If the Company is unable to generate cash flow from
operations in the future to service its debt, it may be required to refinance
all or a portion of its existing debt or to obtain additional financing. There
can be no assurance that such refinancing would be possible or that any
additional financing could be obtained. In addition, the Notes are subject to
certain limitations on redemption. See "Description of the Notes -- Redemption"
and "Management's Discussion and Analysis of Financial Condition and Results of
Operations - Liquidity and Capital Resources."
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Ranking of Indebtedness
The Notes will be general unsecured obligations of the Issuers and will
rank pari passu in right of payment to all existing and future unsubordinated
indebtedness of the Issuers and senior in right of payment to all future
subordinated indebtedness of the Issuers. In addition, the Notes will be
unconditionally guaranteed, jointly and severally, by each of the Subsidiary
Guarantors. The Guarantees will be general unsecured obligations of the
Subsidiary Guarantors and will rank pari passu in right of payment to all
existing and future unsubordinated indebtedness of the Subsidiary Guarantors and
senior in right of payment to all present and future subordinated indebtedness
of the Subsidiary Guarantors. However, the Notes will be effectively
subordinated to secured indebtedness of the Issuers and the Subsidiary
Guarantors to the extent of the value of the assets securing such indebtedness.
As of September 30, 1996, on a pro forma basis, the Issuers and the Subsidiary
Guarantors would have had $215.1 million of indebtedness outstanding, none of
which would have been secured, and $20.0 million of availability under the New
Credit Facility, which borrowings will be secured. See "Capitalization,"
"Description of the Notes" and "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Liquidity and Capital
Resources."
Repurchase of Notes Upon a Change of Control
Upon the occurrence of a Change of Control, the Issuers must offer to
purchase all of the Notes then outstanding at a purchase price equal to 101% of
the principal amount thereof, plus accrued interest to the date of purchase (a
"Change of Control Offer"). See "Description of the Notes -- Change of Control."
Prior to commencing such an offer to purchase, the Issuers may be
required to (i) repay in full all indebtedness of the Issuers that would
prohibit the repurchase of the Notes, including that under the New Credit
Facility, or (ii) obtain any requisite consent to permit the repurchase. See "
Management's Discussion and Analysis of Financial Condition and Results of
Operations - Liquidity and Capital Resources." If the Issuers were unable to
repay all of such indebtedness or were unable to obtain the necessary consents,
then the Issuers would be unable to offer to repurchase the Notes and such
failure would constitute an Event of Default under the Indenture. There can be
no assurance that the Issuers will have sufficient funds available at the time
of any Change of Control to repurchase the Notes.
The events that require a Change of Control Offer under the Indenture may
also constitute events of default under the New Credit Facility. Such events may
permit the lenders under such debt instruments to accelerate the payment of the
debt and, if the debt is not paid, to commence litigation which could ultimately
result in a sale of substantially all of the assets of the Company to satisfy
the debt, thereby limiting the Company's ability to raise cash to repurchase the
Notes and reducing the practical benefit of the offer to purchase provisions to
the holders of the Notes.
Net Losses
The Company has experienced recurring losses. For the years ended
December 31, 1992, 1993, 1994 and 1995, and the nine months ended September 30,
1996, the Company recorded net losses of $4.0 million, $2.4 million, $2.4
million, $1.2 million and $0.2 million, respectively. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the Company's Consolidated Financial Statements and the notes thereto included
elsewhere in this Prospectus.
Industry Conditions; Impact on Company's Profitability
The Company's revenue, profitability and future rate of growth are
substantially dependent upon prevailing prices for crude oil and natural gas.
Crude oil and natural gas prices can be extremely volatile and in recent years
have been depressed by excess total domestic and imported supplies. Prices are
also affected by actions of state and local agencies, the United States and
foreign governments and international cartels. While prices for crude oil and
natural gas increased during the fourth quarter of 1995 and remained at these
levels during 1996, there can be no assurance that these levels for crude oil
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and natural gas prices can be sustained. These external factors and the volatile
nature of the energy markets make it difficult to estimate future prices of
crude oil and natural gas. Any substantial or extended decline in the prices of
crude oil and natural gas would have a material adverse effect on the Company's
financial condition and results of operations, including reduced cash flow and
borrowing capacity. All of these factors are beyond the control of the Company.
Sales of crude oil and natural gas are seasonal in nature, leading to
substantial differences in cash flow at various times throughout the year.
Federal and state regulation of crude oil and natural gas production and
transportation, general economic conditions, changes in supply and changes in
demand all could adversely affect the Company's ability to produce and market
its crude oil and natural gas. If market factors were to change dramatically,
the financial impact on the Company could be substantial. The availability of
markets and the volatility of product prices are beyond the control of the
Company and thus represent a significant risk.
In addition, declines in crude oil and natural gas prices might, under
certain circumstances, require a write-down of the book value of the Company's
crude oil and natural gas properties. If such declines were severe enough, they
could result in the occurrence of an event of default under the Notes or the New
Credit Facility that could require the sale of some of the Company's producing
properties under unfavorable market conditions or require the Company to seek
additional equity capital. In addition, the Indenture and the New Credit
Facility contain certain restrictions on certain sales of assets by the Company.
See "Description of the Notes" and "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Liquidity and Capital
Resources."
In order to manage its exposure to price risks in the marketing of its
crude oil and natural gas, the Company from time to time has 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, the
Company 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 its futures position and sell its production
to a customer. Such contracts may expose the Company to the risk of financial
loss in certain circumstances, including instances where production is less than
expected, the Company's 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. Such contracts may also restrict the
ability of the Company to benefit from unexpected increases in crude oil and
natural gas prices.
Restrictions Imposed by Terms of the Company's Indebtedness
The Indenture and the New Credit Facility will restrict, among other
things, the Company's ability to incur additional indebtedness, incur liens, pay
dividends or make certain other restricted payments, consummate certain asset
sales, enter into certain transactions with affiliates, merge or consolidate
with any other person or sell, assign, transfer, lease, convey or otherwise
dispose of all or substantially all of the assets of the Company. In addition,
the New Credit Facility will contain additional and more restrictive covenants.
The Indenture and the New Credit Facility also will require the Company to
maintain specified financial ratios and satisfy certain financial tests. The
Company's ability to meet such financial ratios and tests may be affected by
events beyond its control, and there can be no assurance that the Company will
meet such ratios and tests. See "Description of the Notes -- Certain Covenants"
and "Management's Discussion and Analysis of Financial Condition and Results of
Operations - Liquidity and Capital Resources." A breach of any of these
covenants could result in a default under the Indenture and/or the New Credit
Facility. Upon the occurrence of an event of default under the New Credit
Facility, the lenders thereunder could elect to declare all amounts outstanding
under the New Credit Facility, together with accrued interest, to be immediately
due and payable. If the Company were unable to repay those amounts, such lenders
could proceed against the collateral granted to them to secure that
indebtedness. If the lenders under the New Credit Facility accelerate the
payment of such indebtedness, there can be no assurance that the assets of the
Company would be sufficient to repay in full such indebtedness and the other
indebtedness of the Company, including the Notes. Substantially all of the
Company's U.S. assets, including, without limitation, working capital and
interests in producing properties and related assets owned by the Company, and
the proceeds thereof will be pledged as security under the New Credit Facility.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations - Liquidity and Capital Resources."
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Substantial Capital Requirements
The Company makes, and will continue to make, substantial capital
expenditures for the acquisition, exploitation, development, exploration and
production of crude oil and natural gas reserves. Historically, the Company has
financed these expenditures primarily with cash flow from operations, bank
borrowings and the offering of its equity securities. The Company believes that
it will have sufficient capital to finance planned capital expenditures. If
revenue or the Company's borrowing base under the New Credit Facility decrease
as a result of lower crude oil and natural gas prices, operating difficulties or
declines in reserves, the Company may have limited ability to finance planned
capital expenditures in the future. There can be no assurance that additional
debt or equity financing or cash generated by operations will be available to
meet these requirements. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources."
Integration of Operations; Foreign Operations
The Company's future operations and earnings will be largely dependent
upon the Company's ability to integrate the operations of Canadian Abraxas and
the Wyoming Properties into the current operations of the Company. The
operations of Canadian Abraxas and the Wyoming Properties vary in geography from
those of the Company prior to the consummation of the Transactions, and with
respect to Canadian Abraxas, to some extent, in scope and type, from those of
the Company prior to the consummation of the Transactions. There can be no
assurance that the Company will be able to successfully integrate such
operations with those of the Company, and a failure to do so would have a
material adverse effect on the Company's financial position, results of
operations and cash flows. Additionally, although the Company does not currently
have any specific acquisition plans, the need to focus management's attention on
integration of the new operations, as well as other factors, may limit the
Company's ability to successfully pursue acquisitions or other opportunities
related to its business for the foreseeable future. Also, successful integration
of operations will be subject to numerous contingencies, some of which are
beyond management's control. These contingencies include general and regional
economic conditions, prices for crude oil and natural gas, competition and
changes in regulation. Even if the Company were successful in integrating the
new operations, the acquisition of CGGS in particular will significantly
increase the Company's dependence on international operations, specifically
those in Canada, and therefore the Company will be subject to various additional
political, economic and other uncertainties. Among other risks, the Company's
operations will be subject to the risks of restrictions on transfers of funds,
export duties and quotas, domestic and international customs and tariffs, and
changing taxation policies, foreign exchange restrictions, political conditions
and governmental regulations. In addition, the Company will receive a
substantial portion of its revenue in Canadian dollars. As a result,
fluctuations in the exchange rates of the Canadian dollar with respect to the
U.S. dollar could have an adverse effect on the Company's financial position,
results of operations and cash flows. The Company may from time to time engage
in hedging programs intended to reduce the Company's exposure to currency
fluctuations.
Future Availability of Natural Gas Supply
To obtain volumes of committed natural gas reserves to supply the
Canadian Abraxas Plants, Canadian Abraxas will contract to process natural gas
with various producers. Future natural gas supplies available for processing at
the Canadian Abraxas Plants will be affected by a number of factors that are not
within the Company's control, including the depletion rate of natural gas
reserves currently connected to the Canadian Abraxas Plants and the extent of
exploration for, production and development of, and demand for natural gas in
the areas in which Canadian Abraxas will operate. Long-term contracts will not
protect Canadian Abraxas from shut-ins or supply curtailments by natural gas
suppliers. Although CGGS was historically successful in contracting for new
natural gas supplies and in renewing natural gas supply contracts as they
expired, there is no assurance that Canadian Abraxas will be able to do so on a
similar basis in the future.
Operating Hazards; Uninsured Risks
The nature of the crude oil and natural gas business involves certain
operating hazards such as crude oil and natural gas blowouts, explosions,
encountering formations with abnormal pressures, cratering and crude oil spills
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and fires, any of which could result in damage to or destruction of crude oil
and natural gas wells, destruction of producing facilities, damage to life or
property, suspension of operations, environmental damage and possible liability
to the Company. In accordance with customary industry practices, the Company
maintains insurance against some, but not all, of such risks and some, but not
all, of such losses. The occurrence of such an event not fully covered by
insurance could have a material adverse effect on the financial condition and
results of operations of the Company.
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Competition
The Company encounters strong competition from major oil companies and
independent operators in acquiring properties and leases for the exploration
for, and production of, crude oil and natural gas. 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. Many of
the Company's competitors have financial resources, staff and facilities
substantially greater than those of the Company. In addition, the producing,
processing and marketing of crude oil and natural gas is affected by a number of
factors which are beyond the control of the Company, the effect of which cannot
be accurately predicted.
The principal raw materials and 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. The Company must compete for
such raw materials and resources with both major crude oil and natural gas
companies and independent operators. Although the Company believes its current
operating and financial resources are adequate to preclude any significant
disruption of its operations in the immediate future, the continued availability
of such materials and resources to the Company cannot be assured.
The Company will 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. The Company's principal competitors will 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 the Company. Smaller local distributors may enjoy
a marketing advantage in their immediate service areas.
The Company will compete against other companies in its natural gas
processing business both for supplies of natural gas and for customers to which
it will sell its products. Competition for natural gas supplies is based
primarily on location of natural gas gathering facilities and natural gas
gathering plants, operating efficiency and reliability and ability to obtain a
satisfactory price for products recovered. Competition for customers is based
primarily on price and delivery capabilities.
Reliance on Estimates of Proved Reserves and Future Net Revenue
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and the timing of
development expenditures, including many factors beyond the control of the
Company. The reserve data included in this Prospectus represent only estimates.
In addition, the estimates of future net revenue from proved reserves and the
present value thereof are based upon certain 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 Prospectus are based on the assumption that future
crude oil and natural gas prices remain the same as crude oil and natural gas
prices at June 30, 1996, with respect to Abraxas' existing properties, and for
the month of July 1996 with respect to the Canadian Abraxas Properties. The
average sales prices as of such dates used for purposes of such estimates were
$19.86 per Bbl of crude oil, $14.09 per Bbl of NGLs and $1.27 per Mcf of natural
gas with respect to the Canadian Abraxas Properties, $21.70 per Bbl of crude
oil, $9.25 per Bbl of NGLs and $1.07 per Mcf of natural gas with respect to the
Wyoming Properties, $19.98 per Bbl of crude oil, $14.50 per Bbl of NGLs and
$2.65 per Mcf of natural gas with respect to Portilla and Happy and $20.64 per
Bbl of crude oil, $12.38 per Bbl of NGLs and $2.29 per Mcf of natural gas with
respect to the Company's other properties in the aggregate. Also assumed is the
Company's making future capital expenditures of approximately $19.7 million in
the aggregate, including $3.4 million on the Wyoming Properties, $1.7 million on
the Canadian Abraxas Properties and $2.2 million on Portilla and Happy,
necessary to develop and realize the value of proved undeveloped reserves on
these properties. Any significant variance in these assumptions could materially
affect the estimated quantity and value of reserves set forth herein. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources" and "Business -- Reserves
Information."
Certain Business Risks
The Company intends to continue acquiring producing crude oil and natural
gas properties or companies that own such properties. Although the Company
performs a review of the acquired properties that it believes is consistent with
industry practices, such reviews are inherently incomplete. It generally is not
feasible to review in depth every individual property involved in each
acquisition. Ordinarily, the Company will focus its review efforts on the
higher-valued properties and will sample the remainder. However, even an
in-depth review of all properties and records may not necessarily reveal
existing or potential problems nor will it permit the Company to become
sufficiently familiar with the properties to assess fully their deficiencies and
capabilities. Inspections may not always be performed on every well, and
environmental problems, such as ground water contamination, are not necessarily
observable even when an inspection is undertaken. Furthermore, the Company must
rely on information, including financial, operating and geological information,
provided by the seller of the properties without being able to verify fully all
such information and without the benefit of knowing the history of operations of
all such properties.
In addition, a high degree of risk of loss of invested capital exists in
almost all exploration and development activities which the Company undertakes.
No assurance can be given that crude oil or natural gas will be discovered to
replace reserves currently being developed, produced and sold, or that if crude
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oil or natural gas reserves are found, they will be of a sufficient quantity to
enable the Company to recover the substantial sums of money incurred in their
acquisition, discovery and development. Drilling activities are subject to
numerous risks, including the risk that no commercially productive crude oil or
natural gas reservoirs will be encountered. The cost of drilling, completing and
operating wells is often uncertain. The Company's operations may be curtailed,
delayed or cancelled as a result of numerous factors including title problems,
weather conditions, compliance with governmental requirements and shortages or
delays in the delivery of equipment. The availability of a ready market for the
Company's natural gas production depends on a number of factors, including,
without limitation, the demand for and supply of natural gas, the proximity of
natural gas reserves to pipelines, the capacity of such pipelines and government
regulations.
Depletion of Reserves
The rate of production from crude oil and natural gas properties declines
as reserves are depleted. Except to the extent the Company acquires additional
properties containing proved reserves, conducts successful exploration and
development activities or, through engineering studies, identifies additional
behind-pipe zones or secondary recovery reserves, the proved reserves of the
Company will decline as reserves are produced. Future crude oil and natural gas
production is therefore highly dependent upon the Company's level of success in
acquiring or finding additional reserves. See "-- Certain Business Risks."
The Company's ability to continue to acquire producing properties or
companies that own such properties assumes that major integrated oil companies
and independent oil companies will continue to divest many of their crude oil
and natural gas properties. There can be no assurance, however, that such
divestitures will continue or that the Company will be able to acquire such
properties at acceptable prices or develop additional reserves in the future. In
addition, under the terms of the Indenture and the New Credit Facility, the
Company's ability to obtain additional financing in the future for acquisitions
and capital expenditures may be limited.
Government Regulation
The Company's business is subject to certain federal, state, provincial
and local laws and regulations relating to the exploration for and development,
production and marketing of crude oil and natural gas, as well as environmental
and safety matters. Such laws and regulations have generally become more
stringent in recent years, often imposing greater liability on a larger number
of potentially responsible parties. Because the requirements imposed by such
laws and regulations are frequently changed, the Company is unable to predict
the ultimate cost of compliance with such requirements. There is no assurance
that laws and regulations enacted in the future will not adversely affect the
Company's financial condition and results of operations. See "Business
- --Regulatory Matters."
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Fraudulent Conveyance
Various fraudulent conveyance laws enacted for the protection of
creditors may apply to the Subsidiary Guarantors' issuance of the Guarantees. To
the extent that a court were to find that (x) a Guarantee was incurred by a
Subsidiary Guarantor with actual intent to hinder, delay or defraud any present
or future creditor or (y) such Subsidiary Guarantor did not receive fair
consideration or reasonably equivalent value for issuing its Guarantee and such
Subsidiary Guarantor (i) was insolvent, (ii) was rendered insolvent by reason of
the issuance of such Guarantee, (iii) was engaged or about to engage in a
business or transaction for which the remaining assets of such Subsidiary
Guarantor constituted unreasonably small capital to carry on its business or
(iv) intended to incur, or believed that it would incur, debts beyond its
ability to pay such debts as they matured, the court could avoid or subordinate
such Guarantee in favor of the Subsidiary Guarantor's creditors. Among other
things, a legal challenge of a Guarantee on fraudulent conveyance grounds may
focus on the benefits, if any, realized by the Subsidiary Guarantor as a result
of the issuance by the Company of the Notes. To the extent any Guarantees were
avoided as a fraudulent conveyance or held unenforceable for any other reason,
the claims of holders of the Notes in respect of such Subsidiary Guarantor would
be adversely affected and such holders would, to such extent, be creditors
solely of the Company and any Subsidiary Guarantor whose Guarantee was not
avoided or held unenforceable. To the extent the claims of the holders of the
Notes against the issuer of an invalid Guarantee were subordinated, they would
be subject to the prior payment of all liabilities of such Subsidiary Guarantor.
There can be no assurance that, after providing for all prior claims, there
would be sufficient assets to satisfy the claims of the holders of the Notes
relating to any voided portion of any of the Guarantees.
The measure of insolvency for purposes of the foregoing considerations
will vary depending upon the law applied in any such proceeding. Under one
measure, the Subsidiary Guarantors may be considered insolvent if the sum of
their debts, including contingent liabilities, were greater than the fair
marketable value of all of their assets at a fair valuation or if the present
fair marketable value of their assets were less than the amount that would be
required to pay their probable liability on their existing debts, including
contingent liabilities, as they become absolute and mature.
Based upon financial and other information, the Company believes that the
Notes and the Guarantees are being incurred for proper purposes and in good
faith and that the Company and each Subsidiary Guarantor is solvent and will
continue to be solvent after issuing the Notes or its Guarantee, as the case may
be, will have sufficient capital for carrying on its business after such
issuance and will be able to pay its debts as they mature. There can be no
assurance, however, that a court passing on such standards would agree with the
Company.
Dependence on Key Personnel
The Company depends to a large extent on Robert L. G. Watson, its
Chairman of the Board, President and Chief Executive Officer, for its management
and business and financial contacts. See "Management." The unavailability of Mr.
Watson would have a materially adverse effect on the Company's business. The
Company's success is also dependent upon its ability to employ and retain
skilled technical personnel. While the Company has not to date experienced
difficulties in employing or retaining such personnel, its failure to do so in
the future could adversely affect its business.
Limitations on the Availability of the Company's Net Operating Loss
Carryforwards
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 ("Section 382") of the Internal Revenue Code of 1986, as amended
(the "Code"), occurred in December 1991. Accordingly, it is expected that the
use of net operating loss carryforwards generated prior to December 31, 1991 of
$6.9 million will be limited to approximately $235,000 per year. During 1992,
the Company acquired 100% of the outstanding capital stock of an unrelated
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corporation. The use of net operating loss carryforwards of $3.6 million of the
unrelated corporation are limited to approximately $115,000 per year. As a
result of the issuance of additional shares of Common Stock for acquisitions and
to raise capital, an additional ownership change occurred in October 1993.
Accordingly, it is expected that the use of the $13.4 million of net operating
loss carryforwards generated through October 1993 will be limited to
approximately $1.0 million per year, subject to the limitations described above,
and $7.2 million in the aggregate. Future changes in ownership may further limit
the use of the Company's carryforwards. In addition to the Section 382
limitations, uncertainties exist as to the future utilization of the
carryforwards under the criteria set forth in Financial Accounting Standards
Board ("FASB") Statement No. 109, "Accounting for Income Taxes." The Company
established a valuation allowance of $5.5 million and $5.7 million for deferred
tax assets at December 31, 1994 and 1995, respectively.
Lack of Public Market
There is no existing trading market for the Notes. Although the Initial
Purchasers have advised the Issuers that they currently intend to make a market
in the Notes and, if issued, the Exchange Notes, they are not obligated to do so
and they may discontinue such market-making at any time without notice. In
addition, such market-making activity may be limited during the Exchange Offer
and the pendency of the Shelf Registration Statement (as defined herein), if
any. Although the Notes will be eligible for trading in the PORTAL Market, there
can be no assurance as to the development of any market or the liquidity of any
market that may develop for the Notes or the Exchange Notes. The Issuers do not
intend to apply for listing or quotation of the Notes on any securities exchange
or stock market.
PURPOSE OF THE EXCHANGE OFFER
In connection with the initial sale of the Series A Notes, the Issuers
agreed, subject to certain conditions, to use their best efforts to conduct the
Exchange Offer pursuant to the terms of the Registration Rights Agreement by and
among the Issuers and the Initial Purchasers (the "Registration Rights
Agreement"). The Registration Rights Agreement, pursuant to which the Issuers
agreed, with respect to the Series A Notes and subject to the Issuers'
determination that the Exchange Offer is permitted under applicable law and
Commission policy, to (i) cause to be filed with the Commission, no later than
45 days after the Issue Date, a registration statement under the Securities Act
relating to the Exchange Notes and the Exchange Offer, (ii) use their best
efforts (a) to cause such registration statement to be declared effective by the
Commission in no event later than 120 days after the Issue Date, (b) upon the
effectiveness of such registration statement, to commence the Exchange Offer,
and (c) to cause the Exchange Offer to remain open for a period of not less than
30 days. The Issuers' purpose in making the Exchange Offer is to comply with
such agreement and to avoid the increase in interest rate on the Series A Notes
which would occur if the Exchange Offer were not duly and timely consummated.
The Exchange Offer should provide holders of the Series A Notes with the ability
to effect, for federal income tax purposes, a tax-free exchange of such Series A
Notes, which are subject to trading limitations, for Exchange Notes that will
not be subject to such restrictions.
The Exchange Offer provides holders of the Series A Notes with the
Exchange Notes that will generally be freely transferable by holders thereof
(other than any holder who is an "affiliate" or "promoter" of the Issuers within
the meaning of Rule 405 under the Securities Act), who may offer for resale,
resell or otherwise transfer such Exchange Notes without complying with the
registration and prospectus delivery provisions of the Securities Act, provided
that such Exchange Notes are acquired in the ordinary course of each such
holder's business and such holders have no arrangement or understanding with any
person to participate in a distribution of the Exchange Notes. Each holder who
participates in the Exchange Offer will be required to represent that any
Exchange Notes received by it will be acquired in the ordinary course of its
business, that at the time of consummation of the Exchange Offer such holder
will have no arrangement or understanding with any person to participate in the
distribution of the Exchange Notes in violation of the provisions of the
Securities Act, and that such holder is not an affiliate of the Issuers within
the meaning of the Securities Act.
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RESALE OF THE EXCHANGE NOTES
With respect to resales of the Exchange Notes, based on interpretations
by the staff of the Commission set forth in no-action letters issued to third
parties, the Issuers believe that a holder or other person who receives Exchange
Notes, whether or not such person is the holder (other than a person that is an
"affiliate" of the Issuers within the meaning of Rule 405 under the Securities
Act) who receives Exchange Notes in exchange for Series A Notes in the ordinary
course of business and who is not participating, does not intend to participate,
and has no arrangement or understanding with any person to participate, in the
distribution of the Exchange Notes, will be allowed to resell the Exchange Notes
to the public without further registration under the Securities Act and without
delivering to the purchasers of the Exchange Notes a prospectus that satisfies
the requirements of Section 10 of the Securities Act. However, if any holder
acquires Exchange Notes in the Exchange Offer for the purpose of distributing or
participating in a distribution of the Exchange Notes, such holder cannot rely
on the position of the staff of the Commission enunciated in such no-action
letters or any similar interpretive letters, and must comply with the
registration and prospectus delivery requirements of the Securities Act (with
such prospectus containing the selling securityholder information required by
Item 507 of Regulation S-K under the Securities Act) in connection with any
resale transaction, unless an exemption from registration is otherwise
available. Further, each Participating Broker-Dealer that receives Exchange
Notes for its own account in exchange for Series A Notes, where such Series A
Notes were acquired by such Participating Broker-Dealer as a result of
market-making activities or other trading activities, may be a statutory
underwriter and must acknowledge that it will deliver a prospectus meeting the
requirements of the Securities Act (which may be this Prospectus, as it may be
amended or supplemented from time to time) in connection with any resale of such
Exchange Notes.
As contemplated by these no-action letters and the Registration Rights
Agreement, each holder accepting the Exchange Offer is required to represent to
the Issuers in the Letter of Transmittal that (i) the Exchange Notes are to be
acquired by the holder or the person receiving such Exchange Notes, whether or
not such person is the holder, in the ordinary course of business, (ii) the
holder or any such other person (other than a broker-dealer referred to in the
next sentence) is not engaging and does not intend to engage, in the
distribution of the Exchange Notes, (iii) the holder or any such other person
has no arrangement or understanding with any person to participate in the
distribution of the Exchange Notes, (iv) neither the holder nor any such other
person is an "affiliate" of the Issuers within the meaning of Rule 405 under the
Securities Act, and (v) the holder or any such other person acknowledges that if
such holder or other person participates in the Exchange Offer for the purpose
of distributing the Exchange Notes it must comply with the registration and
prospectus delivery requirements of the Securities Act in connection with any
resale of the Exchange Notes and cannot rely on such no-action letters. As
indicated above, each Participating Broker-Dealer that receives an Exchange Note
for its own account in exchange for the Series A Notes must acknowledge that it
will deliver a prospectus in connection with any resale of such Exchange Notes.
For a description of the procedures for such resales by Participating
Broker-Dealers, see "Plan of Distribution."
PLAN OF DISTRIBUTION
Each Participating Broker-Dealer that receives Exchange Notes for its own
account pursuant to the Exchange Offer must acknowledge that it will deliver a
prospectus in connection with any resale of such Exchange Notes. This
Prospectus, as it may be amended or supplemented from time to time, may be used
by a Participating Broker-Dealer in connection with resales of Exchange Notes
received in exchange for the Series A Notes where such Series A Notes were
acquired as a result of market-making activities or other trading activities.
The Issuers have agreed that they will make this Prospectus, as amended or
supplemented, available to any Participating Broker-Dealer for use in connection
with any such resale during the period required by the Securities Act.
The Issuers will not receive any proceeds from any sales of the Exchange
Notes by Participating Broker-Dealers. The Exchange Notes received by
Participating Broker-Dealers for their own account pursuant to the Exchange
Offer may be sold from time to time in one or more transactions in the
over-the-counter market, in negotiated transactions, through the writing of
options on the Exchange Notes or a combination of such methods of resale, at
market prices prevailing at the time of resale, at prices related to such
prevailing market prices or negotiated prices. Any such resale may be made
directly to the purchaser or through brokers or dealers who may receive
compensation in the form of commissions or concessions from any such
Participating Broker-Dealer and/or the purchasers of any such Exchange Notes.
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Any Participating Broker-Dealer that resells the Exchange Notes that were
received by it for its own account pursuant to the Exchange Offer and any broker
or dealer that participates in a distribution of such Exchange Notes may be
deemed to be an "underwriter" within the meaning of the Securities Act and any
profit on any such resale of Exchange Notes and any commissions or concessions
received by any such persons may be deemed to be underwriting compensation under
the Securities Act. The Letter of Transmittal states that by acknowledging that
it will deliver and by delivering a prospectus, a Participating Broker-Dealer
will not be deemed to admit that it is an "underwriter" within the meaning of
the Securities Act. The Issuers have agreed to pay all expenses incident to the
Exchange Offer other than commissions or concessions of any brokers or dealers
and will indemnify an Eligible Holder (including any broker-dealer) against
certain liabilities, including liabilities under the Securities Act.
The Issuers will promptly send additional copies of this Prospectus and
any amendment or supplement to this Prospectus to any Participating
Broker-Dealer that requests such documents in the Letter of Transmittal.
THE EXCHANGE OFFER
Terms of the Offer
The Issuers hereby offer, upon the terms and conditions set forth herein
and in the related Letter of Transmittal, to exchange the Exchange Notes for a
like principal amount of the outstanding Series A Notes. An aggregate of $215.0
million principal amount of Series A Notes are outstanding. The Exchange Offer
is not conditioned upon any minimum amount of the Series A Notes being tendered.
The Exchange Offer will expire at 5:00 p.m., New York City time, on March
14, 1997, unless extended. The term "Expiration Date" means 5:00 p.m., New York
City time, on March 14 , 1997, unless the Issuers, in their sole discretion,
notify the Exchange Agent that the period of the Exchange Offer has been
extended, in which case the term "Expiration Date" means the latest time and
date on which the Exchange Offer as so extended will expire. See "-- Expiration
and Extension."
Holders of the Series A Notes who wish to exchange the Series A Notes for
the Exchange Notes and who validly tender the Series A Notes to the Exchange
Agent or validly tender the Series A Notes by complying with the book-entry
transfer procedures described below and, in each case, who furnish the Letter of
Transmittal and any other required documents to the Exchange Agent, will either
have the Exchange Notes mailed to them by the Exchange Agent or have the
Exchange Notes credited to their account in accordance with the book-entry
transfer procedures described below, promptly after such tender is accepted by
the Issuers. Subject to the terms and conditions of the Exchange Offer, the
Series A Notes which have been validly tendered prior to the Expiration Date
will be accepted on or promptly after the Expiration Date. Subject to the
applicable rules of the Commission, the Issuers, however, reserve the right,
prior to the first acceptance of tendered Series A Notes, to delay acceptance of
tendered Series A Notes, or to terminate the Exchange Offer, subject to the
provisions of Rule 14e-1(c) under the Exchange Act, which requires that a tender
offeror pay the consideration offered or return the tendered securities promptly
after the termination or withdrawal of a tender offer.
In addition, the Issuers reserve the right to waive any condition or
otherwise amend the Exchange Offer in any respect consistent with the Indenture
and the Registration Rights Agreement prior to the acceptance of tendered Series
A Notes. If any amendment by the Issuers of the Exchange Offer or waiver by the
Issuers of any condition thereto constitutes a material change in the
information previously disclosed to the holders of Series A Notes, the Issuers
will, in accordance with the applicable rules of the Commission, disseminate
promptly disclosure of such change in a manner reasonably calculated to inform
such holders of such change. If it is necessary to permit an adequate
dissemination of information regarding such material change, the Issuers will
extend the Exchange Offer to permit an adequate time for holders of the Series A
Notes to consider the additional information.
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Certain Effects of the Exchange Offer
Because the Exchange Offer is for any and all Series A Notes, the number
of Series A Notes tendered and exchanged in the Exchange Offer will reduce the
principal amount of Series A Notes outstanding. As a result, the liquidity of
any remaining Series A Notes may be substantially reduced. The Series A Notes
are currently eligible for sale pursuant to Rule 144A through the PORTAL System
of the National Association of Securities Dealers, Inc. Because the Issuers
anticipate that most holders of Series A Notes will elect to exchange such
Series A Notes for the Exchange Notes due to the absence of restrictions on the
resale of the Exchange Notes under the Securities Act, the Issuers anticipate
that the liquidity of the market for any Series A Notes remaining after the
consummation of the Exchange Offer may be substantially limited.
Expiration and Extension
The Exchange Offer will expire at 5:00 p.m., New York City time, on March
14 , 1997, unless extended by the Issuers. The Exchange Offer may be extended by
oral or written notice from the Issuers to the Exchange Agent at any time or
from time to time, on or prior to the date then fixed for the expiration of the
Exchange Offer. Public announcement of any extension of the Exchange Offer will
be timely made by the Company, but, unless otherwise required by law or
regulation, the Company will not have any obligation to communicate such public
announcement other than by making a release to the Dow Jones News Service.
The Issuers reserve the right, in their sole discretion, (i) to delay
accepting any Series A Notes, (ii) to extend the Exchange Offer or (iii) if any
conditions set forth below under "-- Conditions" shall not have been satisfied,
to terminate the Exchange Offer by giving oral or written notice of such delay,
extension or termination to the Exchange Agent. Any such delay in acceptance,
extension, termination or amendment will be followed as promptly as practicable
by oral or written notice thereof to the registered holders. If the Exchange
Offer is amended in a manner determined by the Issuers to constitute a material
change, the Issuers will promptly disclose such amendment by means of a
prospectus supplement that will be distributed to the registered holders of the
Private Notes, and the Issuers will extend the Exchange Offer for a period of
five to ten business days, depending upon the significance of the amendment and
the manner of disclosure to the registered holders, if the Exchange Offer would
otherwise expire during such five to ten business day period.
Conditions
The Exchange Offer is subject to the following conditions: (i) the
Exchange Offer does not violate applicable law or any applicable interpretation
of the staff of the Commission, (ii) no action or proceeding is instituted or
threatened in any court or by any governmental agency which might materially
impair the ability of the Issuers to proceed with the Exchange Offer and no
material adverse development has occurred in any existing action or proceeding
with respect to the Issuers and (iii) all governmental approvals have been
obtained, which approvals the Issuers deem necessary for the consummation of the
Exchange Offer.
Registration Rights
On November 14, 1996, the Issuers entered into the Registration Rights
Agreement with the Initial Purchasers pursuant to which the Issuers have, for
the benefit of the holders of the Notes, at the Issuers' cost, agreed to (i)
file the registration statement of which this Prospectus forms a part (the
"Exchange Offer Registration Statement"), under the Securities Act with respect
to the Exchange Offer which constitutes the Issuers' offer to exchange the
Series A Notes for the Exchange Notes, which will have terms identical in all
material respects to the Series A Notes (except that the Exchange Notes will not
contain terms with respect to transfer restrictions and will not contain certain
provisions relating to an increase in the interest rate which were applicable to
the Series A Notes in certain circumstances relating to the timing of the
Exchange Offer), and (ii) cause the Exchange Offer Registration Statement to be
declared effective under the Securities Act within 120 days after the Issue
Date. The Issuers will keep the Exchange Offer open for not less than 30
calendar days (or longer if required by applicable law) after the date notice of
the Exchange Offer is mailed to the holders of the Series A Notes.
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In the event that (i) any changes in law or the applicable
interpretations of the staff of the Commission do not permit the Issuers to
effect the Exchange Offer, (ii) the Exchange Offer is not consummated within 150
days of the Issue Date, (iii) in certain circumstances, certain holders of
unregistered Exchange Notes so request within 60 days after the consummation of
the Exchange Offer or (iv) in the case of any holder that participates in the
Exchange Offer, such holder does not receive Exchange Notes on the date of the
exchange that may be sold without restriction under state and federal securities
laws (other than due solely to the status of such holder as an affiliate of the
Issuers within the meaning of the Securities Act) and so notifies the Issuers
within 30 days after such holder first becomes aware of such restriction and
provides the Issuers with a reasonable basis for its conclusion, in the case of
each of clauses (i)-(iv) of this sentence, then the Issuers will promptly
deliver to the holders and the Trustee written notice thereof and, at their
cost, (a)30 days after the delivery of such notice, file a shelf registration
statement covering resales of the Notes (the "Shelf Registration Statement"),
(b) use their best efforts to cause the Shelf Registration Statement to be
declared effective under the Securities Act and (c) use their best efforts to
keep the Shelf Registration Statement effective until three years after their
effective date, or such shorter period ending when (i) all Notes covered by the
Shelf Registration Statement have been sold in the manner set forth and as
contemplated therein or (ii) a subsequent Shelf Registration Statement covering
all unregistered Notes has been declared effective under the Securities Act. The
Issuers will, in the event of the filing of a Shelf Registration Statement,
provide to each holder of the Notes copies of the prospectus which is a part of
the Shelf Registration Statement, notify each such holder when the Shelf
Registration Statement for the Notes has become effective and take certain other
actions as are required to permit unrestricted resales of the Notes. A holder of
Notes that sells such Notes pursuant to the Shelf Registration Statement
generally will be required to be named as a selling securityholder in the
related prospectus and to deliver a prospectus to purchasers, will be subject to
certain of the civil liability provisions under the Securities Act in connection
with such sales and will be bound by the provisions of the Registration Rights
Agreement which are applicable to such a holder (including certain
indemnification obligations). In addition, each holder of the Notes will be
required to deliver information to be used in connection with the Shelf
Registration Statement and to provide comments on the Shelf Registration
Statement within the time periods set forth in the Registration Rights Agreement
in order to have its Notes included in the Shelf Registration Statement and to
benefit from the provisions regarding liquidated damages set forth therein.
The summary herein of certain provisions of the Registration Rights
Agreement does not purport to be complete and is subject to, and is qualified in
its entirety by reference to, all the provisions of the Registration Rights
Agreement, a copy of which is available without charge by writing to the Company
at 500 North Loop 1604 East, Suite 100, San Antonio, Texas 78232, Attention:
Secretary.
How to Tender
A holder of the Series A Notes may tender the Series A Notes by (a)
properly completing and signing the Letter of Transmittal or a facsimile thereof
(all references in this Prospectus to the Letter of Transmittal shall be deemed
to include a facsimile thereof) and delivering the same, together with the
Series A Notes being tendered (or a confirmation of an appropriate book-entry
transfer) to the Exchange Agent on or prior to the Expiration Date or (b)
requesting a broker, dealer, bank, trust company or other nominee to effect the
transaction for such holder prior to the Expiration Date.
If Exchange Notes are to be delivered to an address other than that of
the registered holder appearing on the note register (the "Note Register")
maintained by the registrar of the Notes, the signature on the Letter of
Transmittal must be guaranteed by a commercial bank or trust company having an
office or correspondent in the United States, or by a member firm of a national
securities exchange or the National Association of Securities Dealers, Inc. (any
of the foregoing is hereinafter referred to as an "Eligible Institution").
Exchange Notes will not be issued in the name of a person other than that of the
registered holder of the Series A Notes appearing on the Note Register.
The Exchange Agent will establish an account with respect to the Series A
Notes at DTC within two business days after the date of this Prospectus, and any
financial institution which is a participant in DTC may make book-entry delivery
of the Series A Notes by causing DTC to transfer such Series A Notes into the
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Exchange Agent's account in accordance with DTC's procedure for such transfer.
Although delivery of the Series A Notes may be effected through book-entry
transfer into the Exchange Agent's account at DTC, the Letter of Transmittal,
with any required signature guarantees and any other required documents, must in
any case be transmitted to and received by the Exchange Agent on or prior to the
Expiration Date at one of its addresses set forth below under "Exchange Agent",
or in compliance with the guaranteed delivery procedure described below.
DELIVERY OF DOCUMENTS TO DTC DOES NOT CONSTITUTE DELIVERY TO THE EXCHANGE AGENT.
All references in this Prospectus to deposit or delivery of Series A Notes shall
be deemed to include DTC's book-entry delivery method.
Notwithstanding the foregoing, any financial institution that is a
participant in the Depository's Book-Entry Transfer Facility system may make
book-entry delivery of the Existing Notes by causing the Depositary to transfer
such Existing Notes into the Exchange Agent's account in accordance with the
Depository's Automated Tender Offer Program ("ATOP") procedures for such
book-entry transfers. However, the exchange for the Existing Notes so tendered
will only be made after timely confirmation (a "Book-Entry Confirmation") of
such Book-Entry Transfer of Existing Notes into the Exchange Agent's account,
and timely receipt by the Exchange Agent of an Agent's Message (as such term is
defined in the next sentence) and any other documents required by the Letter of
Transmittal. The term "Agent's Message" means a message, transmitted by the
Book-Entry Transfer Facility and received by the Exchange Agent and forming a
part of a Book-Entry Confirmation, which states that the Book-Entry Transfer
Facility has received an express acknowledgment from a participant tendering the
Series A Notes that is the subject of such Book-Entry Confirmation that such
participant has received and agrees to be bound by the terms of the Letter of
Transmittal, and that the Issuers may enforce such agreement against such
participant.
THE METHOD OF DELIVERY OF THE SERIES A NOTES AND ALL OTHER DOCUMENTS,
INCLUDING DELIVERY THROUGH DTC, IS AT THE ELECTION AND RISK OF THE HOLDER. IF
SENT BY MAIL, IT IS RECOMMENDED THAT REGISTERED MAIL, RETURN RECEIPT REQUESTED,
BE USED, AND PROPER INSURANCE BE OBTAINED.
If a holder desires to tender Series A Notes pursuant to the Exchange
Offer and such holder's Series A Notes are not immediately available or time
will not permit all of the above documents to reach the Exchange Agent prior to
the Expiration Date, or such holder cannot complete the procedure of book-entry
transfer on a timely basis, such tender may be effected if the following
conditions are satisfied:
(a) such tenders are made by or through an Eligible Institution;
(b) a properly completed and duly executed Notice of Guaranteed
Delivery, in substantially the form provided by the Issuers, is received by the
Exchange Agent as provided below on or prior to the Expiration Date; and
(c) the Series A Notes, in proper form for transfer (or
confirmation of book-entry transfer of such Series A Notes into the Exchange
Agent's account at DTC as described above), together with a properly completed
and duly executed Letter of Transmittal and all other documents required by the
Letter of Transmittal, are received by the Exchange Agent within three New York
Stock Exchange, Inc. trading days after the date of execution of such Notice of
Guaranteed Delivery.
The Notice of Guaranteed Delivery may be delivered by hand or
transmitted by facsimile transmission or mailed to the Exchange Agent and must
include a guarantee by an Eligible Institution in the form set forth in such
Notice of Guaranteed Delivery.
A tender will be deemed to have been received as of the date when
the tendering holder's duly signed Letter of Transmittal accompanied by Series A
Notes (or a timely confirmation received of a book-entry transfer of Series A
Notes into the Exchange Agent's account at DTC) or a Notice of Guaranteed
Delivery from an Eligible Institution is received by the Exchange Agent.
Issuances of Exchange Notes in exchange for Series A Notes tendered pursuant to
a Notice of Guaranteed Delivery by an Eligible Institution will be made only
against delivery of the Letter of Transmittal (and any other required documents)
and the tendered Series A Notes (or a timely confirmation received of a
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book-entry transfer of Series A Notes into the Exchange Agent's account at DTC)
with the Exchange Agent.
Partial tenders of Series A Notes may be made only if (i) the
principal amount tendered is equal to $1,000 or an integral multiple thereof;
and (ii) the remaining untendered portion of such Series A Note is in a
principal amount of $250,000, or any integral multiple of $1,000 in excess of
such amount. Holders tendering less than the entire principal amount of any
Series A Note they hold in accordance with the foregoing restrictions must
appropriately indicate such fact on the Letter of Transmittal accompanying the
tendered Series A Note.
With respect to tenders of Series A Notes, the Issuers reserve
full discretion to determine whether the documentation is complete and generally
to determine all questions as to tenders, including the date of receipt of a
tender, the propriety of execution of any document, and other questions as to
the validity, form, eligibility or acceptability of any tender. The Issuers
reserve the right to reject any tender not in proper form or otherwise not valid
or the acceptance for exchange of which may, in the opinion of the Issuers'
counsel, be unlawful or to waive any irregularities or conditions, and the
Issuers' interpretation of the terms and conditions of the Exchange Offer
(including the instructions on the Letter of Transmittal) will be final and
binding. The Issuers and the Exchange Agent shall not be obligated to give
notice of any defects or irregularities in tenders and shall not incur any
liability for failure to give any such notice. The Exchange Agent may, but shall
not be obligated to, give notice of any irregularities or defects in tenders,
and shall not incur any liability for any failure to give any such notice. The
Series A Notes shall not be deemed to have been duly or validly tendered unless
and until all defects and irregularities have been cured or waived. All
improperly tendered Series A Notes, as well as Series A Notes in excess of the
principal amount tendered for exchange, will be returned (unless irregularities
and defects are timely cured or waived), without cost to the tendering holder
(or, in the case of Series A Notes delivered by book-entry transfer within DTC,
will be credited to the account maintained within DTC by the participant in DTC
which delivered such shares), promptly after the Expiration Date.
Terms and Conditions of the Letter of Transmittal
The Letter of Transmittal contains, among other things, certain
terms and conditions which are summarized below and are part of the Exchange
Offer.
Each holder who participates in the Exchange Offer will be
required to represent that any Exchange Notes received by it will be acquired in
the ordinary course of its business, unless it is a Participating Broker-Dealer,
it is not engaging and does not intend to engage in the distribution of the
Exchange Notes, that at the time of consummation of the Exchange Offer such
holder will have no arrangement or understanding with any person to participate
in the distribution of the Exchange Notes in violation of the provision of the
Securities Act, that such holder is not an "affiliate" of the Issuers within the
meaning of the Securities Act and that if it participates in the Exchange Offer
for the purpose of distributing the Exchange Notes it must comply with the
registration and prospectus delivery requirements of the Securities Act in
connection with any resale of the Exchange Notes.
The Series A Notes tendered in exchange for the Exchange Notes
(or a timely confirmation of a book-entry transfer of such Series A Notes into
the Exchange Agent's account at DTC) must be received by the Exchange Agent,
with the Letter of Transmittal and any other required documents, by 5:00 p.m.,
New York City time, on or prior to March 14, 1997, unless extended, or within
the time periods set forth above in "-- How to Tender" pursuant to a Notice of
Guaranteed Delivery from an Eligible Institution. The party tendering the Series
A Notes for exchange (the "Holder") will sell, assign and transfer the Series A
Notes to the Exchange Agent, as agent of the Issuers, and irrevocably constitute
and appoint the Exchange Agent as the Holder's agent and attorney-in-fact to
cause the Series A Notes to be transferred and exchanged. The Holder will
warrant that it has full power and authority to tender, exchange, sell, assign
and transfer the Series A Notes and to acquire the Exchange Notes issuable upon
the exchange of such tendered Series A Notes, the Exchange Agent, as agent of
the Issuers, will acquire good and unencumbered title to the tendered Series A
Notes, free and clear of all liens, restrictions, charges and encumbrances, and
that the Series A Notes tendered for exchange are not subject to any adverse
claims or encumbrance when accepted by the Exchange Agent, as agent of the
Issuers. The Holder will also covenant and agree that it will, upon request,
execute and deliver any additional documents deemed by the Issuers or the
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Exchange Agent to be necessary or desirable to complete the exchange, sale,
assignment and transfer of the Series A Notes. All authority conferred or agreed
to be conferred in the Letter of Transmittal by the Holder will survive the
death or incapacity of the Holder and any obligation of the Holder shall be
binding upon the heirs, personal representatives, successors and assigns of such
Holder.
Signature(s) on the Letter of Transmittal will be required to be
guaranteed as set forth above in "-- How to Tender." All questions as to the
validity, form, eligibility (including time of receipt) and acceptability of any
tender will be determined by the Issuers, in their sole discretion, and such
determination will be final and binding. Unless waived by the Issuers,
irregularities and defects must be cured by the Expiration Date. The Issuers
will pay all security transfer taxes, if any, applicable to the transfer and
exchange of the Series A Notes tendered.
Withdrawal Rights
All tenders of the Series A Notes may be withdrawn at any time
prior to acceptance thereof on the Expiration Date. To be effective, a notice of
withdrawal must be timely received by the Exchange Agent at the address set
forth below under "-- Exchange Agent." Any notice of withdrawal must specify the
person named in the Letter of Transmittal as having tendered the Series A Notes
to be withdrawn. If the Series A Notes have been physically delivered to the
Exchange Agent, the tendering holder must also submit the serial number shown on
the particular Series A Notes to be withdrawn. If the Series A Notes have been
delivered pursuant to the book-entry procedures set forth above under "--How to
Tender," any notice of withdrawal must specify the name and number of the
participant's account at DTC to be credited with the withdrawn Series A Notes.
The Exchange Agent will return the properly withdrawn Series A Notes as soon as
practicable following receipt of notice of withdrawal. All questions as to the
validity, including time of receipt, of notices of withdrawals will be
determined by the Issuers, and such determinations will be final and binding on
all parties.
Acceptance of Tenders
Subject to the terms and conditions of the Exchange Offer,
including the reservation of certain rights by the Issuers, the Series A Notes
tendered (either physically or through book-entry delivery as described in
"--How to Tender") with a properly executed Letter of Transmittal and all other
required documentation, and not withdrawn, will be accepted promptly after the
Expiration Date. Subject to such terms and conditions, Exchange Notes to be
issued in exchange for properly tendered Series A Notes will either be mailed by
the Exchange Agent or credited to the holder's account in accordance with the
appropriate book-entry procedures promptly after the acceptance of the properly
tendered Series A Notes. Acceptance of Series A Notes will be effected by the
delivery of a notice to that effect by the Issuers to the Exchange Agent.
Subject to the applicable rules of the Commission, the Issuers, however, reserve
the right, prior to the acceptance of tendered Series A Notes, to delay
acceptance of tendered Series A Notes upon the occurrence of any of the
conditions set forth above under the caption "-- Conditions." The Issuers
confirms that their reservation of the right to delay acceptance of tendered
Series A Notes is subject to the provisions of Rule 14e-1(c) under the 1934 Act
which requires that a tender offeror pay the consideration offered or return the
tendered securities promptly after the termination or withdrawal of a tender
offer.
Although the Issuers do not currently intend to do so, if they
modify the terms of the Exchange Offer, such modified terms will be available to
all holders of Series A Notes, whether or not their Series A Notes have been
tendered prior to such modification. Any material modification will be disclosed
in accordance with the applicable rules of the Commission and, if required, the
Exchange Offer will be extended to permit holders of Series A Notes adequate
time to consider such modification.
The tender of Series A Notes pursuant to any one of the
procedures set forth in "-- How to Tender" will constitute an agreement between
the tendering holder and the Issuers upon the terms and subject to the
conditions of the Exchange Offer.
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EXCHANGE AGENT
IBJ Schroder Bank & Trust Company has been appointed as Exchange
Agent for the Exchange Offer. Letters of Transmittal must be addressed to the
Exchange Agent as follows:
If Delivery By Mail: If Delivered By Courier or By Hand:
IBJ Schroder Bank & Trust Company IBJ Schroder Bank & Trust Company
One State Street One State Street
New York, New York, 10004 New York, New York 10004
Attention: Reorganization Operations Attention: Securities Processing
Department Window,Subcellar One (SC-1)
Delivery to other than the above addresses will not constitute
valid delivery.
Solicitation of Tenders; Expenses
Except as described above under "Exchange Agent," the Issuers
have not retained any agent in connection with the Exchange Offer and will not
make any payments to brokers, dealers or other persons for soliciting or
recommending acceptances of the Exchange Offer. The Issuers will, however,
reimburse the Exchange Agent for its reasonable out-of-pocket expenses in
connection therewith. The Issuers will also pay brokerage houses and other
custodians, nominees and fiduciaries the reasonable out-of-pocket expenses
incurred by them in forwarding copies of this Prospectus and related documents
to the beneficial owners of the Series A Notes and in handling or forwarding
tenders for their customers.
35
<PAGE>
USE OF PROCEEDS
The Issuers will not receive any proceeds as a result of the
Exchange Offer.
The net proceeds to the Issuers from the Offering were
approximately $206.8 million after deducting discounts and estimated offering
expenses payable by the Issuers. The Issuers utilized the net proceeds,
primarily to (i) consummate the Recent Acquisitions, (ii) repay all indebtedness
outstanding under the Company's credit facility with BTCo and ING Capital and
(iii) pay certain expenses incurred in connection with the Transactions. The
following table illustrates the sources and uses of proceeds:
Sources of Funds Uses of Funds
- ------------------------------ ------------------------------------------
(dollars in thousands)
Notes $215,000 Purchase of CGGS (2) $ 94,771
Purchase of Portilla
and Happy (3) 26,848
Purchase of East White
Point and Stedman Island (4) 8,771
Repay Bridge Facility 85,000
Fees and Expenses 8,200
Working Capital (8,590)
----------- ---------
Total Sources (1) $215,000 Total Uses $215,000
----------- ---------
- --------
(1) Does not include the borrowing base of $40.0 million under the New Credit
Facility, $20.0 million of which will initially be available upon
consummation of the Offering.
(2) $126.4 million converted at an approximate exchange rate of U.S.$0.7499
to one Canadian dollar.
(3) Includes $20.6 million paid to Christiania Bank og Kreditkasse
("Christiania") and $7.0 million paid to Acco and the holders of certain
notes (the "Partnership Notes") and options to purchase certain
overriding royalty interests issued by the Partnership, net of estimate
for the accrual of net crude oil and natural gas revenues to the closing
date.
(4) Includes $9.3 million purchase price before estimate for the accrual of
net crude oil and natural gas revenues to the closing date.
36
<PAGE>
CAPITALIZATION
The following table sets forth the total consolidated
capitalization of the Issuers at September 30, 1996, on an historical basis and
on a pro forma basis. This table should be read in conjunction with the
Consolidated Financial Statements of the Issuers and the notes thereto, the
unaudited Pro Forma Financial Information and the notes thereto and the other
financial information included elsewhere in this Prospectus.
September 30, 1996
Pro Forma
Actual As Adjusted
-------- -----------
(dollars in thousands)
Cash and cash equivalents $ 9,993 $ 11,486
-------- ---------
Total debt, including current maturities:
Bridge Facility (1) 85,000 --
Other long-term obligation 124 124
New Credit Facility -- --
11 1/2% Senior Notes due 2004 -- 215,000
-------- ---------
Total debt 85,124 215,124
-------- ---------
Stockholders' equity:
Preferred stock, $.01 par value;
1,000,000 shares authorized; 45,741
shares of Series 1995-B Preferred
Stock issued and outstanding
(liquidation preference 4,574,100) 0 0
Common stock, $.01 par value; 50,000,000
shares authorized; 5,804,812 shares issued 58 58
Treasury stock, 70,711 shares (374) (374)
Additional paid-in capital 50,920 50,920
-------- ---------
Retained deficit (14,184) (14,407)
-------- ---------
Total stockholders' equity 36,420 36,197
-------- ---------
Total capitalization $ 121,544 $ 251,321
======== =========
- ------------
(1) All amounts outstanding under the Bridge Facility were repaid with a
portion of the proceeds of the initial offering of the Series A Notes.
37
<PAGE>
PRO FORMA FINANCIAL INFORMATION
The following unaudited pro forma financial data are derived from
the historical financial statements of the Company set forth elsewhere in this
Prospectus and are adjusted to reflect the consummation of the Transactions.
The Unaudited Pro Forma Condensed Balance Sheet of the Company as
of September 30, 1996 has been prepared assuming the Transactions were
consummated on September 30, 1996, and the Unaudited Pro Forma Statements of
Operations of the Company for the year ended December 31, 1995 and the nine
months ended September 30, 1996 have been prepared assuming the Transactions
were consummated on January 1, 1995 and January 1, 1996, respectively. The
historical revenues and expenses of CGGS, the Wyoming Properties, Portilla and
Happy and East White Point and Stedman Island represent amounts recorded by or
with respect to such businesses or properties for the periods indicated.
The historical financial statements of CGGS were prepared in
Canadian dollars in accordance with Canadian generally accepted accounting
principles. This information has been adjusted to present the historical
financial statements in accordance with United States generally accepted
accounting principles. The statements of operations have been translated into
U.S. dollars at the average exchange rates of $0.7321 and $0.7273 to one
Canadian dollar for the nine months ended October 31, 1996 and the fiscal year
ended October 31, 1995, respectively. The monetary amounts on the unaudited
balance sheet as of October 31, 1996 have been translated at the period-end
exchange rate of $0.7458 to one Canadian dollar. Non-monetary amounts have been
translated at a historical November 1, 1994 rate with changes in the amounts
since that date translated at the average rate over the twenty-five month
period. The historical financial statements of CGGS include the results of the
Hoole Area. See "Business - Recent Acquisitions - CGGS" and "Business - Primary
Operating Areas - Western Canada."
The Company previously owned a 50% working interest in Portilla
and a 12% working interest in Happy. In March 1996, the Company sold its
interests in Portilla and Happy to Acco for net consideration of $15.6 million.
Acco separately obtained the release of the 50% overriding royalty interest in
Portilla previously owned by the Pension Fund and subsequently contributed its
interests in Portilla and Happy to the Partnership. The pro forma adjustments
assume that the Issuers acquired the Pension Fund's interest in Portilla at the
beginning of the periods indicated and that the Issuers owned Portilla and Happy
during the period from March 21, 1996 to September 30, 1996.
The Unaudited Pro Forma Condensed Balance Sheet reflects the
preliminary allocations of the purchase prices for the Recent Acquisitions to
the assets and liabilities of the Company. The final allocation of the purchase
prices, and the resulting effect on DD&A expense in the accompanying unaudited
Pro Forma Statements of Operations, will differ from the preliminary estimates
because the final allocation will be based on purchase prices allocated to
assets and liabilities on the basis of the estimated fair values of the assets
and liabilities determined at the end of the allocation period as allowed by
Accounting Principles Board Opinion No. 38.
The unaudited pro forma financial data should be read in
conjunction with the notes thereto, the Consolidated Financial Statements of the
Company and the notes thereto and the historical financial information and the
notes thereto relating to CGGS, the Wyoming Properties and the Portilla Field
included elsewhere in this Prospectus.
The unaudited pro forma financial data are not indicative of the
financial position or results of operations of the Company which would actually
have occurred if the Transactions had occurred at the dates presented or which
may be obtained in the future. In addition, future results may vary
significantly from the results reflected in such statements due to normal crude
oil and natural gas production declines, reductions in prices paid for crude oil
and natural gas, future acquisitions and other factors.
38
<PAGE>
<TABLE>
<CAPTION>
UNAUDITED PRO FORMA STATEMENT OF OPERATIONS
For the Year Ended December 31, 1995
Historical Acquisitions
----------- -----------------------------------------------
East White Adjustment
Abraxas Point and to Reflect Acquisition
Petroleum Wyoming Stedman Sale of and Offering
Corporation CGGS Properties Portilla(1) Island(2) Nevis (a) Adjustments Pro Forma
----------- ---------- ----------- ----------- ---------- ----------- ------------- ----------
(dollars in thousands)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Operating revenue:
Oil and gas
production $ 13,660 $ 13,849 $ 7,542 $ 3,676 $ 2,062 $ -- $ -- $ 40,789
Processing - 24,072 -- -- -- (20,012) -- 4,060
Rig revenue 108 - -- -- -- -- -- 108
Other 49 690 -- -- -- -- -- 739
---------- --------- -------- -------- ------- -------- -------- --------
Total operating
revenue 13,817 38,611 7,542 3,676 2,062 (20,012) -- 45,696
Operating costs
and expenses:
LOE 4,333 4,137 2,142 835 475 -- -- 11,922
Processing -- 10,737 -- -- -- (9,501) -- 1,236
DD&A 5,434 10,003 -- -- -- (3,672) 9,327 (b) 21,092
Rig operations 125 -- -- -- -- -- -- 125
G&A 1,042 3,257 -- -- -- (1,173) (534)(c) 2,592
---------- --------- -------- -------- ------- -------- -------- --------
Total operating
expenses 10,934 28,134 2,142 835 475 (14,346) 8,793 36,967
---------- --------- -------- -------- ------- -------- -------- --------
Operating Income 2,883 10,477 5,400 2,841 1,587 (5,666) (8,793) 8,729
Other(income)expense:
Interest incom e (34) (82) -- -- -- -- -- (116)
Amortization of
deferred financing
fee 214 106 -- -- -- -- 705(d) 1,025
Interest expense 3,911 11,822 -- -- -- (5,782) 14,325(e) 24,276
Unrealized foreign
exchange gain -- (795) -- -- -- -- 795(f) --
Realized foreingn
exchange loss -- 44 -- -- -- -- -- 44
---------- --------- -------- -------- ------- -------- -------- --------
Income(loss)
before tax (1,208) (618) 5,400 2,841 1,587 116 (24,618) (16,500)
Income tax(benefit):
Current -- 224 -- -- -- (128) -- 96
Deferred -- -- -- -- -- -- (679)(g) (679)
---------- --------- -------- -------- ------- -------- -------- --------
Net income(loss) $ (1,208) $ (842) $ 5,400 $ 2,841 $ 1,587 $ 244 $(23,939) $(15,917)
Less dividend
requirement on
cumulative preferred
stock (366) -- -- -- -- -- -- (366)
---------- --------- -------- -------- ------- -------- -------- --------
Net income (loss)
available to common
stockholders $ (1,574) $ (842) $ 5,400 $ 2,841 $ 1,587 $ 244 $(23,939) $(16,283)
========== ========= ======== ======== ======== ======== ======== ========
Earnings (loss)
per share: $ (0.34) $ -- $ -- $ -- $ -- $ -- $ -- $ (3.51)
========== ========== ======== ======== ======== ======== ======== ========
Other data:
EBITDA $ 8,351 $ 20,518 $ 5,400 $ 2,841 $ 1,587 $ (9,338) $ 534 $ 29,893
========== ========== ======== ======== ======== ======== ======== ========
</TABLE>
- -------------
(1) The data for Portilla reflects that portion of Portilla previously owned by
the Pension Fund.
(2) The data for East White Point and Stedman Island reflects that portion of
East White Point and Stedman Island previously owned by the Pension Fund.
See notes to unaudited pro forma financial statements.
39
<PAGE>
<TABLE>
<CAPTION>
UNAUDITED PRO FORMA STATEMENT OF OPERATIONS
For the Nine Months Ended September 30, 1996
Historical Acquisitions
----------- -----------------------------------------------
East White Adjustment
Abraxas Point and to Reflect Acquisition
Petroleum Wyoming Portilla & Stedman Sale of and Offering
Corporation CGGS Properties Happy (h) Island Nevis (a) Adjustments Pro Forma
----------- ---------- ----------- ----------- ---------- ----------- ------------- ---------
(dollars in thousands)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Operating revenue:
Oil and gas
production $ 11,786 $ 12,246 $ 7,280 $ 5,232 $ 2,359 $ -- $ -- $ 38,903
Processing -- 20,279 -- -- -- (17,214) -- 3,065
Rig revenue 106 -- -- -- -- -- -- 106
Other 17 160 -- -- -- -- -- 177
----------- ---------- ----------- ----------- ---------- ----------- ----------- --------
Total operating
revenue 11,909 32,685 7,280 5,232 2,359 (17,214) -- 42,251
Operating costs
and expenses:
LOE 3,296 2,920 1,844 1,086 404 -- -- 9,550
Processing -- 11,289 -- -- -- (10,097) -- 1,192
DD&A 4,145 7,722 -- -- -- (3,098) 8,895(b) 17,664
Rig operations 113 -- -- -- -- -- -- 113
G&A 1,250 2,156 -- -- -- (481) (380(c) 2,545
Hedging loss 511 -- -- 370 -- -- -- 881
----------- ---------- ----------- ----------- ---------- ----------- ----------- --------
Total operating
expense 9,315 24,087 1,844 1,456 404 (13,676) 8,515 31,945
----------- ---------- ----------- ----------- ---------- ----------- ----------- --------
Operating income 2,594 8,598 5,436 3,776 1,955 (3,538) (8,515) 10,306
Other (income)
expense:
Interest income (156) (226) -- -- -- -- -- (382)
Amortization
of deferred
financing fee 192 80 -- -- -- -- 497(d) 769
Interest expense 2,142 8,870 -- -- -- (4,255) 11,394(e) 18,151
Minority interest 58 -- -- -- -- -- -- 58
Unrealized foreign
exchange gain -- (2,070) -- -- -- -- 2,070(f) --
Realized foreign
exchange gain -- (51) -- -- -- -- -- (51)
Loss on
Securities 235 -- -- -- -- -- -- 235
----------- ---------- ----------- ----------- ---------- ----------- ------------ --------
Income (loss)
before tax 123 1,995 5,436 3,776 1,955 717 (22,476) (8,474)
Income Tax (benefit):
Current -- 190 -- -- -- (89) -- 101
Deferred -- -- -- -- -- -- (541(g) (541)
----------- ---------- ----------- ----------- ---------- ----------- ------------ --------
Net income (loss)
excluding
extraordinary
items 123 1,805 5,436 3,776 1,955 806 (21,935) (8,034)
Less dividend
requirement on
cumulative
preferred stock (274) -- -- -- -- -- -- (274)
----------- ---------- ----------- ----------- ---------- ----------- ------------ --------
Net income (loss)
available to
common
stockholders $ (151) $ 1,805 $ 5,436 $ 3,776 $ 1,955 $ 806 $ (21,935) $(8,308)
=========== ========== =========== =========== ========== =========== =========== ========
Earnings (loss)
per share $ (0.03) $ (1.54)
=========== ========
Other data:
EBITDA $ 6,895 $ 16,597 $ 5,436 $ 3,776 $ 1,955 $ (6,636) $ 380 $28,403
=========== ========== =========== =========== ========== =========== =========== ========
</TABLE>
- -------------
See notes to unaudited pro forma financial statements.
40
<PAGE>
<TABLE>
<CAPTION>
UNAUDITED PRO FORMA CONDENSED BALANCE SHEET
As of September 30, 1996
Historical Acquisitions
------------ -------------------- Acquisition
Adjustments Adjustments
Abraxas to Reflect Portilla and
Petroleum Sale of East White Point Offering
Corporation CGGS Nevis(a) and Stedman Island Adjustments ProForma
------------ -------- ----------- ------------------ ------------ ----------
(dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Assets:
Cash $ 9,993 $ 7,495 $ 87,000 $ (84,412) (b) $ (8,590) (f) $ 11,486
Accounts receivable 3,965 10,099 (5,769) -- -- 8,295
Other 280 -- -- -- -- 280
-------- -------- ----------- ----------- --------- ---------
Total current assets 14,238 17,594 81,231 (84,412) (8,590) 20,061
Property and equipment:
Oil and gas properties 111,104 12,769 -- 49,336 (b) --
29,022 (d) --
8,771 (e) -- 211,002
Processing facilities -- 78,860 (50,790) 18,190 (b) -- 46,260
Other property and
equipment 872 -- -- 3,600 (b) -- 4,472
Investment and advances
to partnership 2,397 -- -- (2,397) (d) -- --
Deferred financing fees 971 992 -- 223 (d) 8,200 (f)
(992) (b) (223)(b) 9,171
Other assets 858 -- -- -- 858
-------- -------- ----------- ----------- --------- ---------
Total assets $130,440 $110,215 $ 30,441 $ 21,341 $ (613) $291,824
======== ======== =========== =========== ========= =========
Liabilities and
stockholders' equity:
Total current liabilities $ 6,556 $ 5,586 $ (2,050) $ (2,135) (b) $ -- $ 7,957
Long-term debt:
Financing agreement 85,000 -- -- -- (85,000)(f) --
CGGS debentures -- 84,412 -- (84,412) (b) -- --
Acquisition debt:
CGGS shareholders -- -- -- 94,771 (b) (94,771)(f) --
Portilla -- -- -- 26,848 (d) (26,848)(f) --
East White
Point/Stedman -- -- -- 8,771 (e) (8,771)(f) --
Notes -- -- -- -- 215,000 (f) 215,000
Other liabilities 124 3,834 (1,664) -- -- 2,294
Deferred income taxes 187 -- -- 28,036 (b) -- 28,223
Minority interest 2,153 -- -- -- -- 2,153
Shareholders' equity:
Preferred stock -- -- -- -- -- --
Common stock 58 25,296 -- (25,296) (c) -- 58
Additional paid in
capital 50,920 -- -- -- -- 50,920
Retained earnings
(deficit) (14,184) (8,672) 34,155 (25,483) (c) (223)(g) (14,407)
Cumulative foreign
exchange adjustment -- (241) -- 241 (c) -- --
exchange
Treasury stock (374) -- -- -- -- (374)
--------- --------- --------- ----------- --------- ---------
Total stockholders' equity 36,420 16,383 34,155 (50,538) (223) 36,197
--------- --------- --------- ----------- --------- ---------
Total liabilities and
Stockholders' equity $130,440 $110,215 $30,441 $ 21,341 $ (613) $291,824
========= ========= ========= ========== ========= =========
</TABLE>
- -------------
See notes to unaudited pro forma financial statements.
41
<PAGE>
NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS
Note 1. The pro forma unaudited Statements of Operations for the periods ended
December 31, 1995 and September 30, 1996 reflect the Transactions as if
consummated on January 1, 1995 and January 1, 1996, respectively:
a. To adjust for the sale of the Nevis Plant prior to the Issuers' acquisition
of CGGS.
The reduction in G&A expense represents the contractual management and
administrative fee paid to the operator related to the results of the Nevis
Plant, net of overhead recoveries charged to third parties for processing of
natural gas.
The reduction in interest expense relates to the repayment of a portion
of the debentures issued by CGGS in connection with its acquisition of the Nevis
Plant.
b. To adjust DD&A expense for the year ended December 31, 1995 to reflect the
acquisition of CGGS, the Wyoming Properties, the 50% overriding royalty interest
in Portilla previously owned by the Pension Fund and the 50% overriding royalty
interest in East White Point and Stedman Island for the twelve months ended
December 31, 1995 and to adjust DD&A expense for the nine months ended September
30, 1996 to reflect the acquisitions of CGGS, the Wyoming Properties, the
reacquisition of Portilla and Happy for the period March 21, 1996 to September
30, 1996, the acquisition of the 50% overriding royalty interest in Portilla
previously owned by the Pension Fund for the nine months ended September 30,
1996 and the 50% overriding royalty interest in East White Point and Stedman
Island for the nine months ended September 30, 1996. DD&A expense of crude oil
and natural gas properties is computed using the units of production method.
Depreciation of natural gas processing facilities is computed using the straight
line method over the estimated useful life of 18 years.
c. To adjust G&A expense of CGGS to reflect the following:
Fiscal Nine Months
1995 Ended
September 30,
1996
--------- ---------------
(dollars in thousands)
Reversal of management and administrative
fees paid to third party $(1,649) $(1,340)
Additional expenses relating to salaries
and benefits, office rent and other G&A 1,115 960
------- ------
$ (534) $(380)
------- ------
d. To adjust the amortization of the deferred financing fee for the First Union
Credit Facility and the repayment of the CGGS debentures and the fees and
expenses related to the issuance of the Notes.
e. To adjust interest expense using a rate of 11.5% for the issuance of the
Notes and to reflect the repayment of the Bridge Facility and the retirement of
the CGGS debentures.
f. To adjust the foreign exchange gain realized by CGGS with respect to certain
U.S. dollar-denominated debentures.
g. To reflect the deferred tax benefit.
Year Ended Nine Months
December 31, 1995 Ended
September 30,
1996
------------------ -----------------
(dollars in thousands)
Deferred tax benefit $679 $541
==== ====
42
<PAGE>
h. The following reflects the results of operations of the 50% overriding
royalty interest in Portilla previously owned by the Pension Fund for the nine
months ended September 30, 1996 and the results from Portilla and Happy
previously owned by the Issuers for the period March 21, 1996 to September 30,
1996:
<TABLE>
<CAPTION>
Certain
Overriding
Royalty
Interests in
the Portilla
Field Acquired
by Abraxas Portilla and Happy
Petroleum previously owned
Corporation by the Company
for the Nine for the period Portilla
Months Ended March 21, 1996 to and
September 30, 1996 September 30, 1996 Happy
------------------ ------------------ ----------
(dollars in thousands)
<S> <C> <C> <C>
Oil and gas production sales $ 2,822 $ 2,410 $ 5,232
LOE (622) (464) (1,086)
Hedging loss -- (370) (370)
================== ================== ==========
$ $ $
$ 2,200 $ 1,576 $ 3,776
================== ================== ==========
</TABLE>
Note 2. The pro forma unaudited Condensed Balance Sheet as of September 30,
1996, reflects the Transactions as if they had occurred as of September 30, 1996
as follows (the acquisition of the Wyoming Properties closed on September 30,
1996, and is reflected in the historical balance sheet of the Company at
September 30, 1996 the acquisitions of CGGS and Portilla and Happy were
consummated on November 14, 1996 and the acquisition of East White Point and
Stedman Island was consummated on November 27, 1996):
a. Canadian Abraxas purchased all of the outstanding shares of capital stock of
CGGS and immediately thereafter merged CGGS with and into Canadian Abraxas.
Prior to the Canadian Abraxas' acquisition of CGGS, the Nevis Plant was sold and
Canadian Abraxas, as the surviving entity of the CGGS acquisition, used the net
proceeds from the sale of the Nevis Plant to retire the outstanding debentures
of CGGS. The CGGS balance sheet included in the accompanying Unaudited Pro Forma
Condensed Balance Sheet dated as of September 30, 1996 represents the historical
unaudited balance sheet of CGGS as of October 31, 1996, converted into United
States generally accepted accounting principles and into U.S. dollars. The
balances included in the "Adjustments to Reflect Sale of Nevis" column on the
accompanying Unaudited Pro Forma Condensed Balance Sheet represent the sale of
the Nevis Plant and related accounts receivable and payable at a sales price of
approximately CDN$116.1 million, net of estimated selling costs and related
closing adjustments, or approximately U.S.$87.0 million, and the removal of the
historical net book value of the Nevis Plant and the working capital and other
liabilities associated with the operations of the Nevis Plant as of October 31,
1996. Retained earnings represent the approximate gain from the sale of the
Nevis Plant.
b. The acquisition of CGGS was accounted for as a purchase in accordance with
Accounting Principles Board Opinion No. 16 "Business Combinations." The purchase
price was allocated to the crude oil and natural gas properties, the natural gas
processing plants and other assets based upon estimated fair values. A deferred
income tax liability has been established representing the tax effect of the
difference in the fair value of the assets acquired and their historical tax
basis and has been allocated as additional basis of the crude oil and natural
gas properties, the natural gas processing plants and other assets.
(dollars in
thousands)
The total purchase price has been allocated as follows:
Purchase price for the outstanding capital stock of
CGGS including amounts paid for working capital $94,771
Book value of net assets acquired 49,546
==========
Increase in basis $45,225
==========
43
<PAGE>
Allocation of increase in basis:
Increase in crude oil and natural gas properties $49,336
Increase in natural gas processing facilities 18,190
Increase in other property and equipment 3,600
Deferred financing fee (992)
Change in accounts payable 3,127
Change in deferred tax liabilities (28,036)
==========
$45,225
==========
Retirement of CGGS debentures:
Cash $(84,412)
CGGS debentures 84,412
c. To reflect the elimination of CGGS equity balance:
Common stock $25,296
Retained earnings 25,483
Cumulative foreign exchange adjustment (241)
d. To reflect the purchase of Portilla and Happy:
Purchase price of Portilla and Happy $27,600
Estimated adjustments to purchase price for accrual of
net crude oil and natural gas revenues to November 14, 1996 (752)
----------
Net amount due to seller 26,848
Elimination of the Issuers' equity investment in and
advances to the partnership 2,397
Deferred financing fee related to debt repaid (223)
==========
Net purchase price allocated to oil and gas properties $29,022
==========
Acco entered into a commodity price hedge with Christiania which
was assumed by the Company and BTCo and ING Capital in connection with the
consummation of the Transactions. Under the terms of this commodity price hedge,
the Company is required to receive or make payment to BTCo and ING Capital based
on a differential between a fixed and variable price for crude oil and natural
gas through the last business day of November 2001 on volumes ranging from 8,160
barrels of crude oil to 20,000 barrels of crude oil per month and 14,850 MMBTU
of natural gas to 87,406 MMBTU of natural gas per month. Under this agreement,
the Company receives fixed prices ranging from $17.20 per barrel of crude oil to
$18.55 per barrel of crude oil and $1.793 per MMBTU of natural gas to $1.925 per
MMBTU of natural gas and makes payments based on the price for west Texas
intermediate light sweet crude oil on the NYMEX for crude oil and the Inside
FERC, Tennessee Gas Pipeline Co: Texas (Zone 0) price for natural gas. Currently
there is a net unrealized loss of approximately $1.8 million under the commodity
price hedge.
e. To reflect the purchase of East White Point and Stedman
Island
Purchase price of East White Point and Stedman Island $9,271
Estimated adjustment to purchase price for accrual of
net crude oil and natural gas revenues due to the
Company from August 1996 to November 1996 (500)
===========
Net purchase price allocated to oil and gas properties. $8,771
===========
44
<PAGE>
f. To reflect the issuance of Notes and application of
the proceeds
therefrom:
Issuance of Notes $215,000
Expense for issuance of Notes (8,200)
Repayment of the Bridge Facility (85,000)
Payment of amount due to CGGS (94,771)
Payment of amounts due to seller of Portilla and Happy (26,848)
Payment of amounts due to seller of East White Point and
Stedman Island (8,771)
-----------
Decrease in existing cash $8,590
===========
g. To reflect the write-off of deferred financing fees upon
retirementof certain related debt $(223)
===========
45
<PAGE>
SELECTED CONSOLIDATED FINANCIAL DATA
The following historical selected consolidated financial data are
derived from, and qualified by reference to, the Company's Consolidated
Financial Statements and the notes thereto. The statement of operations data for
the nine months ended September 30, 1996 is not necessarily indicative of
results for a full year. The consolidated financial data for each of the nine
month periods ended September 30, 1995 and 1996 are derived from the unaudited
financial statements and, in the opinion of management, include all adjustments
that are of a normal and recurring nature and necessary for a fair presentation.
The historical consolidated financial data should be read in conjunction with
the Consolidated Financial Statements of the Company and the notes thereto
included elsewhere in this Prospectus and "Management's Discussion and Analysis
of Financial Condition and Results of Operations."
<TABLE>
<CAPTION>
Nine Months Ended
Year Ended December 31, September 30,
---------------------------------------------- -------------------
1991 1992 1993 1994 1995 1995 1996
------- ------- ------ ------- ------- ------- -----------
Consolidated Statements (dollars in thousands except per share data)
of Operations
<S> <C> <C> <C> <C> <C> <C> <C>
Operating revenue:
Oil and gas production
sales $ 933 $ 2,666 $ 7,275 $11,114 $13,660 $9,795 $11,786
Other revenue 217 25 219 235 157 134 123
------ ------- ------ ------- ------- ------- ------
Total operating revenue 1,150 2,691 7,494 11,349 13,817 9,929 11,909
------ ------- ------ ------- ------- ------- ------
Operating costs and
expenses:
Lease operating and
production taxes 322 1,075 2,896 3,693 4,333 3,183 3,296
Depreciation, depletion
and amortization 361 957 2,373 3,790 5,434 3,541 4,145
General and administrative
expenses 338 770 510 810 1,042 768 1,250
Other 73 (29) 103 133 125 95 624
------ ------- ------ ------- ------- ------- ------
Total Operating expenses 1,094 2,773 5,882 8,426 10,934 7,587 9,315
------ ------- ------ ------- ------- ------- ------
Operating income (loss) 56 (82) 1,612 2,923 2,883 2,342 2,594
Net interest expense 121 892 2,492 2,343 3,877 2,907 1,986
Amortization of deferred
financing fees (1) -- -- 649 400 214 120 192
Other (income) expense (50) 98 (136) 67 -- -- 293
------ ------- ------ ------- ------- ------- ------
Income (loss) from
continuing operations
before tax and
extraordinary items (15) (1,072) (1,393) 113 (1,208) (685) 123
Deferred income tax
expense -- -- (187) -- -- -- --
Loss from discontinued
operations (2) - - (2,883) (280) (1,335) -- -- --
------ ------- ------ ------- ------- ------- ------
Income (loss) before
extraordinary items (15) (3,955) (1,860) (1,222) (1,208) (685) 123
Extraordinary items -- -- (573)(3) (1,172)(3) -- -- (369) (3)
------ ------- ------ ------- ------- ------- ------
Net income (loss) (15) (3,955) (2,433) (2,394) (1,208) (685) (246)
Preferred dividends
requirement (249) (249) (186) (183) (366) (274) (274)
------- ------- ------ ------- ------- ------- ------
Net income (loss)
applicable to
common stockholders' $(264) $(4,204) $(2,619) $(2,577) $(1,574) $ (959) $(520)
======= ======= ======= ======= ======= ======= ======
Earnings per share:
Income (loss) from
continuing operations $(0.28) $(1.23) $ (0.91) $ (0.02) $ (0.34 $(0.21) $(0.03)
======= ====== ======== ======= ======= ====== =======
Discontinued operatios -- (2.69) (0.14) (0.31) -- -- --
Extraordinary items -- -- (0.29) (0.27) -- -- (0.06)
------- ------ -------- ------- ------- ------ -------
Net income (loss) per
common share $(0.28) $(3.92) $ (1.34) $ (0.60) $ (0.34) $(0.21) $(0.09)
======= ====== ======== ======= ======= ======= =======
Weighted average shares
outstanding 947 1,074 1,947 4,310 4,635 4,456 5,804
======= ====== ======== ======= ======= ======= =======
Other Data:
EBITDA $ 168 $760 $ 4,049 $ 6,728 $ 8,351 $5,892 $ 6,894
Capital expenditures $2,940 $7,866 $ 26,234 $40,906 $12,256 $9,223 $58,040
</TABLE>
46
<PAGE>
<TABLE>
<CAPTION>
At December 31, At September 30,
----------------------------------------- ------------------
1991 1992 1993 1994 1995 1995 1996
------- ------- ------- -------- ------- --------- --------
(dollars in thousands)
Consolidated Balance
Sheet Data:
<S> <C> <C> <C> <C> <C> <C> <C>
Working capital
(deficit)(4) $(1,323) $(7,184) $(1,368) $(1,605) $2,633 $(2,465) $ 7,682
Total assets 13,078 18,017 43,396 75,361 85,067 80,578 130,440
Long-term debt (5) 7,080 6,602 12,484 41,235 41,557 43,974 85,000
Stockholders' equity 3,869 2,233 25,143 28,502 37,063 27,546 36,421
</TABLE>
- -----------
(1) Consists of financing fees incurred in connection with the acquisition of
crude oil and natural gas producing properties.
(2) Discontinued operations consist primarily of coal operations which were
terminated in January 1995. The Company anticipates no additional costs
associated with coal operations in the future. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations -- Results of
Operations."
(3) Consists of loss incurred in connection with extinguishment of debt.
(4) Includes current maturities of long-term debt and capital lease obligations.
(5) Excludes current maturities of long-term debt and capital lease obligations.
47
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following is a discussion of the Company's financial
condition, results of operations, liquidity and capital resources. This
discussion should be read in conjunction with the Consolidated Financial
Statements of the Company and the notes thereto included elsewhere in this
Prospectus.
Results of Operations
The Company's revenue, 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 NGLs produced by the Company. In
addition, the Company's proved reserves will decline as crude oil, NGLs and
natural gas are produced unless the Company is successful in acquiring producing
properties or conducts successful exploration and development activities.
Selected Operating Data. The following table sets forth certain
operating data of the Company for the periods presented:
<TABLE>
<CAPTION>
Nine Months
Ended
Years Ended December 31, September 30,
------------------------------------------
(dollars in thousands, except per unit
data)
1993 1994 1995 1995 1996
---- ---- ---- ---- ----
Operating revenue:
<S> <C> <C> <C> <C> <C>
Crude oil sales $ 4,210 $ 5,501 $ 6,889 $ 4,887 $ 5,306
NGLs sales 500 1,193 1,553 1,165 1,350
Natural gas sales 2,565 4,420 5,218 3,743 5,130
Other 219 235 157 134 123
------ -------- -------- ------- --------
Total operating revenue $ 7,494 $ 11,349 $ 13,817 $ 9,929 $ 11,909
======= ======== ======== ======= ========
Operating income $ 1,612 $ 2,923 $ 2,883 $ 2,342 $ 2,595
Crude oil production (MBbls) 270.9 355.7 401.4 283.5 266.0
NGLs production (MBbls) 33.9 113.2 143.4 106.5 106.1
Natural gas production (MMcf) 985.4 2,392.9 3,552.7 2,645.1 2,625.4
Average crude oil sales
prices (per Bbl) $ 15.54 $ 15.47 $ 17.16 $ 17.24 $ 19.94
Average NGLs sales price
(per Bbl) $ 14.75 $ 10.54 $10.83 $ 10.94 $ 12.73
Average natural gas sales
prices (per Mcf) $ 2.60 $ 1.85 $ 1.47 $ 1.41 $ 1.95
</TABLE>
Comparison of Nine Months Ended September 30, 1996 to Nine Months Ended
September 30, 1995
Operating Revenue. Operating revenue from crude oil, NGLs and
natural gas sales increased by 20.3%, from $9.8 million to $11.8 million, from
the nine months ended September 30, 1995 to the nine months ended September 30,
1996, primarily due to an increase in crude oil, NGLs and natural gas sales
prices and increased production volumes from the Company's properties other than
Portilla and Happy in 1996 as compared to 1995 which somewhat offset the loss in
production volumes from the sale of Portilla and Happy. Operating revenue from
Portilla and Happy decreased from $3.3 million to $1.2 million from the nine
months ended September 30, 1995 to the nine months ended September 30, 1996. The
Company's average sales prices for its crude oil, NGLs and natural gas were
$17.24 per Bbl, $10.94 per Bbl and $1.41 per Mcf, respectively, for the first
nine months of 1995 as compared to $19.94 per Bbl, $12.73 per Bbl and $1.95 per
Mcf, respectively, for the first nine months of 1996. Crude oil and NGLs sales
volumes decreased by 4.6%, from 390.0 MBbls to 372.1 MBbls, from the nine months
ended September 30, 1995 to the nine months ended September 30, 1996 and natural
48
<PAGE>
gas sales volumes decreased by 0.7%, from 2,645.1 MMcf to 2,625.4 MMcf, from the
nine months ended September 30, 1995 to the nine months ended September 30, 1996
as a result of the sale of Portilla and Happy. Portilla and Happy contributed
161.8 MBbls of crude oil and NGLs (41.5% of Company total) and 376.0 MMcf of
natural gas (14.2% of Company total) during the first nine months of 1995 as
compared to 54.2 MBbls of crude oil and NGLs (14.6% of Company total) and 117.5
MMcf of natural gas (4.5% of Company total) for the first nine months of 1996.
Lease Operating Expenses. LOE increased by 3.6%, from $3.2
million to $3.3 million, from the first nine months of 1995 to the first nine
months of 1996, primarily due to the increased percentage of the Company's
production base attributable to west Texas crude oil production than that from
Texas Gulf Coast properties, which generally have lower LOE than the west Texas
properties. Of the LOE incurred during the first nine months of 1995, $445,000,
or 14.0% of the Company's total LOE, was attributable to Portilla and Happy, as
compared to $233,000, or 7.1% of the Company's total LOE, during the first nine
months of 1996. The Company's LOE on a per BOE basis for the first nine months
of 1995 was $3.83 per BOE as compared to $4.07 per BOE for the first nine months
of 1996.
G&A Expenses. G&A expenses increased by 62.7%, from $769,000 to
$1.2 million, from the first nine months of 1995 to the first nine months of
1996, primarily as a result of hiring additional staff to manage the Company's
assets, including the establishment of a Canadian administrative office. The
Company's G&A expenses on a per BOE basis for the first nine months of 1995 were
$0.93 per BOE as compared to $1.54 per BOE for the first nine months of 1996.
DD&A Expenses. DD&A increased by 17.1%, from $3.5 million to $4.2
million, from the first nine months of 1995 to the first nine months of 1996
primarily due to the increase in sales volumes of crude oil and natural gas. The
Company's DD&A expenses on a per BOE basis for the first nine months of 1995
were $4.27 per BOE as compared to $5.27 per BOE for the first nine months of
1996.
Interest Expense and Preferred Dividends. Interest expense and
preferred dividends decreased 24.2%, from $3.2 million to $2.4 million, from the
first nine months of 1995 to the first nine months of 1996. The decrease was
attributable to the sale of Portilla and Happy, part of the proceeds of which
were used to reduce the indebtedness outstanding under the First Union Credit
Facility by $12.0 million to $29.5 million.
Comparison of Year Ended December 31, 1994 to Year Ended December 31, 1995
Operating Revenue. Operating revenue from crude oil, NGLs and
natural gas sales increased by 22.9%, from $11.1 million to $13.7 million, from
the year ended December 31, 1994 to the year ended December 31, 1995. This
increase was primarily attributable to an increase in crude oil and NGLs sales
volumes of 16.2%, from 468.9 MBbls to 544.8 MBbls, and an increase in natural
gas sales volumes of 48.5%, from 2,392.9 MMcf to 3,552.7 MMcf. The increase in
sales volumes were primarily attributable to the acquisition of 80% of the
overriding royalty interest previously granted to a lender (the "ORRI") and the
acquisition of certain properties located in west Texas (the "West Texas
Properties") by the Company in June 1994 and July 1994, respectively. The
Company's average sales prices for its crude oil, NGLs and natural gas were
$15.47 per Bbl, $10.54 per Bbl and $1.85 per Mcf, respectively, for the year
ended December 31, 1994 as compared to $17.16 per Bbl, $10.83 per Bbl and $1.47
per Mcf, respectively, for the year ended December 31, 1995. A general weakening
of natural gas prices at the wellhead during the first nine months of 1995
resulted in a lower average natural gas sales price received by the Company
during the year ended December 31, 1995 as compared to the year ended December
31, 1994. This decrease was partially offset by an increase in average crude oil
prices received by the Company during the year ended December 31, 1995 as
compared to the year ended December 31, 1994.
Lease Operating Expenses. LOE increased by 17.3%, from $3.7
million to $4.3 million, from the year ended December 31, 1994 to the year ended
December 31, 1995, primarily due to the Company's owning a greater number of
wells during the year ended December 31, 1995 than it did during the year ended
December 31, 1994. The Company's LOE on a per BOE basis for the year ended
December 31, 1994 was $4.26 per BOE as compared to $3.81 per BOE for the year
ended December 31, 1995.
49
<PAGE>
G&A Expenses. G&A expenses increased by 28.6%, from $810,000 to
$1.0 million, from the year ended December 31, 1994 to the year ended December
31, 1995 as a result of hiring additional staff to manage and develop the West
Texas Properties. The Company's G&A expenses on a per BOE basis for the year
ended December 31, 1994 were $0.93 per BOE as compared to $0.92 per BOE for the
year ended December 31, 1995.
DD&A Expenses. DD&A increased by 43.4%, from $3.8 million to $5.4
million, from the year ended December 31, 1994 to the year ended December 31,
1995 primarily as a result of the increase in sales volumes of crude oil and
natural gas. The Company's DD&A expenses on a per BOE basis for the year ended
December 31, 1994 were $4.37 per BOE as compared to $4.78 per BOE for the year
ended December 31, 1995.
Interest Expense and Preferred Dividends. Interest expense and
preferred dividends increased 68.3%, from $2.5 million to $4.3 million from the
year ended December 31, 1994 to the year ended December 31, 1995, primarily as a
result of the Company's borrowing $28.0 million under the First Union Credit
Facility to acquire the West Texas Properties in July 1994.
Comparison of Year Ended December 31, 1993 to Year Ended December 31, 1994
Operating Revenue. Operating revenue from crude oil, NGLs and
natural gas sales increased by 52.8%, from $7.3 million to $11.1 million, from
the year ended December 31, 1993 to the year ended December 31, 1994. This
increase was primarily attributable to an increase in crude oil and NGLs sales
volumes of 53.8%, from 304.8 MBbls to 468.9 MBbls, and an increase in natural
gas sales volumes of 142.8%, from 985.4 MMcf to 2,392.9 MMcf. The increase in
sales volumes was primarily attributable to the acquisition of the ORRI and the
West Texas Properties by the Company in June 1994 and July 1994, respectively,
the further development of the Sinton Properties, which were acquired in April
1993, and the Company's ongoing development drilling program. The Company's
average sales prices for its crude oil, NGLs and natural gas were $15.54 per
Bbl, $14.75 per Bbl and $2.60 per Mcf, respectively, for the year ended December
31, 1993 as compared to $15.47 per Bbl, $10.54 per Bbl and $1.85 per Mcf,
respectively, for the year ended December 31, 1994. A general weakening of
natural gas prices at the wellhead during the year ended December 31, 1994
resulted in a lower average natural gas sales price received by the Company as
compared to the average natural gas sales price received by the Issuers during
the year ended December 31, 1993.
Lease Operating Expenses. LOE increased by 27.5%, from $2.9
million to $3.7 million, from the year ended December 31, 1993 to the year ended
December 31, 1994, primarily due to the Company's owning a greater number of
wells during the year ended December 31, 1994 than it did during the year ended
December 31, 1993. The Company's LOE on a per BOE basis for the year ended
December 31, 1993 was $6.17 per BOE as compared to $4.26 per BOE for the year
ended December 31, 1994.
G&A Expenses. G&A expenses increased by 59.0%, from $510,000 to
$810,000, from the year ended December 31, 1993 to the year ended December 31,
1994 as a result of an increase in staff. The Company's G&A expenses on a per
BOE basis for the year ended December 31, 1993 were $1.09 per BOE as compared to
$0.93 per BOE for the year ended December 31, 1994.
DD&A Expenses. DD&A increased by 59.7%, from $2.4 million to $3.8
million, from the year ended December 31, 1993 to the year ended December 31,
1994 primarily as a result of the increase in sales volumes of crude oil and
natural gas. The Company's DD&A expenses on a per BOE basis for the year ended
December 31, 1993 were $5.06 per BOE as compared to $4.37 per BOE for the year
ended December 31, 1994.
Interest Expense and Preferred Dividends. Interest expense and
preferred dividends decreased by 6.4%, from $2.7 million to $2.5 million, from
the year ended December 31, 1993 to the year ended December 31, 1994, primarily
as a result of the Company's restructuring its long-term debt in June 1994.
50
<PAGE>
Liquidity and Capital Resources
Capital expenditures for the years ended December 31, 1993, 1994
and 1995 were $26.2 million, $40.9 million and $12.3 million, respectively. For
the nine months ended September 30, 1995, capital expenditures were $9.2 million
compared to $58.0 million during the same period in 1996. The table below sets
forth the components of these capital expenditures on a historical basis for the
three years ended December 31, 1993, 1994 and 1995 and the nine months ended
September 30, 1995 and 1996.
Nine Months Ended
Year Ended December 31 September 30,
--------------------------- --------------------
(dollars in thousands)
1993 1994 1995 1995 1996
---- ---- ---- ---- ----
Expenditure category:
Property acquisitions (1) $20,480 $33,597 $ 719 $ 199 $47,655 (1)
Development 5,167 7,151 11,398 8,935 10,016
Coal property development 46 -- -- -- --
Facilities and other 541 158 139 89 369
------ ------ ------ ------ ------
Total $26,234 $40,906 $12,256 $9,223 $58,040
======= ======= ======= ====== =======
- --------------
(1) Acquisition costs include approximately 78,000 shares of Common Stock valued
at $533,000 for the year ended December 31, 1993, and 45,741 shares of Preferred
Stock valued at $4.6 million in 1994 and $1.1 million of oil and gas properties
acquired from Cascade in the nine months ended September 30, 1996.
Acquisitions of crude oil and natural gas producing properties
beginning in 1993 and continuing through the nine months ended September 30,
1996 account for the majority of the capital expenditures made by the Company
since January 1, 1993. These expenditures were funded through internally
generated cash flow, borrowings from the Company's lenders and the issuance of
shares of the Company's Common and Preferred Stock.
After consummation of the Offering and application of the net
proceeds therefrom, the Company increased its total outstanding debt to
approximately $215.1 million from $85.0 million at September 30, 1996. In
addition, on November 14, 1996, the Company entered into the New Credit Facility
concurrently with the consummation of the Offering. The New Credit Facility
provides for a revolving line of credit with an initial availability of $20.0
million, subject to certain customary conditions including a borrowing base
condition.
Commitments available under the New Credit Facility are subject
to Borrowing Base redeterminations to be performed semi-annually and, at the
option of each of the Company and the Lenders, one additional time per year. Any
outstanding principal balance in excess of the Borrowing Base will be due and
payable in three equal monthly payments after a Borrowing Base redetermination.
The Borrowing Base will be determined in the Agent's sole discretion, subject to
the approval of the Lenders, based on the value of the Company's reserves as set
forth in the reserve report of the Company's independent petroleum engineers,
with consideration given to other assets and liabilities.
The New Credit Facility has an initial revolving term of two
years and a reducing period of three years from the end of the initial two-year
period. The commitment under the New Credit Facility will be reduced during such
reducing period by eleven equal quarterly reductions. Quarterly reductions will
equal 8.2% per quarter with the remainder due at the end of the three-year
reducing period.
The applicable interest rate charged on the outstanding balance
of the New Credit Facility is based on a facility usage grid. If the borrowings
under the New Credit Facility represent an amount less than or equal to 33.3% of
the available Borrowing Base, then the applicable interest rate charged on the
outstanding balance will be either (a) an adjusted rate of the London Inter-Bank
51
<PAGE>
Offered Rate ("LIBOR") plus 1.25% or (b) the prime rate of the Agent (which is
based on the Agent's published prime rate) plus 0.50%. If the borrowings under
the New Credit Facility represent an amount greater than or equal to 33.3% but
less than 66.7% of the available Borrowing Base, then the applicable interest
rate on the outstanding principal will be either (a) LIBOR plus 1.75% or (b) the
prime rate of the Agent plus 0.50%. If the borrowings under the New Credit
Facility represent an amount greater than or equal to 66.7% of the available
Borrowing Base, then the applicable interest rate on the outstanding principal
will be either (a) LIBOR plus 2.00% or (b) the prime rate of the Agent plus
0.50%. LIBOR elections can be made for periods of one, three or six months.
The New Credit Facility contains a number of covenants that,
among other things, restrict the ability of the Company to (i) incur certain
indebtedness or guarantee obligations, (ii) prepay other indebtedness including
the Notes, (iii) make investments, loans or advances, (iv) create certain liens,
(v) make certain payments, dividends and distributions, (vi) merge with or sell
assets to another person or liquidate, (vii) sell or discount receivables,
(viii) engage in certain intercompany transactions and transactions with
affiliates, (ix) change its business, (x) experience a change of control and
(xi) make amendments to its charter, by-laws and other debt instruments. In
addition, under the New Credit Facility, the Company is required to comply with
specified financial ratios and tests, including minimum debt service coverage
ratios, maximum funded debt to EBITDA tests, minimum net worth tests and minimum
working capital tests.
The New Credit Facility contains customary events of default,
including nonpayment of principal, interest or fees, violation 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 and change of control. The Notes also contain
a number of covenants and events of default. See "Description of the Notes."
At September 30, 1996, the Company had current assets of $14.2
million and current liabilities of $6.6 million, resulting in working capital of
$7.6 million. This compares to working capital of $2.6 million at December 31,
1995 and a deficiency of $2.5 million at September 30, 1995. The material
components of the Company's current liabilities at September 30, 1996 include
trade accounts payable of $4.7 million and revenue due third parties of $1.4
million.
The Company's current budget for capital expenditures, other than
acquisition expenditures, for 1997 is $33.3 million. Such expenditures will be
made primarily for the development of existing properties. Additional capital
expenditures may be made for acquisitions of producing properties as such
opportunities arise. The Company does not have an acquisition budget since the
timing and size of acquisitions are difficult to forecast. The Company has no
material long-term capital commitments and is consequently able to adjust the
level of its expenditures as circumstances dictate. Additionally, the level of
capital expenditures will vary during future periods depending on market
conditions and other related economic factors.
In August 1995, the Company entered into a rate swap agreement
with First Union relating to $25.0 million of principal amount outstanding under
the First Union Credit Facility. This agreement was assumed by BTCo and ING
Capital in connection with the consummation of the Bridge Facility and remains
in effect. Under the agreement, the Company pays a fixed rate of 6.15% while the
lenders under the New Credit Facility will pay a floating rate equal to the
USD-LIBOR-BBA rate for one month maturities, quoted on the eighteenth day of
each month, to the Company. Settlements are due monthly. The agreement
terminates in August 1997 and may be extended for an additional year by the
Lenders.
Acco entered into a commodity price hedge with Christiania which
was assumed by the Company and BTCo and ING Capital in connection with the
consummation of the Transactions. Under the terms of this commodity price hedge,
the Company is required to receive or make payment to BTCo and ING Capital based
on a differential between a fixed and variable price for crude oil and natural
gas through the last business day of November 2001 on volumes ranging from 8,160
barrels of crude oil to 20,000 barrels of crude oil per month and 14,850 MMBTU
of natural gas to 87,406 MMBTU of natural gas per month. Under this agreement,
the Company receives fixed prices ranging from $17.20 per barrel of crude oil to
$18.55 per barrel of crude oil and $1.793 per MMBTU of natural gas to $1.925 per
MMBTU of natural gas and will make payments based on the price for west Texas
52
<PAGE>
intermediate light sweet crude oil on the NYMEX for crude oil and the Inside
FERC, Tennessee Gas Pipeline Co: Texas (Zone 0) price for natural gas.
Operating activities during the nine months ended September 30,
1996 provided $4.8 million of cash to the Company compared to $1.4 million in
the same period in 1995. Net income plus non-cash expense items during 1996 and
net changes in operating assets and liabilities accounted for most of these
funds. Investing activities required $41.1 million during the first nine months
of 1996 primarily from the acquisition of the Wyoming Properties. This compares
to cash requirements of $6.5 million during the same period of 1995 primarily
for the development of crude oil and natural gas properties. Financing
activities provided $41.9 million for the first nine months of 1996 compared to
providing $5.3 million for the same period of 1995.
For the year ended December 31, 1995, operating activities
provided $4.4 million of cash. Investing activities required $10.0 million
primarily for the development of existing properties. Total cash provided from
financing activities for 1995 was $9.8 million as the result of the sale of
1,330,000 shares of Common Stock and contingent value rights during November
1995 which resulted in net proceeds of $10.1 million.
During 1994, operating activities provided $4.3 million of cash.
Investing activities during 1994 utilized $35.9 million of cash primarily for
the acquisition of the ORRI and the West Texas Properties for $29.0 million and
the development of producing properties of $7.2 million. The Company borrowed
$40.9 million during 1994, repaid $12.7 million of long-term debt, sold Common
Stock for proceeds of $1.5 million and paid financing fees and dividends on
preferred stock resulting in a net contribution of $29.2 million from financing
activities.
For the year ended December 31, 1993, operating activities
produced $665,000 of cash. Investment activities during 1993 utilized $25.2
million of cash primarily for the acquisition of the Sinton Properties in the
amount of $19.9 million and the development of existing producing properties at
a cost of $5.2 million being offset by the sale of equipment inventory and
various crude oil and natural gas properties for $768,000. The Company borrowed
$20.6 million during 1993 and repaid $17.2 million of long-term debt and sold
2,250,000 shares of Common Stock for net proceeds of $23.1 million resulting in
a net contribution of $26.4 million from financing activities.
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 net operating loss carry forwards generated prior to December 31,
1991 of $6.9 million will be limited to approximately $235,000 per year. During
1992, the Company acquired 100% of the capital stock of an unrelated
corporation. The use of net operating loss carry forwards of $3.6 million of the
unrelated corporation are limited to approximately $115,000 per year. As a
result of the issuance of additional shares of Common Stock for acquisitions and
to raise capital, an additional ownership change occurred in October 1993.
Accordingly, it is expected that the use of the $13.4 million of net operating
loss carry forwards generated through October 1993 will be limited to
approximately $1.0 million per year, subject to the limitations described above,
and $7.2 million in the aggregate. Future changes in ownership may further limit
the use of the Company's net operating loss carry forwards. In addition to
Section 382 limitations, uncertainties exist as to the future utilization of the
operating loss carry forwards under the criteria set forth under FASB Statement
No. 109. Therefore, the Company has established a valuation allowance of $5.7
million and $5.5 million for deferred tax assets at December 31, 1995 and 1994,
respectively.
Based upon the current level of operations, the Company believes
that the proceeds from the initial offering of the Series A Notes, cash flow
from operations and the New Credit Facility will be adequate to meet its
anticipated requirements for working capital, capital expenditures and scheduled
interest payments for the foreseeable future. A depressed price for natural gas
or crude oil would have a material adverse effect on the Company's cash flow
from operations and anticipated levels of working capital, and could force the
Company to revise its planned capital expenditures.
53
<PAGE>
New Accounting Standards
In October 1995, the FASB issued SFAS 123, "Accounting for
Stock-Based Compensation." SFAS 123, effective for fiscal years beginning after
December 31, 1995, defines a fair value-based method of accounting and
establishes financial accounting and reporting standards for stock-based
employee compensation plans. Under the fair value-based method, compensation
cost is measured at the grant date based upon the value of the award and is
recognized over the service period. SFAS 123 allows for the election to continue
to measure stock-based compensation cost using the intrinsic value method of
Accounting Principles Board Opinion No. 25 "Accounting for Stock Issued to
Employees" ("APB 25"). The election of this option requires a pro forma
disclosure of net income and earnings per share as if the fair value-based
method of accounting, as defined by SFAS 123, had been applied. Currently, the
Company expects to continue to follow APB 25 and will adopt the required
disclosures for financial statements beginning in 1996.
54
<PAGE>
BUSINESS
General
The Company is an independent energy company engaged primarily in
the acquisition, exploration, development and production of crude oil and
natural gas. Since January 1, 1991, the Company's principal means of growth has
been through the acquisition and subsequent development and exploitation of
producing properties and related assets. The Company utilizes a disciplined
acquisition strategy, focusing its efforts on producing properties and related
assets possessing the following characteristics: a concentration of operations;
significant, quantifiable development potential; historically low operating
expenses; and the potential to reduce G&A expenses per BOE. The Company seeks to
complement its acquisition and development activities by selectively
participating in exploration projects with experienced industry partners. After
giving effect to the Recent Acquisitions, the Company's principal areas of
operation are Texas, western Canada and southwestern Wyoming. The Company owns
interests in 225,290 gross acres (126,845 net acres) and 507 gross wells (325.8
net wells), 352 of which are operated by the Company, and varying interests in
13 natural gas processing plants or compression facilities. On a pro forma
basis, at June 30, 1996, the Company would have had total proved reserves of
45,647 MBOE (64.9% natural gas), of which 81.7% would have been proved
developed. On a pro forma basis, for the nine months ended September 30, 1996,
the Company's EBITDA would have been $28.4 million.
The Company's acquisition, development, exploitation and
exploration activities have substantially increased the Company's proved reserve
base, average daily production and natural gas processing plant throughput while
decreasing its total operating and G&A expenses per BOE. After consummation of
the Recent Acquisitions, the Company has completed 16 acquisitions of producing
properties totaling 46,009 MBOE of proved reserves at an average net acquisition
cost of $3.83 per BOE since January 1, 1991. From January 1, 1991, on an
historical basis, to June 30, 1996, on a pro forma basis, the Company's total
proved reserves would have increased from 889 MBOE to 45,647 MBOE and aggregate
PV-10 would have increased from $11.9 million to $218.3 million. From January 1,
1991, on an historical basis, to the nine months ended September 30, 1996, on a
pro forma basis, average net daily production would have increased from 0.141
MBOE per day to 14.1 MBOE per day. On a pro forma basis, the Company would have
had net natural gas processing capacity of 128.1 MMcf per day as of September
30, 1996. In addition, on a pro forma basis, for the nine months ended September
30, 1996, average net daily natural gas processing plant throughput would have
been 87.4 MMcf per day, of which 27.3 MMcf would have been processed for third
parties, and net operating revenue from processing natural gas of third parties
at the Canadian Abraxas Plants would have been $1.9 million. From the year ended
December 31, 1991, on an historical basis, to the nine months ended September
30, 1996, on a pro forma basis, the Company's direct operating expenses per BOE
would have decreased from $6.30 per BOE to $2.81 per BOE and G&A expenses per
BOE would have decreased from $5.39 per BOE to $0.66 per BOE. As a result of the
Company's successful acquisition strategy and its ability to decrease its direct
operating and G&A expenses per BOE, the Company's EBITDA (excluding interest
income) has increased from $6.66 per BOE, for the year ended December 31, 1991,
to, on a pro forma basis, $7.24 per BOE, for the nine months ended September 30,
1996.
The Company was founded in 1977 by Robert L.G. Watson, the
Company's Chairman of the Board, President and Chief Executive Officer. Canadian
Abraxas was formed by the Company in 1996 to acquire CGGS. The Company's
principal offices are located at 500 North Loop 1604 East, Suite 100, San
Antonio, Texas 78232 and its telephone number is (210) 490-4788. Canadian
Abraxas' principal offices are located at 630 - 6th Avenue, S.W., Suite 303,
Calgary, Alberta and its telephone number is (403) 262-1949. At June 30, 1996,
pro forma for the Recent Acquisitions, the Company would have had total proved
reserves of 45,647 MBOE (64.9% natural gas) with an aggregate PV-10 of $218.3
million, 71.7% of which would have been attributable to proved developed
reserves. In addition, the Company owns varying interests in 13 natural gas
processing plants or compression facilities and 197 miles of natural gas
gathering systems.
55
<PAGE>
Business Strategy
The Company's primary business objectives are to: increase its
recoverable reserves, production and cash flow from operations through strategic
acquisitions; exploit and develop its producing properties; maintain low cost
operations; and pursue a focused exploration strategy. The Company seeks to
achieve its business objectives through the use of the following strategies:
o Disciplined Acquisition Strategy. The Company utilizes a disciplined
acquisition strategy, focusing its acquisition efforts on producing properties
and related assets possessing the following characteristics: a concentration of
operations; significant, quantifiable development potential; historically low
operating expenses; and the potential to reduce G&A expenses per BOE. The
success of the Company's acquisition strategy is illustrated by the following
table:
<TABLE>
<CAPTION>
June 30,
Property Purchase Purchase Cumulative Cumulative 1996
- -------- Date Price(1) CapEx(2) Cash Flow(3) PV-10 IRR(4)
-------- --------- ---------- ------------ -------- ------
(dollars in millions)
<S> <C> <C> <C> <C> <C> <C>
Delaware 7/1/94 $ 25.0 $ 6.8 $ 6.0 $ 37.6 19.3%
Properties (5)
Sinton Properties(6) 1/1/93 19.6 13.4 12.1(7) 43.0 21.4%
Sharon Ridge/
Westbrook 9/1/92 4.4 0.4 2.0 5.2 13.1%
Spraberry 7/1/94 3.2 3.0 0.9 7.1 18.5%
Happy 8/12/92 2.2 0.1 2.6(7) 2.0 31.0%
- ----------------
</TABLE>
(1) Purchase price is net of accrual of net revenue from the effective date of
acquisition to purchase date.
(2) Consists of capital expenditures on a cumulative basis from date of purchase
through June 30, 1996 (undiscounted).
(3) Consists of operating revenue less LOE on a cumulative basis from date of
purchase through June 30, 1996 (undiscounted).
(4) IRR was calculated assuming that the purchase price for each property was
paid on the purchase date and that the cumulative capital expenditures and
cumulative cash flow occurred in equal monthly amounts over the time periods
presented.
(5) Consist of the Company's interests in Cherry Canyon and the Delaware Area
(each as defined herein).
(6) Consist of the Company's interests in Portilla, East White Point and Stedman
Island (each as defined herein). Does not include the 50% overriding royalty
interest in Portilla, East White Point and Stedman Island previously owned
by the Pension Fund (as defined herein).
(7) Does not include results of operations of the Partnership (as defined
herein) from March 21, 1996 to June 30, 1996 or proceeds from the Acco Sale
(as defined herein).
In connection with the acquisition of the Sinton Properties, the
Company also acquired interests in two natural gas processing plants, one of
which was subsequently sold in the Acco Sale. See "-- Recent Acquisitions --
Portilla and Happy." Since being acquired by the Company, the average net daily
natural gas processing throughput of these plants has increased by an average of
7.3% per year, revenue has increased by an average of 24.5% per year and
operating expenses as a percentage of revenue have decreased by an average of
13.7% per year.
o Exploitation Of Existing Properties. The Company allocates a significant
amount of its non-acquisition capital budget to the exploitation of its
producing properties. As of June 30, 1996, on a pro forma basis, approximately
18.3% (8,373 MBOE) of the Company's total proved reserves would have been
classified as proved undeveloped. Management believes that the proximity of
these undeveloped reserves to existing production makes development of these
properties less risky and more cost-effective than other drilling opportunities
available to the Company. The Company has identified 276 potential exploitation
opportunities on the Company's existing properties including those acquired in
the Recent Acquisitions. The Company drilled 38 wells during 1996 (including
seven in western Canada) at a total cost of $13.2 million with a success rate of
90% . In addition, the Company performed 42 workovers or recompletions during
1996 at an estimated cost of $3.3 million and plans to drill 113 wells and
perform 48 workovers or recompletions during 1997 at an estimated cost of $33.3
million.
o Low Cost Operations. The Company seeks to maintain low operating and G&A
expenses per BOE by operating a majority of its producing properties and related
assets and by using contract personnel to assist with the development or
evaluation of producing properties and related assets. As a result of this
56
<PAGE>
strategy, the Company's EBITDA Margin has consistently improved since 1991, even
in years with depressed commodity prices. From the year ended December 31, 1991
to, on a pro forma basis, the nine months ended September 30, 1996, the
Company's direct operating and G&A expenses per BOE have decreased by 55.4% and
87.8%, respectively, resulting in an improvement in EBITDA Margin as illustrated
below:
<TABLE>
<CAPTION>
Nine Months Ended
Year Ended December 31 September 30,
------------------------------------------------------- ------------------
Pro Pro
Forma Forma
(per BOE) (1) 1991 1992 1993 1994 1995 1995 (5) 1996 1996 (5)
--------- ------- ------- ------- ------- ---------- -------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Total operating
revenue (2) $ 18.35 $ 16.03 $ 15.98 $ 13.08 $ 12.15 $ 8.61 (5) $ 14.08 $ 10.71 (5)
Direct operating
expenses (3) 6.30 6.23 6.39 4.41 3.92 2.50 (5) 4.21 2.81 (5)
G&A 5.39 4.59 1.09 0.93 0.92 0.49 1.54 0.66
--------- ------- ------- ------- ------- ---------- -------- ----------
EBITDA (4) $ 6.6 $ 5.2 $ 8.5 $ 7.7 $ 7.31 $ 5.62 (5) $ 8.33 $ 7.24(5)
EBITDA Margin 36.3% 32.5% 53.2% 59.2% 60.2% 65.3% 59.2% 67.6%(5)
</TABLE>
- --------------------
(1) Amounts are calculated on the basis of dollars per BOE of production.
Production data does not include third-party natural gas processing volumes.
(2) Consists of crude oil and natural gas production sales, revenue from rig
operations and processing of natural gas of third parties as well as other
miscellaneous revenue. Both historical and pro forma total operating revenue
for the nine months ended September 30, 1996 are presented net of a loss
from hedging activities incurred during such period.
(3) Consists of lease operating expenses, production taxes, abandoned projects,
rig operating expenses and processing expenses.
(4) Does not include interest income.
(5) Includes results from the Hoole Area. See " - Recent Acquisitions - CGGS"
and " - Primary Operating Areas - Western Canada."
o Focused Exploration Activity. The Company allocates a portion of its capital
budget to the drilling of exploratory wells which have high reserve potential.
The Company believes that by devoting a relatively small amount of capital to
high impact, high risk projects while reserving the majority of its available
capital for development projects, it can reduce its risk profile while still
benefiting from the potential for significant reserve additions. See "Business
- -- Primary Operating Areas -- Exploration Opportunities."
Recent Acquisitions
The Company has recently acquired CGGS, the Wyoming Properties,
Portilla and Happy, East White Point and Stedman Island for an aggregate
purchase price of approximately $176.2 million (the "Recent Acquisitions"). The
Company believes that each of the Recent Acquisitions is consistent with the
Company's acquisition strategy.
CGGS
In November 1996, Canadian Abraxas acquired 100% of the
outstanding capital stock of CGGS, after the consummation of the sale of the
Nevis Plant, for CDN$126.4 million, or approximately U.S.$94.8 million,
including approximately $8.3 million for CGGS' working capital.
Canadian Abraxas owns producing properties in western Canada
consisting primarily of natural gas reserves and interests ranging from 10% to
100% in 197 miles of natural gas gathering systems and 11 natural gas processing
plants or compression facilities, four of which are operated by Canadian
Abraxas. The Canadian Abraxas Properties consist of 154,968 gross acres (86,327
net acres) and 120 gross wells (68.8 net wells), 48 of which are operated by
Canadian Abraxas. As of September 1, 1996, the Canadian Abraxas Properties had
total proved reserves of 10,821 MBOE (91.8% natural gas) with an aggregate PV-10
of $46.4 million, 86.3% of which was attributable to proved developed reserves.
The Canadian Abraxas Plants had aggregate net natural gas processing capacity of
98.3 MMcf per day at September 1, 1996. For the nine months ended September 30,
1996, the Canadian Abraxas Plants processed an average of 182.8 gross MMcf (65.7
net MMcf) of natural gas per day, of which 19.6% (39.7% net) was custom
processed for third parties. For the nine months ended September 30, 1996, the
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<PAGE>
Canadian Abraxas Properties and the Canadian Abraxas Plants would have
contributed $10.3 million of EBITDA to the Company on a pro forma basis.
In January 1997, Canadian Abraxas entered into a letter of intent
to sell its interest in the Hoole Area for approximately $9.3 million. The Hoole
Area consists of 9,728 gross acres (3,311 net acres) and 6.4 gross wells (3.2
net wells), none of which are operated by Canadian Abraxas. As of September 1,
1996, the Hoole Area natural gas properties had total proved reserves of 1,477.0
MBOE with an aggregate PV-10 of $6.3 million, 89.3% of which was attributable to
proved developed reserves. The Hoole Area natural gas processing plant had
aggregate net natural gas processing capacity of 32.0 MMcf per day at September
1, 1996. For the nine months ended September 30, 1996, the Hoole Area natural
gas processing plant processed an average of 18.9 gross MMcf (9.5 net MMcf) of
natural gas per day, of which 4.4% (2.2% net) was custom processed for third
parties. For the nine months ended September 30, 1996, the Hoole Area properties
and natural gas processing plants contributed $2.4 million of revenue to CGGS.
The Company believes that the Canadian Abraxas Properties have
significant, quantifiable development potential which can be realized through
exploitation and development. The Company believes that processing volumes at
the Canadian Abraxas Plants can be increased due to unutilized gross natural gas
processing throughput capacity at the plants of approximately 62.7 MMcf (32.4
net MMcf) of natural gas per day. The Company intends to utilize this excess
capacity by seeking to process additional natural gas volumes from third parties
and from increased production from the Canadian Abraxas Properties. In addition,
the Company believes that increases in the demand for natural gas from Alberta,
Canada will help to reduce the existence of basis differentials in the pricing
of natural gas produced in this area. The Company believes that its ownership of
the Canadian Abraxas Properties and the Canadian Abraxas Plants will afford it a
competitive advantage relative to other area operators due to the Company's
preferential access to the natural gas processing capacity at these facilities.
Immediately after the acquisition of CGGS, the Company
amalgamated CGGS with Canadian Abraxas, and Canadian Abraxas, being the name of
the surviving entity, used the net proceeds from the sale of the Nevis Plant to
retire the outstanding debentures of CGGS. In addition, Canadian Abraxas intends
to sell a 10% working interest in the Canadian Abraxas Properties and the
Canadian Abraxas Plants to Cascade, in connection with the Company's plan to
integrate the operations of the Canadian Abraxas Properties and the Canadian
Abraxas Plants into the existing operations of Cascade. The Company has
identified potential cost savings through anticipated decreases in the G&A
expenses of CGGS, which would have amounted to approximately $380,000 for the
nine months ended September 30, 1996, on a pro forma basis. See the unaudited
Pro Forma Financial Information and the notes thereto included elsewhere in this
Prospectus.
The Wyoming Properties
On September 30, 1996, the Company acquired the Wyoming
Properties which had total proved reserves of 9,935 MBOE (68.5% natural gas) as
of June 30, 1996, for $47.5 million in cash, before adjustment for accrual of
net revenue and interest from April 1, 1996 to September 30, 1996. The Wyoming
Properties consist of 19,587 gross acres (14,091 net acres) and 25 gross wells
(20.4 net wells), 22 of which are operated by the Company. In addition, the
Company acquired various overriding royalty interests in four wells. As of June
30, 1996, the aggregate PV-10 of the Wyoming Properties was $30.3 million
(based, in part, on an assumed natural gas price of $1.07 per Mcf), 97.3% of
which was attributable to proved developed reserves. For the nine months ended
September 30, 1996, the Wyoming Properties would have contributed $5.4 million
of EBITDA to the Company on a pro forma basis. As of September 30, 1996, the
Company had recorded the preliminary net purchase price of $45.9 million to its
crude oil and natural gas properties.
Management believes that the Wyoming Properties have significant
development potential which will enable the Company to increase its cash flow
from operations and reserve base without significant capital expenditures. The
Company intends to exploit this development potential through the more efficient
use of compression and gathering facilities, low cost recompletions of various
behind-pipe zones and drilling of infill development wells on closer spacing.
The Company has drilled two wells on the Wyoming Properties since September 30,
58
<PAGE>
1996. Additionally, the Company has identified potential exploitation and
development opportunities which it believes may have up to 15,400 MBOE of
additional reserves. The Wyoming Properties are geographically concentrated,
thereby enabling the Company to operate the properties without incurring
additional G&A expenses. In addition, the Company believes that expected
improvements in the transportation infrastructure and an increase in the demand
for natural gas from southwestern Wyoming will help to reduce the existence of
basis differentials in the pricing of natural gas produced in the area.
Portilla and Happy
In November 1996, the Company acquired Acco's partnership
interest in the Partnership for $27.6 million, including the repayment of
certain indebtedness and before adjustment for the accrual of net revenue to the
closing date. The Company previously owned the remaining 25% interest in the
Partnership. The Partnership owned a 100% working interest in the Portilla
Field, a 100% interest in the Portilla Plant and a 12% working interest in Happy
Field. Portilla and Happy consist of 1,405 gross acres (1,115 net acres) and 78
gross wells (52 net wells), 61 of which are operated by the Company. As of June
30, 1996, Portilla and Happy had total proved reserves of 4,314 MBOE (18.4%
natural gas) with an aggregate PV-10 of $30.2 million, 99.8% of which was
attributable to proved developed reserves. The Portilla Plant had natural gas
processing capacity of approximately 20.0 MMcf per day at September 30, 1996.
During the nine months ended September 30, 1996, the Portilla Plant processed an
average of 17.2 MMcf of natural gas per day. For the nine months ended September
30, 1996, Portilla and Happy would have contributed an additional $3.8 million
of EBITDA to the Company on a pro forma basis.
The Company previously owned a 50% interest in Portilla and a 12%
working interest in Happy. In March 1996, the Company sold its interests in
Portilla and Happy to Acco for net consideration of $15.6 million. Acco
subsequently obtained the release of a 50% overriding royalty interest in
Portilla previously owned by the Pension Fund and Acco then contributed its
interests in Portilla and Happy to the Partnership in return for the Partnership
Interest. The Company continued to operate Portilla subsequent to the Acco Sale.
See "Recent Acquisitions -- Portilla and Happy."
East White Point and Stedman Island
In November 1996, the Company obtained the release of the 50%
overriding royalty interests in East White Point and Stedman Island from the
Pension Fund for $9.3 million before adjustment for accrual of net revenue from
August 1996 to November 27, 1996. The Pension Fund's interest in East White
Point and Stedman Island consisted of 3,723 gross acres (1,256 net acres) and 25
gross wells (6.5 net wells), 15 of which are operated by the Company. As of June
30, 1996, East White Point and Stedman Island had total proved reserves of 5,304
MBOE (62.3% natural gas) with an aggregate PV-10 of $29.4 million, 71.7% of
which was attributable to proved developed reserves. The East White Point
natural gas processing plant, a modern cyrogenic plant with capacity of
approximately 25.0 MMcf of natural gas per day, extracted approximately 679 Bbls
of NGLs per day for the nine months ended September 30, 1996.
Primary Operating Areas
Texas
Abraxas Cherry Canyon Field, Ward County, Texas. In connection
with the acquisition of the West Texas Properties in July 1994, the Company
acquired an interest in approximately 7,360 gross acres (4,500 net acres) in
this field and currently operates 20 of the wells in its acreage. The Company
drilled its first shallow pool exploratory test well in this field in March
1995. Since that time, this field has become the principal focus of the
Company's development activity. To date, 24 wells have been drilled and
completed in one or more sands, including the Bell Canyon, Cherry Canyon and
Brushy Canyon Sands. Four other sands have been production tested with
additional sands remaining behind pipe to be tested in the future. The Company
is currently attempting to delineate this field by drilling wells in several
different areas. The Company has not yet drilled any dry holes in this field.
Two wells have been drilled by Chevron USA, Inc. and Southwest Royalties, Inc.
offsetting the Company's acreage. Both of these wells are currently being
completed and, if successful, could prove additional locations on the Company's
59
<PAGE>
acreage. At June 30, 1996, this field had estimated net proved reserves of 3,647
MBOE (50.4% natural gas) with a PV-10 of $20.3 million, 73.0% of which was
attributable to proved developed reserves. For the nine months ended September
30, 1996, this field produced an average of approximately 256 net Bbls of crude
oil and NGLs and approximately 1,417 net Mcf of natural gas per day from 11.1
net wells.
Delaware Area (Howe, ROC, Block 16, Taurus, Gomez and Nine Mile
Draw Fields), Ward, Reeves, and Pecos Counties, Texas. In connection with the
acquisition of the West Texas Properties in July 1994, the Company acquired
working interests ranging from 18% to 100% in 35 wells, 29 of which are operated
by the Company. These fields produce from Devonian, Wolfcamp, Ellenburger and
Cherry Canyon formations at depths ranging from 6,500 feet to 17,600 feet. At
June 30, 1996, these fields had estimated total net proved reserves of 3,644
MBOE (83.4% natural gas) with a PV-10 of $17.3 million, 100% of which was
attributable to proved developed reserves. For the nine months ended September
30, 1996, these fields produced an average of approximately 127 net Bbls of
crude oil and NGLs and 4,253 net Mcf of natural gas per day from 21.1 net wells.
Portilla Field, San Patricio County, Texas. The Company
originally acquired a 50% working interest in Portilla in April 1993. In March
1996, the Company sold its interest in Portilla to Acco, which subsequently
contributed it to the Partnership. In September 1996, the Company entered into
an agreement to reacquire Portilla, including the 50% interest previously owned
by the Pension Fund. See "--Recent Acquisitions -- Portilla and Happy." This
field was discovered in the 1950's by Superior Oil Company and produces from
numerous Miocene, Frio and Vicksburg age sands at depths ranging from 4,000 feet
to 9,000 feet. At June 30, 1996, this field had estimated net proved reserves of
4,134 MBOE (19.2% natural gas) with a PV-10 of $28.2 million, 99.8% of which was
attributable to proved developed reserves. For the nine months ended September
30, 1996, the field produced an average of approximately 872 net Bbls of crude
oil and NGLs and approximately 1,957 net Mcf of natural gas per day from 51.0
net wells. The Company owns a 100% interest in the Portilla Plant which had
aggregate capacity of approximately 20.0 MMcf of natural gas per day at
September 30, 1996. During the nine months ended September 30, 1996, the
Portilla Plant processed an average of approximately 17.2 MMcf of natural gas
per day and extracted an average of approximately 271 Bbls of NGLs per day. The
Company is currently the operator of the Portilla Plant and all of the wells in
the Portilla Field.
East White Point Field, San Patricio County, Texas. The Company
originally acquired an approximate 30% working interest in this field in April
1993. The field produces crude oil and natural gas from numerous sands in the
Lower Frio formation at depths ranging from 9,000 feet to 13,000 feet. At June
30, 1996, this field had estimated net proved reserves of 8,191 MBOE (61.0%
natural gas) with a PV-10 of $45.9 million, 74.2% of which was attributable to
proved developed reserves. The Company operates 11 wells in this field, and
Marathon Oil Company ("Marathon") operates 10 additional wells in which the
Company has an interest. For the nine months ended September 30, 1996, this
field produced an average of approximately 461 Net Bbls of crude oil and NGLs
and 3,544 net Mcf of natural gas per day from 5.7 net wells. The Company also
owns an approximate 38.4% interest in and operates a natural gas processing
plant in this field. The East White Point natural gas processing plant, a modern
cyrogenic plant with capacity of approximately 25 MMcf of natural gas per day,
processed an average of approximately 11.6 MMcf of natural gas per day and
extracted approximately 679 Bbls of NGLs per day for the nine months ended
September 30, 1996.
Stedman Island Field, Nueces County, Texas. The Company
originally acquired a 25% working interest in this field in April 1993 and an
additional 25% in October 1995. This field produces crude oil and natural gas
from Frio sands at depths ranging from 8,500 feet to 10,000 feet. At June 30,
1996, this field had estimated net proved reserves of 2,305 MBOE (67.6% natural
gas) with a PV-10 of $12.3 million, 62.6% of which was attributable to proved
developed reserves. For the nine months ended September 30, 1996, this field
produced an average of approximately 42 net Bbls of crude oil and NGLs and 913
net Mcf of natural gas per day from 2.5 net wells. In July 1996, the Company
placed a successful recompletion well on production which produced an average of
approximately 20 net Bbls of crude oil and 800 net Mcf of natural gas per day
during the balance of the month of July and during August and 13 net Bbls of
crude oil and 665 net Mcf of natural gas per day during September 1996. The
Company believes that additional productive zones remain behind pipe. Two
additional workovers have been identified and are expected to be completed
during the first quarter of 1997. The Company has also identified a potentially
significant exploratory location using recently acquired and re-processed
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<PAGE>
seismic data in a horizon below current production in the field. The seismic
data indicates the presence of an untested fault block in the deeper Frio sands
and the Company plans to drill a test well during the fourth quarter 1996.
Spraberry Trend Field, Midland, Martin and Reagan Counties,
Texas. Since January 1, 1991, the Company has acquired interests in or drilled
eight new wells in this field. This field produces at depths ranging from 8,000
feet to 9,100 feet in multiple sands. The Company owns interests in 30 wells in
this field, 15 of which are operated by the Company. Following the successful
completion of two wells during the second quarter of 1996, eight additional
proved undeveloped locations were identified by the Company's independent
petroleum engineers. At June 30, 1996, this field had estimated net proved
reserves of 1,335 MBOE (27.0% natural gas) with a PV-10 of $7.1 million, 78.5%
of which was attributable to proved developed reserves. For the nine months
ended September 30, 1996, the field produced an average of approximately 150 net
Bbls of crude oil and NGLs and approximately 351 net Mcf natural gas per day
from 17.4 net wells.
Sharon Ridge and Westbrook Fields, Scurry and Mitchell Counties,
Texas. The Company drilled its first wells in the Westbrook Field in 1978 and
operated approximately 40 wells prior to 1992. These two fields produce crude
oil from Permian age carbonates at depths ranging from 1,700 feet to 3,500 feet.
In 1992, the Company acquired working interests ranging from 57.5% to 100% and
became the operator of 124 wells in the Sharon Ridge Field, which is adjacent to
the Westbrook Field. At June 30, 1996, these fields had estimated total net
proved reserves of 991 MBOE (5.1% natural gas) with a PV-10 of $5.2 million,
75.1% of which was attributable to proved developed reserves. For the nine
months ended September 30, 1996, these fields produced an average of
approximately 200 net Bbls of crude oil and NGLs per day from 89.0 net wells.
The Company is currently investigating production enhancement efforts in this
field, which could include waterflooding and development drilling.
Southwestern Wyoming
The Company acquired the Wyoming Properties in September 1996.
See " -- Recent Acquisitions." The Wyoming Properties produce natural gas from
numerous sands at depths ranging from 8,500 feet to 12,000 feet. At June 30,
1996, the Wyoming Properties had estimated total net proved reserves of 9,935
MBOE (68.5% natural gas) with a PV-10 of $30.3 million (based, in part, on an
assumed natural gas price of $1.07 per Mcf), 97.3% of which was attributable to
proved developed reserves. For the nine months ended September 30, 1996, the
Wyoming Properties produced an average of approximately 997 net Bbls of crude
oil and NGLs and 12,477 net Mcf of natural gas per day from 22.0 net wells.
Western Canada
Producing Properties. In January 1996, the Company invested $3.0
million in Grey Wolf Exploration Ltd. ("Grey Wolf"), a privately held Canadian
corporation, which, in turn, invested these proceeds in newly-issued shares of
Cascade, an Alberta-based corporation whose common shares are traded on The
Alberta Stock Exchange under the symbol "COL." The Company owns 78% of the
outstanding capital stock of Grey Wolf and, through Grey Wolf, the Company owns
approximately 52% of the outstanding capital stock of Cascade. Cascade owns 30.0
gross (4.3 net to Cascade) producing crude oil and natural gas wells and 12,000
net acres of undeveloped leases in southwestern Saskatchewan. These wells
produce crude oil from multiple sands at depths ranging from 4,200 feet to 4,600
feet. A report prepared by Cascade's independent petroleum engineers showed
estimated net proved reserves of 141 MBbls of crude oil with a PV-10 of CDN$1.4
million, or approximately U.S.$0.9 million, at January 1, 1996. None of these
reserves or values are included in the report of the Company's independent
petroleum engineers. See " -- Reserves Information." Cascade has drilled one dry
exploratory well and Grey Wolf has drilled six successful development wells
during 1996. As of January 20, 1997, the market value of the shares of Cascade
held by Grey Wolf was approximately U.S.$13.9 million, based on the closing
price per share of Cascade stock on The Alberta Stock Exchange on such date.
In November 1996, Canadian Abraxas acquired CGGS. As of September
1, 1996, the Canadian Abraxas Properties had estimated total net proved reserves
of 10,821 MBOE (91.7% natural gas) with a PV-10 of $46.4 million, 82.4% of which
was attributable to proved developed reserves. For the nine months ended
September 30, 1996, the Canadian Abraxas Properties produced an average of
approximately 600 net Bbls of crude oil and NGLs and 35.5 net Mcf of natural gas
per day from 68.8 net wells. See "-- Recent Acquisitions."
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The following table sets forth a summary of certain information,
by field, of the Canadian Abraxas Properties:
Average Daily
Production for Nine
Months Ended
September 30, 1996
---------------------
Reserves Crude Oil
at & NGLs Natural
Name of Working Net Wells September (MBbls) Gas
Field Interest 1, 1996 (MMcf)
(MBOE)
- ----------- -------- --------- --------- --------- --------
Quirk Creek (1) 5.0 1,785.3 0.2 3.6
Sundre (2) 9.4 1,794.5 0.3 5.7
Hoole (3) 50% 3.2 1,477.0 -- 7.7
Bellis 100% 10.1 961.7 -- 2.7
Chinchaga 60% 2.4 859.7 -- 3.3
Pouce Coupe 100% 3.0 758.7 -- 3.4
Valhalla 100% 6.0 147.7 0.1 3.1
Other (4) (5) 29.7 3,036.3 -- 6.0
---------------------------------------------
Total 68.8 10,820.9 0.6(6) 35.5 (6)
- ------------
(1) CGGS owns a 21% working interest in 12 wells and a 48% working interest
in four wells.
(2) CGGS owns working interests ranging from 11% to 70% in 16 wells.
(3) In January 1997, the Company entered into a letter of intent to sell its
interest in the Hoole Area for approximately $9.3 million.
(4) Consists of the Big Bend, Knopcik, Eaglesham, Giroux Lake and Minor
Properties.
(5) CGGS owns working interests ranging from 8% to 100% in 58 wells.
(6) Does not reflect burden from royalties payable to the Crown.
Natural Gas Processing. Canadian Abraxas' natural gas processing
business includes natural gas gathering and processing operations. Natural gas
gathering operations involve locating and contracting for natural gas supplies
produced from crude oil and natural gas fields and the operation and maintenance
of a gathering system of pipelines that connect such natural gas supply sources
to natural gas processing plants. Natural gas processing involves subjecting
natural gas to high pressure and low temperature treatments that cause the
natural gas to separate into various products, including a mixture of NGLs
(commonly referred to as raw product), residual natural gas and by-products such
as helium, condensate and sulfur. The combined value of the residual natural
gas, raw product and by-products is generally higher than that of unprocessed
natural gas. Certain of Canadian Abraxas' processing plants are equipped to
fractionate the raw product into its component products of ethane, propane,
butanes and natural gasoline for sale to local markets.
The Company believes that the Canadian Abraxas Plants will
provide substantial revenue-enhancing opportunities to the Company. Several of
the plants are located in areas with little or no competition from other natural
gas processing plants. The Company intends to utilize the plants' excess
capacity by seeking to process additional natural gas volumes from third parties
and from increased production from the Canadian Abraxas Properties. The Company
believes that its ownership of the Canadian Abraxas Properties and the Canadian
Abraxas Plants will afford it a competitive advantage relative to other area
operators due to the Company's preferential access to the natural gas processing
capacity at these facilities.
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For the nine months ended September 30, 1996, the Canadian Abraxas Plants
processed an average of 182.8 MMcf of natural gas per day (65.7 MMcf per day net
to CGGS), of which 19.2% (39.2% net) was custom processed for third parties. The
following table sets forth certain information with respect to the Canadian
Abraxas Plants for the nine months ended September 30, 1996.
Maximum Gross CGGS
Plant Average Third
Working Capacity Throughput Party
Plant Location Interest (MMcfpd) Utilization(MMcfpd) Processing
(MMcfpd)
Quirk Creek 21% 80 67% 53.6 10.4
Knopcik (1) 10% 56 100% 56.0 0.4
Hoole (2) 50% 32 59% 18.9 0.5
Valhalla 100% 30 67% 20.0 18.3
Sundre 23% 20 68% 13.5 --
Bellis 100% 10 76% 7.6 4.8
Big Bend 77% 8 49% 3.9 1.1
Pouce Coupe 100% 8 54% 4.3 0.4
Eaglesham 25% 5 100% 5.0 --
--------- --------- -------- --------
Total 249 73% 182.8 35.9
=== === ===== ====
- ------------
(1) Consists of three plants.
(2) In January 1997, the Company entered into a letter of intent to sell its
interest in the Hoole Area for approximately $9.3 million.
Exploration Opportunities
The Company allocates a portion of its capital budget to the
drilling of exploratory wells which have high reserve potential. The Company
believes that by devoting a relatively small amount of capital to high impact,
high risk projects while reserving the majority of its available capital for
development projects, it can reduce its risk profile while still benefiting from
the potential for significant reserve additions. Some of the Company's current
exploration opportunities include the following:
Yoakum Prospect, DeWitt County, Texas. The Company owns a 100%
interest in approximately 952 acres and intends to drill a 15,000 foot step-out
well to the Yoakum (Edwards) Field. The test will attempt to extend existing
production in the Edwards Field onto the Company's acreage. Offsetting wells
have produced as much as 5,000 Mcf of natural gas per day. This well was drilled
in the fourth quarter of 1996 and currently is in the final stages of
completion.
Roche Ranch, Refugio County, Texas. The Company owns a 100%
interest in approximately 416 acres and intends to drill a 7,500 foot Frio test
well during the first quarter of 1997. This prospect is located approximately
five miles north of Portilla.
Shanghai Field, Wharton County, Texas. The Company owns a 20.0%
working interest in the Shanghai Prospect. Following two inconclusive wells
drilled in 1994, the Company participated in an expansive 3-D seismic shoot. The
seismic data was recently processed and interpreted. During the fourth quarter
of 1996, the Company drilled a third well in the field on a directional basis to
test four potential Yegua Sands which is currently being completed.
Jean Prospect, Young County, Texas. The Company owns a 25.0%
working interest and 18.8% net revenue interest in approximately 1,800 acres on
the Jean 3D seismic project targeting the Mississippi and Caddo formations at
4,500 feet. The Company drilled two wells in the fourth quarter of 1996 and is
currently re-evaluating the seismic data.
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Developmental and Exploratory Acreage
The following table indicates the Company's interest in developed
and undeveloped acreage as of September 30, 1996, on a pro forma basis:
Developed and Undeveloped Acreage
Pro Forma As of September 30, 1996
Developed Acreage Undeveloped Acreage
----------------------- ------------------------
Gross Net Gross Net Acres
Acres Acres Acres
---------- ---------- ---------- ------------
Canada 65,150(1) 39,489(1) 89,818 46,838
Texas 40,032` 21,458 7,159 3,795
N. Dakota 1,864 1,021 -- --
Montana 320 10 -- --
Kansas 640 120 -- --
Wyoming 4,560 3,654 15,027 10,437
Alabama 720 23 -- --
---------- ---------- ---------- ------------
Total 113,286 65,775 112,004 61,070
- -------------
(1) Includes 9,728 gross acres and 3,311 net acres in the Hoole Area. See " -
Recent Acquisitions - CGGS" and " - Primary Operating Areas - Western Canada."
Productive Wells
The following table sets forth the total gross and net productive wells of
the Company, expressed separately for crude oil and natural gas, as of September
30, 1996, on a pro forma basis:
Productive Wells
Pro Forma as of September 30, 1996
Crude Oil Natural Gas
---------------------- ------------------------
Gross Net Gross Net
----------- ----------- ----------- ------------
Canada 16.0 13.5 104.0(1) 55.3 (1)
Texas 248.0 171.3 100.0 62.3
N. Dakota 4.0 1.7 -- --
Montana 1.0 0.1 -- --
New Mexico -- -- 1.0 0.1
Wyoming 1.0 0.1 24.0 20.3
Alabama 2.0 0.1 1.0 0.1
Utah 1.0 0.1 -- --
Kansas 4.0 0.8 -- --
=========== =========== =========== ============
Total 277.0 187.7 230.0 138.1
=========== =========== =========== ============
- -----------
(1) Includes 6.4 gross wells and 3.2 net wells in the Hoole Area. See " - Recent
Acquisitions - CGGS" and " - Primary Operating Areas - Western Canada."
Substantially all of the Company's U.S. crude oil and natural gas
properties on a pro forma basis will be pledged to secure the Company's
indebtedness under the New Credit Facility. See "Management's Discussion of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources."
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Reserves Information
The crude oil and natural gas reserves of Abraxas have been
estimated as of January 1, 1995, and January 1, 1996, and June 30, 1996, and the
crude oil and natural gas reserves of the Wyoming Properties and Portilla and
Happy have been estimated as of June 30, 1996, by DeGolyer & MacNaughton,
Dallas, Texas. The crude oil and natural gas reserves of CGGS have been
estimated as of September 1, 1996, by Sproule Associates Limited, Calgary,
Alberta, Canada. Crude oil and natural gas reserves, and the estimates of the
present value of future net revenue therefrom, were determined based on then
current prices and costs. Reserve calculations involved the estimate of future
net recoverable reserves of crude oil and natural gas and the timing and amount
of future net revenue to be received therefrom. Such estimates are not precise
and are based on assumptions regarding a variety of factors, many of which are
variable and uncertain.
The following table sets forth certain information regarding
estimates of the Company's crude oil, NGLs and natural gas reserves as of
January 1, 1995, January 1, 1996 and June 30, 1996, on a historical basis and on
a pro forma basis:
Estimated Proved Reserves
------------------------------------------------
Proved Proved Total
Developed Undeveloped Proved
------------ ------------ ------------
As of January 1, 1995
Crude oil (MBbls) 3,617 3,033 6,649
NGLs (MBbls) 2,089 418 2,507
Natural gas (MMcf) 48,973 18,606 67,579
As of January 1, 1996 (1)
Crude oil (MBbls) 3,992 1,516 5,508
NGLs (MBbls) 2,007 752 2,759
Natural gas (MMcf) 44,026 10,543 54,569
As of June 30, 1996 (1)
Crude oil (MBbls) 2,906 1,083 3,989
NGLs (MBbls) 1,859 665 2,524
Natural gas (MMcf) 41,903 10,663 52,566
Pro Forma (as of June 30,
1996) (1)(2)
Crude oil (MBbls) 6,895 1,380 8,275
NGLs (MBbls) 6,242 1,522 7,764
Natural gas (MMcf) (3) 144,803 32,848 177,651
- ------------
(1) Does not include reserves of Cascade and Grey Wolf.
(2) Includes reserves of CGGS at September 1, 1996.
(3) Includes 7,651 MMcf of proved developed, 1,211 MMcf of proved undeveloped
and 8,862 MMcf of total proved natural gas reserves attributable to the
Hoole Area. See " - Recent Acquisitions - CGGS" and " Primary Operating
Areas -- Western Canada."
There are numerous uncertainties inherent in estimating
quantities of proved reserves and in projecting future rates of production and
the timing of development expenditures, including many factors beyond the
control of the Company. The reserve data included in this Prospectus represent
only estimates. In addition, the estimates of future net revenue from proved
reserves of the Company and the present value thereof are based upon certain
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
Company's crude oil and natural gas properties included in this Prospectus are
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<PAGE>
based on the assumption that future oil and gas prices remain the same as crude
oil and natural gas prices at June 30, 1996, with respect to the Company's then
existing properties and for Portilla and Happy, and for the month of July 1996
with respect to the Canadian Abraxas Properties. The average sales prices as of
such dates used for purposes of such estimates were $19.86 per Bbl of crude oil,
$14.09 per Bbl of NGLs and $1.27 per Mcf of natural gas with respect to the
Canadian Abraxas Properties, $21.70 per Bbl of crude oil, $9.25 per Bbl of NGLs
and $1.07 per Mcf of natural gas with respect to the Wyoming Properties, $19.98
per Bbl of crude oil, $14.50 per Bbl of NGLs and $2.65 per Mcf of natural gas
with respect to Portilla and Happy and $20.64 per Bbl of crude oil, $12.38 per
Bbl of NGLs and $2.29 per Mcf of natural gas with respect to the Company's other
properties in the aggregate. Also assumed is the Company's making future capital
expenditures of approximately $19.7 million in the aggregate, including $3.4
million on the Wyoming Properties, $1.7 million on the Canadian Abraxas
Properties and $2.2 million on Portilla and Happy, necessary to develop and
realize the value of its undeveloped reserves. Any significant variance in these
assumptions could materially affect the estimated quantity and value of reserves
set forth herein. See "Risk Factors" and "Management's Discussion and Analysis
of Financial Condition and Results of Operations."
In general, the volume of production from crude oil and natural
gas properties declines as reserves are depleted. Except to the extent the
Company acquires properties containing proved reserves or conducts successful
exploration and development activities, or both, the proved reserves of the
Company will decline as reserves are produced. The Company's future crude oil
and natural gas production is therefore highly dependent upon its level of
success in acquiring or finding additional reserves.
The Company files reports of its 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, NGLs and Natural Gas Production and Sales Prices
The following table presents the net crude oil, net NGLs and net
natural gas production for the Company, the average sales price per Bbl of crude
oil and NGLs and per Mcf of natural gas produced and the average LOE per BOE of
production sold, for each of the three years ended December 31, 1995, the nine
months ended September 30, 1996, and on a pro forma basis, for the year ended
December 31, 1995, and the nine months ended September 30, 1996:
Pro Pro Forma
Forma September September
1993 1994 1995 1995(1) 30,1996 30, 1996
------- -------- ------- ------- --------- ----------
Production
Crude oil (MBbls) 270.9 355.7 401.4 666.7 266.0 544.6
NGLs (MBbls) 33.9 113.2 143.4 672.0 106.1 561.0
Natural gas (Mmcf) 985.4 2,392.9 3,552.7 23,825.5 2,625.4 16,533.2
Average sales price
Crude oil
(per Bbl) $15.54 $15.47 $17.16 $17.18 $19.94 $20.04
NGLs (per Bbl) $14.75 $10.54 $10.83 $ 7.82 $12.73 $10.89
Natural gas
(per Mcf) $ 2.60 $ 1.85 $ 1.47 $ 1.01 $ 1.95 $ 1.30
LOE (per BOE) (2) $ 6.17 $ 4.26 $ 3.81 $ 2.25 $ 4.05 $ 2.36
- ----------
(1) Includes results from the Hoole Area. See " - Recent Acquisitions - CGGS"
and " - Primary Operating Areas -- Western Canada."
(2) Crude oil and natural gas were combined by converting natural gas to BOE on
the basis of 6 Mcf natural gas -- 1 Bbl of crude oil.
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Drilling Activities
The following table sets forth the Company's gross and net
working interests in exploratory, development, and service wells drilled during
the year ended December 31, 1995, and the nine months ended September 30, 1996:
1995 1996 (thru
September 30)
--------------------------------
Gross Net Gross Net
--------------------------------
Exploratory -- -- -- --
Productive
Crude oil 2.0 1.0 1.0 0.3
Natural gas -- -- 1.0 0.3
Dry holes 1.0 1.0 1.0 1.0
--------------------------------
Total 3.0 2.0 3.0 1.6
================================
Development
Productive
Crude oil 12.0 9.1 19.0 11.8
Natural gas 1.0 0.3 5.0 0.5
Service -- -- 2.0 --
Dry holes 1.0 0.6 -- 0.8
--------------------------------
Total 14.0 10.0 26.0 13.1
================================
Markets and Customers
The revenue generated by the Company's operations are 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 received by the
Company for its crude oil and natural gas production and the level of such
production are subject to wide fluctuations and depend on numerous factors
beyond the Company's control including seasonality, the condition of the United
States economy (particularly the manufacturing sector), foreign imports,
political conditions in other 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 the Company's proved reserves and the Company's revenue,
profitability and cash flow from operations.
In order to manage its exposure to price risks in the marketing
of its crude oil and natural gas, the Company from time to time has 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, the Company 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 its futures position and sell
its production to a customer. Such contracts may expose the Company to the risk
of financial loss in certain circumstances, including instances where production
is less than expected, the Company's 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. Such contracts may also
restrict the ability of the Company to benefit from unexpected increases in
crude oil and natural gas prices.
In connection with the Acco Sale, Acco entered into a commodity
price hedge with Christiania which was assumed by the Company and BTCo and ING
Capital in connection with the consummation of the Transactions. Under the terms
of this commodity price hedge, the Company is required to receive or make
payment to BTCo and ING Capital based on a differential between a fixed and
variable price for crude oil and natural gas through the last business day of
November 2001 on volumes ranging from 8,160 barrels of crude oil to 20,000
barrels of crude oil per month and 14,850 MMBTU of natural gas to 87,406 MMBTU
of natural gas per month. Under this agreement, the Company receives fixed
prices ranging from $17.20 per barrel of crude oil to $18.55 per barrel of crude
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<PAGE>
oil and $1.793 per MMBTU of natural gas to $1.925 per MMBTU of natural gas and
makes payments based on the price for west Texas intermediate light sweet crude
oil on the NYMEX for crude oil and the Inside FERC, Tennessee Gas Pipeline Co:
Texas (Zone 0) price for natural gas.
Substantially all of the Company's crude oil and natural gas is
sold at current market prices under short term contracts, as is customary in the
industry. During the year ended December 31, 1996, six purchasers accounted for
approximately 61% of the Company's crude oil and natural gas sales. The Company
believes that there are numerous other companies available to purchase the
Company's crude oil and natural gas and that the loss of any or all of these
purchasers would not materially affect the Company's ability to sell crude oil
and natural gas.
In Fiscal 1995, CGGS sold its NGLs and natural gas to a
combination of aggregators, short-term and longer-term Canadian and United
States customers. Pricing terms in these contracts included a mixture of fixed
and floating prices. CGGS received an average of $0.94 per Mcf for its natural
gas production in Fiscal 1995. For the nine months ended October 31, 1996, CGGS
received an average of $1.24 per Mcf of natural gas as a result of utilizing
certain hedging arrangements. During Fiscal 1995, 14 purchasers accounted for
100% of CGGS' crude oil, NGLs and natural gas sales, and during the nine months
ended October 31, 1996, eight purchasers accounted for 100% of CGGS' crude oil,
NGLs and natural gas sales.
The Company believes that expected improvements in the
transportation infrastructure in, and increased demand for natural gas from,
southwest Wyoming and Alberta, Canada will help to reduce the existence of basis
differentials in the pricing of natural gas produced in these areas. With basis
differentials at relatively high historical levels, the Company believes that
the Canadian Abraxas Properties and the Wyoming Properties have the potential
for increasing revenue and asset value as these differentials decrease without
any increase in LOE and G&A expenses.
Competition
The Company encounters strong competition from major oil
companies and independent operators in acquiring properties and leases for the
exploration for, and production of, crude oil and natural gas. Competition is
particularly intense with respect to the acquisition of desirable undeveloped
crude oil and natural gas leases. The principal competitive factors in the
acquisition of such undeveloped crude oil and natural gas leases include the
staff and data necessary to identify, investigate and purchase such leases, and
the financial resources necessary to acquire and develop such leases. Many of
the Company's competitors have financial resources, staff and facilities
substantially greater than those of the Company. In addition, the producing,
processing and marketing of crude oil and natural gas is affected by a number of
factors which are beyond the control of the Company, the effect of which cannot
be accurately predicted.
The principal raw materials and 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. The Company must
compete for such raw materials and resources with both major crude oil companies
and independent operators. Although the Company believes its current operating
and financial resources are adequate to preclude any significant disruption of
its operations in the immediate future, the continued availability of such
materials and resources to the Company cannot be assured.
The Company will 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. The Company's principal competitors will 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 the Company. Smaller local distributors may enjoy
a marketing advantage in their immediate service areas. The Company will compete
against other companies in its natural gas processing business both for supplies
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<PAGE>
of natural gas and for customers to which it will sell its products. Competition
for natural gas supplies is based primarily on location of natural gas gathering
facilities and natural gas gathering plants, operating efficiency and
reliability and ability to obtain a satisfactory price for products recovered.
Competition for customers is based primarily on price and delivery capabilities.
Regulatory Matters
The Company's operations are affected from time to time in
varying degrees by political developments and federal, state, provincial and
local laws and regulations. In particular, oil and gas production operations and
economics are, or in the past have been, affected by 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 recent past, maximum selling prices for certain categories
of crude oil, natural gas, condensate and NGLs were subject to federal
regulation. In 1981, all federal price controls over sales of crude oil,
condensate and NGLs were lifted. Effective January 1, 1993, the Natural Gas
Wellhead Decontrol Act (the "Decontrol Act") deregulated natural gas prices for
all "first sales" of natural gas, which includes all sales by the Company of its
own production. As a result, all sales of the Company's domestically produced
crude oil, natural gas, condensate and NGLs may be sold at market prices, unless
otherwise committed by contract.
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. As is the case with crude
oil, 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 government of Alberta also regulates the volume of natural
gas that may be removed from Alberta for consumption elsewhere based on such
factors as reserve availability, transportation arrangements and marketing
considerations.
The North American Free Trade Agreement
On January 1, 1994, the North American Free Trade Agreement
("NAFTA") among the governments of the United States, Canada and Mexico became
effective. In the context of energy resources, Canada remains free to determine
whether exports to the U.S. or Mexico will be allowed provided that any export
restrictions do not: (i) reduce the proportion of energy resources exported
relative to the total supply of the energy resource (based upon the proportion
prevailing in the most recent 36 month period); (ii) impose an export price
higher than the domestic price; or (iii) disrupt normal channels of supply. All
three countries are prohibited from imposing minimum export or import price
requirements.
NAFTA contemplates the reduction of Mexican restrictive trade
practices in the energy sector and prohibits discriminatory border restrictions
and export taxes. The agreement also contemplates clearer disciplines on
regulators to ensure fair implementation of any regulatory changes and to
minimize disruption of contractual arrangements, which is important for Canadian
natural gas exports.
Natural Gas Regulation
Historically, interstate pipeline companies generally acted as
wholesale merchants by purchasing natural gas from producers and reselling the
gas to local distribution companies and large end users. Commencing in late
1985, the Federal Energy Regulatory Commission (the "FERC") issued a series of
orders that have had a major impact on interstate natural gas pipeline
operations, services, and rates, and thus have significantly altered the
marketing and price of natural gas. The FERC's key rule making action, order No.
636 ("Order 636"), issued in April 1992, required each interstate pipeline to,
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among other things, "unbundle" its traditional bundled sales services and create
and make available on an open and nondiscriminatory basis numerous constituent
services (such as gathering services, storage services, firm and interruptible
transportation services, and standby sales and gas balancing services), and to
adopt a new ratemaking methodology to determine appropriate rates for those
services. To the extent the pipeline company or its sales affiliate makes
natural gas sales as a merchant, it does so pursuant to private contracts in
direct competition with all of the sellers, such as the Company; 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." In subsequent orders, the FERC largely affirmed the major
features of Order 636 and denied a stay of the implementation of the new rules
pending judicial review. By the end of 1994, the FERC had concluded the Order
636 restructuring proceedings, and, in general, accepted rate filings
implementing Order 636 on every major interstate pipeline. However, even through
the implementation of Order 636 on individual interstate pipelines is
essentially complete, many of the individual pipeline restructuring proceedings,
as well as Order 636 itself and the regulations promulgated thereunder, are
subject to pending appellate review and could possibly be changed as a result of
future court orders. The Company cannot predict whether the FERC's orders will
be affirmed on appeal or what the effects will be on its business.
In recent years the FERC also has pursued a number of other
important policy initiatives which could significantly affect the marketing of
natural gas. Some of the more notable of these regulatory initiatives include
(i) 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), (ii) the completion of rule-making involving the
regulation of pipelines with marketing affiliates under Order No. 497, (iii) the
FERC's ongoing efforts to promulgate standards for pipeline electronic bulletin
boards and electronic data exchange, (iv) a generic inquiry into the pricing of
interstate pipeline capacity, (v) efforts to refine the FERC's regulations
controlling operation of the secondary market for released pipeline capacity,
and (vi) a policy statement regarding market based rates and other
non-cost-based rates for interstate pipeline transmission and storage capacity.
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 as a result of the
monopolization of those facilities by their new, unregulated owners. The FERC
has attempted to address some of these concerns in its orders authorizing such
"spin downs," but it remains to be seen what effect these activities will have
on access to markets and the cost to do business. As to all of these recent FERC
initiatives, the ongoing, or, in some instances, preliminary evolving nature of
these regulatory initiatives makes it impossible at this time to predict their
ultimate impact on the Company's business.
Recent orders of the FERC 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." The
Company transports certain of its natural gas through gathering facilities owned
by others, including interstate pipelines, under existing long term contractual
arrangements. With respect to item (i) in the preceding paragraph, on May 27,
1994, the FERC issued orders in the context of the "spin off" or "spin down" of
interstate pipeline owned gathering facilities. A "spin off" is a FERC-approved
sale of such facilities to a non-affiliate. A "spin down" is the transfer by the
interstate pipeline of its gathering facilities to an affiliate. A number of
spin offs and spindowns have been approved by the FERC and implemented. The FERC
held that it retains jurisdiction over gathering provided by interstate
pipelines, but that it generally does not have jurisdiction over pipeline
gathering affiliates, except in the event of affiliate abuse (such as actions by
the affiliate undermining open and nondiscriminatory access to the interstate
pipeline). These orders require nondiscriminatory access for all sources of
supply and prohibit the tying of pipeline transportation service to any service
provided by the pipeline's gathering affiliate. On November 30, 1994, the FERC
issued a series of rehearing orders largely affirming the May 27, 1994 orders.
The FERC now requires interstate pipelines to not only seek authority under
Section 7(b) of the Natural Gas Act of 1938 (the "NGA") to abandon certificated
facilities, but also to seek authority under Section 4 of the NGA to terminate
service from both certificated and uncertificated facilities. On December 31,
1994, an appeal was filed with the U.S. Court of Appeals for the D.C. Circuit to
overturn three of the FERC's November 30, 1994, orders. The Company cannot
predict what the ultimate effect of the FERC's orders pertaining to gathering
will have on its production and marketing, or whether the Appellate Court will
affirm the FERC's orders on these matters.
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State and Other Regulation
All of the jurisdictions in which the Company owns 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. The Company's 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 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 allow the forced pooling or integration
of tracts to facilitate exploration while other states rely on voluntary pooling
of lands and leases. In addition, state conservation laws establish maximum
rates of production from crude oil and natural gas wells, generally prohibit the
venting or flaring of natural gas and impose certain requirements regarding the
ratability of production. Some states, such as Texas and Oklahoma, have, in
recent years, reviewed and substantially revised methods previously used to make
monthly determinations of allowable rates of production from fields and
individual wells. The effect of these regulations is to limit the amounts of
crude oil and natural gas the Company can produce from its wells, and to limit
the number of wells or the location at which the Company can drill.
State regulation of gathering facilities generally includes
various safety, environmental, and in some circumstances, non-discriminatory
take requirements, but does not generally entail rate regulation. 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, Oklahoma recently enacted a prohibition against discriminatory
gathering rates and certain Texas regulatory officials have expressed interest
in evaluating similar rules.
Royalty Matters
United States
By a letter dated May 3, 1993, directed to thousands of producers
holding interests in federal leases, the United States Department of the
Interior (the "DOI") announced its interpretation of existing federal leases to
require the payment of royalties on past natural gas contract settlements which
were entered into in the 1980s and 1990s to resolve, among other things,
take-or-pay and minimum take claims by producers against pipelines and other
buyers. The DOI's letter sets forth various theories of liability, all founded
on the DOI's interpretation of the term "gross proceeds" as used in federal
leases and pertinent federal regulations. In an effort to ascertain the amount
of such potential royalties, the DOI sent a letter to producers on June 18,
1993, requiring producers to provide all data on all natural gas contract
settlements, regardless of whether natural gas produced from federal leases were
involved in the settlement. The Company received a copy of this information
demand letter. In response to the DOI's action, in July 1993, various industry
associations and others filed suit in the United States District Court for the
Northern District of West Virginia seeking an injunction to prevent the
collection of royalties on natural gas contract settlement amounts under the
DOI's theories. The lawsuit, styled "Independent Petroleum Association v.
Babbitt," was transferred to the United States District Court in Washington,
D.C. On June 4, 1995, the Court issued a ruling in this case holding that
royalties are payable to the United States on natural gas contract settlement
proceeds in accordance with the Minerals Management Service's May 3, 1993,
letter to producers. This ruling was appealed and is now pending in the D.C.
Circuit Court of Appeals. The DOI's claim in a bankruptcy proceeding against a
producer based upon an interstate pipeline's earlier buy-out of the producer's
natural gas sale contract was rejected by the Federal Bankruptcy Court in
Lexington, Kentucky, in a proceeding styled "Century Offshore Management Corp."
While the facts of the Court's decision do not involve all of the DOI's
theories, the Court found on those at issue that the DOI's theories were without
legal merit, and the Court's reasoning suggests that the DOI's other claims are
similarly deficient. This decision was upheld in the District Court and is now
on appeal in the Sixth Circuit Court of Appeals. Because both the "Independent
Petroleum Association v. Babbitt" and "Century Offshore Management Corp."
decisions have been appealed, and because of the complex nature of the
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calculations necessary to determine potential additional royalty liability under
the DOI's theories, it is impossible to predict what, if any, additional or
different royalty obligation the DOI may assert or ultimately be entitled to
recover with respect to any of the Company's prior natural gas contract
settlements.
Canada
In addition to Canadian federal regulation, each province has
legislation and regulations that govern land tenure, royalties, production
rates, environmental protection and other matters. The royalty regime is a
significant factor in the profitability of crude oil and natural gas production.
Royalties payable on production from lands other than Crown lands are determined
by negotiations between the mineral owner and the lessee. Crown royalties are
determined by governmental regulation and are generally calculated as a
percentage of the value of the gross production, and the rate of royalties
payable generally depends in part on prescribed preference prices, well
productivity, geographical location, field discovery date and the type and
quality of the petroleum product produced.
From time to time the governments of Canada, Alberta and
Saskatchewan have established incentive programs which have included royalty
rate reductions, royalty holidays and tax credits for the purpose of encouraging
crude oil and natural gas exploration or enhanced planning projects.
Regulations made pursuant to the Mines and Minerals Act (Alberta)
provide various incentives for exploring and developing crude oil reserves in
Alberta. Crude oil produced from qualifying development wells that were spudded
on or after November 1, 1991, and prior to August 1, 1993 (or spudded in August
but licensed prior thereto) are eligible for a 12-month royalty exemption up to
a maximum of CDN$400,000. Exploration wells spudded on or after November 1, 1991
and prior to April 1, 1992, or if drilled in northern Alberta or the Foothills
area of Alberta prior to April 1, 1993, are entitled to a 24-month exemption to
a maximum of CDN$1.0 million. A 24-month royalty reduction (up to December 31,
1996) is available for crude oil produced from qualifying horizontal extensions
commenced prior to January 1, 1995. Crude oil produced from horizontal
extensions commenced at least five years after the well was originally spudded
may also qualify for a royalty reduction. Wells drilled prior to September 1,
1990, and reactivated between November 1, 1991 and October 1, 1992, having had
no production between September 1, 1990 and November 1, 1991, are entitled to a
five year royalty exemption to a maximum of 4,000 cubic metres. An 8,000 cubic
metres exemption is available to production from a well that has not produced
for a 12-month period, if resuming production in October, November or December
of 1992 or January of 1993, or for a 24-month period if resuming production
after January 31, 1993. In addition, crude oil production from eligible new
field and new pool wildcat wells and deeper pool test wells spudded or deepened
after September 30, 1992, is entitled to a 12-month royalty exemption (to a
maximum of $1 million). Crude oil produced from low productivity wells, enhanced
recovery schemes (such as injection wells) and experimental projects is also
subject to royalty reductions.
The Alberta government also introduced the Third Tier Royalty
with a base rate of 10% and a rate cap of 25% from oil pools discovered after
September 30, 1992. The new oil royalty reserved to the Crown has a base rate of
10% and a rate cap of 30% and for old oil a base rate of 10% and a rate cap of
35%.
Effective January 1, 1994, the calculation and payment of natural
gas royalties became subject to a simplified process. The royalty reserved to
the Crown, subject to various incentives, is between 15% or 30%, in the case of
new natural gas, and between 15% and 35%, in the case of old natural gas,
depending upon a prescribed or corporate average reference price. Natural gas
produced from qualifying exploratory gas wells spudded or deepened after July 1,
1985 and before June 1, 1988 continues to be eligible for a royalty exemption
for a period of 12 months, or such later time that the value of the exempted
royalty quantity equals a prescribed maximum amount. Natural gas produced from
qualifying intervals in eligible natural gas wells spudded or deepened to a
depth below 2,500 meters is also subject to a royalty exemption, the amount of
which depends on the depth of the well.
In Alberta, a producer of crude oil or natural gas is entitled to
credit against the royalties payable to the Crown by virtue of the Alberta
Royalty Tax Credit ("ARTC") program. The ARTC program is based on a
price-sensitive formula, and the ARTC rate currently varies between 75% for
prices for crude oil at or below CDN $100 per cubic metre and 35% for prices
above CDN $210 per cubic metre. The ARTC rate is currently applied to a maximum
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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.
Crude oil and natural gas royalty holidays and reductions for
specific wells reduce the amount of Crown royalties paid to the provincial
governments. The ARTC program provides a rebate on Crown royalties paid in
respect of eligible producing properties.
The Government of Saskatchewan revised its fiscal regime for the
oil and gas industry effective January 1, 1994. Some royalties on wells existing
as of that date will remain unchanged and therefore subject to various periods
of royalty/tax reduction. While a number of incentives were eliminated or
reduced (such as incentives for vertical infill wells and lower cost horizontal
wells), new incentive programs were initiated to encourage greater exploration
and development activity in the province. The new fiscal regime provides an
incentive to encourage the drilling of new vertical oil wells through a revised
royalty/tax structure for new vertical oil wells and incremental production from
new or expanded water flood projects. This "third tier" Crown royalty rate is
price sensitive and varies between heavy and non-heavy oil (from a minimum of
10% for heavy oil at a base price to a maximum of 35% for non-heavy oil at a
price above the base price). Previous time-based royalty/tax holidays applicable
to vertically drilled oil wells have been replaced with volume-based royalty/tax
reduction incentives in which a maximum royalty of 5% will apply to various
volumes depending on the depth and nature of the well (up to 25,000 cubic metres
of oil in the case of deep exploratory wells). The maximum royalty applicable to
the first 12,000 cubic metres of oil has been increased from 5% to 10% for
production from certain horizontal wells. In addition, royalty/tax holidays for
deep horizontal oil wells have been replaced with a 25,000 cubic metres volume
incentive (5% maximum royalty). Oil production from qualifying reactivated oil
wells are subject to a maximum new royalty rate of 5% for the first five years
following re-activation in the case of wells reactivated after 1993 and shut-in
or suspended prior to January 1, 1993. With respect to qualifying exploratory
natural gas wells, the first 25 million cubic metres of natural gas produced
will be subject to an incentive maximum royalty rate of 5%.
Environmental Matters
The Company's operations are subject to numerous federal, state,
and local laws and regulations controlling the discharge of materials into the
environment or otherwise relating to the protection of the environment,
including the Comprehensive Environment Response, Compensation, and Liability
Act ("CERCLA"), also known as the "Federal Superfund Law." Such laws and
regulations, among other things, impose absolute liability upon the lessee under
a lease for the cost of clean up of pollution resulting from a lessee's
operations, subject the lessee to liability for pollution damages, may require
suspension or cessation of operations in affected areas, and impose restrictions
on the injection of liquids into subsurface aquifers that may contaminate
groundwater. The Company maintains insurance against costs of clean-up
operations, but it's not fully insured against all such risks. A serious
incident of pollution may, as it has in the past, also result in the DOI
requiring lessees under federal leases to suspend or cease operation in the
affected area. In addition, the recent trend toward stricter standards in
environmental legislation and regulation may continue. For instance, legislation
has been proposed in Congress from time to time that would reclassify certain
crude oil and natural gas production wastes as "hazardous wastes" which would
make the reclassified exploration and production wastes subject to much more
stringent handling, disposal, and clean up requirements. If such legislation
were to be enacted, it could have a significant impact on the Company's
operating costs, as well as the crude oil and natural gas industry in general.
State initiatives to further regulate the disposal of crude oil and natural gas
wastes are also pending in certain states, and these various matters could have
a similar impact on the Company.
The Company's Canadian operations are also subject to
environmental regulation pursuant to local, provincial and federal legislation.
Canadian environmental legislation provides for restrictions and prohibitions on
releases or emissions of various substances produced in association with certain
crude oil and natural gas industry operations and 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
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clean-up orders. Environmental legislation in Alberta has undergone a major
revision and has been consolidated in the Environmental and Enhancement Act .
Under the new Act, environmental standards and compliance for releases, clean-up
and reporting are stricter. Also, the range of enforcement actions available and
the severity of penalties have been significantly increased. These changes will
have incremental effect on the cost of conducting operations in Alberta.
The Company is not currently involved in any administrative or
judicial proceedings arising under domestic or foreign federal, state, or local
environmental protection laws and regulations which would have a material
adverse effect on the Company's financial position or results of operations.
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Title to Properties
As is customary in the crude oil and natural gas industry, the
Company makes only a cursory review of title to undeveloped crude oil and
natural gas leases at the time they are acquired by the Company. However, before
drilling commences, the Company requires a thorough title search to be
conducted, and any material defects in title are remedied prior to the time
actual drilling of a well on the lease begins. To the extent title opinions or
other investigations reflect title defects, the Company, rather than the seller
of the undeveloped property, is typically obligated to cure any title defect at
its expense. If the Company 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, the Company could suffer a loss of its entire investment in the
property. The Company believes that it has good title to its crude oil and
natural gas properties, some of which are subject to immaterial encumbrances,
easements and restrictions. The crude oil and natural gas properties owned by
the Company are also typically subject to royalty and other similar non-cost
bearing interests customary in the industry. The Company does not believe that
any of these encumbrances or burdens will materially affect the Company's
ownership or use of its properties.
Employees
As of December 20, 1996, Abraxas had 43 full-time employees,
including two executive officers, two non-executive officers, five petroleum
engineers, one landman, one geologist, eleven secretarial and clerical personnel
and 21 field personnel. Additionally, Abraxas retains contract pumpers on a
month-to-month basis. The Company retains independent geologic and engineering
consultants from time to time on a limited basis and expects to continue to do
so in the future.
Office Facilities
The Company's executive and administrative offices are located at
500 North Loop 1604 East, Suite 100, San Antonio, Texas 78232. The Company owns
a 16% limited partnership interest in the partnership which owns this office
building. The Company also has an office in Midland, Texas. These offices,
consisting of approximately 12,650 square feet in San Antonio and 960 square
feet in Midland, are leased until March 2005 at an aggregate rate of $14,194 per
month.
Other Properties
The Company owns 10 acres of land, an office building, workshop,
warehouse and house in Sinton, Texas, 160 acres of land in Coke County, Texas
and a 50% interest in approximately 2.0 acres of land in Bexar County, Texas.
All three properties are used for the storage of tubulars and production
equipment. The Company also owns 19 vehicles which are used in the field by
employees.
Litigation
From time to time, the Company is involved in litigation relating
to claims arising out of its operations in the normal course of business. The
Company is not currently engaged in any legal proceedings that are expected,
individually or in the aggregate, to have a material adverse effect on the
Company.
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MANAGEMENT
Directors and Executive Officers
Set forth below are the names, ages, years of service and
positions of the executive officers and directors of Abraxas , as well as
certain executive officers of Cascade and Canadian Abraxas. The term of the
Class I directors of Abraxas expires in 1999, the Class II directors expires in
1997 and the Class III directors in 1998.
Name Age Office Class
Robert L.G. Watson 46 Chairman of the Board, President and Chief
Executive Officer of Abraxas; Chairman of
the Board and director of Cascade; Chairman
of the Board, President and director of III
Canadian Abraxas
Chris E. Williford 45 Executive Vice President, Chief Financial
Officer, Treasurer and director of Abraxas;
Vice President and Assistant Secretary of III
Canadian Abraxas
Robert Patterson 39 Vice President/Operations of Abraxas --
Stephen T. Wendel 48 Vice President/Land and Marketing of Abraxas --
Franklin A. Burke 62 Director of Abraxas I
Harold D. Carter 57 Director of Abraxas I
Robert D. Gershen 43 Director of Abraxas I
Richard M.
Kleberg, III 54 Director of Abraxas II
James C. Phelps 74 Director of Abraxas III
Paul A. Powell,
Jr. 51 Director of Abraxas II
Richard M. Riggs 76 Director of Abraxas II
Roger L. Bruton 64 Executive Vice President and director of
Cascade; Executive Vice President and --
director of Canadian Abraxas
Donald A. Engle 53 President and director of Cascade; Secretary --
and director of Canadian Abraxas
Robert L. G. Watson 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, Chief Executive
Officer and director of Grey Wolf and Chairman of the Board and a director of
Cascade. In November 1996, Mr. Watson was elected Chairman of the Board,
President and as a director of Canadian Abraxas. Prior to joining Abraxas, Mr.
Watson was employed in various petroleum engineering positions with Tesoro
Petroleum Corporation, a crude oil and natural gas exploration and production
company, from 1972 through 1977, and DeGolyer & 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 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, Assistant Secretary and as a director of Canadian
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 Patterson has served as Vice President/Operations of
Abraxas since December 1995. From 1986 to 1995, Mr. Patterson was employed by
Parker and Parsley Petroleum USA most recently as a Gulf Coast Division Manager.
Prior to that, Mr. Patterson was District Manager for HCW Exploration from 1983
to 1986 and Drilling Engineer with Hilliard Oil and Gas from 1980 to 1983. Prior
to that, he was a Drilling Engineer with Texas Pacific Oil Company from 1979 to
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1980. Mr. Patterson is a registered Professional Engineer in the state of Texas
and graduated with a Bachelor of Science degree in petroleum engineering from
the University of Texas in 1979.
Stephen T. Wendel has served as Vice President/Land and Marketing
of Abraxas since 1990 and Corporate Secretary of Abraxas since 1994. From 1982
to 1990, Mr. Wendel served Abraxas as Manager of Joint Interests and Natural Gas
Contracts. Prior to joining Abraxas, Mr. Wendel was employed in accounting,
auditing and marketing positions with Tenneco Oil Company and Tesoro Petroleum
Corporation, both crude oil and natural gas exploration and production
companies. Mr. Wendel received a Bachelor of Business Administration degree in
Accounting from Texas Lutheran University in 1971.
Franklin A. Burke, a director of Abraxas since June 1992, has
served as President and Treasurer of Venture Securities Corporation since 1971,
where he is in charge of research and portfolio management. He has also been a
general partner and director of Burke, Lawton, Brewer & Burke, a securities
brokerage firm, since 1964, where he is responsible for research and portfolio
management. Mr. Burke also serves as a director of NB Instruments, Inc., an
instrument products company, Omega Institute, a job training entity, and Starkey
Chemical Process Co., a chemical processing company. Mr. Burke received a
Bachelor of Science degree in Finance from Kansas State University in 1955, a
Master's degree in Finance from University of Colorado in 1960 and studied at
the graduate level at the London School of Economics from 1962 to 1963.
Harold D. Carter, a director of Abraxas since May 1996, has
served as a member of the management committee of Brigham Oil & Gas, L.P., a
three-dimensional seismic exploration company, since May 1992. Mr. Carter has
also served as a consultant to Associated Energy Managers, Inc., an investment
manager specializing in structuring and managing private investments in the
energy industry, since October 1994. From 1991 to 1992, Mr. Carter was a
consultant to various companies and investors involved in the crude oil and
natural gas industry. Prior to 1991, Mr. Carter was employed by Pacific
Enterprises Oil Company, where he was an Executive Vice President until
September 1990 and a consultant from September 1990 until December 1990. From
1986 to 1989, Mr. Carter served as President and Chief Operating Officer of
Sabine Corporation.
Robert D. Gershen, a director of Abraxas since May 1995, has
served as President of Associated Energy Managers, Inc., an investment manager
specializing in structuring and managing private investments in the energy
industry, since July 1989. Mr. Gershen has served as an investment advisor to
Endowment Energy Partners, L.P. and Endowment Energy Partners II, Limited
Partnership, limited partnerships formed to make loans to companies in the crude
oil and natural gas business, since October 1989 and January 1993, respectively.
Richard M. Kleberg, III, a director of Abraxas since December
1983, has held the position of managing partner of SFD Enterprises, Ltd., a
private investment partnership, since 1980. Mr. Kleberg has served on the boards
of directors of Cullen Frost Bankers, Inc., a bank holding company, since 1992;
1776 Restaurants, Inc., a restaurant concern, since 1983; The Frost National
Bank of San Antonio, a national banking association, since 1984; and Kleberg &
Co. Bankers, Inc., a bank holding company, since 1980. Mr. Kleberg holds a
Bachelor of Science degree in Political Science from Trinity University.
James C. Phelps, a director of Abraxas since December 1983, has
been a consultant to crude oil and natural gas exploration and production
companies such as Panhandle Producing Company and Tesoro Petroleum Corporation
since April 1981. Mr. Phelps has served as a director of Grey Wolf since April
1995 and of Cascade since January 1996. From April 1995 to May 1996, Mr. Phelps
served as Chairman of the Board and Chief Executive Officer of Grey Wolf, and
from January 1996 to May 1996, he served as President of Cascade. From March
1983 to September 1984, he served as President of Osborn Heirs Company, a
privately owned crude oil exploration and production company based in San
Antonio. Mr. Phelps was President and Chief Operating Officer of Tesoro
Petroleum Corporation from 1971 to 1981 and prior to that was Senior Vice
President and Assistant to the President of Continental Oil Company. He received
a Bachelor of Science degree in Industrial Engineering and a Master of Science
degree in Industrial Engineering from Oklahoma State University.
Paul A. Powell, Jr., a director of Abraxas since 1987, is
currently Trustee of the Paul A. Powell Trust and has served as Vice President
and Director of Mechanical Development Co., Inc., a tool and die and production
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machine company, since 1984. He also serves as trustee of sixteen investment
trusts. Mr. Powell is a director and officer of Frameco, Inc., a tool and die
and production machine company, Somerset Investments, Ltd., an investment
company, and Powell Lake Properties, a real estate investment and management
company. He attended Emory and Henry College and graduated from National
Business College with a degree in Accounting.
Richard M. Riggs, a director of Abraxas since 1985, is a
self-employed geological consultant. He served as Vice President of Petro
Consultants Energy Corporation, a crude oil and natural gas exploration and
production company, from June 1978 to December 1984. Mr. Riggs has served as a
director of Cascade since May 1996. He has previously been employed by Tesoro
Petroleum Corporation, a crude oil and natural gas exploration and production
company, as Exploration Vice President for North America, and prior to that time
was Manager of Domestic Exploration for Ashland Oil, Inc., a crude oil and
natural gas exploration and production company. Mr. Riggs graduated with a
Bachelors degree in Geology from Dartmouth College and a Masters degree in
Geology from Columbia University.
Roger L. Bruton is currently Executive Vice President and a
director of Cascade. From January 1996 to October 1996, he served as President
of Cascade. In November 1996, Mr. Bruton was elected Vice President of Canadian
Abraxas and in December 1996 was elected as a director of Canadian Abraxas.
Prior to joining Cascade, Mr. Bruton served as a geologist with Panhandle
Eastern Pipeline Company from 1958 to 1963. From 1976 to 1977 he served as
Regional Exploration Manager for Anadarko Production Company. He also served as
Exploration Manager for the western United States and Canada for General Crude
Oil Company from 1977 to 1979. From 1984 to 1990, Mr. Bruton served as President
of Western Oil Corporation and Plains Petroleum Corporation, both of which are
subsidiaries of KN Energy. Mr. Bruton was Regional General Manager of Anadarko
Petroleum of Canada Ltd. from 1972 to 1976. Mr. Bruton received a Bachelors of
Science degree in Geology and a Masters of Science degree in Geology from Kansas
State University.
Donald A. Engle, is currently President and a director of
Cascade. From January 1996 to October 1996, he served as Vice President of
Cascade. In November 1996, Mr. Engle was elected Secretary and as a director of
Canadian Abraxas. From 1985 to 1995, he was President of Sapphire Resources,
Ltd. Prior to that, Mr. Engle served as President of Neomar Resources Limited
from 1980 to 1985 and as General Manager of Anadarko Petroleum of Canada Limited
from 1976 to 1979. Mr. Engle received a Bachelor of Commerce degree from the
University of Saskatchewan.
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EXECUTIVE COMPENSATION
Compensation Summary
The following table sets forth a summary of compensation for the
fiscal years ended December 31, 1993, 1994 and 1995 paid by the Company to
Robert L.G. Watson, the Chairman of the Board, President and Chief Executive
Officer of the Company and Chris E. Williford, the Executive Vice President,
Chief Financial Officer and Treasurer of the Company. The Company did not have
any executive officers other than Messrs. Watson and Williford whose total
annual salary and bonus exceeded $100,000 for the years ended December 31, 1993,
1994 and 1995.
Long-Term
Compensation
Awards-Number
Annual of Shares
Compensation Underlying
Name and Principal Position Year Salary ($) Options/SARs
--------------------------- ------ --------------- --------------
Robert L. G. Watson 1993 123,977(1)(2) 800,000 (3)
Chairman of the Board, 1994 157,450(1)(4) --
President and Chief 1995 108,281(1)(4) 60,000 (6)
Executive Officer (2)
Chris E. Williford 1993 78,374 20,000 (6)
Executive Vice President, 1994 101,028 --
Chief Financial Officer 1995 115,795(7) 20,000 (6)
and Treasurer
- -----------
(1) Mr. Watson received repayments of loans to Abraxas of $54,826 during
1993, $287,940 during 1994 and $354,677 during 1995. See "Certain
Relationships and Related Transactions."
(2) Includes $50,000 of stock awards and $73,977 of salary.
(3) On May 4, 1993, Mr. Watson, who at the time was Chairman of the Board of
Castle Minerals, Inc. ("CMI"), approximately 86% of the common stock of
which was owned indirectly by the Company at that time, was awarded
options to purchase 800,000 shares of CMI Common Stock for $0.13 per
share. On April 19, 1994, the Company sold its interests in CMI and all
of the options previously granted to Mr. Watson were terminated.
(4) Includes $53,750 of stock awards and $103,700 of salary.
(5) Includes $1,093 of stock awards and $107,188 of salary.
(6) Represents the number of options to purchase Common Stock which were
exercisable as of the end of the respective years.
(7) Includes $8,607 of stock awards and $107,188 of salary.
Stock Option Plans
Pursuant to the Abraxas Petroleum Corporation 1984 Incentive
Stock Option Plan (the "ISO Plan"), the Abraxas Petroleum Corporation 1993 Key
Contributor Stock Option Plan (the "1993 Plan") and the Abraxas Petroleum
Corporation 1994 Long Term Incentive Plan (the "LTIP"), the Company grants to
employees and officers of the Company (including directors of the Company who
are also employees) incentive stock options and non-qualified stock options. The
ISO Plan, the 1993 Plan and the LTIP are administered by the Compensation
Committee of the Board of Directors which, based upon the recommendation of the
Chief Executive Officer, determines the number of shares subject to each option.
In addition to the ability to grant either incentive stock options and
non-qualified stock options under the LTIP, the Compensation Committee may grant
or award (a) stock appreciation rights in conjunction with stock options or
independently, (b) restricted stock or (c) other stock-based awards to executive
and other key employees of the Company.
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Employment Agreements
The Company has entered into employment agreements (the
"Employment Agreements") with each of Mr. Watson and Mr. Williford, pursuant to
which each of Messrs. Watson and Williford will receive compensation as
determined from time to time by the Board in its sole discretion. The Employment
Agreements terminate on December 31, 1996 except that the term of the Employment
Agreements may be automatically extended for an additional year if by December 1
of the prior year neither the Company nor Mr. Watson or Mr. Williford, as the
case may be, has given notice that it does not wish to extend the term. Except
in the event of a change in control, at all times during the term of the
Employment Agreements, each of Mr. Watson's and Mr. Williford's employment is at
will and may be terminated by the Company for any reason without notice or
cause. If a change in control occurs during the term of the Employment Agreement
or any extension thereof, the expiration date of Mr. Watson's Employment
Agreement is automatically extended to a date no earlier than four years
following the effective date of such change in control and the expiration date
of Mr. Williford's Employment Agreement is automatically extended to a date no
earlier than three years following the effective date of such change in control.
If, following a change in control, Mr. Watson's or Mr. Williford's employment is
terminated other than for Cause (as defined in each of the Employment
Agreements) or Disability (as defined in each of the Employment Agreements), by
reason of Mr. Watson's or Mr. Williford's death or retirement or by either Mr.
Watson or Mr. Williford, as the case may be, other than for Good Reason (as
defined in each of the Employment Agreements), then Mr. Watson will be entitled
to receive a lump sum payment equal to four times his annual base salary and Mr.
Williford will be entitled to receive a lump sum payment equal to three times
his annual base salary. If any such lump sum payment would individually or
together with any other amounts paid or payable constitute an "excess parachute
payment" within the meaning of Section 280G ("Section 280G") of the Code, and
applicable regulations thereunder, the amounts to be paid will be increased so
that Mr. Watson or Mr. Williford, as the case may be, will be entitled to
receive the amount of compensation provided in his contract after payment of the
tax imposed by Section 280G.
Compensation of Directors
Non-Qualified Stock Option Plan
Messrs. Burke, Kleberg, Phelps, Powell and Riggs have previously
been granted options to purchase 8,900 shares of Common Stock under the
Company's 1984 Non-Qualified Stock Option Plan (the "Non-Qualified Plan"). There
are currently outstanding options to purchase 8,900 shares of Common Stock under
the Non-Qualified Plan at an exercise price of $6.75 per share.
Restricted Share Plan for Directors
Pursuant to the Abraxas Petroleum Corporation Restricted Share
Plan for Directors (the "Director Plan"), each director of the Company, other
than Messrs. Watson and Williford, is entitled to receive a grant of shares of
Common Stock for attendance at regular and special meetings of the Board of
Directors. Each eligible director of the Company was issued 400 shares of Common
Stock during 1994 as an initial grant under the Director Plan and thereafter
receives a number of shares of Common Stock equal to the product of 1,000 times
the Capitalization Factor (as defined in the Director Plan) divided by the
Average Stock Price (as defined in the Director Plan) as of the date of a
meeting of the Board. For 1995, each of the directors, received the number of
shares of Common Stock set forth opposite his name under the Director Plan:
Number of
Name Shares
- -------------------------- ------------
Franklin M. Burke 365
Robert D. Gershen 365
Richard M. Kleberg 659
James C. Phelps 659
Paul A. Powell 365
Richard M. Riggs 659
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Director Stock Option Plan
Pursuant to the Abraxas Petroleum Corporation Director Stock
Option Plan, each non-employee member of the Board of Directors of the Company
on June 1, 1996 was granted an option to purchase 8,000 shares of Common Stock
at a price of $6.75 per share. Each person who becomes a director after that
date will also be granted an option to purchase 8,000 shares of Common Stock at
the then prevailing price of the Common Stock as quoted on the Nasdaq National
Market.
Other Compensation
The directors of the Company received no other compensation for
services as directors, except for reimbursement of travel expenses to attend
Board meetings.
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SECURITIES HOLDINGS OF PRINCIPAL STOCKHOLDERS,
DIRECTORS AND OFFICERS
Based upon information received from the persons concerned, each
person known to the Company to be the beneficial owner of more than five percent
of the outstanding shares of Common Stock and Preferred Stock of Abraxas, each
director and officer and all directors and officers of Abraxas as a group, owned
beneficially as of January 20, 1997 the number and percentage of outstanding
shares of Common Stock and Preferred Stock of Abraxas indicated in the following
table:
Beneficial Ownership
------------------------------------------------------------
Number of Shares (1) Percentage
----------------------- ----------------------------------
Name and Address of
Beneficial Owner Common Preferred Common Preferred Voting
Stock (2) Stock Stock (2) Stock Stock (2)(3)
Robert L. G. Watson 262,564 (4) 4.51 4.15
Endowment
Advisors, Inc. 864,790 (5) 45,741(5) 6.14 100 13.70
450 Post Road E.
Westport, CT 06881
Wellington Management
Company 572,300 (6) 9.86 9.07
75 State Street
19th Floor
Boston, MA 02109
Ralph Wanger 516,000 (7) 8.89 8.17
227 West
Monroe Street
Suite 3000
Chicago, IL 60606
First Union 424,000 (8) 6.81 6.29
National Bank of
North Carolina
230 South Tryon
Charlotte, NC 28202
Kayne, Anderson
Management, Inc. 375,000 (9) 6.46 5.94
1800 Avenue of
the Stars
Suite 1425
Los Angeles,CA 90067
Metropolitan Life
Insurance Company 375,000 (10) 6.46 5.94
One Madison Avenue
New York, NY 10010
Franklin A. Burke 90,362 (11) 1.1 *
Paul A. Powell, Jr. 36,484 (12) * *
James C. Phelps 32,109 (13) * *
Richard M.
Kleberg, III 30,756 (14) * *
Robert D. Gershen 22,994 (15) * *
Chris E. Williford 15,997 (16) * *
Richard M. Riggs 12,315 (17) * *
Harold D. Carter 5,000 * *
All Officers and 507,611(4)(11) 8.75 8.04
Directors as a (12)(13)
Group(9 persons) (14)(15)
(16)(17)
- ---------
* Less than 1%
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(1) Unless otherwise indicated, all shares are held directly with sole voting
and investment power.
(2) Does not include an aggregate of 1,995,000 shares of Common Stock which may
be issued in exchange for the Company's Contingent Value Rights. (3) Includes
Common Stock and Preferred Stock. The holder of each share of Preferred Stock
has 11.11 votes on all matters voted on by the holders of Common Stock.
(4) Includes 20,316 shares owned by Wind River Resources Corporation, a
corporation owned by Mr. Watson, as to which Mr. Watson has sole voting and
investment power and 15,000 shares issuable upon exercise of options granted
pursuant to the Abraxas Petroleum Corporation 1994 Long Term Incentive Plan.
Does not include a total of 75,880 shares owned by the Robert L. G. Watson, Jr.
Trust and the Carey B. Watson Trust, the trustees of which are Mr. Watson's
brothers and the beneficiaries of which are Mr. Watson's children. Mr. Watson
disclaims beneficial ownership of the shares owned by these trusts.
(5) Includes 34,288 shares of Series 1995-B Preferred Stock convertible into
380,940 shares of Common Stock and 262,645 shares of Common Stock owned by
Endowment Energy Partners, L.P. ("EEP") and 11,453 shares of Series 1995-B
Preferred Stock convertible into 127,243 shares of Common Stock and 93,962
shares of Common Stock owned by Endowment Energy Partners II, Limited
Partnership ("EEP II"). EEP and EEP II are limited partnerships whose investors
are educational institutions and which were formed to make loans to companies in
the crude oil and natural gas business. The general partner of both EEP and EEP
II is Fairfield Partners, Inc. (Del.) ("Fairfield") which is a wholly-owned
subsidiary of Endowment Advisers, Inc. ("EAI"), a Delaware nonstock corporation
controlled by its trustees and management. Voting and investment power over the
shares held by EEP and EEP II is exercised by the Board of Trustees of EAI, and
by Susan J. Carter, the Senior Vice President and Chief Operating Officer of
both EAI and Fairfield. The trustees of EAI are principally individuals who are
financial officers of educational institutions that have invested in investment
partnerships sponsored by EAI, including EEP and EEP II.
(6) Wellington Management Company is an investment manager which has the power
to make investment decisions for unrelated clients.
(7) Includes 156,000 shares owned by Wanger Asset Management, L.P. ("WAM") and
360,000 shares owned by the Acorn Investment Trust, Series Designated Acorn Fund
(the "Trust"). Wanger Asset Management, Ltd. ("WAM Ltd.") is the general partner
of WAM and Ralph Wanger is the general partner of WAM Ltd. WAM serves as
investment advisor to the Trust. Certain limited partners and employees of WAM
are officers and trustees of the Trust. The Trust has delegated to WAM shared
voting and investment power over the shares owned by the Trust. Does not include
shares owned by clients of WAM over which WAM does not have or share voting or
investment power.
(8) Includes warrants to purchase 424,000 shares of Common Stock at an exercise
price of $9.79 per share.
(9) Kayne, Anderson Management, Inc. is an investment manager which has the
power to make investment decisions for unrelated clients.
(10) State Street Research & Management, Inc. ("State Street") is an investment
manager which has the power to make investment decisions for the account
specified above. State Street disclaims beneficial ownership of all of the
shares of Common Stock listed above.
(11) Includes 8,900 shares issuable upon exercise of options granted pursuant to
the Abraxas Petroleum Corporation 1984 Non-Qualified Stock Option Plan.
(12) Includes 4,228 shares owned by Mechanical Development Co., Inc., all of the
outstanding capital stock of which is owned by members of Mr. Powell's family,
13,998 shares owned by the Paul A. Powell Trust of which Mr. Powell is a trustee
and his family members are the primary beneficiaries, 51 shares owned by the
Paul A. Powell Individual Trust of which Mr. Powell is a trustee, 4,989 shares
owned by West Point Associates of which Mr. Powell is a general partner and 63
shares owned by NAD Properties of which Mr. Powell is a general partner. Mr.
Powell shares voting and investment power as to all of such shares.
(13) Includes 8,000 shares owned by Marie Phelps, Mr. Phelps' wife.
(14) Includes 16,688 shares owned by SFD Enterprises, Ltd., a private investment
partnership. Mr. Kleberg shares voting and investment power as to the shares
owned by SFD Enterprises.
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(15) Includes warrants to purchase 13,500 shares of Common Stock at a price of
$7.00 per share owned by Associated Energy Managers, Inc., the principal
shareholder and Chief Executive Officer of which is Mr. Gershen.
(16) Includes 3,126 shares issuable upon exercise of options granted pursuant to
the Abraxas Petroleum Corporation 1984 Incentive Stock Option Plan, 6,874 shares
issuable upon exercise of options granted pursuant to the Abraxas Petroleum
Corporation 1993 Key Contributor Stock Option Plan and 5,000 shares issuable
upon exercise of options granted pursuant to the Abraxas Petroleum Corporation
1994 Long Term Incentive Plan.
(17) Includes 700 shares owned by the Riggs Family Trust of which Mr. Riggs is
one of the trustees and 1,000 shares owned jointly by Mr. Riggs and his wife.
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DESCRIPTION OF THE NOTES
The Series A Notes were and the Exchange Notes will be issued
under an indenture (the "Indenture") dated as of November 14, 1996 by and among
the Issuers, the Subsidiary Guarantors and IBJ Schroder Bank & Trust Company, as
Trustee (the "Trustee"). The following summary of certain provisions of the
Indenture does not purport to be complete and is subject to, and is qualified in
its entirety by reference to, the Trust Indenture Act of 1939, as amended (the
"TIA"), and to all of the provisions of the Indenture, including the definitions
of certain terms therein and those terms made a part of the Indenture by
reference to the TIA as in effect on the date of the Indenture. A copy of the
form of Indenture may be obtained from the Issuers or the Initial Purchasers.
The definitions of certain capitalized terms used in the following summary are
set forth below under "-- Certain Definitions."
The Series A Notes were and the Exchange Notes will be general
unsecured obligations of the Issuers and will rank pari passu in right of
payment to all existing and future unsubordinated obligations of the Issuers.
The Series A Notes rank and the Exchange Notes will rank senior in right of
payment to all future subordinated indebtedness of the Issuers. The Series A
Notes are, and the Exchange Notes will be, however, effectively subordinated in
right of payment to all existing and future secured indebtedness of the Issuers
to the extent of the value of the assets securing such indebtedness. The
Guarantees will be general unsecured obligations of the Subsidiary Guarantors
and rank pari passu in right of payment to all existing and future
unsubordinated indebtedness of the Subsidiary Guarantors and senior in right of
payment to all existing and future subordinated indebtedness of the Subsidiary
Guarantors. The Guarantees will be effectively subordinated to secured
indebtedness of the Subsidiary Guarantors to the extent of the value of the
assets securing such indebtedness.
The Series A Notes were and the Exchange Notes will be issued in
fully registered form only, without coupons, in denominations of $1,000 and
integral multiples thereof. The Trustee currently acts as paying agent and
registrar for the Notes. The Notes may be presented for registration of transfer
and exchange at the offices of the registrar, which initially will be the
Trustee's corporate trust office. The Issuers may change any paying agent and
registrar without notice to holders of the Notes (the "Holders"). The Issuers
will pay principal (and premium, if any) on the Notes at the Trustee's corporate
office in New York, New York. At the Issuers' option, interest may be paid at
the Trustee's corporate trust office or by check mailed to the registered
addresses of the Holders. Any Series A Notes that remain outstanding after the
completion of the Exchange Offer, together with the Exchange Notes issued in
connection with the Exchange Offer, will be treated as a single class of
securities under the Indenture. See "Exchange Offer and Registration Rights."
Principal, Maturity and Interest
The Notes are limited in aggregate principal amount to
$215,000,000 and will mature on November 1, 2004. Interest on the Notes will
accrue at the rate of 11.5% per annum and will be payable semi-annually in cash
on each May 1 and November 1, commencing on May 1, 1997, to the Persons who are
registered Holders at the close of business on the April 15 and October 15,
respectively, immediately preceding the applicable interest payment date.
Interest on the Notes will accrue from and including the most recent date to
which interest has been paid or, if no interest has been paid, from and
including the date of issuance.
The Notes will not be entitled to the benefit of any mandatory
sinking fund.
Redemption
Optional Redemption
The Notes will be redeemable, at the Issuers' option, in whole at
any time or in part from time to time, on and after November 1, 2000, upon not
less than 30 nor more than 60 days' notice, at the following redemption prices
(expressed as percentages of the principal amount thereof) if redeemed during
the twelve-month period commencing on November 1 of the years set forth below,
plus, in each case, accrued and unpaid interest, if any, thereon to the date of
redemption:
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Year Percentage
2000 105.750%
2001 102.875%
2002 and thereafter 100.000%
Optional Redemption upon Equity Offerings
At any time, or from time to time, on or prior to November 1,
1999, the Issuers may, at their option, use all or a portion of the net cash
proceeds of one or more Equity Offerings (as defined below) to redeem up to 35%
of the aggregate principal amount of the Notes originally issued at a redemption
price equal to 111.5% of the aggregate principal amount of the Notes to be
redeemed, plus accrued and unpaid interest, if any, thereon to the date of
redemption; provided, however, that at least $139.75 million aggregate principal
amount of Notes remains outstanding immediately after giving effect to any such
redemption (it being expressly agreed that for purposes of determining whether
this condition is satisfied, Notes owned by either Issuer or any of their
Affiliates shall be deemed not to be outstanding). In order to effect the
foregoing redemption with the proceeds of any Equity Offering, the Issuers shall
make such redemption not more than 60 days after the consummation of any such
Equity Offering.
Selection and Notice of Redemption
In the event that less than all of the Notes are to be redeemed
at any time, selection of such Notes, or portions thereof, for redemption will
be made by the Trustee in compliance with the requirements of the principal
national securities exchange, if any, on which the Notes are listed or, if the
Notes are not then listed on a national securities exchange, on a pro rata
basis, by lot or by such other method as the Trustee shall deem fair and
appropriate; provided, however, that no Notes of a principal amount of $1,000 or
less shall be redeemed in part; and provided, further, that if a partial
redemption is made with the proceeds of an Equity Offering, selection of the
Notes or portions thereof for redemption shall be made by the Trustee only on a
pro rata basis or on as nearly a pro rata basis as is practicable (subject to
the procedures of DTC), unless such method is otherwise prohibited. Notice of
redemption shall be mailed by first-class mail at least 30 but not more than 60
days before the redemption date to each Holder of Notes to be redeemed at its
registered address. If any Note is to be redeemed in part only, the notice of
redemption that relates to such Note shall state the portion of the principal
amount thereof to be redeemed. A new Note in a principal amount equal to the
unredeemed portion thereof will be issued in the name of the Holder thereof upon
cancellation of the original Note. On and after the applicable redemption date,
interest will cease to accrue on Notes or portions thereof called for redemption
as long as the Issuers have deposited with the paying agent for the Notes funds
in satisfaction of the applicable redemption price pursuant to the Indenture.
Guarantees
Each Subsidiary Guarantor will unconditionally guarantee, on a
senior basis, jointly and severally, to each Holder and the Trustee, the full
and prompt performance of the Issuers' obligations under the Indenture and the
Notes, including the payment of principal of and interest on the Notes. The
obligations of each Subsidiary Guarantor will be limited to the maximum amount
which, after giving effect to all other contingent and fixed liabilities of such
Subsidiary Guarantor and after giving effect to any collections from or payments
made by or on behalf of any other Subsidiary Guarantor in respect of the
obligations of such other Subsidiary Guarantor under its Guarantee or pursuant
to its contribution obligations under the Indenture, will result in the
obligations of such Subsidiary Guarantor under its Guarantee not constituting a
fraudulent conveyance or fraudulent transfer under Federal or state law. Each
Subsidiary Guarantor that makes a payment or distribution under its Guarantee
shall be entitled to a contribution from each other Subsidiary Guarantor in an
amount pro rata, based on the net assets of each Subsidiary Guarantor,
determined in accordance with GAAP.
Each Subsidiary Guarantor may consolidate with or merge into or
sell its assets to the Company or another Subsidiary Guarantor that is a Wholly
Owned Restricted Subsidiary without limitation, or with or to other Persons upon
the terms and conditions set forth in the Indenture. See "-- Certain Covenants
- -- Merger, Consolidation and Sale of Assets." In the event all of the Capital
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Stock of a Subsidiary Guarantor is sold by the Company and/or one or more of its
Restricted Subsidiaries and the sale complies with the provisions set forth in
"-- Certain Covenants -- Limitation on Asset Sales," such Subsidiary Guarantor's
Guarantee will be released.
Change of Control
The Indenture provides that upon the occurrence of a Change of
Control, each Holder will have the right to require that the Issuers purchase
all or a portion of such Holder's Notes pursuant to the offer described below
(the "Change of Control Offer"), at a purchase price equal to 101% of the
principal amount thereof, plus accrued and unpaid interest, if any, thereon to
the date of purchase.
Within 30 days following the date upon which the Change of
Control occurred, the Issuers must send, by first class mail, a notice to each
Holder, with a copy to the Trustee, which notice shall govern the terms of the
Change of Control Offer. Such notice shall state, among other things, the
purchase date, which must be no earlier than 30 days nor later than 45 days from
the date such notice is mailed, other than as may be required by law (the
"Change of Control Payment Date"). A Change of Control Offer shall remain open
for a period of 20 Business Days or such longer period as may be required by
law. Holders electing to have a Note purchased pursuant to a Change of Control
Offer will be required to surrender the Note, with the form entitled "Option of
Holder to Elect Purchase" on the reverse of the Note completed, to the paying
agent for the Notes at the address specified in the notice prior to the close of
business on the third Business Day prior to the Change of Control Payment Date.
The Issuers shall not be required to make a Change of Control
Offer upon a Change of Control if a third party makes the Change of Control
Offer at the Change of Control Purchase Price, at the same times and otherwise
in compliance with the requirements applicable to a Change of Control Offer made
by the Issuers and purchases all Notes validly tendered and not withdrawn under
such Change of Control Offer.
If a Change of Control Offer is made, there can be no assurance
that the Issuers will have available funds sufficient to pay the Change of
Control purchase price for all the Notes that might be delivered by Holders
seeking to accept the Change of Control Offer. In the event the Issuers are
required to purchase outstanding Notes pursuant to a Change of Control Offer,
the Issuers expect that they would seek third party financing to the extent they
do not have available funds to meet their purchase obligations. However, there
can be no assurance that the Issuers would be able to obtain such financing.
Neither the Board of Directors of either of the Issuers nor the
Trustee may waive the covenant relating to the Issuers' obligation to make a
Change of Control Offer. Restrictions in the Indenture described herein on the
ability of the Company and its Restricted Subsidiaries to incur additional
Indebtedness, to grant liens on their property, to make Restricted Payments and
to make Asset Sales may also make more difficult or discourage a takeover of the
Company, whether favored or opposed by the management of the Company. See
"Certain Antitakeover Provisions." Consummation of any such transaction in
certain circumstances may require repurchase of the Notes, and there can be no
assurance that the Company or the acquiring party will have sufficient financial
resources to effect such repurchase. Such restrictions and the restrictions on
transactions with Affiliates may, in certain circumstances, make more difficult
or discourage any leveraged buyout of the Company by the management of the
Company. While such restrictions cover a wide variety of arrangements which have
traditionally been used to effect highly leveraged transactions, the Indenture
may not afford the Holders of Notes protection in all circumstances from the
adverse aspects of a highly leveraged transaction, reorganization,
restructuring, merger or similar transaction.
The Issuers will comply with the requirements of Rule 14e-1 under
the Exchange Act and any other securities laws and regulations thereunder to the
extent such laws and regulations are applicable in connection with the
repurchase of Notes pursuant to a Change of Control Offer. To the extent that
the provisions of any securities laws or regulations conflict with the "Change
of Control" provisions of the Indenture, the Issuers shall comply with the
applicable securities laws and regulations and shall not be deemed to have
breached their obligations under the "Change of Control" provisions of the
Indenture by virtue thereof.
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Certain Covenants
The Indenture contains, among others, the following covenants:
Limitation on Incurrence of Additional Indebtedness. Other than
Permitted Indebtedness, the Company will not, and will not cause or permit any
of its Restricted Subsidiaries to, directly or indirectly, create, incur,
assume, guarantee, acquire, become liable, contingently or otherwise, with
respect to, or otherwise become responsible for payment of (collectively,
"incur") any Indebtedness; provided, however, that if no Default or Event of
Default shall have occurred and be continuing at the time of or as a consequence
of the incurrence of any such Indebtedness, the Company and the Restricted
Subsidiaries or any of them may incur Indebtedness (including, without
limitation, Acquired Indebtedness), in each case, if on the date of the
incurrence of such Indebtedness, after giving pro forma effect to the incurrence
thereof and the receipt and application of the proceeds therefrom, (i) both (a)
the Company's Consolidated EBITDA Coverage Ratio would have been greater than
2.25 to 1.0 if such proposed incurrence is on or prior to November 1, 1997 and
at least equal to 2.5 to 1.0 if such proposed incurrence is thereafter and (b)
the Company's Adjusted Consolidated Net Tangible Assets are equal to or greater
than 150% of the aggregate consolidated Indebtedness of the Company and its
Restricted Subsidiaries or (ii) the Company's Adjusted Consolidated Net Tangible
Assets are equal to or greater than 200% of the aggregate consolidated
Indebtedness of the Company and its Restricted Subsidiaries.
For purposes of determining any particular amount of Indebtedness
under this covenant, guarantees of Indebtedness otherwise included in the
determination of such amount shall not also be included.
Indebtedness of a Person existing at the time such Person becomes
a Restricted Subsidiary (whether by merger, consolidation, acquisition of
Capital Stock or otherwise) or is merged with or into the Company or any
Restricted Subsidiary or which is secured by a Lien on an asset acquired by the
Company or a Restricted Subsidiary (whether or not such Indebtedness is assumed
by the acquiring Person) shall be deemed incurred at the time the Person becomes
a Restricted Subsidiary or at the time of the asset acquisition, as the case may
be.
The Company will not, and will not permit any Subsidiary
Guarantor to incur any Indebtedness which by its terms (or by the terms of any
agreement governing such Indebtedness) is subordinated in right of payment to
any other Indebtedness of the Company or such Subsidiary Guarantor unless such
Indebtedness is also by its terms (or by the terms of any agreement governing
such Indebtedness) made expressly subordinate in right of payment to the Notes
or the Guarantee of such Subsidiary Guarantor, as the case may be, pursuant to
subordination provisions that are substantively identical to the subordination
provisions of such Indebtedness (or such agreement) that are most favorable to
the holders of any other Indebtedness of the Company or such Subsidiary
Guarantor, as the case may be.
Limitation on Restricted Payments. The Company will not, and will
not cause or permit any of its Restricted Subsidiaries to, directly or
indirectly, (a) declare or pay any dividend or make any distribution (other than
dividends or distributions payable solely in Qualified Capital Stock of the
Company) on or in respect of shares of the Company's Capital Stock to holders of
such Capital Stock, (b) purchase, redeem or otherwise acquire or retire for
value any Capital Stock of the Company or any warrants, rights or options to
purchase or acquire shares of any class of such Capital Stock other than through
the exchange therefor solely of Qualified Capital Stock of the Company or
warrants, rights or options to purchase or acquire shares of Qualified Capital
Stock of the Company, (c) make any principal payment on, purchase, defease,
redeem, prepay, decrease or otherwise acquire or retire for value, prior to any
scheduled final maturity, scheduled repayment or scheduled sinking fund payment,
any Indebtedness of the Company or a Subsidiary Guarantor that is subordinate or
junior in right of payment to the Notes or such Subsidiary Guarantor's
Guarantee, as the case may be, or (d) make any Investment (other than a
Permitted Investment) (each of the foregoing actions set forth in clauses (a),
(b), (c) and (d) being referred to as a "Restricted Payment"), if at the time of
such Restricted Payment or immediately after giving effect thereto, (i) a
Default or an Event of Default shall have occurred and be continuing or (ii) the
Company is not able to incur at least $1.00 of additional Indebtedness (other
than Permitted Indebtedness) in compliance with "-- Limitation on Incurrence of
Additional Indebtedness" above; provided, however, that notwithstanding the
provisions of clause (i)(a) of "-- Limitation on Incurrence of Additional
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Indebtedness" above, for purposes of determining whether the Company could incur
such additional Indebtedness pursuant to this clause (ii), the Consolidated
EBITDA Coverage Ratio which shall be required shall be at least 2.5 to 1.0, or
(iii) the aggregate amount of Restricted Payments (including such proposed
Restricted Payment) made subsequent to the Issue Date (the amount expended for
such purposes, if other than in cash, being the fair market value of such
property as determined reasonably and in good faith by the Board of Directors of
the Company) shall exceed the sum of: (A) 50% of the cumulative Consolidated Net
Income (or if cumulative Consolidated Net Income shall be a loss, minus 100% of
such loss) of the Company earned subsequent to the Issue Date and on or prior to
the last date of the Company's fiscal quarter immediately preceding such
Restricted Payment (the "Reference Date") (treating such period as a single
accounting period); plus (B) 100% of the aggregate net cash proceeds received by
the Company from any Person (other than a Restricted Subsidiary of the Company)
from the issuance and sale subsequent to the Issue Date and on or prior to the
Reference Date of Qualified Capital Stock of the Company; plus (C) without
duplication of any amounts included in clause (iii)(B) above, 100% of the
aggregate net cash proceeds of any equity contribution received by the Company
from a holder of the Company's Capital Stock (excluding, in the case of clauses
(iii)(B) and (C), any net cash proceeds from an Equity Offering to the extent
used to redeem the Notes); plus (D) an amount equal to the net reduction in
Investments in Unrestricted Subsidiaries resulting from dividends, interest
payments, repayments of loans or advances, or other transfers of cash, in each
case to the Company or to any Restricted Subsidiary of the Company from
Unrestricted Subsidiaries (but without duplication of any such amount included
in calculating cumulative Consolidated Net Income of the Company), or from
redesignations of Unrestricted Subsidiaries as Restricted Subsidiaries (in each
case valued as provided in "-- Limitation on Designation of Unrestricted
Subsidiaries" below), not to exceed, in the case of any Unrestricted Subsidiary,
the amount of Investments previously made by the Company or any Restricted
Subsidiary in such Unrestricted Subsidiary and which was treated as a Restricted
Payment under the Indenture; plus (E) without duplication of the immediately
preceding subclause (D), an amount equal to the lesser of the cost or net cash
proceeds received upon the sale or other disposition of any Investment made
after the Issue Date which had been treated as a Restricted Payment (but without
duplication of any such amount included in calculating cumulative Consolidated
Net Income of the Company); plus (F) $5,000,000.
Notwithstanding the foregoing, the provisions set forth in the
immediately preceding paragraph shall not prohibit: (1) the payment of any
dividend or redemption payment within 60 days after the date of declaration of
such dividend or the applicable redemption if the dividend or redemption
payment, as the case may be, would have been permitted on the date of
declaration; (2) if no Default or Event of Default shall have occurred and be
continuing, the acquisition of any shares of Capital Stock of the Company,
either (A) solely in exchange for shares of Qualified Capital Stock of the
Company or (B) through the application of net proceeds of a substantially
concurrent sale for cash (other than to a Restricted Subsidiary of the Company)
of shares of Qualified Capital Stock of the Company; (3) if no Default or Event
of Default shall have occurred and be continuing, the acquisition of any
Indebtedness of the Company or Subsidiary Guarantor that is subordinate or
junior in right of payment to the Notes or such Subsidiary Guarantor's
Guarantee, as the case may be, either (A) solely in exchange for shares of
Qualified Capital Stock of the Company, or (B) through the application of net
proceeds of a substantially concurrent sale for cash (other than to a Restricted
Subsidiary of the Company) of (I) shares of Qualified Capital Stock of the
Company or (II) Refinancing Indebtedness; (4) if no Default or Event of Default
shall have occurred and be continuing, the payment of dividends in respect of
the Company's Series 1995-B Preferred Stock in an amount not to exceed $400,000
in any one year, (5) the initial designation of Grey Wolf, Cascade and Western
Associated Energy Corporation as Unrestricted Subsidiaries under the Indenture
and (6) the payment of such portion of the CGGS purchase price, if any, as shall
have been placed in an escrow account to the former shareholders of CGGS. In
determining the aggregate amount of Restricted Payments made subsequent to the
Issue Date in accordance with clause (iii) of the immediately preceding
paragraph, amounts expended pursuant to clauses (1), (2)(B) and (5) shall be
included in such calculation.
Limitation on Asset Sales. The Company will not, and will not
cause or permit any of its Restricted Subsidiaries to, consummate an Asset Sale
unless (a) the Company or the applicable Restricted Subsidiary, as the case may
be, receives consideration at the time of such Asset Sale at least equal to the
fair market value of the assets sold or otherwise disposed of (as determined in
good faith by the Company's Board of Directors or senior management of the
Company); (b) (i) at least 70% of the consideration received by the Company or
such Restricted Subsidiary, as the case may be, from such Asset Sale shall be in
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the form of cash or Cash Equivalents and is received at the time of such
disposition and (ii) at least 15% of such consideration received if in a form
other than cash or Cash Equivalents is converted into or exchanged for cash or
Cash Equivalents within 120 days of such disposition; and (c) upon the
consummation of an Asset Sale, the Company shall apply, or cause such Restricted
Subsidiary to apply, the Net Cash Proceeds relating to such Asset Sale within
365 days of receipt thereof either (i) to repay or prepay Indebtedness
outstanding under the New Credit Facility, including, without limitation, a
permanent reduction in the related commitment, (ii) to repay or prepay any
Indebtedness of the Company that is secured by a Lien permitted to be incurred
pursuant to "-- Limitation on Liens" below, (iii) to make an investment in
properties or assets that replace the properties or assets that were the subject
of such Asset Sale or in properties or assets that will be used in the business
of the Company and its Restricted Subsidiaries as existing on the Issue Date or
in businesses reasonably related thereto ("Replacement Assets"), (iv) to an
investment in Crude Oil and Natural Gas Related Assets or (v) a combination of
prepayment and investment permitted by the foregoing clauses (c)(i) through
(c)(iv). On the 366th day after an Asset Sale or such earlier date, if any, as
the Board of Directors of the Company determines not to apply the Net Cash
Proceeds relating to such Asset Sale as set forth in clauses (c)(i) through
(c)(iv) of the next preceding sentence (each a "Net Proceeds Offer Trigger
Date"), such aggregate amount of Net Cash Proceeds which have been received by
the Company or such Restricted Subsidiary but which have not been applied on or
before such Net Proceeds Offer Trigger Date as permitted in clauses (c)(i)
through (c)(iv) of the next preceding sentence (each a "Net Proceeds Offer
Amount") shall be applied by the Company or such Restricted Subsidiary, as the
case may be, to make an offer to purchase (a "Net Proceeds Offer") on a date
(the "Net Proceeds Offer Payment Date") not less than 30 nor more than 45 days
following the applicable Net Proceeds Offer Trigger Date, from all Holders on a
pro rata basis, that principal amount of Notes purchasable with the Net Proceeds
Offer Amount at a price equal to 100% of the principal amount of the Notes to be
purchased, plus accrued and unpaid interest, if any, thereon to the date of
purchase; provided, however, that if at any time any non-cash consideration
received by the Company or any Restricted Subsidiary, as the case may be, in
connection with any Asset Sale is converted into or sold or otherwise disposed
of for cash (other than interest received with respect to any such non-cash
consideration), then such conversion or disposition shall be deemed to
constitute an Asset Sale hereunder and the Net Cash Proceeds thereof shall be
applied in accordance with this covenant. The Company may defer the Net Proceeds
Offer until there is an aggregate unutilized Net Proceeds Offer Amount equal to
or in excess of $5,000,000 resulting from one or more Asset Sales (at which
time, the entire unutilized Net Proceeds Offer Amount, and not just the amount
in excess of $5,000,000, shall be applied as required pursuant to this
paragraph).
In the event of the transfer of substantially all (but not all)
of the property and assets of the Company and its Restricted Subsidiaries as an
entirety to a Person in a transaction permitted under "-- Merger, Consolidation
and Sale of Assets," the successor corporation shall be deemed to have sold the
properties and assets of the Company and its Restricted Subsidiaries not so
transferred for purposes of this covenant, and shall comply with the provisions
of this covenant with respect to such deemed sale as if it were an Asset Sale.
In addition, the fair market value of such properties and assets of the Company
or its Restricted Subsidiaries deemed to be sold shall be deemed to be Net Cash
Proceeds for purposes of this covenant.
Notwithstanding the two immediately preceding paragraphs, the
Company and its Restricted Subsidiaries will be permitted to consummate an Asset
Sale without complying with such paragraphs to the extent (a) the consideration
for such Asset Sale constitutes Replacement Assets and/or Crude Oil and Natural
Gas Related Assets and (b) such Asset Sale is for fair market value; provided,
however, that any consideration not constituting Replacement Assets and Crude
Oil and Natural Gas Related Assets received by the Company or any of its
Restricted Subsidiaries in connection with any Asset Sale permitted to be
consummated under this paragraph shall constitute Net Cash Proceeds subject to
the provisions of the two immediately preceding paragraphs.
Notice of each Net Proceeds Offer will be mailed to the record
Holders as shown on the register of Holders within 30 days following the Net
Proceeds Offer Trigger Date, with a copy to the Trustee, and shall comply with
the procedures set forth in the Indenture. Upon receiving notice of the Net
Proceeds Offer, Holders may elect to tender their Notes in whole or in part in
integral multiples of $1,000 in exchange for cash. To the extent Holders
properly tender Notes with an aggregate principal amount exceeding the Net
Proceeds Offer Amount, Notes of tendering Holders will be purchased on a pro
rata basis (based on principal amounts tendered). A Net Proceeds Offer shall
remain open for a period of 20 Business Days or such longer period as may be
required by law.
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The Company's ability to repurchase Notes in a Net Proceeds Offer
is restricted by the terms of the New Credit Facility and may be prohibited or
otherwise limited by the terms of any then existing borrowing arrangements and
by the Company's financial resources.
The Company will comply with the requirements of Rule 14e-1 under
the Exchange Act and any other securities laws and regulations thereunder to the
extent such laws and regulations are applicable in connection with the
repurchase of Notes pursuant to a Net Proceeds Offer. To the extent that the
provisions of any securities laws or regulations conflict with the "Asset Sale"
provisions of the Indenture, the Company shall comply with the applicable
securities laws and regulations and shall not be deemed to have breached its
obligations under the "Asset Sale" provisions of the Indenture by virtue
thereof.
Limitation on Dividend and Other Payment Restrictions Affecting
Restricted Subsidiaries. The Company will not, and will not cause or permit any
of its Restricted Subsidiaries to, directly or indirectly, create or otherwise
cause or permit to exist or become effective any encumbrance or restriction on
the ability of any Restricted Subsidiary to (a) pay dividends or make any other
distributions on or in respect of its Capital Stock; (b) make loans or advances,
or to pay any Indebtedness or other obligation owed, to the Company or any other
Restricted Subsidiary; (c) guarantee any Indebtedness or any other obligation of
the Company or any Restricted Subsidiary; or (d) transfer any of its property or
assets to the Company or any other Restricted Subsidiary (each such encumbrance
or restriction, a "Payment Restriction"), except for such encumbrances or
restrictions existing under or by reason of: (i) applicable law; (ii) the
Indenture; (iii) the New Credit Facility; (iv) customary non-assignment
provisions of any contract or any lease governing a leasehold interest of any
Restricted Subsidiary; (v) any instrument governing Acquired Indebtedness, which
encumbrance or restriction is not applicable to such Restricted Subsidiary, or
the properties or assets of such Restricted Subsidiary, other than the Person or
the properties or assets of the Person so acquired; (vi) agreements existing on
the Issue Date to the extent and in the manner such agreements are in effect on
the Issue Date; (vii) customary restrictions with respect to a Restricted
Subsidiary of the Company pursuant to an agreement that has been entered into
for the sale or disposition of Capital Stock or assets of such Restricted
Subsidiary to be consummated in accordance with the terms of the Indenture
solely in respect of the assets or Capital Stock to be sold or disposed of;
(viii) any instrument governing a Permitted Lien, to the extent and only to the
extent such instrument restricts the transfer or other disposition of assets
subject to such Permitted Lien; or (ix) an agreement governing Refinancing
Indebtedness incurred to Refinance the Indebtedness issued, assumed or incurred
pursuant to an agreement referred to in clause (ii), (iii), (v) or (vi) above;
provided, however, that the provisions relating to such encumbrance or
restriction contained in any such Refinancing Indebtedness are no less favorable
to the Holders in any material respect as determined by the Board of Directors
of the Company in their reasonable and good faith judgment than the provisions
relating to such encumbrance or restriction contained in the applicable
agreement referred to in such clause (ii), (iii), (v) or (vi).
Limitation on Preferred Stock of Restricted Subsidiaries. The
Company will not cause or permit any of its Restricted Subsidiaries to issue any
Preferred Stock (other than to the Company or to a Wholly Owned Restricted
Subsidiary) or permit any Person (other than the Company or a Wholly Owned
Restricted Subsidiary) to own any Preferred Stock of any Restricted Subsidiary.
Limitation on Liens. Other than Permitted Liens, the Company will
not, and will not cause or permit any of its Restricted Subsidiaries to,
directly or indirectly, create, incur, assume or permit or suffer to exist any
Liens of any kind against or upon any property or assets of the Company or any
of its Restricted Subsidiaries (whether owned on the Issue Date or acquired
after the Issue Date) or any proceeds therefrom, or assign or otherwise convey
any right to receive income or profits therefrom unless (a) in the case of Liens
securing Indebtedness that is expressly subordinate or junior in right of
payment to the Notes or any Guarantee, the Notes or such Guarantee, as the case
may be, are secured by a Lien on such property, assets or proceeds that is
senior in priority to such Liens at least to the same extent as the Notes are
senior in priority to such Indebtedness and (b) in all other cases, the Notes
and the Guarantees are equally and ratably secured.
Merger, Consolidation and Sale of Assets. The Company will not,
in a single transaction or series of related transactions, consolidate or merge
with or into any Person, or sell, assign, transfer, lease, convey or otherwise
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dispose of (or cause or permit any Restricted Subsidiary to sell, assign,
transfer, lease, convey or otherwise dispose of) all or substantially all of the
Company's assets (determined on a consolidated basis for the Company and its
Restricted Subsidiaries), whether as an entirety or substantially as an entirety
to any Person unless: (a) either (i) the Company or such Restricted Subsidiary,
as the case may be, shall be the surviving or continuing corporation or (ii) the
Person (if other than the Company) formed by such consolidation or into which
the Company is merged or the Person which acquires by sale, assignment,
transfer, lease, conveyance or other disposition the properties and assets of
the Company and its Restricted Subsidiaries substantially as an entirety (the
"Surviving Entity") (x) shall be a corporation organized and validly existing
under the laws of the United States or any state thereof or the District of
Columbia and (y) shall expressly assume, by supplemental indenture (in form and
substance satisfactory to the Trustee), executed and delivered to the Trustee,
the due and punctual payment of the principal of, premium, if any, and interest
on all of the Notes and the performance of every covenant of the Notes, the
Indenture and the Registration Rights Agreement on the part of the Company to be
performed or observed; (b) immediately after giving effect to such transaction
and the assumption contemplated by clause (a)(ii)(y) above (including giving
effect to any Indebtedness incurred or anticipated to be incurred in connection
with or in respect of such transaction), the Company or such Surviving Entity,
as the case may be, (i) shall have a Consolidated Net Worth equal to or greater
than the Consolidated Net Worth of the Company immediately prior to such
transaction and (ii) shall be able to incur at least $1.00 of additional
Indebtedness (other than Permitted Indebtedness) pursuant to "-- Limitation on
Incurrence of Additional Indebtedness" above; (c) immediately before and
immediately after giving effect to such transaction and the assumption
contemplated by clause (a)(ii)(y) above (including, without limitation, giving
effect to any Indebtedness incurred or anticipated to be incurred and any Lien
granted in connection with or in respect of the transaction), no Default or
Event of Default shall have occurred or be continuing; and (d) the Company or
the Surviving Entity, as the case may be, shall have delivered to the Trustee an
officers' certificate and an opinion of counsel, each stating that such
consolidation, merger, sale, assignment, transfer, lease, conveyance or other
disposition and, if a supplemental indenture is required in connection with such
transaction, such supplemental indenture comply with the applicable provisions
of the Indenture and that all conditions precedent in the Indenture relating to
such transaction have been satisfied; provided, however, that such counsel may
rely, as to matters of fact, on a certificate or certificates of officers of the
Company.
For purposes of the foregoing, the transfer (by lease,
assignment, sale or otherwise, in a single transaction or series of
transactions) of all or substantially all of the properties or assets of one or
more Restricted Subsidiaries the Capital Stock of which constitutes all or
substantially all of the properties and assets of the Company, shall be deemed
to be the transfer of all or substantially all of the properties and assets of
the Company.
Upon any consolidation, combination or merger or any transfer of
all or substantially all of the assets of the Company in accordance with the
foregoing, in which the Company is not the continuing corporation, the successor
Person formed by such consolidation or into which the Company is merged or to
which such conveyance, lease or transfer is made shall succeed to, and be
substituted for, and may exercise every right and power of, the Company under
the Indenture and the Notes with the same effect as if such surviving entity had
been named as such.
Each Subsidiary Guarantor (other than any Subsidiary Guarantor
whose Guarantee is to be released in accordance with the terms of the Guarantee
and the Indenture in connection with any transaction complying with the
provisions of the Indenture described under "Merger, Consolidation and Sale of
Assets") will not, and the Company will not cause or permit any Subsidiary
Guarantor to, consolidate with or merge with or into any Person other than the
Company or another Subsidiary Guarantor that is a Wholly Owned Restricted
Subsidiary unless: (a) the entity formed by or surviving any such consolidation
or merger (if other than the Subsidiary Guarantor) or to which such sale, lease,
conveyance or other disposition shall have been made is a corporation organized
and existing under the laws of the United States or any state thereof or the
District of Columbia; (b) such entity assumes by execution of a supplemental
indenture all of the obligations of the Subsidiary Guarantor under its
Guarantee; (c) immediately after giving effect to such transaction, no Default
or Event of Default shall have occurred and be continuing; and (d) immediately
after giving effect to such transaction and the use of any net proceeds
therefrom on a pro forma basis, the Company could satisfy the provisions of
clause (b) of the first paragraph of this covenant. Any merger or consolidation
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of a Subsidiary Guarantor with and into the Company (with the Company being the
surviving entity) or another Subsidiary Guarantor that is a Wholly Owned
Restricted Subsidiary need only comply with clause (d) of the first paragraph of
this covenant.
Limitations on Transactions with Affiliates. (a) The Company will
not, and will not cause or permit any of its Restricted Subsidiaries to,
directly or indirectly, enter into, amend or permit or suffer to exist any
transaction or series of related transactions (including, without limitation,
the purchase, sale, lease or exchange of any property, the guaranteeing of any
Indebtedness or the rendering of any service) with, or for the benefit of, any
of their respective Affiliates (each an "Affiliate Transaction"), other than (i)
Affiliate Transactions permitted under paragraph (b) of this covenant and (ii)
Affiliate Transactions that are on terms that are fair and reasonable to the
Company or the applicable Restricted Subsidiary and are no less favorable to the
Company or the applicable Restricted Subsidiary than those that might reasonably
have been obtained in a comparable transaction at such time on an arm's-length
basis from a Person that is not an Affiliate of the Company or such Restricted
Subsidiary. All Affiliate Transactions (and each series of related Affiliate
Transactions which are similar or part of a common plan) involving aggregate
payments or other property with a fair market value in excess of $1,000,000
shall be approved by the Board of Directors of the Company, such approval to be
evidenced by a Board Resolution stating that such Board of Directors has
determined that such transaction complies with the foregoing provisions. If the
Company or any Restricted Subsidiary enters into an Affiliate Transaction (or a
series of related Affiliate Transactions related to a common plan) that involves
an aggregate fair market value of more than $10,000,000, the Company shall,
prior to the consummation thereof, obtain a favorable opinion as to the fairness
of such transaction or series of related transactions to the Company or the
relevant Restricted Subsidiary, as the case may be, from a financial point of
view, from an Independent Advisor and file the same with the Trustee.
(b) The restrictions set forth in clause (a) shall not apply to
(i) reasonable fees and compensation paid to and indemnity provided on behalf
of, officers, directors, employees or consultants of the Company or any
Restricted Subsidiary as determined in good faith by the Board of Directors or
senior management of the Company or such Restricted Subsidiary, as the case may
be; (ii) transactions exclusively between or among the Company and any of its
Restricted Subsidiaries or exclusively between or among such Restricted
Subsidiaries; provided, however, that such transactions are not otherwise
prohibited by the Indenture; (iii) Restricted Payments permitted by the
Indenture; and (iv) the payment of such portion of the CGGS purchase price, if
any, as shall have been held in escrow to the former shareholders of CGGS.
Limitation on Restricted and Unrestricted Subsidiaries. The
Indenture provides that the Board of Directors may, if no Default or Event of
Default shall have occurred and be continuing or would arise therefrom,
designate an Unrestricted Subsidiary to be a Restricted Subsidiary; provided,
however, that (i) any such redesignation shall be deemed to be an incurrence as
of the date of such redesignation by the Company and its Restricted Subsidiaries
of the Indebtedness (if any) of such redesignated Subsidiary for purposes of "--
Limitation on Incurrence of Additional Indebtedness" above, (ii) unless such
redesignated Subsidiary shall not have any Indebtedness outstanding, other than
Indebtedness which would be Permitted Indebtedness, no such designation shall be
permitted if immediately after giving effect to such redesignation and the
incurrence of any such additional Indebtedness the Company could not incur $1.00
of additional Indebtedness (other than Permitted Indebtedness) pursuant to "--
Limitation on Incurrence of Additional Indebtedness" above and (iii) such
Subsidiary assumes by execution of a supplemental indenture all of the
obligations of a Subsidiary Guarantor under a Guarantee.
The Board of Directors of the Company also may, if no Default or
Event of Default shall have occurred and be continuing or would arise therefrom,
designate any Restricted Subsidiary to be an Unrestricted Subsidiary if (i) such
designation is at that time permitted under "-- Limitation on Restricted
Payments" above and (ii) immediately after giving effect to such designation,
the Company could incur $1.00 of additional Indebtedness (other than Permitted
Indebtedness) pursuant to "-- Limitation on Incurrence of Additional
Indebtedness" above. Any such designation by the Board of Directors shall be
evidenced to the Trustee by the filing with the Trustee of a certified copy of
the resolution of the Board of Directors giving effect to such designation or
redesignation and an Officers' Certificate certifying that such designation or
redesignation complied with the foregoing conditions and setting forth in
reasonable detail the underlying calculations. In the event that any Restricted
Subsidiary is designated an Unrestricted Subsidiary in accordance with this
covenant, such Restricted Subsidiary's Guarantee will be released.
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The Indenture provides that for purposes of the covenant
described under "-- Limitation on Restricted Payments" above, (i) an
"Investment" shall be deemed to have been made at the time any Restricted
Subsidiary is designated as an Unrestricted Subsidiary in an amount
(proportionate to the Company's equity interest in such Subsidiary) equal to the
net worth of such Restricted Subsidiary at the time that such Restricted
Subsidiary is designated as an Unrestricted Subsidiary; (ii) at any date the
aggregate amount of all Restricted Payments made as Investments since the Issue
Date shall exclude and be reduced by an amount (proportionate to the Company's
equity interest in such Subsidiary) equal to the net worth of any Unrestricted
Subsidiary at the time that such Unrestricted Subsidiary is designated a
Restricted Subsidiary, not to exceed, in the case of any such redesignation of
an Unrestricted Subsidiary as a Restricted Subsidiary, the amount of Investments
previously made by the Company and its Restricted Subsidiaries in such
Unrestricted Subsidiary (in each case (i) and (ii) "net worth" to be calculated
based upon the fair market value of the assets of such Subsidiary as of any such
date of designation); and (iii) any property transferred to or from an
Unrestricted Subsidiary shall be valued at its fair market value at the time of
such transfer.
The Indenture provides that notwithstanding the foregoing, the
Board of Directors may not designate any Subsidiary of the Company to be an
Unrestricted Subsidiary if, after such designation, (a) the Company or any
Restricted Subsidiary (i) provides credit support for, or a guarantee of, any
Indebtedness of such Subsidiary (including any undertaking, agreement or
instrument evidencing such Indebtedness) or (ii) is directly or indirectly
liable for any Indebtedness of such Subsidiary or (b) such Subsidiary owns any
Capital Stock of, or owns or holds any Lien on any property of, any Restricted
Subsidiary which is not a Subsidiary of the Subsidiary to be so designated.
The Indenture provides that Subsidiaries of the Company that are
not designated by the Board of Directors as Restricted or Unrestricted
Subsidiaries will be deemed to be Restricted Subsidiaries. Notwithstanding any
provisions of this covenant, all Subsidiaries of an Unrestricted Subsidiary will
be Unrestricted Subsidiaries.
Additional Subsidiary Guarantees. If the Company or any of its
Restricted Subsidiaries transfers or causes to be transferred, in one
transaction or a series of related transactions, any property to any Restricted
Subsidiary that is not a Subsidiary Guarantor, or if the Company or any of its
Restricted Subsidiaries shall organize, acquire or otherwise invest in or hold
an Investment in another Restricted Subsidiary having total consolidated assets
with a book value in excess of $500,000 that is not a Subsidiary Guarantor, then
such transferee or acquired or other Restricted Subsidiary shall (a) execute and
deliver to the Trustee a supplemental indenture in form reasonably satisfactory
to the Trustee pursuant to which such Restricted Subsidiary shall
unconditionally guarantee all of the Company's obligations under the Notes and
the Indenture on the terms set forth in the Indenture and (b) deliver to the
Trustee an opinion of counsel that such supplemental indenture has been duly
authorized, executed and delivered by such Restricted Subsidiary and constitutes
a legal, valid, binding and enforceable obligation of such Restricted
Subsidiary. Thereafter, such Restricted Subsidiary shall be a Subsidiary
Guarantor for all purposes of the Indenture.
Limitation on Conduct of Business. The Company will not, and will
not permit any of its Restricted Subsidiaries to, engage in the conduct of any
business other than the Crude Oil and Natural Gas Business.
Reports to Holders. The Company will deliver to the Trustee
within 15 days after the filing of the same with the Commission, copies of the
quarterly and annual reports and of the information, documents and other
reports, if any, which the Company is required to file with the Commission
pursuant to Section 13 or 15(d) of the Exchange Act. Notwithstanding that the
Company may not be subject to the reporting requirements of Section 13 or 15(d)
of the Exchange Act, the Company will file with the Commission, to the extent
permitted, and provide the Trustee and Holders with such annual reports and such
information, documents and other reports specified in Sections 13 and 15(d) of
the Exchange Act. The Company will also comply with the other provisions of
Section 314(a) of the TIA.
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Events of Default
The following events are defined in the Indenture as "Events of
Default":
(a) the failure to pay interest (including any Additional
Interest) on any Notes when the same becomes due and payable and the default
continues for a period of 30 days;
(b) the failure to pay the principal on any Notes, when such
principal becomes due and payable, at maturity, upon redemption or otherwise
(including the failure to make a payment to purchase Notes tendered pursuant to
a Change of Control Offer or a Net Proceeds Offer);
(c) a default in the observance or performance of any other
covenant or agreement contained in the Indenture which default continues for a
period of 30 days after either Issuer receives written notice specifying the
default (and demanding that such default be remedied) from the Trustee or the
Holders of at least 25% of the outstanding principal amount of the Notes (except
in the case of a default with respect to observance or performance of any of the
terms or provisions of "-- Change of Control" or "Certain Covenants -- Merger,
Consolidation and Sale of Assets" or "-- Limitation on Asset Sales" which will
constitute an Event of Default with such notice requirement but without such
passage of time requirement);
(d) a default under any mortgage, indenture or instrument under
which there may be issued or by which there may be secured or evidenced any
Indebtedness of the Company or of any Restricted Subsidiary (or the payment of
which is guaranteed by the Issuers or any Restricted Subsidiary), whether such
Indebtedness now exists or is created after the Issue Date, which default (i) is
caused by a failure to pay principal of or premium, if any, or interest on such
Indebtedness after any applicable grace period provided in such Indebtedness (a
"payment default") or (ii) results in the acceleration of such Indebtedness
prior to its express maturity and, in each case, the principal amount of any
such Indebtedness, together with the principal amount of any other such
Indebtedness under which there has been a payment default or the maturity of
which has been so accelerated, aggregates at least $5,000,000;
(e) one or more judgments in an aggregate amount in excess of
$5,000,000 (unless covered by insurance by a reputable insurer as to which the
insurer has acknowledged coverage) shall have been rendered against the Company
or any of its Restricted Subsidiaries and such judgments remain undischarged,
unvacated, unpaid or unstayed for a period of 60 days after such judgment or
judgments become final and non-appealable;
(f) certain events of bankruptcy affecting the Company or any of
its Subsidiaries; or
(g) any of the Guarantees cease to be in full force and effect or
any of the Guarantees are declared to be null and void or invalid and
unenforceable or any of the Subsidiary Guarantors denies or disaffirms its
liability under its Guarantees (other than by reason of release of a Subsidiary
Guarantor in accordance with the terms of the Indenture).
The Indenture provides that, if an Event of Default (other than
an Event of Default specified in clause (f) above) shall occur and be
continuing, the Trustee or the Holders of at least 25% in principal amount of
outstanding Notes may declare the principal of, premium, if any, and accrued and
unpaid interest on all the Notes to be due and payable by notice in writing to
the Issuers and the Trustee specifying the Event of Default and that it is a
"notice of acceleration", and the same shall become immediately due and payable.
If an Event of Default specified in clause (f) above occurs and is continuing,
then all unpaid principal of, and premium, if any, and accrued and unpaid
interest on all of the outstanding Notes shall ipso facto become and be
immediately due and payable without any declaration or other act on the part of
the Trustee or any Holder.
The Indenture provides that, at any time after a declaration of
acceleration with respect to the Notes as described in the preceding paragraph,
the Holders of a majority in principal amount of the Notes may rescind and
cancel such declaration and its consequences (a) if the rescission would not
conflict with any judgment or decree, (b) if all existing Events of Default have
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been cured or waived except nonpayment of principal or interest that has become
due solely because of such acceleration, (c) to the extent the payment of such
interest is lawful, interest on overdue installments of interest and overdue
principal, which has become due otherwise than by such declaration of
acceleration, has been paid, (d) if the Issuers have paid the Trustee its
reasonable compensation and reimbursed the Trustee for its expenses,
disbursements and advances and (e) in the event of the cure or waiver of an
Event of Default of the type described in clause (f) of the description of
Events of Default above, the Trustee shall have received an officers'
certificate and an opinion of counsel that such Event of Default has been cured
or waived; provided, however, that such counsel may rely, as to matters of fact,
on a certificate or certificates of officers of the Company. No such rescission
shall affect any subsequent Default or impair any right consequent thereto.
The Indenture provides that, at any time prior to the declaration
of acceleration of the Notes, the Holders of a majority in principal amount of
the Notes may waive any existing Default or Event of Default under the
Indenture, and its consequences, except a default in the payment of the
principal of or interest on any Notes.
The Indenture provides that, Holders of the Notes may not enforce
the Indenture or the Notes except as provided in the Indenture and under the
TIA. During the existence of an Event of Default, the Trustee is required to
exercise such rights and powers vested in it under the Indenture and use the
same degree of care and skill in its exercise thereof as a prudent man would
exercise or use under the circumstances in the conduct of his own affairs.
Subject to the provisions of the Indenture relating to the duties of the
Trustee, whether or not an Event of Default shall occur and be continuing, the
Trustee is under no obligation to exercise any of its rights or powers under the
Indenture at the request, order or direction of any of the Holders, unless such
Holders have offered to the Trustee reasonable indemnity. Subject to all
provisions of the Indenture and applicable law, the Holders of a majority in
aggregate principal amount of the then outstanding Notes have the right to
direct the time, method and place of conducting any proceeding for any remedy
available to the Trustee or exercising any trust or power conferred on the
Trustee.
Under the Indenture, the Issuers are required to provide an
officers' certificate to the Trustee promptly upon any such officer obtaining
knowledge of any Default or Event of Default (provided that such officers shall
provide such certification at least annually whether or not they know of any
Default or Event of Default) that has occurred and, if applicable, describe such
Default or Event of Default and the status thereof.
Legal Defeasance and Covenant Defeasance
The Issuers may, at their option and at any time, elect to have
their obligations and the corresponding obligations of the Subsidiary Guarantors
discharged with respect to the outstanding Notes ("Legal Defeasance"). Such
Legal Defeasance means that the Issuers shall be deemed to have paid and
discharged the entire indebtedness represented by the outstanding Notes, and
satisfied all of their obligations with respect to the Notes, except for (a) the
rights of Holders to receive payments in respect of the principal of, premium,
if any, and interest on the Notes when such payments are due, (b) the Issuers'
obligations with respect to the Notes concerning issuing temporary Notes,
registration of Notes, mutilated, destroyed, lost or stolen Notes and the
maintenance of an office or agency for payments, (c) the rights, powers, trust,
duties and immunities of the Trustee and the Issuers' obligations in connection
therewith and (d) the Legal Defeasance provisions of the Indenture. In addition,
the Issuers may, at their option and at any time, elect to have the obligations
of the Issuers released with respect to certain covenants that are described in
the Indenture ("Covenant Defeasance") and thereafter any omission to comply with
such obligations shall not constitute a Default or Event of Default with respect
to the Notes. In the event Covenant Defeasance occurs, certain events (other
than non-payment, bankruptcy, receivership, reorganization and insolvency
events) described under "-- Events of Default" will no longer constitute an
Event of Default with respect to the Notes.
In order to exercise either Legal Defeasance or Covenant
Defeasance, (a) the Issuers must irrevocably deposit with the Trustee, in trust,
for the benefit of the Holders cash in United States dollars, non-callable
United States government obligations, or a combination thereof, in such amounts
as will be sufficient, in the opinion of a nationally recognized firm of
independent public accountants, to pay the principal of, premium, if any, and
interest on the Notes on the stated date for payment thereof or on the
applicable redemption date, as the case may be; (b) in the case of Legal
Defeasance, the Issuers shall have delivered to the Trustee an opinion of
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counsel in the United States reasonably acceptable to the Trustee confirming
that (i) the Issuers have received from, or there has been published by, the
Internal Revenue Service a ruling or (ii) since the date of the Indenture, there
has been a change in the applicable federal income tax law, in either case to
the effect that, and based thereon such opinion of counsel shall confirm that,
the Holders will not recognize income, gain or loss for federal income tax
purposes as a result of such Legal Defeasance and will be subject to federal
income tax on the same amounts, in the same manner and at the same times as
would have been the case if such Legal Defeasance had not occurred, (c) in the
case of Covenant Defeasance, the Issuers shall have delivered to the Trustee an
opinion of counsel in the United States reasonably acceptable to the Trustee
confirming that the Holders will not recognize income, gain or loss for federal
income tax purposes as a result of such Covenant Defeasance and will be subject
to federal income tax on the same amounts, in the same manner and at the same
times as would have been the case if such Covenant Defeasance had not occurred;
(d) no Default or Event of Default shall have occurred and be continuing on the
date of such deposit or insofar as Events of Default from bankruptcy or
insolvency events are concerned, at any time in the period ending on the 91st
day after the date of deposit; (e) such Legal Defeasance or Covenant Defeasance
shall not result in a breach or violation of, or constitute a default under the
Indenture or any other agreement or instrument to which the Company or any of
its Restricted Subsidiaries is a party or by which the Company or any of its
Restricted Subsidiaries is bound; (f) the Issuers shall have delivered to the
Trustee an officers' certificate stating that the deposit was not made by the
Issuers with the intent of preferring the Holders over any other creditors of
either Issuer or with the intent of defeating, hindering, delaying or defrauding
any other creditors of the Issuers or others; (g) the Issuers shall have
delivered to the Trustee an officers' certificate and an opinion of counsel,
each stating that all conditions precedent provided for or relating to the Legal
Defeasance or the Covenant Defeasance, as the case may be, have been complied
with; provided, however, that such counsel may rely, as to matters of fact, on a
certificate or certificates of officers of the Company; (h) the Issuers shall
have delivered to the Trustee an opinion of counsel to the effect that after the
91st day following the deposit, the trust funds will not be subject to the
effect of any applicable bankruptcy, insolvency, reorganization or similar laws
affecting creditors' rights generally; provided, however, that such counsel may
rely, as to matters of fact, on a certificate or certificates of officers of the
Issuers; and (i) certain other customary conditions precedent are satisfied.
Satisfaction and Discharge
The Indenture will be discharged and will cease to be of further
effect (except as to surviving rights of registration of transfer or exchange of
the Notes, as expressly provided for in the Indenture) as to all outstanding
Notes when (a) either (i) all the Notes, theretofore authenticated and delivered
(except lost, stolen or destroyed Notes which have been replaced or paid and
Notes for whose payment money has theretofore been deposited in trust or
segregated and held in trust by the Issuers and thereafter repaid to the Issuers
or discharged from such trust) have been delivered to the Trustee for
cancellation or (ii) all Notes not theretofore delivered to the Trustee for
cancellation have become due and payable and the Issuers have irrevocably
deposited or caused to be deposited with the Trustee funds in an amount
sufficient to pay and discharge the entire Indebtedness on the Notes not
theretofore delivered to the Trustee for cancellation, for principal of,
premium, if any, and interest on the Notes to the date of deposit together with
irrevocable instructions from the Issuers directing the Trustee to apply such
funds to the payment thereof at maturity or redemption, as the case may be; (b)
the Issuers have paid all other sums payable under the Indenture by the Issuers;
and (c) the Issuers have delivered to the Trustee an officers' certificate and
an opinion of counsel stating that all conditions precedent under the Indenture
relating to the satisfaction and discharge of the Indenture have been complied
with; provided, however, that such counsel may rely, as to matters of fact, on a
certificate or certificates of officers of the Issuers.
Modification of the Indenture
From time to time, the Issuers, the Subsidiary Guarantors and the
Trustee, without the consent of the Holders, may amend the Indenture for certain
specified purposes, including curing ambiguities, defects or inconsistencies, to
comply with any requirements of the Commission in order to effect or maintain
the qualification of the Indenture under the TIA or to make any change that
would provide any additional benefit or rights to the Holders or that does not
adversely affect the rights of any Holder. In formulating its opinion on such
matters, the Trustee will be entitled to rely on such evidence as it deems
appropriate, including, without limitation, solely on an opinion of counsel;
provided, however, that in delivering such opinion of counsel, such counsel may
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rely, as to matters of fact, on a certificate or certificates of officers of the
Company. Other modifications and amendments of the Indenture may be made with
the consent of the Holders of a majority in principal amount of the then
outstanding Notes issued under the Indenture, except that, without the consent
of each Holder affected thereby, no amendment may: (a) reduce the amount of
Notes whose Holders must consent to an amendment; (b) reduce the rate of or
change or have the effect of changing the time for payment of interest,
including defaulted interest, on any Notes; (c) reduce the principal of or
change or have the effect of changing the fixed maturity of any Notes, or change
the date on which any Notes may be subject to redemption or repurchase, or
reduce the redemption or repurchase price therefor; (d) make any Notes payable
in money other than that stated in the Notes; (e) make any change in provisions
of the Indenture protecting the right of each Holder to receive payment of
principal of and interest on such Note on or after the due date thereof or to
bring suit to enforce such payment, or permitting Holders of a majority in
principal amount of Notes to waive Defaults or Events of Default; (f) amend,
change or modify in any material respect the obligation of the Issuers to make
and consummate a Change of Control Offer in the event of a Change of Control or
make and consummate a Net Proceeds Offer with respect to any Asset Sale that has
been consummated or modify any of the provisions or definitions with respect
thereto; (g) modify or change any provision of the Indenture or the related
definitions affecting ranking of the Notes or any Guarantee in a manner which
adversely affects the Holders; or (h) release any Subsidiary Guarantor from any
of its obligations under its Guarantee or the Indenture otherwise than in
accordance with the terms of the Indenture.
Governing Law
The Indenture provides that the Indenture, the Notes and the
Guarantees will be governed by, and construed in accordance with, the laws of
the State of New York but without giving effect to applicable principles of
conflicts of law to the extent that the application of the law of another
jurisdiction would be required thereby.
The Trustee
The Indenture provides that, except during the continuance of an
Event of Default, the Trustee will perform only such duties as are specifically
set forth in the Indenture. During the existence of an Event of Default, the
Trustee will exercise such rights and powers vested in it by the Indenture, and
use the same degree of care and skill in its exercise as a prudent man would
exercise or use under the circumstances in the conduct of his own affairs.
The Indenture and the provisions of the TIA contain certain
limitations on the rights of the Trustee, should it become a creditor of the
Issuers or a Subsidiary Guarantor, to obtain payments of claims in certain cases
or to realize on certain property received in respect of any such claim as
security or otherwise. Subject to the TIA, the Trustee will be permitted to
engage in other transactions; provided, however, that if the Trustee acquires
any conflicting interest as described in the TIA, it must eliminate such
conflict or resign.
Certain Definitions
Set forth below is a summary of certain of the defined terms used
in the Indenture. Reference is made to the Indenture for the full definition of
all such terms, as well as any other terms used herein for which no definition
is provided.
"Acquired Indebtedness" means Indebtedness of a Person or any of
its Subsidiaries (i) existing at the time such Person becomes a Restricted
Subsidiary or at the time it merges or consolidates with the Company or any of
its Restricted Subsidiaries or (ii) which becomes Indebtedness of the Company or
a Restricted Subsidiary in connection with the acquisition of assets from such
Person, in each case not incurred in connection with, or in anticipation or
contemplation of, such Person becoming a Restricted Subsidiary or such
acquisition, merger or consolidation.
"Adjusted Consolidated Net Tangible Assets" means (without
duplication), as of the date of determination, (a) the sum of (i) discounted
future net revenues from proved oil and gas reserves of the Company and its
consolidated Subsidiaries, calculated in accordance with Commission guidelines
(before any state or federal income tax), as estimated by a nationally
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recognized firm of independent petroleum engineers as of a date no earlier than
the date of the Company's latest annual consolidated financial statements, as
increased by, as of the date of determination, the estimated discounted future
net revenues from (A) estimated proved oil and gas reserves acquired since the
date of such year-end reserve report, and (B) estimated oil and gas reserves
attributable to upward revisions of estimates of proved oil and gas reserves
since the date of such year-end reserve report due to exploration, development
or exploitation activities, in each case calculated in accordance with
Commission guidelines (utilizing the prices utilized in such year-end reserve
report), and decreased by, as of the date of determination, the estimated
discounted future net revenues from (C) estimated proved oil and gas reserves
produced or disposed of since the date of such year-end reserve report and (D)
estimated oil and gas reserves attributable to downward revisions of estimates
of proved oil and gas reserves since the date of such year-end reserve report
due to changes in geological conditions or other factors which would, in
accordance with standard industry practice, cause such revisions, in each case
calculated in accordance with Commission guidelines (utilizing the prices
utilized in such year-end reserve report); provided, however, that, in the case
of each of the determinations made pursuant to clauses (A) through (D), such
increases and decreases shall be as estimated by the Company's petroleum
engineers, unless in the event that there is a Material Change as a result of
such acquisitions, dispositions or revisions, then the discounted future net
revenues utilized for purposes of this clause (a)(i) shall be confirmed in
writing, by a nationally recognized firm of independent petroleum engineers
(which may be the Company's independent petroleum engineers who prepare the
Company's annual reserve report) plus (ii) the capitalized costs that are
attributable to oil and gas properties of the Company and its Subsidiaries to
which no proved oil and gas reserves are attributable, based on the Company's
books and records as of a date no earlier than the date of the Company's latest
annual or quarterly financial statements, plus (iii) the Net Working Capital on
a date no earlier than the date of the Company's latest consolidated annual or
quarterly financial statements plus (iv) with respect to each other tangible
asset of the Company or its consolidated Restricted Subsidiaries specifically
including, but not to the exclusion of any other qualifying tangible assets, the
Company's or its consolidated Restricted Subsidiaries' gas producing facilities
and unproved oil and gas properties (less any remaining deferred income taxes
which have been allocated to such gas processing facilities in connection with
the acquisition thereof), land, equipment, leasehold improvements, investments
carried on the equity method, restricted cash and the carrying value of
marketable securities, the greater of (A) the net book value of such other
tangible asset on a date no earlier than the date of the Company's latest
consolidated annual or quarterly financial statements or (B) the appraised
value, as estimated by a qualified Independent Advisor, of such other tangible
assets of the Company and its Restricted Subsidiaries, as of a date no earlier
than the date of the Company's latest audited financial statements minus (b)
minority interests and, to the extent not otherwise taken into account in
determining Adjusted Consolidated Net Tangible Assets, any gas balancing
liabilities of the Company and its consolidated Restricted Subsidiaries
reflected in the Company's latest audited financial statements. In addition to,
but without duplication of, the foregoing, for purposes of this definition,
"Adjusted Consolidated Net Tangible Assets" shall be calculated after giving
effect, on a pro forma basis, to (1) any Investment not prohibited by the
Indenture, to and including the date of the transaction giving rise to the need
to calculate Adjusted Consolidated Net Tangible Assets (the "Assets Transaction
Date"), in any other Person that, as a result of such Investment, becomes a
Restricted Subsidiary of the Company, (2) the acquisition, to and including the
Assets Transaction Date (by merger, consolidation or purchase of stock or
assets), of any business or assets, including, without limitation, Permitted
Industry Investments, and (3) any sales or other dispositions of assets
permitted by the Indenture (other than sales of Hydrocarbons or other mineral
products in the ordinary course of business) occurring on or prior to the Assets
Transaction Date.
"Affiliate" means, with respect to any specified Person, (a) any
other Person who directly or indirectly through one or more intermediaries
controls, or is controlled by, or under common control with, such specified
Person and (b) any Related Person of such Person. The term "control" means the
possession, directly or indirectly, of the power to direct or cause the
direction of the management and policies of a Person, whether through the
ownership of voting securities, by contract or otherwise; and the terms
"controlling" and "controlled" have meanings correlative of the foregoing.
"Affiliate Transaction" has the meaning set forth under "Certain
Covenants -- Limitation on Transactions with Affiliates."
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"Asset Acquisition" means (a) an Investment by the Company or any
Restricted Subsidiary in any other Person pursuant to which such Person shall
become a Restricted Subsidiary, or shall be merged with or into the Company or
any Restricted Subsidiary, or (b) the acquisition by the Company or any
Restricted Subsidiary of the assets of any Person (other than a Restricted
Subsidiary) which constitute all or substantially all of the assets of such
Person or comprises any division or line of business of such Person or any other
properties or assets of such Person other than in the ordinary course of
business.
"Asset Sale" means any direct or indirect sale, issuance,
conveyance, transfer, exchange, lease (other than operating leases entered into
in the ordinary course of business), assignment or other transfer for value by
the Company or any of its Restricted Subsidiaries (including any Sale and
Leaseback Transaction) to any Person other than the Company or a Restricted
Subsidiary of (a) any Capital Stock of any Restricted Subsidiary; or (b) any
other property or assets (including any interests therein) of the Company or any
Restricted Subsidiary, including any disposition by means of a merger,
consolidation or similar transaction; provided, however, that Asset Sales shall
not include (i) the sale, lease, conveyance, disposition or other transfer of
all or substantially all of the assets of the Company in a transaction which is
made in compliance with the provisions of "-- Certain Covenants -- Merger,
Consolidation and Sale of Assets", (ii) any Investment in an Unrestricted
Subsidiary which is made in compliance with the provisions of "-- Certain
Covenants -- Limitation on Restricted Payments" above, (iii) disposals or
replacements of obsolete equipment in the ordinary course of business, (iv) the
sale, lease, conveyance, disposition or other transfer (each, a "Transfer") by
the Company or any Restricted Subsidiary of assets or property to the Company or
one or more Restricted Subsidiaries, (v) any disposition of Hydrocarbons or
other mineral products for value in the ordinary course of business and (vi) the
Transfer by the Company or any Restricted Subsidiary of assets or property in
the ordinary course of business; provided, however, that the aggregate amount
(valued at the fair market value of such assets or property at the time of such
Transfer) of all such assets and property Transferred since the Issue Date
pursuant to this clause (vi) shall not exceed $1,000,000 in any one year.
"Board of Directors" means, as to any Person, the board of
directors of such Person or any duly authorized committee thereof.
"Board Resolution" means, with respect to any Person, a copy of a
resolution certified by the Secretary or an Assistant Secretary of such Person
to have been duly adopted by the Board of Directors of such Person and to be in
full force and effect on the date of such certification, and delivered to the
Trustee.
"Business Day" means any day other than a Saturday, Sunday or any
other day on which banking institutions in the City of New York are required or
authorized by law or other governmental action to be closed.
"Capitalized Lease Obligation" means, as to any Person, the
discounted present value of the rental obligations of such Person under a lease
of (or other agreement conveying the right to use) any property (whether real,
personal or mixed) that is required to be classified and accounted for as a
capital lease obligation at such date, determined in accordance with GAAP.
"Capital Stock" means (a) with respect to any Person that is a
corporation, any and all shares, interests, participations or other equivalents
(however designated and whether or not voting) of corporate stock, including
each class of Common Stock and Preferred Stock of such Person and including any
warrants, options or rights to acquire any of the foregoing and instruments
convertible into any of the foregoing and (b) with respect to any Person that is
not a corporation, any and all partnership or other equity interests of such
Person.
"Cash Equivalents" means (a) marketable direct obligations issued
by, or unconditionally guaranteed by, the United States Government or issued by
any agency thereof and backed by the full faith and credit of the United States,
in each case maturing within one year from the date of acquisition thereof; (b)
marketable direct obligations issued by any state of the United States of
America or any political subdivision of any such state or any public
instrumentality thereof maturing within one year from the date of acquisition
thereof and, at the time of acquisition, having one of the two highest ratings
obtainable from either Standard & Poor's Corporation ("S&P") or Moody's
Investors Service, Inc. ("Moody's"); (c) commercial paper maturing no more than
one year from the date of creation thereof and, at the time of acquisition,
having a rating of at least A-1 from S&P or at least P-1 from Moody's; (d)
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certificates of deposit or bankers' acceptances maturing within one year from
the date of acquisition thereof issued by any bank organized under the laws of
the United States of America or any state thereof or the District of Columbia or
any United States branch of a foreign bank having at the date of acquisition
thereof combined capital and surplus of not less than $250,000,000; (e)
repurchase obligations with a term of not more than seven days for underlying
securities of the types described in clause (a) above entered into with any bank
meeting the qualifications specified in clause (d) above and (f) money market
mutual or similar funds having assets in excess of $100,000,000.
"Change of Control" means the occurrence of one or more of the
following events: (a) any sale, lease, exchange or other transfer (in one
transaction or a series of related transactions) of all or substantially all of
the assets of the Company to any Person or group of related Persons for purposes
of Section 13(d) of the Exchange Act (a "Group") (whether or not otherwise in
compliance with the provisions of the Indenture); (b) the approval by the
holders of Capital Stock of the Company of any plan or proposal for the
liquidation or dissolution of the Company (whether or not otherwise in
compliance with the provisions of the Indenture); (c) any Person or Group shall
become the owner, directly or indirectly, beneficially or of record, of shares
representing more than 35% of the aggregate ordinary voting power represented by
the issued and outstanding Capital Stock of the Company; or (d) the replacement
of a majority of the Board of Directors of the Company over a two-year period
from the directors who constituted the Board of Directors of the Company at the
beginning of such period with directors whose replacement shall not have been
approved (by recommendation, nomination or election, as the case may be) by a
vote of at least a majority of the Board of Directors of the Company then still
in office who either were members of such Board of Directors at the beginning of
such period or whose election as a member of such Board of Directors was
previously so approved.
"Change of Control Offer" has the meaning set forth under "--
Change of Control."
"Change of Control Payment Date" has the meaning set forth under
"-- Change of Control."
"Common Stock" of any Person means any and all shares, interests
or other participations in, and other equivalents (however designated and
whether voting or non-voting) of such Person's common stock, whether outstanding
on the Issue Date or issued after the Issue Date, and includes, without
limitation, all series and classes of such common stock.
"Commission" means the Securities and Exchange Commission.
"Company" means Abraxas Petroleum Corporation, a Nevada
corporation.
"Company Properties" means all Properties, and equity,
partnership or other ownership interests therein, that are related or incidental
to, or used or useful in connection with, the conduct or operation of any
business activities of the Company or the Subsidiaries, which business
activities are not prohibited by the terms of the Indenture.
"Consolidated EBITDA" means, for any period, the sum (without
duplication) of (a) Consolidated Net Income and (b) to the extent Consolidated
Net Income has been reduced thereby, (i) all income taxes of the Company and its
Restricted Subsidiaries paid or accrued in accordance with GAAP for such period
(other than income taxes attributable to extraordinary, unusual or nonrecurring
gains or losses or taxes attributable to sales or dispositions outside the
ordinary course of business), (ii) Consolidated Interest Expense, (iii) the
amount of any Preferred Stock dividends paid by the Company and its Restricted
Subsidiaries and (iv) Consolidated Non-cash Charges, less any non-cash items
increasing Consolidated Net Income for such period, all as determined on a
consolidated basis for the Company and its Restricted Subsidiaries in accordance
with GAAP.
"Consolidated EBITDA Coverage Ratio" means, with respect to the
Company, the ratio of (a) Consolidated EBITDA of the Company during the four
full fiscal quarters for which financial information in respect thereof is
available (the "Four Quarter Period") ending on or prior to the date of the
transaction giving rise to the need to calculate the Consolidated EBITDA
Coverage Ratio (the "Transaction Date") to (b) Consolidated Fixed Charges of the
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Company for the Four Quarter Period. In addition to and without limitation of
the foregoing, for purposes of this definition, "Consolidated EBITDA" and
"Consolidated Fixed Charges" shall be calculated after giving effect (without
duplication) on a pro forma basis for the period of such calculation to (a) the
incurrence or repayment of any Indebtedness of the Company or any of its
Restricted Subsidiaries (and the application of the proceeds thereof) giving
rise to the need to make such calculation and any incurrence or repayment of
other Indebtedness (and the application of the proceeds thereof), other than the
incurrence or repayment of indebtedness in the ordinary course of business for
working capital purposes pursuant to working capital facilities, occurring
during the Four Quarter Period or at any time subsequent to the last day of the
Four Quarter Period and on or prior to the Transaction Date, as if such
incurrence or repayment, as the case may be (and the application of the proceeds
thereof), occurred on the first day of the Four Quarter Period and (b) any Asset
Sales or Asset Acquisitions (including, without limitation, any Asset
Acquisition giving rise to the need to make such calculation as a result of the
Company or one of its Restricted Subsidiaries (including any Person who becomes
a Restricted Subsidiary as a result of the Asset Acquisition) incurring,
assuming or otherwise being liable for Acquired Indebtedness, and also
including, without limitation, any Consolidated EBITDA attributable to the
assets which are the subject of the Asset Acquisition or Asset Sale during the
Four Quarter Period) occurring during the Four Quarter Period or at any time
subsequent to the last day of the Four Quarter Period and on or prior to the
Transaction Date, as if such Asset Sale or Asset Acquisition (including the
incurrence, assumption or liability for any such Acquired Indebtedness) occurred
on the first day of the Four Quarter Period. If the Company or any of its
Restricted Subsidiaries directly or indirectly guarantees Indebtedness of a
third Person, the preceding sentence shall give effect to the incurrence of such
guaranteed Indebtedness as if the Company or the Restricted Subsidiary, as the
case may be, had directly incurred or otherwise assumed such guaranteed
Indebtedness. Furthermore, in calculating "Consolidated Fixed Charges" for
purposes of determining the denominator (but not the numerator) of this
"Consolidated EBITDA Coverage Ratio," (i) interest on outstanding Indebtedness
determined on a fluctuating basis as of the Transaction Date and which will
continue to be so determined thereafter shall be deemed to have accrued at a
fixed rate per annum equal to the rate of interest on such Indebtedness in
effect on the Transaction Date; (ii) if interest on any Indebtedness actually
incurred on the Transaction Date may optionally be determined at an interest
rate based upon a factor of a prime or similar rate, a eurocurrency interbank
offered rate, or other rates, then the interest rate in effect on the
Transaction Date will be deemed to have been in effect during the Four Quarter
Period; (iii) notwithstanding clauses (i) and (ii) above, interest on
Indebtedness determined on a fluctuating basis, to the extent such interest is
covered by agreements relating to Interest Swap Obligations, shall be deemed to
accrue at the rate per annum resulting after giving effect to the operation of
such agreements.
"Consolidated Fixed Charges" means, with respect to the Company
for any period, the sum, without duplication, of (a) Consolidated Interest
Expense (including any premium or penalty paid in connection with redeeming or
retiring Indebtedness of the Company and its Restricted Subsidiaries prior to
the stated maturity thereof pursuant to the agreements governing such
Indebtedness), plus (b) the product of (i) the amount of all dividend payments
on any series of Preferred Stock of the Company (other than dividends paid in
Qualified Capital Stock) paid, accrued or scheduled to be paid or accrued during
such period times (ii) a fraction, the numerator of which is one and the
denominator of which is one minus the then current effective consolidated
federal, state and local income tax rate of such Person, expressed as a decimal.
"Consolidated Interest Expense" means, with respect to the
Company for any period, the sum of, without duplication: (a) the aggregate of
the interest expense of the Company and its Restricted Subsidiaries for such
period determined on a consolidated basis in accordance with GAAP, including
without limitation, (i) any amortization of original issue discount, (ii) the
net costs under Interest Swap Obligations, (iii) all capitalized interest and
(iv) the interest portion of any deferred payment obligation; and (b) the
interest component of Capitalized Lease Obligations paid, accrued and/or
scheduled to be paid or accrued by the Company and its Restricted Subsidiaries
during such period, as determined on a consolidated basis in accordance with
GAAP.
"Consolidated Net Income" means, with respect to the Company for
any period, the aggregate net income (or loss) of the Company and its Restricted
Subsidiaries for such period on a consolidated basis, determined in accordance
with GAAP; provided, however, that there shall be excluded therefrom (a)
after-tax gains from Asset Sales or abandonments or reserves relating thereto,
(b) after-tax items classified as extraordinary or nonrecurring gains, (c) the
net income of any Person acquired in a "pooling of interests" transaction
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accrued prior to the date it becomes a Restricted Subsidiary or is merged or
consolidated with the Company or any Restricted Subsidiary, (d) the net income
(but not loss) of any Restricted Subsidiary to the extent that the declaration
of dividends or similar distributions by that Restricted Subsidiary of that
income is restricted by charter, contract, operation of law or otherwise, (e)
the net income of any Person in which the Company has an interest, other than a
Restricted Subsidiary, except to the extent of cash dividends or distributions
actually paid to the Company or to a Restricted Subsidiary by such Person, (f)
income or loss attributable to discontinued operations (including, without
limitation, operations disposed of during such period whether or not such
operations were classified as discontinued) and (g) in the case of a successor
to the Company by consolidation or merger or as a transferee of the Company's
assets, any net income (or loss) of the successor corporation prior to such
consolidation, merger or transfer of assets.
"Consolidated Net Worth" of any Person as of any date means the
consolidated stockholders' equity of such Person, determined on a consolidated
basis in accordance with GAAP, less (without duplication) amounts attributable
to Disqualified Capital Stock of such Person.
"Consolidated Non-cash Charges" means, with respect to the
Company, for any period, the aggregate depreciation, depletion, amortization and
other non-cash expenses of the Company and its Restricted Subsidiaries reducing
Consolidated Net Income of the Company for such period, determined on a
consolidated basis in accordance with GAAP (excluding any such charges
constituting an extraordinary item or loss or any such charge which requires an
accrual of or a reserve for cash charges for any future period).
"consolidation" means, with respect to any Person, the
consolidation of the accounts of the Restricted Subsidiaries of such Person with
those of such Person, all in accordance with GAAP; provided, however, that
"consolidation" will not include consolidation of the accounts of any
Unrestricted Subsidiary of such Person with the accounts of such Person. The
term "consolidated" has a correlative meaning to the foregoing.
"Covenant Defeasance" has the meaning set forth under "-- Legal
Defeasance and Covenant Defeasance."
"Crude Oil and Natural Gas Business" means (i) the acquisition,
exploration, development, operation and disposition of interests in oil, gas and
other hydrocarbon properties located in North America, and (ii) the gathering,
marketing, treating, processing, storage, selling and transporting of any
production from such interests or properties of the Company or of others.
"Crude Oil and Natural Gas Hedge Agreements" means, with respect
to any Person, any oil and gas agreements and other agreements or arrangements
or any combination thereof entered into by such Person in the ordinary course of
business and that is designed to provide protection against oil and natural gas
price fluctuations.
"Crude Oil and Natural Gas Properties" means all Properties,
including equity or other ownership interests therein, owned by any Person which
have been assigned "proved oil and gas reserves" as defined in Rule 4-10 of
Regulation S-X of the Securities Act as in effect on the Issue Date.
"Crude Oil and Natural Gas Related Assets" means any Investment
or capital expenditure (but not including additions to working capital or
repayments of any revolving credit or working capital borrowings) by the Company
or any Subsidiary of the Company which is related to the business of the Company
and its Subsidiaries as it is conducted on the date of the Asset Sale giving
rise to the Net Cash Proceeds to be reinvested.
"Currency Agreement" means any foreign exchange contract,
currency swap agreement or other similar agreement or arrangement designed to
protect the Company or any Restricted Subsidiary of the Company against
fluctuations in currency values.
"Default" means an event or condition the occurrence of which is,
or with the lapse of time or the giving of notice or both would be, an Event of
Default.
"Disqualified Capital Stock" means that portion of any Capital
Stock which, by its terms (or by the terms of any security into which it is
convertible or for which it is exchangeable), or upon the happening of any
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event, matures or is mandatorily redeemable, pursuant to a sinking fund
obligation or otherwise, or is mandatorily redeemable at the sole option of the
holder thereof, in whole or in part, in either case, on or prior to the final
maturity of the Notes.
"Equity Offering" means an offering of Qualified Capital Stock of
the Company.
"Exchange Act" means the Securities Exchange Act of 1934, as
amended, or any successor statute or statutes thereto.
"fair market value" means, with respect to any asset or property,
the price which could be negotiated in an arm's-length, free market transaction,
for cash, between an informed and willing seller and an informed and willing
buyer, neither of whom is under undue pressure or compulsion to complete the
transaction. Fair market value shall be determined by the Board of Directors of
the Company acting reasonably and in good faith and shall be evidenced by a
Board Resolution of the Company delivered to the Trustee; provided, however,
that (A) if the aggregate non-cash consideration to be received by the Company
or any Restricted Subsidiary from any Asset Sale shall reasonably be expected to
exceed $5,000,000 or (B) if the net worth of any Restricted Subsidiary to be
designated as an Unrestricted Subsidiary shall reasonably be expected to exceed
$10,000,000, then fair market value shall be determined by an Independent
Advisor.
"GAAP" means generally accepted accounting principles set forth
in the opinions and pronouncements of the Accounting Principles Board of the
American Institute of Certified Public Accountants and statements and
pronouncements of the Financial Accounting Standards Board as of any date of
determination.
"Holder" means any Person holding a Note.
"Hydrocarbons" means oil, gas, casinghead gas, drip gasoline,
natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous
hydrocarbons and all constituents, elements or compounds thereof and products
processed therefrom.
"incur" has the meaning set forth under "-- Certain Covenants --
Limitation on Incurrence of Additional Indebtedness."
"Indebtedness" means with respect to any Person, without
duplication, (a) all Obligations of such Person for borrowed money, (b) all
Obligations of such Person evidenced by bonds, debentures, notes or other
similar instruments, (c) all Capitalized Lease Obligations of such Person, (d)
all Obligations of such Person issued or assumed as the deferred purchase price
of property, all conditional sale obligations and all Obligations under any
title retention agreement (but excluding trade accounts payable), (e) all
Obligations for the reimbursement of any obligor on a letter of credit, banker's
acceptance or similar credit transaction, (f) guarantees and other contingent
obligations in respect of Indebtedness referred to in clauses (a) through (e)
above and clause (h) below, (g) all Obligations of any other Person of the type
referred to in clauses (a) through (f) above which are secured by any Lien on
any property or asset of such Person, the amount of such Obligation being deemed
to be the lesser of the fair market value of such property or asset or the
amount of the Obligation so secured, (h) all Obligations under Currency
Agreements and Interest Swap Obligations and (i) all Disqualified Capital Stock
issued by such Person with the amount of Indebtedness represented by such
Disqualified Capital Stock being equal to the greater of its voluntary or
involuntary liquidation preference and its maximum fixed redemption price or
repurchase price. For purposes hereof, the "maximum fixed repurchase price" of
any Disqualified Capital Stock which does not have a fixed repurchase price
shall be calculated in accordance with the terms of such Disqualified Capital
Stock as if such Disqualified Capital Stock were purchased on any date on which
Indebtedness shall be required to be determined pursuant to the Indenture, and
if such price is based upon, or measured by, the fair market value of such
Disqualified Capital Stock, such fair market value shall be determined
reasonably and in good faith by the Board of Directors of the Company. The
"amount" or "principal amount" of Indebtedness at any time of determination as
used herein represented by (a) any Indebtedness issued at a price that is less
than the principal amount at maturity thereof shall be the face amount of the
liability in respect thereof, (b) any Capitalized Lease Obligation shall be the
amount determined in accordance with the definition thereof, (c) any Interest
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Swap Obligations included in the definition of Permitted Indebtedness shall be
zero, (d) all other unconditional obligations shall be the amount of the
liability thereof determined in accordance with GAAP and (e) all other
contingent obligations shall be the maximum liability at such date of such
Person.
"Independent Advisor" means a reputable accounting, appraisal or
nationally recognized investment banking, engineering or consulting firm (a)
which does not, and whose directors, officers and employees or Affiliates do
not, have a direct or indirect material financial interest in the Company and
(b) which, in the judgment of the Board of Directors of the Company, is
otherwise disinterested, independent and qualified to perform the task for which
it is to be engaged.
"Initial Purchasers" means, collectively, BT Securities
Corporation, Bankers Trust International plc, Jefferies & Company, Inc. and ING
Baring (U.S.) Securities Corporation.
"Interest Swap Obligations" means the obligations of any Person
pursuant to any arrangement with any other Person, whereby, directly or
indirectly, such Person is entitled to receive from time to time periodic
payments calculated by applying either a floating or a fixed rate of interest on
a stated notional amount in exchange for periodic payments made by such other
Person calculated by applying a fixed or a floating rate of interest on the same
notional amount and shall include, without limitation, interest rate swaps,
caps, floors, collars and similar agreements.
"Investment" means, with respect to any Person, any direct or
indirect (i) loan, advance or other extension of credit (including, without
limitation, a guarantee) or capital contribution to (by means of any transfer of
cash or other property (valued at the fair market value thereof as of the date
of transfer) others or any payment for property or services for the account or
use of others), (ii) purchase or acquisition by such Person of any Capital
Stock, bonds, notes, debentures or other securities or evidences of Indebtedness
issued by, any Person (whether by merger, consolidation, amalgamation or
otherwise and whether or not purchased directly from the issuer of such
securities or evidences of Indebtedness), (iii) guarantee or assumption of the
Indebtedness of any other Person (other than the guarantee or assumption of
Indebtedness of such Person or a Restricted Subsidiary of such Person which
guarantee or assumption is made in compliance with the provisions of "-- Certain
Covenants -- Limitation on Incurrence of Additional Indebtedness" above), and
(iv) other items that would be classified as investments on a balance sheet of
such Person prepared in accordance with GAAP. Notwithstanding the foregoing,
"Investment" shall exclude extensions of trade credit by the Company and its
Restricted Subsidiaries on commercially reasonable terms in accordance with
normal trade practices of the Company or such Restricted Subsidiary, as the case
may be. The amount of any Investment shall not be adjusted for increases or
decreases in value, or write-ups, write-downs or write-offs with respect to such
Investment. If the Company or any Restricted Subsidiary sells or otherwise
disposes of any Capital Stock of any Restricted Subsidiary such that, after
giving effect to any such sale or disposition, it ceases to be a Subsidiary of
the Company, the Company shall be deemed to have made an Investment on the date
of any such sale or disposition equal to the fair market value of the Capital
Stock of such Restricted Subsidiary not sold or disposed of.
"Issue Date" means the date of original issuance of the Notes.
"Legal Defeasance" has the meaning set forth under "-- Legal
Defeasance and Covenant Defeasance."
"Lien" means any lien, mortgage, deed of trust, pledge, security
interest, charge or encumbrance of any kind (including any conditional sale or
other title retention agreement, any lease in the nature thereof and any
agreement to give any security interest).
"Material Change" means an increase or decrease of more than 10%
during a fiscal quarter in the discounted future net cash flows (excluding
changes that result solely from changes in prices) from proved oil and gas
reserves of the Company and consolidated Subsidiaries (before any state or
federal income tax); provided, however, that the following will be excluded from
the Material Change calculation: (i) any acquisitions during the quarter of oil
and gas reserves that have been estimated by independent petroleum engineers and
on which a report or reports exist, (ii) any disposition of properties existing
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at the beginning of such quarter that have been disposed of as provided in
"Limitation on Asset Sales" and (iii) any reserves added during the quarter
attributable to the drilling or recompletion of wells not included in previous
reserve estimates, but which will be included in future quarters.
"Net Cash Proceeds" means, with respect to any Asset Sale, the
proceeds in the form of cash or Cash Equivalents including payments in respect
of deferred payment obligations when received in the form of cash or Cash
Equivalents received by the Company or any of its Restricted Subsidiaries from
such Asset Sale net of (a) reasonable out-of-pocket expenses and fees relating
to such Asset Sale (including, without limitation, legal, accounting and
investment banking fees and sales commissions), (b) taxes paid or payable after
taking into account any reduction in consolidated tax liability due to available
tax credits or deductions and any tax sharing arrangements, (c) repayment of
Indebtedness that is required to be repaid in connection with such Asset Sale
and (d) appropriate amounts (determined by the Chief Financial Officer of the
Company) to be provided by the Company or any Restricted Subsidiary, as the case
may be, as a reserve, in accordance with GAAP, against any post closing
adjustments or liabilities associated with such Asset Sale and retained by the
Company or any Restricted Subsidiary, as the case may be, after such Asset Sale,
including, without limitation, pension and other post-employment benefit
liabilities, liabilities related to environmental matters and liabilities under
any indemnification obligations associated with such Asset Sale (but excluding
any payments which, by the terms of the indemnities will not, be made during the
term of the Notes).
"Net Proceeds Offer" has the meaning set forth under "-- Certain
Covenants -- Limitation on Asset Sales."
"Net Proceeds Offer Amount" has the meaning set forth under "--
Certain Covenants -- Limitation on Asset Sales."
"Net Proceeds Offer Payment Date" has the meaning set forth under
"-- Certain Covenants -- Limitation on Asset Sales."
"Net Proceeds Offer Trigger Date" has the meaning set forth under
"-- Certain Covenants -- Limitation on Asset Sales."
"Net Working Capital" means (i) all current assets of the Company
and its consolidated Subsidiaries, minus (ii) all current liabilities of the
Company and its consolidated Subsidiaries, except current liabilities included
in Indebtedness, in each case as set forth in financial statements of the
Company prepared in accordance with GAAP.
"New Credit Facility" means the Amended and Restated Credit
Agreement dated as of November 14, 1996, by and among the Company, BTCo and ING
Capital, as Co-Agents, and each of the Lenders named therein, or any successor
or replacement agreement and whether by the same or any other agent, lender or
group of lenders, together with the related documents thereto (including,
without limitation, any guarantee agreements and security documents), in each
case as such agreements may be amended (including any amendment and restatement
thereof), supplemented or otherwise modified from time to time, including any
agreements extending the maturity of, refinancing, replacing, increasing or
otherwise restructuring all or any portion of the Indebtedness under such
agreements.
"Non-Recourse Indebtedness" with respect to any Person means
Indebtedness of such Person for which (i) the sole legal recourse for collection
of principal and interest on such Indebtedness is against the specific property
identified in the instruments evidencing or securing such Indebtedness and such
property was acquired with the proceeds of such Indebtedness or such
Indebtedness was incurred within 90 days after the acquisition of such property
and (ii) no other assets of such Person may be realized upon in collection of
principal or interest on such Indebtedness; provided, however, that any such
Indebtedness shall not cease to be "Non-Recourse Indebtedness" solely as a
result of the instrument governing such Indebtedness containing terms pursuant
to which such Indebtedness becomes recourse upon (a) fraud or misrepresentation
by the Person in connection with such Indebtedness, (b) such Person failing to
pay taxes or other charges that result in the creation of liens on any portion
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of the specific property securing such Indebtedness or failing to maintain any
insurance on such property required under the instruments securing such
Indebtedness, (c) the conversion of any of the collateral for such Indebtedness,
(d) such Person failing to maintain any of the collateral for such Indebtedness
in the condition required under the instruments securing the Indebtedness, (e)
any income generated by the specific property securing such Indebtedness being
applied in a manner not otherwise allowed in the instruments securing such
Indebtedness, (f) the violation of any applicable law or ordinance governing
hazardous materials or substances or otherwise affecting the environmental
condition of the specific property securing the Indebtedness or (g) the rights
of the holder of such Indebtedness to the specific property becoming impaired,
suspended or reduced by any act, omission or misrepresentation of such Person;
provided, further, however, that upon the occurrence of any of the foregoing
clauses (a) through (g) above, any such Indebtedness which shall have ceased to
be "Non-Recourse Indebtedness" shall be deemed to have been Indebtedness
incurred by such Person at such time.
"Obligations" means all obligations for principal, premium,
interest, penalties, fees, indemnifications, reimbursements, damages and other
liabilities payable under the documentation governing any Indebtedness.
"Payment Restriction" has the meaning set forth under "-- Certain
Covenants -- Limitation on Dividend and Other Payment Restrictions Affecting
Restricted Subsidiaries."
"Permitted Indebtedness" means, without duplication, each of the
following:
(a) Indebtedness under the Notes, the Exchange Notes, the Private
Exchange Notes, if any, the Indenture and the Guarantees;
(b) Indebtedness incurred pursuant to the New Credit Facility in
an aggregate principal amount at any time outstanding not to exceed $50,000,000,
reduced by any required permanent repayments (which are accompanied by a
corresponding permanent commitment reduction) thereunder;
(c) Interest Swap Obligations of the Company or a Restricted
Subsidiary covering Indebtedness of the Company or any of its Restricted
Subsidiaries; provided, however, that such Interest Swap Obligations are entered
into to protect the Company and its Restricted Subsidiaries from fluctuations in
interest rates on Indebtedness incurred in accordance with the Indenture to the
extent the notional principal amount of such Interest Swap Obligations does not
exceed the principal amount of the Indebtedness to which such Interest Swap
Obligation relates;
(d) Indebtedness of a Restricted Subsidiary to the Company or to
a Wholly Owned Restricted Subsidiary for so long as such Indebtedness is held by
the Company or a Wholly Owned Restricted Subsidiary, in each case subject to no
Lien held by a Person other than the Company or a Wholly Owned Restricted
Subsidiary; provided, however, that if as of any date any Person other than the
Company or a Wholly Owned Restricted Subsidiary owns or holds any such
Indebtedness or holds a Lien in respect of
such Indebtedness, such date shall be deemed the incurrence of Indebtedness not
constituting Permitted Indebtedness by the issuer of such Indebtedness;
(e) Indebtedness of the Company to a Wholly Owned Restricted
Subsidiary for so long as such Indebtedness is held by a Wholly Owned Restricted
Subsidiary, in each case subject to no Lien; provided, however, that (i) any
Indebtedness of the Company to any Wholly Owned Restricted Subsidiary that is
not a Subsidiary Guarantor is unsecured and subordinated, pursuant to a written
agreement, to the Company's obligations under the Indenture and the Notes and
(ii) if as of any date any Person other than a Wholly Owned Restricted
Subsidiary owns or holds any such Indebtedness or holds a Lien in respect of
such Indebtedness, such date shall be deemed the incurrence of Indebtedness not
constituting Permitted Indebtedness by the Company;
(f) Indebtedness arising from the honoring by a bank or other
financial institution of a check, draft or similar instrument inadvertently
(except in the case of daylight overdrafts) drawn against insufficient funds in
the ordinary course of business; provided, however, that such Indebtedness is
extinguished within two Business Days of incurrence;
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(g) Indebtedness of the Company or any of its Restricted
Subsidiaries represented by letters of credit for the account of the Company or
such Restricted Subsidiary, as the case may be, in order to provide security for
workers' compensation claims, payment obligations in connection with
self-insurance or similar requirements in the ordinary course of business;
(h) Refinancing Indebtedness;
(i) Capitalized Lease Obligations of the Company outstanding on
the Issue Date;
(j) Capitalized Lease Obligations and Purchase Money Indebtedness
of the Company or any of its Restricted Subsidiaries not to exceed $5,000,000 at
any one time outstanding;
(k) Permitted Operating Obligations;
(l) Obligations arising in connection with Crude Oil and Natural
Gas Hedge Agreements of the Company or a Restricted Subsidiary;
(m) Non-Recourse Indebtedness;
(n) Indebtedness under Currency Agreements; provided, however,
that in the case of Currency Agreements which relate to Indebtedness, such
Currency Agreements do not increase the Indebtedness of the Company and its
Restricted Subsidiaries outstanding other than as a result of fluctuations in
foreign currency exchange rates or by reason of fees, indemnities and
compensation payable thereunder;
(o) additional Indebtedness of the Company or any of its
Restricted Subsidiaries in an aggregate principal amount at any time outstanding
not to exceed the greater of (i) $10.0 million or (ii) 5.0% of Adjusted
Consolidated Net Tangible Assets of the Company; and
(p) Indebtedness outstanding on the Issue Date.
"Permitted Industry Investments" means (i) capital expenditures,
including, without limitation, acquisitions of Company Properties and interests
therein; (ii) (a) entry into operating agreements, joint ventures, working
interests, royalty interests, mineral leases, unitization agreements, pooling
arrangements or other similar or customary agreements, transactions, properties,
interests or arrangements, and Investments and expenditures in connection
therewith or pursuant thereto, in each case made or entered into in the ordinary
course of the oil and gas business, and (b) exchanges of Company Properties for
other Company Properties of at least equivalent value as determined in good
faith by the Board of Directors of the Company; (iii) Investments of operating
funds on behalf of co-owners of Crude Oil and Natural Gas Properties of the
Company or the Subsidiaries pursuant to joint operating agreements.
"Permitted Investments" means (a) Investments by the Company or
any Restricted Subsidiary in any Person that is or will become immediately after
such Investment a Restricted Subsidiary or that will merge or consolidate into
the Company or a Restricted Subsidiary that is not subject to any Payment
Restriction, (b) Investments in the Company by any Restricted Subsidiary;
provided, however, that any Indebtedness evidencing any such Investment held by
a Restricted Subsidiary that is not a Subsidiary Guarantor is unsecured and
subordinated, pursuant to a written agreement, to the Company's obligations
under the Notes and the Indenture; (c) investments in cash and Cash Equivalents;
(d) Investments made by the Company or its Restricted Subsidiaries as a result
of consideration received in connection with an Asset Sale made in compliance
with "-- Certain Covenants -- Limitation on Asset Sales" above; and (e)
Permitted Industry Investments.
"Permitted Liens" means each of the following types of Liens:
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(a) Liens existing as of the Issue Date to the extent and in the
manner such Liens are in effect on the Issue Date (and any extensions,
replacements or renewals thereof covering property or assets secured by such
Liens on the Issue Date);
(b) Liens securing Indebtedness outstanding under the New Credit
Facility and Liens arising under the Indenture;
(c) Liens securing the Notes and the Guarantees;
(d) Liens of the Company or a Restricted Subsidiary on assets of
any Restricted Subsidiary;
(e) Liens securing Refinancing Indebtedness which is incurred to
Refinance any Indebtedness which has been secured by a Lien permitted under the
Indenture and which has been incurred in accordance with the provisions of the
Indenture; provided, however, that such Liens (x) are no less favorable to the
Holders and are not more favorable to the lienholders with respect to such Liens
than the Liens in respect of the Indebtedness being Refinanced and (y) do not
extend to or cover any property or assets of the Company or any of its
Restricted Subsidiaries not securing the Indebtedness so Refinanced;
(f) Liens for taxes, assessments or governmental charges or
claims either (i) not delinquent or (ii) contested in good faith by appropriate
proceedings and as to which the Company or a Restricted Subsidiary, as the case
may be, shall have set aside on its books such reserves as may be required
pursuant to GAAP;
(g) statutory and contractual Liens of landlords to secure rent
arising in the ordinary course of business to the extent such Liens relate only
to the tangible property of the lessee which is located on such property and
Liens of carriers, warehousemen, mechanics, suppliers, materialmen, repairmen
and other Liens imposed by law incurred in the ordinary course of business for
sums not yet delinquent or being contested in good faith, if such reserve or
other appropriate provision, if any, as shall be required by GAAP shall have
been made in respect thereof;
(h) Liens incurred or deposits made in the ordinary course of
business (i) in connection with workers' compensation, unemployment insurance
and other types of social security, including any Lien securing letters of
credit issued in the ordinary course of business consistent with past practice
in connection therewith, or (ii) to secure the performance of tenders, statutory
obligations, surety and appeal bonds, bids, leases, government contracts,
performance and return-of-money bonds and other similar obligations (exclusive
of obligations for the payment of borrowed money);
(i) judgment and attachment Liens not giving rise to an Event of
Default;
(j) easements, rights-of-way, zoning restrictions, restrictive
covenants, minor imperfections in title and other similar charges or
encumbrances in respect of real property not interfering in any material respect
with the ordinary conduct of the business of the Company or any of its
Restricted Subsidiaries;
(k) any interest or title of a lessor under any Capitalized Lease
Obligation; provided that such Liens do not extend to any property or assets
which is not leased property subject to such Capitalized Lease Obligation;
(l) Liens securing Purchase Money Indebtedness of the Company or
any Restricted Subsidiary; provided, however, that (i) the Purchase Money
Indebtedness shall not be secured by any property or assets of the Company or
any Restricted Subsidiary other than the property and assets so acquired or
constructed and (ii) the Lien securing such Indebtedness shall be created within
90 days of such acquisition or construction;
(m) Liens securing reimbursement obligations with respect to
commercial letters of credit which encumber documents and other property
relating to such letters of credit and products and proceeds thereof;
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(n) Liens encumbering deposits made to secure obligations arising
from statutory, regulatory, contractual, or warranty requirements of the Company
or any of its Restricted Subsidiaries, including rights of offset and set-off;
(o) Liens securing Interest Swap Obligations which Interest Swap
Obligations relate to Indebtedness that is otherwise permitted under the
Indenture and Liens securing Crude Oil and Natural Gas Hedge Agreements;
(p) Liens securing Acquired Indebtedness incurred in accordance
with "-- Certain Covenants -- Limitation on Incurrence of Additional
Indebtedness" above; provided, however, that (i) such Liens secured such
Acquired Indebtedness at the time of and prior to the incurrence of such
Acquired Indebtedness by the Company or a Restricted Subsidiary and were not
granted in connection with, or in anticipation of, the incurrence of such
Acquired Indebtedness by the Company or a Restricted Subsidiary and (ii) such
Liens do not extend to or cover any property or assets of the Company or of any
of its Restricted Subsidiaries other than the property or assets that secured
the Acquired Indebtedness prior to the time such Indebtedness became Acquired
Indebtedness of the Company or a Restricted Subsidiary and are no more favorable
to the lienholders than those securing the Acquired Indebtedness prior to the
incurrence of such Acquired Indebtedness by the Company or a Restricted
Subsidiary;
(q) Liens on, or related to, properties and assets of the Company
and its Subsidiaries to secure all or a part of the costs incurred in the
ordinary course of business of exploration, drilling, development, production,
processing, transportation, marketing or storage, or operation thereof;
(r) Liens on pipeline or pipeline facilities, Hydrocarbons or
properties and assets of the Company and its Subsidiaries which arise out of
operation of law;
(s) royalties, overriding royalties, revenue interests, net
revenue interests, net profit interests, revisionary interests, production
payments, production sales contracts, operating agreements and other similar
interests, properties, arrangements and agreements, all as ordinarily exist with
respect to Properties and assets of the Company and its Subsidiaries or
otherwise as are customary in the oil and gas business;
(t) with respect to any Properties and assets of the Company and
its Subsidiaries, Liens arising under, or in connection with, or related to,
farm-out, farm-in, joint operation, area of mutual interest agreements and/or
other similar or customary arrangements, agreements or interests that the
Company or any Subsidiary determines in good faith to be necessary for the
economic development of such Property;
(u) any (a) interest or title of a lessor or sublessor under any
lease, (b) restriction or encumbrance that the interest or title of such lessor
or sublessor may be subject to (including, without limitation, ground leases or
other prior leases of the demised premises, mortgages, mechanics' liens, tax
liens, and easements), or (c) subordination of the interest of the lessee or
sublessee under such lease to any restrictions or encumbrance referred to in the
preceding clause (b);
(v) Liens in favor of collecting or payor banks having a right of
setoff, revocation, refund or chargeback with respect to money or instruments of
the Company or any Restricted Subsidiary on deposit with or in possession of
such bank; and
(w) Liens securing Non-recourse Indebtedness.
"Permitted Operating Obligations" means Indebtedness of the
Company or any Restricted Subsidiary in respect of one or more standby letters
of credit, bid, performance or surety bonds, or other reimbursement obligations,
issued for the account of, or entered into by, the Company or any Restricted
Subsidiary in the ordinary course of business (excluding obligations related to
the purchase by the Company or any Restricted Subsidiary of Hydrocarbons for
which the Company or such Restricted Subsidiary has contracts to sell), or in
lieu of any thereof or in addition to any thereto, guarantees and letters of
credit supporting any such obligations and Indebtedness (in each case, other
than for an obligation for borrowed money, other than borrowed money represented
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by any such letter of credit, bid, performance or surety bond, or reimbursement
obligation itself, or any guarantee and letter of credit related thereto).
"Person" means an individual, partnership, corporation,
unincorporated organization, limited liability company, trust, estate, or joint
venture, or a governmental agency or political subdivision thereof.
"Preferred Stock" of any Person means any Capital Stock of such
Person that has preferential rights to any other Capital Stock of such Person
with respect to dividends or redemptions or upon liquidation.
"Property" means, with respect to any Person, any interests of
such Person in any kind of property or asset, whether real, personal or mixed,
or tangible or intangible, including, without limitation, Capital Stock,
partnership interests and other equity or ownership interests in any other
Person.
"Purchase Money Indebtedness" means Indebtedness the net proceeds
of which are used to finance the cost (including the cost of construction) of
property or assets acquired in the normal course of business by the Person
incurring such Indebtedness.
"Qualified Capital Stock" means any Capital Stock that is not
Disqualified Capital Stock.
"Reference Date" has the meaning set forth under "-- Certain
Covenants -- Limitation on Restricted Payments."
"Refinance" means, in respect of any security or Indebtedness, to
refinance, extend, renew, refund, repay, prepay, redeem, defease or retire, or
to issue a security or Indebtedness in exchange or replacement for, such
security or Indebtedness in whole or in part. "Refinanced" and "Refinancing"
shall have correlative meanings.
"Refinancing Indebtedness" means any Refinancing by the Company
or any Restricted Subsidiary of the Company of Indebtedness incurred in
accordance with "-- Certain Covenants -- Limitation on Incurrence of Additional
Indebtedness" above (other than pursuant to clause (b), (c), (d), (e), (f), (g),
(j), (k), (l), (n) or (o) of the definition of Permitted Indebtedness), in each
case that does not (i) result in an increase in the aggregate principal amount
of Indebtedness of such Person as of the date of such proposed Refinancing (plus
the amount of any premium required to be paid under the terms of the instrument
governing such Indebtedness and plus the amount of reasonable expenses incurred
by the Company and its Restricted Subsidiaries in connection with such
Refinancing) or (ii) create Indebtedness with (x) a Weighted Average Life to
Maturity that is less than the Weighted Average Life to Maturity of the
Indebtedness being Refinanced or (y) a final maturity earlier than the final
maturity of the Indebtedness being Refinanced; provided, however, that (1) if
such Indebtedness being Refinanced is Indebtedness of the Company or a
Subsidiary Guarantor, then such Refinancing Indebtedness shall be Indebtedness
solely of the Company and/or such Subsidiary Guarantor and (2) if such
Indebtedness being Refinanced is subordinate or junior to the Notes or a
Guarantee, then such Refinancing Indebtedness shall be subordinate to the Notes
or such Guarantee, as the case may be, at least to the same extent and in the
same manner as the Indebtedness being Refinanced.
"Registration Rights Agreement" means the Registration Rights
Agreement dated as of the Issue Date among the Company, the Subsidiary
Guarantors and the Initial Purchasers.
"Related Person" of any Person means any other Person directly or
indirectly owning 10% or more of the outstanding voting Common Stock of such
Person (or, in the case of a Person that is not a corporation, 10% or more of
the equity interest in such Person).
"Replacement Assets" has the meaning set forth under "-- Certain
Covenants -- Limitation on Asset Sales."
"Restricted Payment" has the meaning set forth under "-- Certain
Covenants -- Limitation on Restricted Payments."
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"Restricted Subsidiary" means any Subsidiary of the Company
(including, without limitation, Canadian Abraxas) that has not been designated
by the Board of Directors of the Company, by a Board Resolution delivered to the
Trustee, as an Unrestricted Subsidiary pursuant to and in compliance with "--
Certain Covenants -- Limitation on Restricted and Unrestricted Subsidiaries"
above. Any such designation may be revoked by a Board Resolution of the Company
delivered to the Trustee, subject to the provisions of such covenant.
"Sale and Leaseback Transaction" means any direct or indirect
arrangement with any Person or to which any such Person is a party, providing
for the leasing to the Company or a Restricted Subsidiary of any property,
whether owned by the Company or any Restricted Subsidiary at the Issue Date or
later acquired which has been or is to be sold or transferred by the Company or
such Restricted Subsidiary to such Person or to any other Person from whom funds
have been or are to be advanced by such Person on the security of such property.
"Subsidiary", with respect to any Person, means (a) any
corporation of which the outstanding Capital Stock having at least a majority of
the votes entitled to be cast in the election of directors under ordinary
circumstances shall at the time be owned, directly or indirectly, by such Person
or (b) any other Person of which at least a majority of the voting interests
under ordinary circumstances is at the time, directly or indirectly, owned by
such Person.
"Subsidiary Guarantor" means each of the Company's Restricted
Subsidiaries that in the future executes a supplemental indenture in which such
Restricted Subsidiary agrees to be bound by the terms of the Indenture as a
Subsidiary Guarantor; provided, however, that any Person constituting a
Subsidiary Guarantor as described above shall cease to constitute a Subsidiary
Guarantor when its Guarantee is released in accordance with the terms of the
Indenture.
"Surviving Entity" has the meaning set forth under "-- Certain
Covenants -- Merger, Consolidation and Sale of Assets."
"Unrestricted Subsidiary" means any Subsidiary of the Company
designated as such pursuant to and in compliance with "-- Certain Covenants --
Limitation on Restricted and Unrestricted Subsidiaries" above; provided,
however, that Unrestricted Subsidiaries shall initially include Cascade Oil &
Gas Ltd., an Alberta, Canada corporation, Grey Wolf Exploration, Ltd., an
Alberta corporation, and Western Associated Energy Corporation, a Texas
corporation. Any such designation may be revoked by a Board Resolution of the
Company delivered to the Trustee, subject to the provisions of such covenant.
"Weighted Average Life to Maturity" means, when applied to any
Indebtedness at any date, the number of years obtained by dividing (a) the then
outstanding aggregate principal amount of such Indebtedness into (b) the sum of
the total of the products obtained by multiplying (i) the amount of each then
remaining installment, sinking fund, serial maturity or other required payment
of principal, including payment at final maturity, in respect thereof, by (ii)
the number of years (calculated to the nearest one-twelfth) which will elapse
between such date and the making of such payment.
"Wholly Owned Restricted Subsidiary" means any Restricted
Subsidiary of which all the outstanding voting securities normally entitled to
vote in the election of directors are owned by the Company or another Wholly
Owned Restricted Subsidiary.
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DESCRIPTION OF CAPITAL STOCK
Common Stock
Abraxas
Abraxas is authorized to issue 50,000,000 shares of Common Stock,
par value $.01 per share. At January 20, 1997, there were 5,804,812 shares of
Common Stock issued and outstanding. Holders of the Common Stock are entitled to
cast one vote for each share held of record on all matters submitted to a vote
of stockholders and are not entitled to cumulate votes for the election of
directors. Holders of Common Stock do not have preemptive rights to subscribe
for additional shares of Common Stock issued by Abraxas.
Holders of the Common Stock are entitled to receive dividends as
may be declared by the Board of Directors out of funds legally available
therefor, subject to the rights of the holders of Abraxas' Series 1995-B
Preferred Stock and any subsequently issued classes or series of Abraxas'
Preferred Stock. No dividend may be declared or paid on the Common Stock and no
Common Stock may be purchased by Abraxas, unless all accrued and unpaid
dividends on the outstanding Series 1995-B Preferred Stock for all past or
current dividend periods, if any, have been paid, except for a purchase of
shares of the Common Stock by Abraxas pursuant to Rule 13e-4(h)(5) of the
Exchange Act. In addition, under the terms of the New Credit Facility , Abraxas
may not pay dividends on shares of the Common Stock. In the event of
liquidation, holders of the Common Stock are entitled to share pro rata in any
distribution of Abraxas' assets remaining after payment of liabilities, subject
to the preferences and rights of the holders of the Series 1995-B Preferred
Stock. All of the outstanding shares of the Common Stock are fully paid and
nonassessable.
References herein to Abraxas' Common Stock include the common
share purchase rights distributed by Abraxas to its stockholders on November 17,
1994 as long as they trade with the Common Stock. See "-- Stockholder Rights
Plan".
Canadian Abraxas
Canadian Abraxas is authorized to issue an unlimited number
shares of Common Stock, without par value. At December 20, 1996, there was one
(1) share of Common Stock issued and outstanding which was held by Abraxas.
Holders of the Common Stock are entitled to cast one vote for each share held of
record on all matters submitted to a vote of stockholders and are not entitled
to cumulate votes for the election of directors. Holders of Common Stock do not
have preemptive rights to subscribe for additional shares of Common Stock issued
by Canadian Abraxas.
Holders of the Common Stock are entitled to receive dividends as
may be declared by the Board of Directors out of funds legally available
therefor, subject to the rights of the holders of the class or series of
Canadian Abraxas' preferred stock. Under the terms of the New Credit Facility ,
Canadian Abraxas may not pay dividends on shares of the Common Stock. In the
event of liquidation, holders of the Common Stock are entitled to share pro rata
in any distribution of Canadian Abraxas' assets remaining after payment of
liabilities, subject to the preferences and rights of the holders of any shares
of preferred stock. All of the outstanding shares of the Common Stock are fully
paid and nonassessable.
Preferred Stock
Abraxas
General. Abraxas' Articles of Incorporation authorize the
issuance of up to 1,000,000 shares of Preferred Stock, par value $.01 per share,
in one or more series. The Board of Directors is authorized, without any further
action by the stockholders, to determine the dividend rights, dividend rate,
conversion rights, voting rights, rights and terms of redemption, liquidation
preferences, sinking fund terms and other rights, preferences, privileges and
restrictions of any series of Preferred Stock, the number of shares constituting
any such series, and the designation thereof. The rights of the holders of
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Common Stock will be subject to, and may be adversely affected by, the rights of
holders of any Preferred Stock that may be issued in the future.
Description of Series 1995-B Preferred Stock. Abraxas is
authorized to issue 1,000,000 shares of Preferred Stock, of which 45,741 shares
have been designated as the Series 1995-B Preferred Stock. The holders of the
Series 1995-B Preferred Stock have the full right and power to vote with the
holders of the Common Stock on all matters on which the stockholders of the
Common Stock are entitled to vote. Holders of the Series 1995-B Preferred Stock
are entitled to 11.11 votes for each share of the Series 1995-B Preferred Stock
and are not entitled to cumulate votes in the election of directors. Holders of
the Series 1995-B Preferred Stock do not have preemptive rights to subscribe for
or to purchase any additional shares of the Series 1995-B Preferred Stock. All
or any shares of the Series 1995-B Preferred Stock may be redeemed at the option
of Abraxas at any time after January 1, 1997 at $100 per share plus the amount
of accrued and unpaid dividends. If Abraxas redeems, repurchases, exchanges any
security or property for, or otherwise acquires for consideration any shares of
Common Stock (other than an acquisition pursuant to Rule 13e-4(h)(5) promulgated
under the Exchange Act) at a price equal to or greater than $100 divided by the
number of shares of Common Stock into which one share of the Series 1995-B
Preferred Stock is then convertible, any holder of shares of Series 1995-B
Preferred Stock may require Abraxas to redeem a number of shares of such
holder's Series 1995-B Preferred Stock equal to the product of (i) the
percentage of the shares of the Common Stock so redeemed or otherwise acquired
times (ii) the total number of shares of the Series 1995-B Preferred Stock held
by such holder at a price per share equal to the product of (x) the number of
shares of Common Stock that such holder's shares of Series 1995-B Preferred
Stock is then convertible times (y) the per share price paid for a share of
Common Stock by Abraxas plus all accrued and unpaid dividends. Each share of
Series 1995-B Preferred Stock may be converted, subject to adjustment, into
11.11 shares of the Common Stock.
Shares of the Series 1995-B Preferred Stock are entitled to a
cumulative dividend of $8.00 per share per annum payable on a quarterly basis,
when and if declared by the Board of Directors. In the event of the dissolution,
liquidation or winding up of Abraxas, the holders of the Series 1995-B Preferred
Stock shall be entitled to receive an amount of money equal to the redemption
price per share plus all accrued and unpaid dividends thereon in cash or in any
assets of Abraxas remaining after the debts of Abraxas have been paid in full
and before any payment is made or assets set aside for payment to the holders of
the Common Stock. All outstanding shares of the Series 1995-B Preferred Stock
are fully paid and nonassessable.
Canadian Abraxas
Canadian Abraxas' Articles of Incorporation authorize the
issuance of an unlimited number of First Preferred Shares, without par value.
The Board of Directors is authorized, without any further action by the
stockholders, to determine the dividend rights, dividend rate, conversion
rights, voting rights, rights and terms of redemption, liquidation preferences,
sinking fund terms and other rights, preferences, privileges and restrictions of
the First Preferred Shares. The rights of the holders of Canadian Abraxas'
Common Stock will be subject to, and may be adversely affected by, the rights of
holders of the First Preferred Shares that may be issued in the future.
Contingent Value Rights
General. The CVRs were issued under the CVR Agreement (the "CVR
Agreement") between Abraxas and First Union. The definitions of certain
capitalized terms used in the following summary are set forth below under "--
Certain Definitions."
Issuance of Shares at Extended Maturity Date. The CVR Agreement
provides that, subject to adjustment as described under "Antidilution" below,
Abraxas shall issue to each holder of the CVRs (each such person, a "CVR
Holder") on the Extended Maturity Date (as defined below), for each CVR held by
such CVR Holder, Abraxas shall issue a number of shares of Common Stock, if any,
equal to (a) the Target Price (as defined below) minus the Current Market Value
divided by (b) the Current Market Value; provided, however, in no event shall
more than 1.5 shares of Common Stock be issued in exchange for each CVR at the
Extended Maturity Date. Such determination by Abraxas absent manifest error
shall be final and binding on Abraxas and the CVR Holder.
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Determination that No Shares are Issuable With Respect to the
CVRs. If the Current Market Value of a share of the Common Stock equals or
exceeds $12.50 on the Extended Maturity Date, no shares of the Common Stock will
be issuable with respect to the CVRs. In addition, the CVRs will terminate if
the Per Share Market Value (as defined below) equals or exceeds the Target Price
for any period of 30 consecutive Trading Days during the period from and after
November 17, 1996 to and including November 17, 1997.
In the event that Abraxas determines that no shares of the Common
Stock are issuable with respect to the CVRs to the CVR Holders, Abraxas shall
give to the CVR Holders notice of such determination. Upon making such
determination and absent manifest error, the CVRs shall terminate and become
null and void and the CVR Holders shall have no further rights with respect
thereto. The failure to give such notice or any defect therein shall not affect
the validity of such determination.
Antidilution. In the event Abraxas shall in any manner subdivide
(by stock split, stock dividend or otherwise) or combine (by reverse stock split
or otherwise) the number of outstanding shares of the Common Stock, Abraxas
shall similarly subdivide or combine the CVRs and shall approximately adjust the
Target Price. Whenever such an adjustment is made, Abraxas shall (i) promptly
prepare a certificate setting forth such adjustment and a brief statement of the
facts accounting for such adjustment, (ii) promptly file with First Union a copy
of such certificate and (iii) mail a brief summary thereof to each CVR Holder.
First Union shall be fully protected in relying on any such certificate and on
any adjustment therein contained. Such adjustment absent manifest error shall be
final and binding on Abraxas and the CVR Holders. Each outstanding CVR
Certificate shall thenceforth represent that number of adjusted CVRs necessary
to reflect such subdivision or combination and reflect the adjusted Target
Price.
Consolidation, Merger and Sale of Assets. The CVR Agreement
provides that Abraxas may, without the consent of the holders of any of the
outstanding CVRs, consolidate with or merge into any other entity or convey,
transfer or lease its properties and assets substantially as an entirety to any
entity, provided that (i) the Surviving Person (as defined below) assumes
Abraxas' obligations under the CVRs and the CVR Agreement and (ii) Abraxas
delivers to First Union an officer's certificate regarding compliance with the
foregoing. For the purposes hereof, "convey, transfer or lease its properties
and assets substantially as an entirety" shall mean properties and assets
contributing in the aggregate of at least 80% of Abraxas' total revenues as
reported in Abraxas' last available periodic financial report (quarterly or
annual, as the case may be) filed with the Commission.
In the event that Abraxas were merged out of existence,
liquidated or subject to some other event resulting in the lack of any market
for the Common Stock (each, a "Transaction"), the holders of the CVRs would be
entitled to receive securities of the Surviving Person or such other
consideration that holders of shares of the Common Stock received in such a
Transaction on the basis described herein. In the event of a Transaction in
which the consideration received by the stockholders of Abraxas were shares of
capital stock or other securities of the Surviving Person, the CVRs would mature
on the Extended Maturity Date, the Target Price would be adjusted by dividing
the Target Price by the Conversion Ratio (as defined below) and the holders of
the CVRs would receive on the Extended Maturity Date a number of shares of the
capital stock or other securities of the Surviving Person equal to (a) the
Adjusted Target Price (as defined below) minus the Adjusted Current Market Value
(as defined below) divided by (b) the Adjusted Current Market Value; provided,
however, in no event shall the Surviving Person (a) be required to issue a
number of shares of its capital stock or other securities greater than 1.5 times
the Conversion Ratio at the Extended Maturity Date and (b) issue shares of its
capital stock or other securities which are not publicly traded to the holders
of the CVRs for any CVRs held by them. In the event that the shares of capital
stock or other securities of the Surviving Person to be issued in a Transaction
are not publicly traded, the consideration to be received by the holders of the
CVRs for any CVRs held by them shall be cash calculated in the manner described
in the following sentence. In the event of a Transaction in which the holders of
Abraxas' Common Stock received cash, the holders of the CVRs would receive cash
in an amount equal to the Adjusted Target Price minus the cash received by the
stockholders of Abraxas for one share of the Common Stock on the effective date
of such a Transaction; provided, however that the holders of the CVRs would not
receive greater than $7.50 per CVR in cash from and after November 17, 1996 to
and including the Extended Maturity Date.
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Certain Definitions.
"Adjusted Current Market Value" per share means, with respect to
the Extended Maturity Date, the median of the averages of the closing bid prices
of the shares of capital stock or other securities of the Surviving Person
received by the holders of Common Stock in a Transaction on the principal stock
exchange on which such shares of capital stock or other securities are traded
during each 20 consecutive Trading Day period that both begins and ends in the
Valuation Period.
"Adjusted Target Price" means the Target Price divided by the
Conversion Ratio.
"Authorized Newspaper" means The Wall Street Journal, or if The
Wall Street Journal shall cease to be published, or, if the publication or
general circulation of The Wall Street Journal shall be suspended for whatever
reason, such other English language newspaper as is selected by Abraxas with
general circulation in The City of New York, New York.
"Conversion Ratio" means the number of shares of capital stock or
other securities of the Surviving Person received by the holder of one (1) share
of the Common Stock.
"Current Market Value" means with respect to the Extended
Maturity Date, the median of the averages of the closing bid prices on the
NASDAQ Stock Market (or, if the Common Stock is listed on a securities exchange,
on such exchange) of shares of the Common Stock during each 20 consecutive
trading day period that both begins and ends in the Valuation Period.
"Extended Maturity Date" means November 17, 1997.
"Person" means any individual, corporation, partnership, joint
venture, association, joint-stock company, trust, unincorporated organization or
government or any agency or political subdivision thereof.
"Per Share Market Value" means on any particular date (a) the
closing bid price per share of the Common Stock on such date on the principal
stock exchange on which the Common Stock has been listed or, if there is no such
price on such date, then the average of such prices on such exchange on the date
nearest preceding such date, or (b) if the Common Stock is not listed on any
stock exchange, the average of the high and low sales prices for a share of
Common Stock in the over-the-counter market, as reported by the NASDAQ Stock
Market for such date, or, if there are no such prices on such date, then the
average of such prices on the date nearest preceding such date, or (c) if the
Common Stock is not quoted on the NASDAQ Stock Market, the average of the final
bid and final asked prices for a share of Common Stock in the over-the-counter
market as reported by the National Quotation Bureau Incorporated (or any similar
organization or agency succeeding to its functions of reporting prices), or (d)
if the Common Stock is no longer publicly traded, as determined by a nationally
recognized or major regional investment banking firm or firm of independent
certified public accountants of recognized standing (which may be the firm that
regularly examines the financial statements of Abraxas) selected in good faith
by the Board of Directors of Abraxas.
"Surviving Person" means any other Person into which Abraxas
shall consolidate with or merge into or the Person which acquires by conveyance
or transfer or which leases, the properties and assets of Abraxas substantially
as an entirety.
"Target Price" means $12.50. Upon each occurrence of an event
specified under "Antidilution" above, such amount, as it may have been
previously adjusted, shall be adjusted as described under "Antidilution" above.
"Trading Day" means (a) a day on which the Common Stock is traded
on the principal stock exchange on which the Common Stock has been listed, or
(b) if the Common Stock is not listed on any stock exchange, a day on which the
Common Stock is traded in the over-the-counter market, as reported by the NASDAQ
Stock Market, or (c) if the Common Stock is not traded on the NASDAQ Stock
Market, a day on which the Common Stock is traded in the over-the-counter market
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as reported by the National Quotation Bureau Incorporated (or any similar
organization or agency succeeding to its functions of reporting prices).
"Valuation Period" means the 60 Trading Day period immediately
preceding (and including) the Maturity Date or the Extended Maturity Date.
Warrants
Abraxas has warrants ("Warrants") outstanding to purchase an
aggregate of 437,500 shares of Common Stock. Associated Energy Managers, Inc.
("AEM"), has Warrants to purchase 13,500 shares at an exercise price of $7.00
per share. First Union has Warrants to purchase 424,000 shares of Common Stock
at an exercise price of $9.79 per share. These Warrants were issued to First
Union in connection with Abraxas' credit agreement. First Union and AEM have
certain registration rights with respect to shares of the Common Stock issued
pursuant to the exercise of such Warrants. See " -- Registration Rights."
All outstanding Warrants contain provisions that protect AEM and
First Union against dilution by adjusting the price at which the Warrants are
exercisable and the number of shares of the Common Stock issuable upon exercise
thereof upon the occurrence of certain events, including payment of stock
dividends and distributions, stock splits, recapitalizations, reclassifications,
mergers, consolidations or the issuance or sale of Common Stock or options,
rights or securities convertible into shares of the Common Stock, in the case of
AEM, at less than the current market price or, in the case of First Union, at a
price less than the greater of the current market price or the exercise price. A
holder of Warrants has no rights as a stockholder of Abraxas until the Warrants
are exercised. All Warrants are currently exercisable, although none have been
exercised as of the date hereof.
Registration Rights
The shares of the Common Stock to be received by AEM and First
Union upon exercise of Warrants and any shares of the Common Stock owned by
Endowment Energy Partners, L.P. ("EEP") and Endowment Energy Partners II,
Limited Partnership ("EEP II") are entitled to certain rights with respect to
the registration of such shares under the Securities Act.
Under the terms of the Registration Rights Agreement with EEP and
EEP II, in the event that Abraxas proposes to register any shares of the Common
Stock or securities convertible into Common Stock under the Securities Act for
its own account, except in certain circumstances, EEP and EEP II are entitled to
unlimited Piggyback Registrations, subject to the right of the underwriters of
any such offering to limit the number of shares included in such registration.
Abraxas has agreed to pay all expenses in connection with a Piggyback
Registration except for underwriting discounts and selling commissions which
shall be borne by EEP and/or EEP II with respect to shares of the Common Stock
owned by EEP and EEP II other than the 211,500 shares of Common Stock acquired
by EEP and EEP II through the exercise of the Warrants formerly owned by EEP and
EEP II ("Warrant Shares"). EEP and EEP II have the additional right to require
Abraxas to effect one Demand Registration of all shares of the Common Stock
(other than Warrant Shares) in the aggregate at any time and Abraxas is required
to effect such registration, subject to certain conditions and limitations.
Abraxas is required to bear the expenses of a Demand Registration except for
underwriting discounts and selling commissions which shall be borne by EEP
and/or EEP II with respect to shares of Common Stock owned by EEP and EEP II
other than Warrant Shares. Abraxas has agreed to customary indemnities including
an agreement to indemnify, subject to certain limited exceptions, EEP and EEP II
in connection with a Demand Registration and a Piggyback Registration.
Under the terms of its Warrants, AEM has the right to unlimited
Piggyback Registrations. EEP and EEP II have the right to one Demand
Registration in the aggregate at any time after December 20, 1995 and unlimited
Piggyback Registrations with respect to Warrant Shares. Abraxas has agreed to
pay all expenses in connection with Piggyback Registrations by AEM and by EEP
and EEP II with respect to Warrant Shares and to share expenses equally with EEP
and EEP II with respect to Warrant Shares registered in a Demand Registration;
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provided, however, all underwriting discounts and selling commissions shall be
borne by EEP, EEP II or AEM, as the case may be.
Under the terms of its Warrants, First Union has the right to two
Demand Registrations and, subject to the rights to Piggyback Registration of
EEP, EEP II and AEM, unlimited Piggyback Registrations. Abraxas will pay all
expenses incurred in connection with any such registration other than
underwriting discounts and selling commissions which shall be borne by First
Union. Abraxas has also agreed to customary indemnities, including an agreement
to indemnify, subject to certain limitations, First Union in connection with a
Demand Registration and a Piggyback Registration.
Anti-takeover Effects of Certain Provisions of the Articles of
Incorporation and Bylaws
Abraxas' Articles of Incorporation and Bylaws provide for the
Board of Directors to be divided into three classes of directors serving
staggered three-year terms. As a result, approximately one-third of the Board of
Directors will be elected each year. The Articles of Incorporation and Bylaws
provide that the Board of Directors will consist of not less than three nor more
than twelve members, with the exact number to be determined from time to time by
the affirmative vote of a majority of directors then in office. The Board of
Directors, and not the stockholders, has the authority to determine the number
of directors, and could prevent any stockholder from obtaining majority
representation on Abraxas' Board of Directors by enlarging the Board of
Directors and by filling the new directorships with the stockholder's own
nominees. In addition, directors may be removed by the stockholders only for
cause.
The Articles of Incorporation and Bylaws provide that special
meetings of stockholders of Abraxas may be called only by the Chairman of the
Board, the President or a majority of the members of the Board of Directors.
This provision may make it more difficult for stockholders to take actions
opposed by the Board of Directors.
The Articles of Incorporation and Bylaws provide that any action
required to be taken or which may be taken by holders of Common Stock must be
effected at a duly called annual or special meeting of such holders, and may not
be taken by any written consent of such stockholders. These provisions may have
the effect of delaying consideration of a stockholder proposal until the next
annual meeting unless a special meeting is called by the persons set forth
above. The provisions of the Articles of Incorporation and Bylaws prohibiting
stockholder action by written consent could prevent the holders of a majority of
the voting power of Abraxas from using the written consent procedure to take
stockholder action and taking action by consent without giving all the
stockholders of Abraxas entitled to vote on a proposed action the opportunity to
participate in determining such proposed action.
Stockholder Rights Plan
On November 17, 1994, the Board of Directors of Abraxas adopted a
stockholder rights plan (the "Rights Plan"). Under the terms of the Rights Plan,
the Board of Directors of Abraxas declared a dividend of one common share
purchase right ("Right") on each share of the Common Stock outstanding on
November 17, 1994. Each Right entitles the holder thereof to buy one-half of one
share of Common Stock at an exercise price of $40 per share ($20 per half
share), subject to adjustment.
The Rights are not exercisable until the occurrence of specified
events. Upon the occurrence of such an event (which events are generally those
which would signify the commencement of a hostile bid to acquire Abraxas), the
Rights then become exercisable (unless redeemed by the Board of Directors) for a
number of shares of Common Stock having a market value of four times the
exercise price of the Right. If the acquiror were to conclude the acquisition of
Abraxas, the Rights would then become exercisable for shares of the
controlling/surviving corporation having a value of four times the exercise
price of the Rights. If the Rights were exercised at any time, significant
dilution would result, thus making the acquisition prohibitively expensive for
the acquiror. In order to encourage a bidder to negotiate with the Board of
Directors, the Rights Plan provides that the Rights may be redeemed under
prescribed circumstances by the Board of Directors.
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The Rights are not intended to prevent a takeover of Abraxas and
will not interfere with any tender offer or business combination approved by the
Board of Directors. The Rights Plan is intended to protect the stockholders in
the event of (a) an unsolicited offer to acquire Abraxas, including offers that
do not treat all stockholders equally, (b) the acquisition in the open market of
shares constituting control of Abraxas without offering fair value to all
stockholders and (c) other coercive takeover tactics which could impair the
Board's ability to fully represent the interests of the stockholders.
Anti-takeover Statutes
The Nevada GCL contains two provisions, described below as
"Combination Provisions" and the "Control Share Act," that may make more
difficult the accomplishment of unsolicited or hostile attempts to acquire
control of a corporation through certain types of transactions.
Restrictions on Certain Combinations Between Nevada Resident
Corporations and Interested Stockholders
The Nevada GCL includes certain provisions (the "Combination
Provisions") prohibiting certain "combinations" (generally defined to include
certain mergers, disposition of assets transactions, and share issuance or
transfer transactions) between a resident domestic corporation and an
"interested stockholder" (generally defined to be the beneficial owner of 10% or
more of the voting power of the outstanding shares of the corporation), except
those combinations which are approved by the board of directors before the
interested stockholder first obtained a 10% interest in the corporation's stock.
There are additional exceptions to the prohibition, which apply to combinations
if they occur more than three years after the interested stockholder's date of
acquiring shares. The Combination Provisions apply unless the corporation elects
against their application in its original articles of incorporation or an
amendment thereto, or in its bylaws. Abraxas' Articles of Incorporation and
Bylaws do not currently contain a provision rendering the Combination Provisions
inapplicable.
Nevada Control Share Act
Nevada's Control Share Acquisition Act (the "Control Share Act")
imposes procedural hurdles on and curtails greenmail practices of corporate
raiders. The Control Share Act temporarily disenfranchises the voting power of
"control shares" of a person or group ("Acquiring Person") purchasing a
"controlling interest" in an "issuing corporation" (as defined in the Nevada
GCL) not opting out of the Control Share Act. In this regard, the Control Share
Act will apply to an "issuing corporation" unless, before an acquisition is
made, the articles of incorporation or bylaws in effect on the tenth day
following the acquisition of a controlling interest provide that it is
inapplicable. Abraxas' Articles of Incorporation and Bylaws do not currently
contain a provision rendering the Control Share Act inapplicable.
Under the Control Share Act, an "issuing corporation" is a
corporation organized in Nevada which has 200 or more stockholders, at least 100
of whom are stockholders of record (which for this purpose includes registered
and beneficial owners) and residents of Nevada, and which does business in
Nevada directly or through an affiliated company. The status of Abraxas at the
time of the occurrence of a transaction governed by the Control Share Act
(assuming that Abraxas' Articles of Incorporation or Bylaws have not theretofore
been amended to include an opting out provision) would determine whether the
Control Share Act is applicable.
The Control Share Act requires an Acquiring Person to take
certain procedural steps before he or it can obtain the full voting power of the
control shares. "Control shares" are the shares of a corporation (1) acquired or
offered to be acquired which will enable the Acquiring Person to own a
"controlling interest," and (2) acquired within 90 days immediately preceding
that date. A "controlling interest" is defined as the ownership of shares which
would enable the Acquiring Person to exercise certain graduated amounts
(beginning with one-fifth) of all voting power of the corporation. The Acquiring
Person may not vote any control shares without first obtaining approval from the
stockholders not characterized as "interested stockholders" (as defined below).
To obtain voting rights in control shares, the Acquiring Person
must file a statement at the principal office of the issuer ("Offeror's
Statement") setting forth certain information about the acquisition or intended
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acquisition of stock. The Offeror's Statement may also request a special meeting
of stockholders to determine the voting rights to be accorded to the Acquiring
Person. A special stockholders' meeting must then be held at the Acquiring
Person's expense within 30 to 50 days after the Offeror's Statement is filed. If
a special meeting is not requested by the Acquiring Person, the matter will be
addressed at the next regular or special meeting of stockholders.
At the special or annual meeting at which the issue of voting
rights of control shares will be addressed, "interested stockholders" may not
vote on the question of granting voting rights to control the corporation or its
parent unless the articles of incorporation of the issuing corporation provide
otherwise. Abraxas' Articles of Incorporation do not currently contain a
provision allowing for such voting power.
If full voting power is granted to the Acquiring Person by the
disinterested stockholders, and the Acquiring Person has acquired control shares
with a majority or more of the voting power, then (unless otherwise provided in
the articles of incorporation or bylaws in effect on the tenth day following the
acquisition of a controlling interest) all stockholders of record, other than
the Acquiring Person, who have not voted in favor of authorizing voting rights
for the control shares, must be sent a notice advising them of the fact and of
their right to receive "fair value" for their shares. Abraxas' Articles of
Incorporation and Bylaws do not provide otherwise. Within 20 days of the mailing
of the notice, any such stockholder may demand to receive from the corporation
the "fair value" for all or part of his shares. "Fair value" is defined in the
Control Share Act as "not less than the highest price per share paid by the
Acquiring Person in an acquisition."
The Control Share Act permits a corporation to redeem the control
shares in the following two instances, if so provided in the articles of
incorporation or bylaws of the corporation in effect on the tenth day following
the acquisition of a controlling interest: (1) if the Acquiring Person fails to
deliver the Offeror's Statement to the corporation within 10 days after the
Acquiring Person's acquisition of the control shares; or (2) an Offeror's
Statement is delivered, but the control shares are not accorded full voting
rights by the stockholders. Abraxas' Articles of Incorporation and Bylaws do not
address this matter.
CERTAIN UNITED STATES AND CANADIAN INCOME TAX CONSIDERATIONS
The discussion below is intended to be a general description of
the material United States and Canadian tax consequences of the Exchange Offer
to holders of the Notes. In addition, the discussion describes, in general, the
material United States and Canadian tax consequences associated with the
acquisition, ownership and disposition of the Notes. It does not take into
account the individual circumstances of any particular investor and does not
purport to discuss all of the possible tax consequences of the Exchange Offer or
the ownership or disposition of the Notes and is not intended as tax advice. The
summary below is general in nature and does not discuss all aspects of United
States and Canadian income taxation that may be relevant to a particular
investor in the light of the investor's particular circumstances.
Certain U.S. Federal Income Tax Considerations
The following is a summary of certain United States federal
income tax consequences related to the Exchange Offer and the associated with
the acquisition, ownership, and disposition of the Notes. The following summary
does not discuss all of the aspects of federal income taxation that may be
relevant to a prospective holder of the Notes in light of his or her particular
circumstances, or to certain types of holders which are subject to special
treatment under the federal income tax laws (including persons who hold the
Notes as part of a conversion, straddle or hedge, dealers in securities,
insurance companies, tax-exempt organizations, financial institutions,
broker-dealers and S corporations). Further, this summary pertains only to
holders that are citizens or residents of the United States, corporations,
partnerships or other entities created in or under the laws of the United States
or any political subdivision thereof, or estates or trusts the income of which
is subject to United States federal income taxation regardless of its source. In
addition, this summary does not describe any tax consequences under state,
local, or foreign tax laws.
This summary is based upon the Internal Revenue Code of 1986, as
amended (the "Code"), Treasury Regulations (the "Regulations"), rulings and
pronouncements issued by the Internal Revenue Service ("IRS") and judicial
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decisions now in effect, all of which are subject to change at any time by
legislative, judicial or administrative action. Any such changes may be applied
retroactively in a manner that could adversely affect the holders of the Notes.
The Issuers have not sought and will not seek any rulings from the IRS or
opinions from counsel with respect to the matters discussed below except for the
opinion of both U.S. and Canadian counsel with respect to the federal income tax
consequences of the Exchange Offer delivered to the Issuers. There can be no
assurance that the IRS will not take positions concerning the tax consequences
of the Exchange Offer or the valuation, purchase, ownership or disposition of
the Notes which are different from those discussed herein.
Tax Consequences of the Exchange Offer
An exchange of the Series A Notes for the Exchange Notes pursuant
to the Exchange Offer should not be treated as a significant modification of the
Series A Notes; accordingly, an Exchange Note should be treated as a
continuation of the corresponding Series A Note and an exchanging holder should
not recognize any gain or loss as a result of participating in the Exchange
Offer. In addition, an exchanging Holder's basis in an Exchange Note should be
equal to the basis of the corresponding Series A Note and the holding period for
an Exchange Note would include such holder's holding period for the
corresponding Series A Note.
The Exchange Offer will not have any federal income tax
consequences to a non-exchanging holder.
Each exchanging holder should consult with his or her individual
tax advisor concerning any foreign, state or local tax consequences of the
Exchange Offer as well as to the effect of his or her particular facts and
circumstances on the matters discussed herein.
Taxation of Accrued Stated Interest on Notes
Accrued stated interest paid on a Note will generally be taxable
to a holder as ordinary interest income at the time it accrues or is received,
in accordance with the holder's regular method of accounting for federal income
tax purposes.
The Company will annually furnish to certain record holders of
the Notes and the IRS information with respect to any stated interest accruing
during the calendar year as may be required under applicable Regulations.
Market Discount
If a holder purchases a Note, other than in connection with the
Offering or the Exchange Offering, for less than the stated redemption price of
the Note at maturity, the difference is considered "market discount," unless
such difference is "de minimis," i.e., less than one-fourth of one percent of
the stated redemption price of the Note at maturity multiplied by the number of
complete years to maturity (after the holder acquires the Note). Under market
discount rules, any gain realized by the holder on a taxable disposition of a
Note having "market discount," as well as any partial principal payment made
with respect to such a Note, will be treated as ordinary income to the extent of
the then "accrued market discount" of the Note. The rules concerning the
calculation of "accrued market discount" are set forth in the paragraph
immediately below. In addition, a holder of such a Note may be required to defer
the deduction of all or a portion of the interest expense on any indebtedness
incurred to purchase or carry a Note having "market discount."
Any market discount will accrue ratably from the date of
acquisition to the maturity date of the Note, unless the holder elects,
irrevocably, to accrue market discount on a constant interest rate method. The
constant interest rate method generally accrues interest at times and in amounts
equivalent to the result which would have occurred had the market discount been
original issue discount computed from the date of the holder's acquisition of
the Note through the maturity date. The election to accrue market discount on a
constant interest rate method is irrevocable but may be made separately as to
each Note held by the holder.
Accrual of market discount will not cause the accrued amounts to
be included currently in a holder's taxable income, in the absence of a
disposition of, or principal payment on, the Note. Nevertheless, a holder may
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elect to currently include market discount in income as it accrues on either a
ratable or constant interest rate method. In such event, interest expense
relating to the acquisition of a Note which would otherwise be deferred would be
currently deductible to the extent otherwise permitted by the Code. The election
to include market discount in income currently, once made, applies to all market
discount obligations acquired by such holder on or after the first day of the
first taxable year to which the election applies and all subsequent years unless
revoked with the consent of the IRS.
Accrued market discount which is included in a holder's gross income will
increase the adjusted tax basis of the Note in the hands of the holder.
Acquisition Premium
If a subsequent holder acquires a Note for an amount which is
greater than the stated redemption price of the Note at maturity, such holder
will be considered to have purchased such Note with "amortizable bond premium"
equal to the amount of such excess. The holder may elect to amortize the premium
using a constant yield method employing six month compounding over the period
from the acquisition date to the maturity date of the Note. Amortized amounts
may be offset only against interest paid with respect to the Note and will
reduce the holder's adjusted tax basis in the Note to the extent so used. Once
made, an election to amortize and offset interest on the Note may be revoked
only with the consent of the IRS and will apply to all Notes held by the holder
on the first day of the taxable year to which the election relates and to
subsequent taxable years and to all Notes subsequently acquired by the holder.
Sale, Exchange or Other Taxable Disposition of the Notes
The sale, redemption or other taxable disposition of a Note will
result in the recognition of gain or loss to the holder in an amount equal to
the difference between (i) the amount of cash and fair market value of property
received (except to the extent attributable to the payment of accrued stated
interest) in exchange therefore and (ii) the holder's adjusted tax basis in such
Note. A holder's initial tax basis in a Note purchased by such holder will be
equal to the issue price of the Note.
Any gain or loss on the sale, redemption or other taxable
disposition of a Note will be capital gain or loss, except to the extent of any
"accrued market discount," assuming a purchaser of the Note holds such security
as a "capital asset" (generally property held for investment) within the meaning
of Section 1221 of the Code. Any capital gain or loss will be long-term capital
gain or loss if the Note is held for more than one year and otherwise will be
short-term capital gain or loss. Payments on such disposition for accrued stated
interest not previously included in income will be treated as ordinary interest
income.
Purchase or Redemption of Notes
Effect of Change of Control and Asset Sale. Upon a Change of
Control, the Issuers are required to offer to redeem all outstanding Notes for a
price equal to 101% of the principal amount thereof plus accrued and unpaid
stated interest. See "Description of the Notes -- Redemption -- Optional
Redemption." Under the Regulations, such a Change of Control redemption
requirement will not affect the yield or maturity date of the Notes unless,
based on all the facts and circumstances as of the issue date, it is more likely
than not that a Change of Control giving rise to the redemption will occur. Upon
certain asset sales, the Issuers will be obligated to offer to repurchase the
Notes at one hundred percent (100%) of the principal amount thereof plus accrued
and unpaid interest to the date of redemption. The Issuers will not treat the
Change of Control or the asset sale redemption provisions of the Notes as
affecting the calculation of the yield to maturity of any Note.
Optional Redemption. The Issuers, at their option, may redeem
part or all of the Notes at any time on or after November 1, 2000, at the
redemption prices set forth herein. In addition, if the Issuers consummate an
Equity Offering on or before November 1, 1999, the Issuers may, at their option,
use all or a portion of the proceeds from such Equity Offering to redeem up to
thirty-five percent (35%) of the aggregate principal amount of the Notes
originally issued in the Offering at a redemption price equal to 111.5%,
together with accrued and unpaid interest to the date of redemption; provided,
however, that, after giving effect to any such redemption, at least $139.75
million aggregate principal amount of the Notes remains outstanding. See
"Description of the Notes -- Redemption -- Optional Redemption." For purposes of
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determining whether the Notes are issued with any "original issue discount," the
Regulations generally provide that an issuer will be treated as exercising any
such option if its exercise would lower the yield of the debt instrument. A
redemption of Notes at the optional redemption prices, however, would increase
rather than decrease the effective yield of the debt instrument as calculated
from the issue date.
The Issuers do not currently intend to exercise any of the
options described above with respect to the Notes. Should the Issuers exercise
an option and redeem a Note, the holder of the Note would be required to treat
any amount paid by the Issuers which exceeds the Note's then principal balance
and all accrued and unpaid interest thereon as an amount received in exchange
for the Note.
Backup Withholding
The backup withholding rules require a payor to deduct and
withhold a tax if (i) the payee fails to properly furnish a taxpayer
identification number ("TIN") to the payor, (ii) the IRS notifies the payor that
the TIN furnished by the payee is incorrect, (iii) the payee has failed to
report properly the receipt of "reportable payments" and the IRS has notified
the payor that withholding is required, or (iv) there has been a failure of the
payee to certify under a penalty of perjury that a payee is not subject to
withholding under Section 3406 of the Code. As a result, if any one of the
events discussed above occurs with respect to a holder of Notes, the Company,
its paying agent or other withholding agent will be required to withhold a tax
equal to 31% of any "reportable payment" made in connection with the Notes to
such holder. A "reportable payment" includes, among other things, amounts paid
in respect of interest or original issue discount and amounts paid through
brokers in retirement of securities. Any amounts withheld from a payment to a
holder under the backup withholding rules will be allowed as a refund or credit
against such holder's federal income tax, provided, that the required
information is furnished to the IRS. Certain holders (including, among others,
corporations and certain tax-exempt organizations) are not subject to the backup
withholding rules.
Certain Canadian Federal Income Tax Considerations
The following is a general summary of the Canadian federal and
certain provincial income tax consequences to a holder of the Notes or Exchange
Notes who is not a resident of Canada, who does not use or hold, and is not
deemed to use or hold, the Notes or Exchange Notes in the course of carrying on
business in Canada and is a person who, throughout the period during which the
Notes or Exchange Notes are held deals at arm's length with Canadian Abraxas and
is not deemed to deal otherwise than at arm's length with Canadian Abraxas. This
summary has been prepared by reference to the Income Tax Act (Canada) (the
"Canadian Act"), the Income Tax Regulations (the "Canadian Regulations"), with
reference to all published proposals for the amendment of the Canadian Act and
the Canadian Regulations.
Receipt or Deemed Receipt of Interest
The terms of the Notes are such that interest paid or deemed to
have been paid (for example, where Notes are redeemed at a premium to their
issue price) on the Notes to a non-resident person with which Canadian Abraxas
deals at arm's length is exempt from taxation under the Canadian Act.
Consequently, provided the aforementioned conditions are met, holders of the
Notes will on disposition thereof not be subject to Canadian taxation in respect
of the receipt or deemed receipt of interest thereon.
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Dispositions of the Notes and Tax Consequences of the Exchange Offer
The Canadian Act does not impose a tax in respect of gains
recognized upon disposition of Notes held by non-resident persons who do not use
or hold the Exchange Notes or the Notes in the course of carrying on a business
in Canada. Consequently, provided that the aforementioned conditions are met,
any gain recognized by a holder of the Notes or the Exchange Notes on a sale,
redemption or other disposition (including any disposition under the Exchange
Offer) will not be subject to taxation under the Canadian Act. Any amount paid
upon a disposition of the Notes or the Exchange Notes which represents accrued
and unpaid interest will generally be treated as a deemed receipt of interest.
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TRANSACTIONS WITH RELATED PARTIES
Messrs. Watson, Phelps and Riggs were founders of Grey Wolf and
in April 1995 purchased 900,000 shares of the capital stock of Grey Wolf
(initially representing 39% of the outstanding shares) for an aggregate of
CDN$90,000 (or CDN$0.10 per share) in cash. In January 1996, the Company
purchased 20,325,096 shares of the capital stock of Grey Wolf (representing 78%
of the outstanding shares) for an aggregate of approximately CDN$4.1 million (or
CDN$.20 per share) in cash. Messrs. Bruton, Engle, Phelps, Riggs and Watson
currently own 13.8% of the issued and outstanding capital stock of Grey Wolf. In
addition, Mr. Watson owns options to purchase up to 450,000 shares of Grey
Wolf's capital stock at an exercise price of CDN$.10 per share.
Messrs. Bruton, Engle, Phelps and Riggs own options to purchase
in the aggregate up to 2,600,000 shares of capital stock of Cascade at an
exercise price of CDN$.20 per share, and Mr. Watson owns options to purchase up
to 800,000 shares of Cascade's capital stock at an exercise price of CDN$.34 per
share. Cascade currently has 61,365,000 shares of capital stock outstanding.
Wind River Resources Corporation ("Wind River"), all of the
capital stock of which is owned by Mr. Watson, owns a twin-engine airplane. The
airplane is available for business use by employees of the Company from time to
time at $385 per hour. The Company paid Wind River a total of $80,678 for use of
the plane during 1995.
Mr. Watson and members of his family previously had an
outstanding loan of $328,259, including accrued interest, to Abraxas as of
December 31, 1994. Abraxas made principal and interest payments of $354,677 on
the note during 1995 which represented payment of all principal and interest due
and owing on the note.
Abraxas has adopted a policy that transactions, including loans,
between Abraxas and its officers, directors, principal stockholders, or
affiliates of any of them, will be on terms no less favorable to Abraxas than
can be obtained on an arm's length basis in transactions with third parties and
must be approved by the vote of at least a majority of the disinterested
directors.
BOOK-ENTRY; DELIVERY AND FORM
The Certificates representing the Exchange Notes will be issued
in fully registered form, without coupons and will be deposited with, or on
behalf of, the Depositary, and registered in the name of Cede & Co., as the
Depository's nominee in the form of a global Exchange Note certificate (the
"Global Certificate") or will remain in the custody of the Trustee.
Except as set forth below, the Global Certificate may be
transferred, in whole and not in part, only by the Depositary to its nominee to
such Depositary or another nominee of the Depositary or by the Depositary or its
nominee to a successor of the Depositary or a nominee of such successor.
The Issuers understand that the Depositary is a limited-purpose
trust company which was created to hold securities for its participating
organizations (the "Participants") and to facilitate the clearance and
settlement of transactions in such securities between Participants through
electronic book-entry changes in accounts of its Participants. Participants
include securities brokers and dealers (including the Initial Purchasers),
banks, trust companies, clearing corporations and certain other organizations.
Access to the Depository's book-entry system is also available to others, such
as banks, brokers, dealers and trust companies that clear through or maintain a
custodial relationship with a Participant, either directly or indirectly
("indirect participants"). Persons who are not participants may beneficially own
securities held by the Depositary through Participants or indirect participants.
Pursuant to procedures established by the Depositary (i) upon
deposit of the Global Certificate, the Depositary will credit the accounts of
Participants with portions of the principal amount of the Global Certificate and
(ii) ownership of the Exchange Notes will be shown on, and the transfer of
ownership thereof will be effected only through, records maintained by the
Depositary (with respect to the interest on the Depository's participants), the
Depository's Participants and the Depository's indirect participants.
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The laws of some jurisdictions require that certain persons take
physical delivery in definitive form of securities that they own. Consequently,
the ability to transfer interests in the Global Certificate will be limited to
such extent.
So long as the nominee of the Depositary is the registered owner
of the Global Certificate, such nominee will be considered the sole owner or
holder of the Exchange Notes for all purposes under the Indenture. Except as
provided below, the owners of interests in the Global Certificate will not be
entitled to have Exchange Notes registered in their names, will not receive or
be entitled to receive physical delivery of Exchange Notes in definitive form
and will not be considered the owners or holders thereof under the Indenture. As
a result, the ability of a person having a beneficial interest in Exchange Notes
represented by the Global Certificate to pledge such interest to persons or
entities that do not participate in the Depository's system or to otherwise take
actions in respect to such interest may be affected by the lack of a physical
certificate evidencing such interest.
Neither the Issuers, the Trustee nor any paying agent will have
any responsibility or liability for any aspect of the records relating to or
payments made on account of interests in the Global Certificate or for
maintaining, supervising or reviewing any records relating to such interests.
Principal and interest payments on the Global Certificate
registered in the name of the Depository's nominee will be made by the Issuers
or through a paying agent to the Depository's nominee as the registered owner of
the Global Certificate. Under the terms of the Indenture, the Issuers and the
Trustee will treat the persons in whose names the Exchange Notes are registered
as the owners of such Exchange Notes for the purpose of receiving payments of
principal and interest on such Exchange Notes and for all other purposes
whatsoever. Therefore, neither the Issuers, the Trustee nor any paying agent has
any direct responsibility or liability for the payment of principal or interest
on the Exchange Notes to owners of interests in the Global Certificate. The
Depositary has advised the Issuers and the Trustee that its present practice is,
upon receipt of any payment of principal or interest, to credit immediately the
account of the Participants with payments in amounts proportionate to their
respective holdings in principal amount of interests in the Global Certificate
as shown on the records of the Depositary. Payments by Participants and indirect
participants to owners of interests in the Global Certificate will be governed
by standing instructions and customary practices, as is now the case with
securities held for the accounts of customers in bearer form or registered in
"street name," and will be the responsibility of such participants or indirect
participants.
If the Depositary is at any time unwilling or unable to continue
as depositary and a successor depositary is not appointed by the Issuers within
90 calendar days, the Issuers will issue Exchange Notes in certificated form in
exchange for the Global Certificate. In addition, the Issuers may at any time
determine not to have the Exchange Notes represented by a Global Certificate,
and, in such event, will issue Exchange Notes in certificated form in exchange
for the Global Certificate. In either instance, an owner of an interest in the
Global Certificate would be entitled to physical delivery of such Exchange Notes
in certificated form. Exchange Notes so issued in certificated form will be
issued in denominations of $1,000 and integral multiples thereof and will be
issued in registered form only.
Neither the Issuers nor the Trustee shall be liable for any delay
by the Depositary or its nominee in identifying the beneficial owners or the
related Exchange Notes, and each such person may conclusively rely on, and shall
be protected in relying on, instructions from the Depositary or its nominee for
all purposes (including with respect to the registration and delivery, and the
respective principal amounts, of the Exchange Notes to be issued).
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AVAILABLE INFORMATION
The Issuers have filed with the Commission a Registration
Statement on Form S-4 (the "Exchange Offer Registration Statement", which term
shall encompass all amendments, exhibits, annexes and schedules thereto)
pursuant to the Securities Act and the rules and regulations promulgated
thereunder, covering the Exchange Notes being offered hereby. This Prospectus
does not contain all the information set forth in the Exchange Offer
Registration Statement. For further information with respect to the Issuers and
the Exchange Offer, reference is made to the Exchange Offer Registration
Statement. Statements made in this Prospectus as to the contents of any
contract, agreement or other document referred to are not necessarily complete.
With respect to each such contract, agreement or other document filed as an
exhibit to the Exchange Offer Registration Statement, reference is made to the
exhibit for a more complete description of the document or matter involved, and
each such statement shall be deemed qualified in its entirety by such reference.
The Exchange Offer Registration Statement, including the exhibits thereto, can
be inspected and copied at the public reference facilities maintained by the
Commission at Room 1024, 450 Fifth Street, N.W., Washington, D.C. 20549, and at
the Regional Offices of the Commission at 7 World Trade Center, New York, New
York 10048 and at Northwestern Atrium Center, 500 West Madison Street, Suite
1400, Chicago, Illinois 60661. Copies of such materials can be obtained from the
Public Reference Section of the Commission at 450 Fifth Street, N.W.,
Washington, D.C. 20549, at prescribed rates.
The Company is subject to the informational reporting
requirements of the Securities Exchange Act of 1934, as amended (the "Exchange
Act"), and in accordance therewith files reports, proxy and information
statements and other information with the Commission. Such material filed by the
Company with the Commission may be inspected by anyone without charge at the
Public Reference Section of the Commission at Room 1024, Judiciary Plaza, 450
Fifth Street, N.W., Washington, D.C. 20549, and at the regional offices of the
Commission located at Northwestern Atrium Center, 500 West Madison Street, Suite
1400, Chicago, Illinois 60661 and 7 World Trade Center, Suite 1300, New York,
New York 10048. Copies of such material may also be obtained at the Public
Reference Section of the Commission at Room 1024, Judiciary Plaza, 450 Fifth
Street, N.W., Washington, D.C. 20549, upon payment of prescribed fees. The
Common Stock of the Company is quoted on The Nasdaq National Market under the
symbol "AXAS" and such reports, proxy and information statements and other
information concerning the Company are available at the offices of The Nasdaq
National Market located at 1735 K Street, N.W., Washington, D.C. 20006.
In the event that the Company ceases to be subject to the
informational reporting requirements of the Exchange Act, the Issuers have
agreed that, so long as the Series A Notes or the Exchange Notes remain
outstanding, they will file with the Commission and distribute to holders of the
Series A Notes or the Exchange Notes, as applicable, copies of the financial
information that would have been contained in annual reports and quarterly
reports, including management's discussion and analysis of financial condition
and results of operations, that the Company would have been required to file
with the Commission pursuant to the Exchange Act. Such financial information
shall include annual reports containing consolidated financial statements and
notes thereto, together with an opinion thereon expressed by an independent
public accounting firm, as well as quarterly reports containing unaudited
condensed consolidated financial statements for the first three quarters of each
fiscal year. The Company will also make such reports available to prospective
purchasers of the Series A Notes or the Exchange Notes, as applicable,
securities analysts and broker-dealers upon their request. In addition, the
Issuers have agreed that for so long as any of the Series A Notes remain
outstanding they will make available to any prospective purchaser of the Series
A Notes or beneficial owner of the Series A Notes in connection with any sale
thereof the information required by Rule 144A(d)(4) under the Securities Act,
until such time as the Issuers have either exchanged the Series A Notes for
securities identical in all material respects which have been registered under
the Securities Act or until such time as the holders thereof have disposed of
such Series A Notes pursuant to an effective registration statement filed by the
Issuers.
ENFORCEABILITY OF CIVIL LIABILITIES AGAINST FOREIGN PERSONS
Canadian Abraxas is a Canadian corporation, certain of its
officers and directors may be residents of various jurisdictions outside the
United States and its Canadian counsel, Burnet, Duckworth & Palmer, are
residents of Canada. All or a substantial portion of the assets of Canadian
Abraxas and of such persons may be located outside the United States. As a
128
<PAGE>
result, it may be difficult for investors to effect service of process within
the United States upon such persons or to enforce judgments obtained against
such persons in United States courts and predicated upon the civil liability
provisions of the Securities Act. Notwithstanding the foregoing, Canadian
Abraxas has irrevocably agreed that it may be served with process with respect
to actions based on offers and sales of securities made hereby in the United
States by serving Chris E. Williford, c/o Abraxas Petroleum Corporation, 500
North Loop 1604 East, Suite 100, San Antonio, Texas 78232, Canadian Abraxas'
United States agent appointed for that purpose. Canadian Abraxas has been
advised by its Canadian counsel, Burnet, Duckworth & Palmer, that there is doubt
as to the enforceability in Canada against Canadian Abraxas or against any of
its directors, controlling persons, officers or experts who are not residents of
the United States, in original actions for enforcement of judgments of United
States courts, of liabilities predicated solely upon United States federal
securities laws.
LEGAL MATTERS
Certain legal matters related to the Notes offered hereby are
being passed upon for the Company by Cox & Smith Incorporated, San Antonio,
Texas and for Canadian Abraxas by Burnet, Duckworth and Palmer, Barristers and
Solicitors, Calgary, Alberta.
EXPERTS
The consolidated financial statements of the Company as of
December 31, 1995 and 1994 and for each of the three years in the period ended
December 31, 1995, the statements of Combined Oil and Gas Revenues and Direct
Operating Expenses of Certain Overriding Royalty Interests in the Portilla Field
Acquired by Abraxas Petroleum Corporation for the years ended December 31, 1994
and 1995 and the balance sheet of Canadian Abraxas Petroleum Limited at
September 30, 1996 included in this Prospectus and the Registration Statement
have been audited by Ernst & Young LLP, independent auditors, as set forth in
their reports thereon appearing elsewhere herein, and are included in reliance
upon such reports given upon the authority of such firm as experts in accounting
and auditing.
The Statements of Revenues and Direct Operating Expenses of
Enserch Exploration, Inc.'s Wamsutter Area Package for the three years ended
December 31, 1995, 1994 and 1993 included in this Prospectus and the
Registration Statement, have been audited by Deloitte & Touche LLP, independent
auditors, as stated in their report appearing elsewhere herein, and are included
in reliance upon such report given upon the authority of such firm as experts in
accounting and auditing.
The financial statements of CGGS Canadian Gas Gathering Systems,
Inc. as of October 31, 1995 and 1994 and for the years ended October 31, 1995,
1994 and 1993 have been included herein and in the Registration Statement in
reliance upon the report of KPMG, Chartered Accountants, appearing elsewhere
herein, and upon the authority of said firm as experts in accounting and
auditing.
The historical reserve information prepared by DeGolyer and
MacNaughton and Sproule Associates Limited included in this Prospectus and the
Registration Statement has been included herein in reliance upon the authority
of such firms as experts with respect to matters contained in such reserve
reports.
129
<PAGE>
GLOSSARY OF TERMS
Unless otherwise indicated in this Prospectus, natural gas
volumes are stated at the legal pressure base of the State or area in which the
reserves are located at 60 degrees Fahrenheit. Natural gas equivalents are
determined using the ratio of six Mcf of natural gas to one barrel of crude oil,
condensate or NGLs.
The following definitions shall apply to the technical terms used
in this Prospectus.
"Bbl" means barrel or barrels.
"Bblpd" means barrels per day.
"Bcf" means billion cubic feet.
"BOE" means barrel of crude oil equivalent.
"DD&A" means depletion, depreciation and amortization.
"Developed acreage" means acreage which consists of acres spaced
or assignable to productive wells.
"Development well" means 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) known to be productive for the purpose of extraction of
proved crude oil or natural gas reserves.
"Dry hole" means an exploratory or development well found to be
incapable of producing either crude oil or gas in sufficient quantities to
justify completion as a crude oil or natural gas well.
"EBITDA" means earnings from continuing operations before income
taxes, interest expense, DD&A and other non-cash charges.
"EBITDA Margin" means EBITDA divided by total operating revenue.
"Exploratory well" means 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.
"Finding cost", expressed in dollars per BOE, is calculated by
dividing the amount of total exploration and development capital expenditures
(excluding any amortization with respect to deferred financing fees) by the
amount of proved reserves added during the same period (including the effect on
proved reserves of reserve revisions).
"G&A" means general and administrative.
"Gross" natural gas and crude oil wells or "gross" wells or acres
is the number of wells or acres in which the Company has an interest.
"LOE" means lease operating expenses and production taxes.
"MBbl" means thousand barrels.
"MBOE" means thousand barrels of crude oil equivalent.
"Mcf" means thousand cubic feet.
130
<PAGE>
"Mcfpd" means thousand cubic feet per day.
"MMBbls" means million barrels of crude oil.
"MMBOE" means million barrels of crude oil equivalent.
"MMBTU" means million British Thermal Units.
"MMcf" means million cubic feet.
"MMcfpd" means million cubic feet per day.
"Net" natural gas and crude oil wells or "net" acres are
determined by multiplying "gross" wells or acres by the Company's working
interest in such wells or acres.
"NGL" means natural gas liquid.
"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.
"Production costs" means lease operating expenses and taxes on
natural gas and crude oil production.
"Productive wells" mean producing wells and wells capable of
production.
"Proved developed reserves" includes only those proved reserves
expected to be recovered from existing completion intervals in existing wells
and those reserves that exist behind the casing of existing wells when the cost
of making such reserves available for production is relatively small compared to
the cost of a new well.
"Proved reserves" or "reserves" means natural gas and crude oil,
condensate and NGLs on a net revenue interest basis, found to be commercially
recoverable.
"Proved undeveloped reserves" includes those proved reserves
expected to be recovered from new wells on undrilled acreage or from existing
wells where a relatively major expenditure is required for recompletion.
"Service Well" is a well used for water injection in secondary
recovery projects or for the disposal of produced water.
"Undeveloped acreage" means 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 whether or not
such acreage contains proved reserves.
131
<PAGE>
INDEX TO FINANCIAL STATEMENTS
Page
Abraxas Petroleum Corporation and Subsidiaries
Report of Independent Auditors F-2
Consolidated Balance Sheets at December 31, 1994 and 1995
and September 30, 1996 (Unaudited) F-3
Consolidated Statements of Operations for the years
ended December 31, 1993, 1994, and 1995 and for the nine
months ended September 30, 1995 and 1996(Unaudited) F-5
Consolidated Statements of Shareholders' Equity for the years
ended December 31, 1993, 1994, and 1995 and for the nine months
ended September 30, 1996 (Unaudited) F-7
Consolidated Statements of Cash Flows for the years ended
December 31, 1993, 1994, and 1995 and for the nine months
ended September 30, 1995 and 1996(Unaudited) F-9
Notes to Consolidated Financial Statements F-12
Supplemental Information Relating to Oil and Gas
Producing Companies F-34
CGGS Canadian Gas Gathering Systems Inc.
Auditors' Report to the Directors F-38
Balance Sheets at October 31, 1994 and 1995
and October 31, 1996 (Unaudited) F-39
Statements of Earnings (Loss) and Deficit for the years
ended October 31, 1993, 1994, and 1995 and for the year
ended October 31, 1996 (Unaudited) F-40
Statements of Changes in Financial Position for the
years ended October 31, 1993, 1994, and 1995 and for the
year ended October 31, 1996 (Unaudited) F-41
Notes to Financial Statements F-42
Enserch Exploration, Inc.'s Wamsutter Area Package
Independent Auditors' Report F-49
Statements of Revenues and Direct Operating Expenses for
the years ended December 31, 1993, 1994, and 1995 and for the
nine months ended September 30, 1995 and 1996 (Unaudited) F-50
Notes to Statements of Revenues and Direct Operating Expenses F-51
Certain Overriding Royalty Interests in the Portilla Field
Acquired by Abraxas Petroleum Corporation
Report of Independent Auditors F-53
Statements of Combined Oil and Gas Revenues and Direct
Operating Expenses for the years ended December 31, 1994
and 1995 and for the nine months ended September 30, 1995
and 1996 (Unaudited) F-54
Notes to Statements of Combined Oil and Gas Revenues and
Direct Operating Expenses F-55
Canadian Abraxas Petroleum Limited
Report of Independent Auditors F-59
Balance Sheet at September 30, 1996 F-60
Note to Balance Sheet F-61
F-1
<PAGE>
Report of Independent Auditors
The Board of Directors and Shareholders
Abraxas Petroleum Corporation
We have audited the accompanying consolidated balance sheets of Abraxas
Petroleum Corporation and Subsidiaries as of December 31, 1994 and 1995, and the
related consolidated statements of operations, shareholders' equity, and cash
flows for each of the three years in the period ended December 31, 1995. 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 generally accepted auditing
standards. 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, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Abraxas
Petroleum Corporation and Subsidiaries at December 31, 1994 and 1995, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1995, in conformity with generally
accepted accounting principles.
ERNST & YOUNG LLP
San Antonio, Texas
March 19, 1996, except for paragraph 2
of Note 16, as to which the date is March 21, 1996
F-2
<PAGE>
<TABLE>
<CAPTION>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31 September 30
---------------------------
1994 1995 1996
------------- ------------- -------------
(Unaudited)
Current assets:
<S> <C> <C> <C>
Cash ............................. $ 5,297 $ 4,249,767 $ 9,992,902
Accounts receivable, less
allowance for doubtful accounts of
$44,369, $35,900, and $35,900 at
December 31, 1994 and 1995, and
September 30, 1996, respectively:
Joint owners .................. 1,260,090 1,334,873 593,481
Oil and gas production sales .. 2,206,037 2,945,681 2,748,505
Affiliates, officers, and 66,497 53,224 59,463
shareholders .................
Other ......................... 54,646 60,367 563,081
---------- --------- ----------
3,587,270 4,394,145 3,964,530
Equipment inventory .............. 51,309 80,070 142,023
Other current assets ............. 126,664 124,820 138,986
---------- --------- ----------
Total current assets .............. 3,770,540 8,848,802 14,238,441
Property and equipment:
Oil and gas properties, including
$8,000,000 excluded from the
amortization base at
September 30, 1996 and gas
processing plants, less
accumulated depreciation,
depletion, and amortization of
$24,338,518, $29,651,521, and
$37,601,185 at December 31, 1994
and 1995, and September 30,
1996, respectively .............. 70,178,563 74,475,683 111,103,581
Other property and equipment:
Land ............................ 152,536 139,466 139,466
Equipment ....................... 552,906 692,508 969,835
Leasehold improvements .......... - 37,430 129,398
Less accumulated depreciation
and amortization .............. (146,158) (266,686) (366,586)
------------ ----------- ------------
Net property and equipment ......... 70,737,847 75,078,401 111,975,694
Investments in and advances to oil
and gas partnership............... - - 2,396,992
Deferred financing fees, net of
accumulated amortization of
$75,000, $289,231, and
$850,650 at December 31, 1994 and
1995, and September 30, 1996,
respectively ..................... 381,284 353,514 970,807
Restricted cash .................... 130,000 134,419 91,160
Marketable securities .............. 326,000 326,000 -
Other assets ....................... 15,188 326,222 766,994
------------- -------------- ------------
Total assets ..................... $75,360,859 $85,067,358 $130,440,088
============= ============= =============
</TABLE>
See accompanying notes.
F-3
<PAGE>
<TABLE>
<CAPTION>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (CONTINUED)
LIABILITIES AND SHAREHOLDERS' EQUITY
December 31 September 30
---------------------------
1994 1995 1996
------------- --------------------------
(Unaudited)
Current liabilities:
<S> <C> <C> <C>
Accounts payable ................. $ 3,813,272 $ 3,928,824 $ 4,694,034
Oil and gas production payable ... 867,756 1,787,152 1,414,212
Accrued interest ................. 336,268 362,750 -
Other accrued expenses ........... 116,806 46,207 356,263
Dividends payable on preferred
stock ........................... 91,462 91,482 91,482
Liabilities related to
discontinued operations ......... 150,000 - -
----------- ----------- -------------
Total current liabilities ......... 5,375,564 6,216,415 6,555,991
Long-term debt:
Financing agreements ............. 40,906,652 41,556,651 85,000,000
Principal shareholder ............ 328,259 - -
----------- ----------- --------------
41,234,911 41,556,651 85,000,000
Other long-term obligations ........ 61,696 44,737 123,538
Deferred income taxes .............. 186,749 186,749 186,749
Minority interest in foreign
subsidiary ....................... - - 2,153,223
Commitments and contingencies
Shareholders' equity:
Preferred stock 8%, authorized
1,000,000 shares; issued and
outstanding 45,741 shares at
December 31, 1994 and 1995, and
at September 30, 1996 ........... 457 457 457
Common stock, par value $.01 per
share - authorized 50,000,000 shares;
issued and outstanding 4,461,890,
5,799,762, and 5,804,812 shares at
December 31, 1994 and 1995, and
September 30, 1996, respectively .. 44,620 57,999 58,050
Additional paid-in capital ....... 36,216,694 50,914,078 50,920,154
Unrealized holding loss on
securities ...................... (244,000) (244,000) -
Retained deficit ................. (12,089,475) (13,663,903) (14,184,400)
Treasury stock, at cost, -0- ,
2,571, and 70,711 shares at
December 31, 1994 and 1995, and
September 30, 1996, respectively - (1,825) (374,079)
Foreign currency translation
adjustment ........................ - - 405
------------ ----------- -------------
Total shareholders' equity ......... 28,501,939 37,062,806 36,420,587
------------ ----------- -------------
Total liabilities and shareholders'
equity $75,360,859 $85,067,358 $130,440,088
============ =========== =============
</TABLE>
See accompanying notes.
F-4
<PAGE>
<TABLE>
<CAPTION>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Nine Months Ended
Year Ended December 31 September 30
-------------------------------------------- ----------------------------
1993 1994 1995 1995 1996
------------ -------------- ------------- ------------ ------------
(Unaudited)
Revenue:
<S> <C> <C> <C> <C> <C>
Oil and gas production sales ......... $ 7,274,676 $ 11,114,028 $ 13,659,556 $ 9,794,667 $ 11,785,848
Rig revenues ......................... 118,081 160,605 108,400 92,250 106,000
Other ................................ 101,580 73,882 48,559 42,257 17,210
------------ ------------ ------------ ------------ ------------
7,494,337 11,348,515 13,816,515 9,929,174 11,909,058
Operating costs and expenses:
Lease operating and production
taxes ............................... 2,895,651 3,693,085 4,333,240 3,182,567 3,295,659
Depreciation, depletion, and
amortization ........................ 2,373,400 3,790,023 5,433,531 3,540,882 4,145,047
Abandoned prospects .................. 22,343 -- -- -- --
Rig operations ....................... 68,118 132,522 125,353 94,978 112,581
General and administrative .......... 509,511 810,315 1,041,740 768,575 1,250,458
Provision for losses on
accounts receivable ................. 13,000 -- -- -- --
Hedging loss ......................... -- -- -- -- 510,767
------------ ------------ ------------ ------------ ------------
5,882,023 8,425,945 10,933,864 7,587,002 9,314,512
------------ ------------ ------------ ------------ ------------
1,612,314 2,922,570 2,882,651 2,342,172 2,594,546
Other (income)expense:
Interest income ...................... (38,917) (16,411) (33,749) (8,392) (155,674)
Amortization of deferred
financing fee ...................... 649,000 400,000 214,231 120,000 192,419
Amortization ......................... 100,000 66,667 -- -- --
Interest expense ..................... 2,530,669 2,359,310 3,910,669 2,915,260 2,141,816
Loss (recovery)on marketable
securities .......................... (235,500) -- -- -- 235,197
------------ ------------ ------------ ------------ ------------
3,005,252 2,809,566 4,091,151 3,026,868 2,413,758
------------ ------------ ------------ ------------ ------------
Income (loss) from continuing
operations before taxes and
extraordinary items ................. (1,392,938) 113,004 (1,208,500) (684,696) 180,788
Deferred income tax expense ............ (186,749) -- -- -- --
Minority interest in income of
consolidated foreign subsidiary ..... -- -- -- -- 57,839
------------ ------------ ------------ ------------ ------------
Income (loss) from continuing
operations before extraordinary items (1,579,687) 113,004 (1,208,500) (684,696) 122,949
</TABLE>
F-5
<PAGE>
<TABLE>
<CAPTION>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Nine Months Ended
Year Ended December 31 September 30
-------------------------------------------- ----------------------------
1993 1994 1995 1995 1996
------------ -------------- ------------- ------------ ------------
(Unaudited)
<S> <C> <C> <C> <C> <C>
Discontinued operations:
Loss from operations of discontinued
coal properties ................. $ (279,673) $ (347,596) $ -- $ -- $ --
Loss on disposal of discontinued
coal properties .................. -- (987,543) -- -- --
------------- ------------ ------------ ----------- ------------
Loss from discontinued operations ... (279,673) (1,335,139) -- -- --
------------- ------------ ------------ ----------- ------------
Income (loss) before
extraordinary items ............... (1,859,360) (1,222,135) (1,208,500) (684,696) 122,949
Extraordinary items:
Gain from partial extinguishment
of debt ........................... 2,462,664 -- -- -- --
Debt extinguishment costs .......... (3,036,000) (1,171,832) -- -- (369,000)
------------- ------------ ------------ ----------- ------------
Net income (loss) .................... (2,432,696) (2,393,967) (1,208,500) (684,696) (246,051)
Less dividend requirement on
cumulative preferred stock ........ (186,285) (182,924) (365,928) (274,464) (274,446)
------------- ------------ ------------ ------------- ------------
Net income (loss) applicable
to common stock ................... $(2,618,981) $(2,576,891) $(1,574,428) $ (959,160) $ (520,497)
============= ============ ============ ============= ============
Income (loss) per common share:
Income (loss)from continuing operations $ (.91) $ (.02) $ (.34) $ (.21) $ (.03)
Discontinued operations (.14) (.31) - - -
Extraordinary items (.29) (.27) - - (.06)
------------- ------------- ------------ ------------- ------------
Net loss per common share $ (1.34) $ (.60) $ (.34) $ (.21) $ (.09)
============= ============= ============ ============= ============
Weighted average shares outstanding 1,947,256 4,309,878 4,635,412 4,456,462 5,804,145
============= ============ ============ ============= ============
</TABLE>
See accompanying notes.
F-6
<PAGE>
<TABLE>
<CAPTION>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
Preferred Stock Common Stock Treasury Stock
--------------------------------------------------- -----------------------
Shares Amount Shares Amount Shares Amount
-------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Balance at ................. 24,910 $ 2,491,000 1,362,600 $ 13,626 -- --
January 1, 1993
Issuance of common stock
for acquisitions
and compensation ....... -- -- 154,394 1,543 -- --
Conversion of preferred
stock and related
dividends in arrears
into common stock ........ (24,910) (2,491,000) 317,539 3,175 -- --
Issuance of
common stock ........... -- -- 2,250,000 22,500 -- --
Options
exercised .............. -- -- 1,250 13 -- --
Issuance of
common stock for debt
prepayment ............. -- -- 116,666 1,167 -- --
Net loss for the year ... -- -- -- -- -- --
------------- ---------- ------------- --------- --------- ------------
Balance at
December 31, 1993 ....... -- -- 4,202,449 42,024 -- --
Issuance of common stock
for compensation ....... -- -- 10,033 101 -- --
Issuance of preferred
stock for acquisition .. 45,741 4,574,100 -- -- -- --
Options and warrants
exercised .............. -- -- 249,408 2,495 -- --
Changes in unrealized
holding loss
on securities .......... -- -- -- -- -- --
Dividend on preferred
stock .................. -- -- -- -- -- --
Net loss for the year .... -- -- -- -- -- --
------------- ---------- ------------- --------- --------- ------------
Balance at
December 31, 1994 ........ 45,741 4,574,100 4,461,890 44,620 -- --
Issuance of common stock
for compensation ....... -- -- 7,872 79 -- --
Issuance of common stock . -- -- 1,330,000 13,300 -- --
Treasury stock
purchased, net ......... -- -- -- -- 2,571 (1,825)
Changes in preferred
stock par value ........ -- (4,573,643) -- -- -- --
Dividend on preferred
stock .................. -- -- -- -- -- --
Net loss for the year .... -- -- -- -- -- --
------------- ---------- ------------- --------- --------- ------------
Balance at
December 31, 1995 ........ 45,741 457 5,799,762 57,999 2,571 (1,825)
------------ ------------- ----------- ------- ------ -------
</TABLE>
See accompanying notes.
F-7
<PAGE>
<TABLE>
<CAPTION>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (CONTINUED)
Unrealized
Additional Holding Foreign
Paid-In Loss Retained Currency
Capital on Deficit Translation Total
Securities
------------- -------------- ------------- ------------ -------------
<S> <C> <C> <C> <C>
Balance at ................. $ 5,874,383 $ -- $ (6,145,763) $ $ 2,233,246
January 1, 1993
Issuance of
common stock for
acquisitions and
compensation ........... 964,180 -- -- -- 965,723
Conversion of preferred
stock and related
dividends in arrears
into common stock ...... (24,910) -- (934,125) -- -- --
Issuance of
common stock ........... 23,022,635 -- -- -- 23,045,135
Options exercised ....... 6,863 -- -- -- 6,876
Issuance of common stock
for debt prepayment .... 1,323,833 -- -- -- 1,325,000
Net loss for the
year ................... -- -- (2,432,696) -- (2,432,696)
------------- -------------- ------------- ------------ -------------
Balance at
December 31, 1993 ........ 34,613,844 -- (9,512,584) -- 25,143,284
Issuance of common stock
for compensation ....... 106,652 -- -- -- 106,753
Issuance of preferred
stock for acquisition .. -- -- -- -- 4,574,100
Options and warrants
exercised .............. 1,496,198 -- -- -- 1,498,693
Changes in unrealized
holding loss
on securities .......... -- (244,000) -- -- (244,000)
Dividend on preferred
stock .................. -- -- (182,924) -- (182,924)
Net loss for the year .... -- -- (2,393,967) -- (2,393,967)
------------- -------------- ------------- ------------ -------------
Balance at
December 31, 1994 ........ 36,216,694 (244,000) (12,089,475) -- 28,501,939
Issuance of common stock
for compensation ....... 73,936 -- -- -- 74,015
Issuance of
common stock ........... 10,049,805 -- -- -- 10,063,105
Treasury stock
purchased, net ......... -- -- -- -- (1,825)
Changes in preferred
stock par value ........ 4,573,643 -- -- -- --
Dividend on preferred
stock .................. -- -- (365,928) -- (365,928)
Net loss for the
year ................... -- -- (1,208,500) -- (1,208,500)
------------- -------------- ------------- ------------ -------------
Balance at
December 31, 1995 ........ 50,914,078 (244,000) (13,663,903) -- 37,062,806
</TABLE>
See accompanying notes.
F-7
<PAGE>
<TABLE>
<CAPTION>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (CONTINUED)
Preferred Stock Common Stock Treasury Stock
---------------------- ----------------------------- -----------------------
Shares Amount Shares Amount Shares Amount
---------------------- ----------------------------- -----------------------
<S> <C> <C> <C> <C> <C> <C>
Issuance of
common stock for
compensation
(Unaudited) .. -- $ -- 5,050 $ 51 -- $ --
Expenses paid related to
private placement
offering (Unaudited) .. -- -- -- -- -- --
Treasury stock purchased, net
(Unaudited) . -- -- -- -- 68,140 (372,254)
Dividend on preferred
stock (Unaudited) .. -- -- -- -- -- --
Foreign currency
translation adjustment
(Unaudited) .. -- -- -- -- -- --
Changes in unrealized
holding loss
on securities -- -- -- -- -- --
Net income
(loss) for the nine month
period (Unaudited) .. -- -- -- -- -- --
-------- ---------- ---------- ----------- --------- ---------
Balance at
September 30, 1996 (Unaudited) 45,741 $ 457 5,804,812 $ 58,050 70,711 $(374,079)
======== =========== ========== ========== ========= ==========
</TABLE>
See accompanying notes.
F-8
<PAGE>
<TABLE>
<CAPTION>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (CONTINUED)
Unrealized
Additional Holding Foreign
Paid-In Loss Retained Currency
Capital on Deficit Translation Total
Securities
------------- -------------- ------------- ------------ -------------
<S> <C> <C> <C> <C> <C>
Issuance of
common stock for
compensation (Unaudited) $ 42,829 -- -- -- $ 42,880
Expenses paid related to
private placement
offering (Unaudited) . (36,753) -- -- -- (36,753)
Treasury stock purchased,
net (Unaudited) . -- -- -- -- (372,254)
Dividend on preferred
stock (Unaudited) .. -- -- (274,446) -- (274,446)
Foreign currency
translation adjustment
(Unaudited) .. -- -- -- 405 405
Changes in unrealized
holding loss
on securities -- 244,000 -- -- 244,000
Net income (loss) for the
nine month period
(Unaudited) .. -- -- (246,051) -- (246,051)
------------- -------------- ------------- ------------ -----------
Balance at
September 30,
1996 (Unaudited) $ 50,920,154 -- (14,184,400) 405 $36,420,587
============= ============== ============= ============ ===========
</TABLE>
See accompanying notes.
F-8
<PAGE>
<TABLE>
<CAPTION>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Nine Months Ended
Year Ended December 31 September 30
----------------------------------------- --------------------------
1993 1994 1995 1995 1996
------------- ------------ -------------- ----------- ------------
(Unaudited)
Operating Activities
<S> <C> <C> <C> <C> <C>
Net income (loss) ................. $(2,432,696) $(2,393,967) $(1,208,500) $ (684,696) $ (246,051)
Adjustments to reconcile net loss to
net cash provided by operating
activities:
Minority interest in income
of foreign subsidiary ........ -- -- -- -- 57,839
Abandoned prospects ............. 22,343 -- -- -- --
Loss on disposal of discontinued
operations .................... -- 987,543 -- -- --
Depreciation, depletion, and
amortization .................. 2,373,400 3,790,023 5,433,531 3,540,882 4,145,047
Amortization of deferred
financing fees ............... 649,000 400,000 214,231 120,000 192,419
Issuance of common stock ........ -- -- -- 55,512 --
Amortization .................... 100,000 66,667 -- -- --
Provision for deferred income
taxes ......................... 186,749 -- -- -- --
(Recovery) on marketable
securities .................... (235,500) -- -- -- --
Provision for losses on
accounts receivable ........... 13,000 -- -- -- --
Net loss from debt
restructuring ................. 573,336 1,171,832 -- -- 369,000
Changes in operating assets and
liabilities:
(Increase) decrease in accounts
receivable ................... (1,898,220) (814,053) (806,875) (1,892,866) 429,615
(Increase) decrease in equipment
inventory .................... 170,030 (9,208) (28,761) (16,872) (61,953)
(Increase) decrease in other
assets ....................... 55,902 (73,912) 1,831 (127,947) (340,166)
Decrease in notes receivable ... 38,484 -- -- -- --
(Decrease)increase in
accounts payable, accrued
expenses, and dividends
payable ...................... 1,053,000 1,274,702 (78,545) 107,469 712,516
Decrease in accounts payable
to affiliates ................ (63,323) (42,839) -- -- --
Decrease in advances on
drilling in progress ......... (242,823) -- -- -- --
Increase (decrease) in oil
and gas production payable ... 301,952 (62,493) 919,396 325,992 (372,940)
------------ ----------- ----------- ---------- ----------
Net cash provided by operating
activities ....................... 664,634 4,294,295 4,446,308 1,427,474 4,885,326
</TABLE>
F-10
<PAGE>
<TABLE>
<CAPTION>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
Nine Months Ended
Year Ended December 31 September 30
------------------------------------------- ----------------------------
1993 1994 1995 1995 1996
------------- ------------ ------------- ------------- -------------
(Unaudited)
<S> <C> <C> <C> <C> <C>
Investing Activities
Development of oil and gas
properties ...................... $ (5,166,747) $ (7,150,943) $(11,398,088) $ (8,934,853) $(10,016,286)
Purchase of oil and gas
producing properties ........... (14,393,911) (28,900,000) (635,435) (153,139) (46,430,993)
Purchase of gas processing
plants and equipment ........... (3,172,430) (123,072) (83,436) (45,843) (123,532)
Proceeds from sale of oil
and gas properties and
equipment inventory ............. 767,812 69,717 2,556,491 2,724,001 16,794,137
Purchase of interest in
real estate partnership ......... -- -- (311,021) -- --
Purchase of equipment ............. (540,515) (158,268) (139,602) (89,252) (369,295)
Assets of acquired companies,
net of cash ..................... -- -- -- -- (645,001)
Investment in and advances
to oil and gas partnership .... -- -- -- -- (2,396,992)
Purchase of interest in real estate
partnership ..................... -- -- -- -- (27,810)
Minority interest related to assets
acquired of foreign subsidiary .. -- -- -- -- 2,095,384
Acquisition costs allocated to
deferred financing fees ......... (2,380,000) -- -- -- --
Purchases of unproved oil and gas
prospects, net ................. -- (4,786) -- -- --
Development of coal properties .... (46,017) -- -- -- --
(Purchase) sale of marketable
securities ...................... (300,000) -- -- -- --
Sale of common stock in
Castle Minerals ................ -- 371,000 -- -- --
------------ ------------ ------------ ------------ ------------
Net cash (used in) provided
by investing activities ........ (25,231,808) (35,896,352) (10,011,091) (6,499,086) (41,120,388)
</TABLE>
F-11
<PAGE>
<TABLE>
<CAPTION>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
Nine Months Ended
Year Ended December 31 September 30
--------------------------------------------- ------------------------------
1993 1994 1995 1995 1996
------------- ------------ ------------- ------------- -------------
(Unaudited)
<S> <C> <C> <C> <C> <C>
Financing Activities
Preferred stock dividends ......... $ -- $ (91,462) $ (365,928) $ (274,464) $ (274,464)
Issuance of common stock,
net of expenses ................ 23,052,011 1,498,693 10,063,105 -- 30,313
Purchase of treasury
stock, net ...................... -- -- (1,825) -- (372,254)
Proceeds from long-term
borrowings ...................... 20,631,793 40,906,652 5,950,000 2,750,000 90,400,000
Proceeds from short-term
borrowings ...................... -- -- -- 3,000,000 --
Payments on long-term
borrowings ...................... (17,236,327) (5,645,219) (10,552) (46,956,650)
Loan origination
fees ............................ -- (451,116) (186,461) (171,996) (970,807)
Increase in ong-term
liabilities ..................... -- -- -- -- 78,800
------------ ------------ ------------ ------------ -------------
Net cash provided by
(used in) financing
activities ...................... 26,447,477 29,203,770 9,813,672 5,292,988 41,934,938
------------ ------------ ------------ ------------ -------------
Increase (decrease) in
cash ............................ 1,880,303 (2,398,287) 4,248,889 221,376 5,699,876
Cash at beginning of
year ............................ 653,281 2,533,584 135,297 135,297 4,384,186
------------ ------------ ------------ ------------ -------------
Cash at end of year,
including restricted
cash ............................ $ 2,533,584 $ 135,297 $ 4,384,186 $ 356,673 $ 10,084,062
============ ============ ============ ============ =============
Supplemental Disclosures
Supplemental disclosures of cash
flow information:
Interest paid ................. $ 2,567,785 $ 2,150,425 $ 3,884,187 $ 2,953,296 $ 2,141,816
============ ============ ============ ============ =============
Supplemental schedule of noncash
investing and financing activities:
Accrual of preferred dividends $ -- $ -- $ -- $ 91,482 $ 91,482
============ ============ ============ ============ =============
Exchange of common stock for
acquisitions and compensation. $ 965,723 $ 106,753 $ 74,015 $ 55,512 $ 42,880
============ ============ ============ ============ =============
Exchange of treasury stock for
noncompete agreement ........ $ -- $ -- $ -- $ 70,625 $ --
============ ============ ============ ============ =============
Exchange of preferred stock in
exchange for oil and gas
producing properties ......... $ -- $ 4,574,100 $ -- $ -- $ --
============ ============ ============ ============ =============
Issuance of subsidiary
preferred stock in
extinguishment of subsidiary
debt ....................... $ 840,000 $ -- $ -- $ -- $ --
============ ============ ============ ============ =============
Conversion of preferred stock
and related dividend in
arrears into common stock ... $ 3,425,125 $ -- $ -- $ -- $ --
============ ============ ============ ============ =============
</TABLE>
See accompanying notes.
F-12
<PAGE>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1993, 1994, and 1995
(Information as to September 30, 1996 and for the Nine Months
Ended September 30, 1995 and 1996 is Unaudited)
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 and in the Permian Basin of west Texas for sale into the U.S.
energy market. The consolidated financial statements include the accounts of the
Company and its subsidiaries. All significant intercompany accounts and
transactions have been eliminated in consolidation.
The accompanying unaudited interim consolidated financial statements
include all adjustments, consisting of only normal recurring adjustments, that,
in the opinion of management, are necessary to present fairly the financial
position as of September 30, 1996 and the results of operations and cash flows
for the nine months ended September 30, 1995 and 1996. The results for the nine
months ended September 30, 1996 are not necessarily indicative of the results to
be expected for the full year. Information as of September 30, 1996 and for the
nine months ended September 30, 1995 and 1996, as well as disclosures of events
occurring after March 1996 are unaudited.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles 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.
Marketable Securities
Management determines the appropriate classification of marketable equity
and debt securities at the time of purchase and reevaluates such designation as
of each balance sheet date. Debt securities that the Company has both the
positive intent and ability to hold to maturity are carried at amortized cost.
Debt securities that the Company does not have the positive intent and ability
to hold to maturity and all marketable equity securities are classified as
available-for-sale or trading and carried at fair value. Unrealized holding
gains and losses on securities classified as available-for-sale are carried as a
separate component of shareholders' equity. Unrealized holding gains and losses
on securities classified as trading are reported in earnings.
Accounts Receivable
Substantially all accounts receivable relate to transactions relating to
crude oil and natural gas activities with customers or joint owners in the
United States. The Company does not require collateral for its receivables.
F-13
<PAGE>
Equipment Inventory
Equipment inventory consists of casing and tubing, 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 costs associated with
acquisition, exploration, and development are capitalized. The Company does not
capitalize internal costs, except for the expenses of its geologist.
Depreciation, depletion, and amortization (DD&A) of crude oil and natural gas
properties are based on the unit-of-production method. If unamortized
capitalized costs are in excess of the discounted present value of future cash
flows relating to proved reserves (ceiling), a charge to operations is recorded.
No gain or loss is recognized upon sale or disposition of crude oil and natural
gas properties, except in unusual circumstances.
Other Property and Equipment
Other property and equipment are recorded on the basis of cost.
Depreciation is provided at amounts calculated to amortize costs of the assets
over their 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.
Stock-Based Compensation
The Company grants stock options for a fixed number of shares to
employees and directors with an exercise price equal to the fair value of the
shares at the date of grant. The Company accounts for stock option grants in
accordance with APB Opinion No. 25, "Accounting for Stock Issued to Employees,"
and, accordingly, recognizes no compensation expense for the stock option
grants.
Revenue Recognition and Major Customers
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. For the years ended December 31, 1993, 1994, and 1995, the Company sold
30%, 35%, and 20%, respectively, of its total crude oil and natural gas sales to
one purchaser. Additionally, for the years ended December 31, 1993, 1994, and
1995, approximately 80%, 74%, and 64%, respectively, of the Company's total
crude oil and natural gas sales were made to five purchasers.
Deferred Financing Fees
Deferred financing fees are being amortized on a level yield basis over
the term of the related debt.
F-14
<PAGE>
Federal Income Taxes
The Company records income taxes under Financial Accounting Standards
Board Statement No. 109 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.
Net Income (Loss) Per Common Share
Net income (loss) per common share is computed by dividing net income
(loss) (adjusted for dividends on preferred stock) by the weighted average
number of shares of common stock outstanding during the period. The weighted
average number of shares includes the number of shares that would be issuable
under the Contingent Value Rights Agreement (CVR Agreement), if the current
market value of the Company's common stock at year-end is less than a specified
target price (see Note 7). Common stock equivalents, including any shares
issuable under the CVR Agreement, are not considered in the computation of
periods with a loss, as their effect is anti-dilutive.
Reclassifications
Certain balances for 1993 and 1994 have been reclassified for comparative
purposes.
2. Acquisitions and Divestitures
Texas Gulf Coast Properties Acquisition
In October 1995, the Company acquired additional working interests in
certain producing crude oil and natural gas properties in which the Company had
an existing working interest ownership. The net purchase price to Abraxas
amounted to approximately $635,000. Revenues and expenses have been included in
the consolidated financial statements since October 1, 1995.
West Texas Properties Acquisition
In July 1994, the Company acquired from various parties interests in
certain producing crude oil and natural gas properties located in West Texas
(the West Texas Properties). The net purchase price to Abraxas amounted to
approximately $28,242,000 including closing costs of approximately $383,000. The
acquisition was accounted for as a purchase and the purchase price was allocated
to crude oil and natural gas properties based on the fair values of the
properties acquired. The transaction was financed principally by additional
borrowings under the Company's credit agreement with First Union National Bank
of North Carolina (First Union), referred to in Note 6. Revenue and expenses
from the West Texas Properties have been included in the consolidated financial
statements since July 1, 1994.
F-15
<PAGE>
Overriding Royalty Interest Acquisition
In June 1994, the Company acquired from its prior secured lenders,
Endowment Energy Partners, L.P. (EEP) and Endowment Energy Co-Investment
Partnership (EECIP), 80% of the previously granted overriding royalty interests.
The net purchase price of approximately $5,174,100 consisted of $600,000 cash
and 45,741 shares of the Company's Series B 8% nonvoting cumulative convertible
preferred stock with a par value of $100 per share (Series B Preferred) at the
time of issuance. The preferred shares were recorded at $4,574,100 at the date
of the acquisition. In November 1995, the Company exchanged the Series B
Preferred for an equal number of shares of its Series 1995-B Preferred Stock,
par value $.01 per share, with a liquidation preference of $100 per share. The
preferred shares are convertible into 508,182 shares of the Company's common
stock. The acquisition was accounted for as a purchase, and the purchase price
was allocated to crude oil and natural gas properties based on the fair values
of the properties acquired. The cash portion of the transaction was financed
principally under the Company's credit agreement with First Union. Revenues and
expenses related to these properties have been included in the consolidated
financial statements since July 1, 1994.
Mobil Acquisition
In April 1993, the Company acquired from Mobil Producing Texas and New
Mexico, Inc. (Mobil) interests in certain producing crude oil and natural gas
properties and natural gas processing plants located in Texas (the Sinton
Properties). The net purchase price to Abraxas amounted to approximately
$19,600,000 ($41,000,000 gross purchase price plus closing costs of $472,000
less the sale of 50% of the Company's interest to an unrelated pension trust
fund for $21,000,000 and the reimbursement from Mobil for net production from
January 1, 1993 through the closing date). The acquisition was accounted for as
a purchase and the purchase price was allocated to crude oil and natural gas
properties, natural gas processing plants and other assets based upon an
estimate of the fair values of the properties acquired and the reimbursement
from Mobil described above. The transaction was financed principally by
additional borrowings under the Company's financing agreement with EECIP
referred to in Note 6. Under the financing agreement, the Company was required
to assign a 10% overriding royalty interest in and to the future gross revenues
to be received from the sales of crude oil and natural gas produced from the
acquired properties. Revenues and expenses from the Sinton Properties have been
included in the consolidated financial statements since April 1, 1993.
Gaelic Properties
In January 1993, the Company acquired from Gaelic Resources the remaining
75% working interest in the Alice Deep wells for $300,000 and 18,200,000 shares
of Gaelic common stock for $300,000. The purchase price of $600,000 cash was
financed through an increase in the financing agreement with EEP. Revenues and
expenses of the Gaelic Properties have been included in the consolidated
financial statements since January 1, 1993.
F-17
<PAGE>
The condensed unaudited combined pro forma financial information for the
periods presented assumes the purchases of the West Texas Properties, the
Overriding Royalty Interest, the Sinton Properties, and the Gaelic Properties
were effective as of January 1, 1993. The pro forma information does not
necessarily represent what the actual consolidated results would have been for
these periods and is not intended to be indicative of future results.
December 31
----------------------------------
1993 1994
----------------- ----------------
(Unaudited)
Revenues ........................ $14,903,431 $13,971,761
Operating costs and expenses .... 16,893,094 14,157,384
----------------- ----------------
Loss from continuing operations . $(1,989,663) $ (185,623)
================= ================
Net loss ........................ $(3,029,421) $(2,692,594)
================= ================
Loss per common share:
Continuing operations ......... $ (1.30) $ (.13)
Net loss ..................... (1.83) (.71)
Divestiture
In July 1995, the Company sold its C.S. Dean Unit for approximately
$2,550,000.
3. Discontinued Operations
In January 1995, the Company entered into a plan to discontinue the
operations of its coal properties and commenced the permanent closing of the
mine. As of December 31, 1994, the Company wrote off its investment in its coal
properties and related equipment, eliminated the related minority interest in
the coal entities, and established a liability of $150,000 pursuant to a plan to
discontinue operations for future costs related to closing the mine.
Additionally, during 1994, the Company sold its interest in Castle Minerals,
Inc., which was acquired in 1992 to finance the coal operations, for $371,000,
net of expenses related to the sale (see Note 11). The Company recorded a loss
on these transactions in 1994 of $987,543. The revenues from coal sales for the
years ended 1993, 1994, and 1995 were $23,759, $104,310, and $-0-, respectively.
F-17
<PAGE>
4. Marketable Securities
In May 1993, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 115, "Accounting for Certain Investments in
Debt and Equity Securities" (SFAS 115), effective for fiscal years beginning
after December 15, 1993. At December 31, 1994, the Company's marketable equity
securities were classified as available-for-sale. As of December 31, 1994, the
Company recognized a decrease of approximately $244,000 in shareholders' equity,
representing the recognition in shareholders' equity of unrealized depreciation,
net of taxes, for the Company's investment in equity securities determined to be
available-for-sale, previously carried at the lower of cost or market.
The marketable securities represent an equity investment in a foreign
corporation which the Company considers as available-for-sale. The securities
had an original cost of $570,000 at December 31, 1994 and 1995, and at September
30, 1996. In October 1996, the Company sold its investment in marketable
securities, realizing a loss of $235,197. Such loss was recorded as of September
30, 1996.
Prior to the adoption of SFAS 115, and to increase the carrying amount of
its marketable securities portfolio to market, a recovery of $235,000 was
recorded during 1993.
5. Related Party Transactions
Accounts receivable from affiliates, officers, and shareholders
represents amounts receivable relating to joint interest billings on properties
which the Company operates and advances made to officers.
Oil and gas production payable includes $5,054 and $-0- at December 31,
1994 and 1995, respectively, which represent amounts due to affiliates and
related parties.
Note payable to the principal shareholder amounted to $328,259 and $-0-
at December 31, 1994 and 1995, respectively, including accrued interest of
$10,550 and $-0-. Principal and interest payments amounted to $333,081 and
$354,677 in the years ended December 31, 1994 and 1995, respectively.
Overhead reimbursements charged to affiliates and related parties
amounted to $70,039, $7,087, and $-0- in 1993, 1994, and 1995, respectively.
Charges to the Company for well and other services performed by related
parties were $52,719, $-0-, and $-0- during 1993, 1994, and 1995, respectively.
Rental expense for office furnishings and equipment of $25,000 in 1993,
$-0- in 1994, and $-0- in 1995, was paid to a related party.
F-18
<PAGE>
During 1993, the Company purchased from a shareholder and director
various working interests in wells. The Company issued 10,368 shares of its
common stock in exchange for the shareholder's working interests in these wells.
The Company increased its full cost pool by $77,760 with a corresponding
increase to shareholder's equity.
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 employees of the Company from time to
time at $385 per hour. The Company paid Wind River a total of $80,678 for use of
the plane during 1995.
6. Long-Term Debt
Long-term debt consists of the following:
December 31 September 30
------------------------------ -------------
1994 1995 1996
-------------- --------------- -------------
(Unaudited)
Revolving lines of
credit due under the
First Union credit
agreement (see
below) ....................... $32,906,652 $35,556,651 $ --
Term notes due under
the First Union
credit agreement
(see below) .................. 8,000,000 6,000,000 --
Bridge facility due to
Bankers Trust
Company and ING
Capital (see
Note 17) ..................... -- -- 85,000,000
Principal shareholder,
interest at 10%
(including accrued
interest of $10,550
and $-0- at
December 31, 1994
and 1995,
respectively), with
remaining balance of
principal and unpaid
interest due
December 20, 2001 ........... 28,259 -- --
---------- ---------- -----------
41,234,911 41,556,651 85,000,000
Less current maturities......... -- -- --
----------- ----------- -----------
$41,234,911 $41,556,651 $85,000,000
=========== =========== ===========
F-19
<PAGE>
In June 1994, the Company entered into a credit agreement with First
Union which was subsequently amended during the year. The Company borrowed
$40,906,652 during 1994 under the agreement. The borrowings were composed of
advances of $32,906,652 under a revolving line of credit which was due June
1997, and $8,000,000 under a term note which was due June 15, 1995. In August
1995, the Company amended the credit agreement with First Union. Under the
amended credit agreement, the Company has two lines of credit, one for
$23,000,000 and one for $17,000,000 and two term notes, one for $3,450,000 and
one for $2,550,000. At December 31, 1995, the Company's borrowings under the
credit agreement were $41,556,651. The borrowings were composed of advances of
$12,656,651 and $22,900,000 under the revolving lines of credit which are due
June 30, 1997, and $6,000,000 under the term notes which are also due June 30,
1997. The interest rate for the revolving credit lines is, at the option of the
Company, either (a) the higher of First Union prime plus 1/4% or the federal
funds rate plus 3/4%, floating, payable monthly, or (b) LIBOR plus 2 1/4% (30-,
60-, 90-, and 180-day options), with interest payable the earlier of maturity of
each LIBOR tranche or quarterly. The interest rate for the term notes is, at the
option of the Company, either (a) the higher of First Union prime plus 3/4% or
the federal funds rate plus 1 1/4%, floating, payable monthly, or (b) LIBOR plus
3 1/4% (30-, 60-, 90-, and 180-day options), with interest payable the earlier
of maturity of each LIBOR tranche or quarterly. At December 31, 1995, the
$12,656,651 revolver carried interest at 8.19%, the $22,900,000 revolver carried
interest at 8.06%, and the term notes at 8.16%. The revolvers provide for
borrowing based principally on the Company's crude oil and natural gas reserve
base, which was $44,000,000 at December 31, 1995.
In April 1996, the Company amended the credit agreement with First Union,
extending the due date to June 1999. In accordance with the credit agreement, in
July 1996 the borrowing base was adjusted to $35,000,000. At September 30, 1996,
the Company's borrowings under this line of credit was $-0-.
The revolving lines of credit may be extended, at First Union's
discretion, and are subject to semi-annual redeterminations of the borrowing
base each June and December. The borrowings under the First Union credit
agreement are secured by a first-priority mortgage on all of the Company's crude
oil and natural gas properties and gas plants, as well as a security interest in
accounts receivable, inventory, contracts, and general intangibles, and are
guaranteed by the Company. The First Union credit agreement requires compliance
with certain covenants including, among other things, the ratio of current
assets to current liabilities, excluding any current portion of the credit
agreement, of not less than 1.0 to 1.0; and the ratio of the Company's
indebtedness compared to annualized net income plus non-cash charges shall not
be greater than 7.5 to 1.0 through December 31, 1995, and 5.0 to 1.0 after
December 31, 1995. In August 1996, the ratio of the Company's indebtedness
compared to annualized net income plus non-cash charges was amended to 8.0 to
1.0 through December 31, 1996, effective December 31, 1995, and to 5.0 to 1.0
after December 31, 1996. In addition, the credit agreement requires certain
financial reporting requirements and limits the payments of dividends on common
stock, additional indebtedness, mergers and acquisitions. Loan fees paid in
connection with the origination of the credit agreement and the amended
agreement have been classified as deferred financing fees. In addition, terms
include a commitment fee of 1/2 of 1% per annum, payable quarterly in arrears on
the average unused portion of the borrowing base. The debt's carrying value
approximate its fair values.
F-20
<PAGE>
On June 30, 1994, the Company secured advances under the First Union
facility adequate to extinguish the total debt and accrued interest owed to the
Company's previous lenders, EEP and EECIP. The prepayment resulted in the
Company recording an extraordinary debt extinguishment charge of $1,171,832,
representing the reduction of the deferred financing fees related to the EEP and
EECIP debt origination.
In August 1993, EEP and EECIP agreed to permit the Company to prepay
$14,000,000 of the outstanding balances of the Company's notes out of the
proceeds of the Company's common stock offering. In consideration of this
agreement, the Company issued an aggregate of 50,000 shares of its common stock
to EEP and EECIP's general partners, EEP and Endowment Energy Partners II, L.P.
(EEP II) and, upon making the prepayment of $14,000,000 in October 1993, issued
an additional 66,666 shares of common stock to EEP and EEP II. The prepayment of
debt and the issuance of the above-discussed shares of common stock resulted in
the Company recording an extraordinary debt extinguishment charge of $3,036,000,
representing the fair value of the shares of common stock issued of $1,325,000
and the reduction of the deferred financing fees of $1,711,000 in proportion to
the amount of debt prepaid. The issuance of the above shares resulted in a
corresponding increase in common stock and additional paid-in capital.
The Company has approximately $90,000 of standby letters of credit open
at December 31, 1995. Approximately $134,419 of cash is restricted and in escrow
related to the letters of credit.
7. Shareholders' Equity
Common Stock
Holders of common stock are entitled to one vote for each share and are
not entitled to preemptive rights to subscribe to additional shares of common
stock issued by the Company. Holders are entitled to receive dividends as may be
declared by the Board of Directors, subject to the rights of holders of
preferred stock and the terms of the Company's credit agreement, which restrict
the payment of dividends.
In October 1993, the Company issued an additional 2,250,000 common shares
through a public offering, resulting in net proceeds of $23,045,135. Loss per
share, calculated on a supplemental basis as if the foregoing event had occurred
at the beginning of the year, would have been $(.16) loss per share from
continuing operations and $(.37) net loss per share for the year ended December
31, 1993. The supplemental earnings per share assumes that interest expense
would have been reduced by $939,000 from the prepayment of $14,000,000 of
long-term debt from the proceeds of the issuance of the additional common stock.
The preferred stock was assumed to be converted as of the beginning of 1993;
therefore, income was not required to be adjusted for preferred stock dividends.
F-21
<PAGE>
In 1994, the Board of Directors adopted a Shareholders' 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 $20 one-half of one share of common
stock of the Company having a value of four 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.
In November 1995, the Company issued 1,330,000 units, each consisting of
one share of common stock and one Contingent Value Right (CVR), through a
private placement, resulting in net proceeds of $10,063,105. Each CVR allows the
holder the right to acquire additional shares of common stock under certain
circumstances. See further discussion of CVRs below. Loss per share, calculated
on a supplemental basis as if the foregoing event had occurred at the beginning
of the year, would have been $(.19) loss per share for the year ended December
31, 1995. The supplemental earnings per share assumes that interest expense
would have been reduced by $455,800 from the prepayment of $5,300,000 of
long-term debt from the proceeds of the issuance of the units for the year ended
December 31, 1995.
Preferred Stock
In June 1994, in connection with the Company's acquisition of the
overriding royalty interest from EEP and EECIP, 45,741 shares of the Company's
Series B 8%, nonvoting cumulative convertible preferred stock with a par value
of $100 were issued. The preferred shares are convertible into 508,182 shares of
the Company's common stock. Preferred stock dividends during 1995 amounted to
$365,928. During 1995, the Company exchanged the Series B 8%, nonvoting
cumulative convertible preferred stock for an equal number of shares of Series
1995-B cumulative convertible preferred stock which have a par value of $.01 per
share and a stated value of $100 per share.
The Board of Directors of the Company is authorized to approve the
issuance of one or more classes or series of preferred stock without further
authorization of the Company's shareholders. At December 31, 1992, 24,910 shares
of preferred stock were outstanding. The stock was entitled to a cumulative
dividend of $10 per share, payable in shares of preferred stock, was redeemable
at the option of the Company, and was convertible into common stock at the rate
of 9.271 shares of common stock for each share of preferred stock plus unpaid
dividend. In October 1993, in connection with the Company's common stock
offering, the holders of the preferred stock converted all of the then
outstanding preferred shares, including the preferred shares issued in payment
of approximately $934,000 cumulative dividends in arrears, into 317,539 shares
of common stock.
F-22
<PAGE>
Contingent Value Rights (CVR)
The CVRs were issued under the CVR Agreement between the Company, the
purchasers, and First Union, as rights agent. The CVR Agreement provides that,
subject to adjustment as described below, the Company shall issue to each holder
of the CVRs on the Maturity Date (November 17, 1996), unless the Company shall,
in its sole discretion, extend the Maturity Date to the Extended Maturity Date
(November 17, 1997), then on the Extended Maturity Date, a number of shares of
common stock, if any, equal to (a) the Target Price ($10.00 on the Maturity Date
or $12.50 on the Extended Maturity Date) minus the current market value divided
by (b) the current market value; provided, however, that in no event shall more
than one share of common stock be issued in exchange for each CVR at the
Maturity Date or more than 1.5 shares of common stock be issued in exchange for
each CVR at the Extended Maturity Date. Such determination by the Company shall
be final and binding on the Company and the holders of CVRs.
If the median of the average prices of the common stock for the three
20-trading day periods immediately preceding the Maturity Date or the Extended
Maturity Date, as the case may be, equals or exceeds $10.00 on the Maturity Date
or $12.50 on the Extended Maturity Date (if the Maturity Date is extended by the
Company to the Extended Maturity Date), as the case may be, no shares of the
common stock will be issuable with respect to the CVRs. In addition, the CVRs
will terminate if the per share market value equals or exceeds the Target Price
for any period of 30 consecutive trading days during either the period from and
after November 17, 1995 to and including November 17, 1996, or from and after
November 17, 1996 to and including November 17, 1997.
In the event that the Company determines that no shares of the common
stock are issuable with respect to the CVRs to such holders, the CVRs shall
terminate and become null and void and the holders shall have no further rights
with respect thereto. If the Maturity Date of the CVR Agreement had been
December 31, 1995 and September 30, 1996, an aggregate of 746,480 and 1,117,200
shares, respectively, of common stock would have been issued to the holders of
the CVRs.
Should any additional shares of common stock be required to be issued
under the terms of the CVR Agreement, such issuance will be considered to be an
adjustment to the original sales price per share received in connection with the
sale of the associated common shares; accordingly, the Company will increase its
common stock for the par value related to the additional shares at the time such
shares are issued with a corresponding decrease in additional paid-in capital.
Treasury Stock
During the nine months ended September 30, 1996, the Company purchased
68,140 shares of its common stock at a cost of $372,254, which are being held as
treasury stock.
F-23
<PAGE>
8. Stock Option Plans and Warrants
The Company grants options to its officers, directors, and key employees
under its 1984 Incentive Stock Option Plan, Non-Qualified Stock Option Plan, Key
Contributor Stock Option Plan, Long-Term Incentive Plan, and Director Stock
Option Plan.
The following is a summary of activity in the stock option plans for the
years ended December 31, 1994 and 1995, and the nine-month period ended
September 30, 1996:
Price Options
Per Share (1) Outstanding
---------------- -------------
Outstanding at December 31, 1993 .. $4.50 - $9.75 132,616
Granted ........................... 9.75 - 10.75 27,500
Canceled .......................... 5.50 - 9.75 (18,675)
Exercised ......................... 4.50 - 9.75 (37,908)
----------
Outstanding at December 31, 1994 .. 4.50 - 10.75 103,533
Granted ........................... 9.50 157,500
Canceled .......................... 9.50 - 10.75 (42,000)
Exercised ......................... -
----------
Outstanding at December 31, 1995 .. 5.50 - 9.75 219,033
Granted ........................... 5.00 - 6.75 200,777 (2)
Canceled .......................... 9.75 (20,000)
Exercised ......................... -
----------
Outstanding at September 30, 1996 . 399,810
==========
Options exercisable at
December 31, 1995 ............... 52,850
==========
(1) During the nine months ended September 30, 1996, the Company amended
the exercise price to $6.75 per share on all previously issued options with an
exercise price greater than $6.75 per share.
(2) Includes 70,000 options granted at an exercise price of $5.00 for
which vesting does not begin until the closing price of the Company's common
stock exceeds $8.00 per share.
F-24
<PAGE>
In addition to stock options granted under the plans described above, the
Long-Term Incentive Plan also provides for the right to receive compensation in
cash, awards of common stock, or a combination thereof. In 1994 and 1995, the
Company made direct awards of common stock of 6,111 shares and 4,800 shares,
respectively.
The Company also has adopted the Restricted Share Plan for Directors
which provides for awards of common stock to nonemployee directors of the
Company who did not, within the year immediately preceding the determination of
the director's eligibility, receive any award under any other plan of the
Company. In 1994 and 1995, the Company made direct awards of common stock of
2,400 shares and 3,072 shares, respectively.
During the nine months ended September 30, 1996, the Company's
shareholders approved the Abraxas Petroleum Corporation Director Stock Option
Plan (Plan), which authorizes the grant of nonstatutory options to acquire an
aggregate of 104,000 common shares to those persons who are directors and not
officers of the Company. Under the Plan, each of the seven eligible directors
was granted an option to purchase 8,000 common shares at $6.75.
Stock Warrants
In connection with the EEP and EECIP financing agreements entered into in
1992 and 1993, the Company granted stock warrants covering 90,000 shares at
$5.25 per share and 135,000 shares at $7.00 per share. During 1994, 211,500
warrants were exercised to purchase common stock for $1,323,000. In 1995, no
warrants were exercised by EEP or EECIP. For the nine month period ended
September 30, 1996, no warrants were exercised.
In connection with an amendment and increase in the facility under the
credit agreement with First Union and the extension of the due date on the term
note, the Company granted stock warrants to First Union covering 424,000 shares
of its common stock at an average price of $9.79 a share. The warrants are
exercisable in whole or in part through December 1999 and are nontransferable
without the consent of the Company.
At December 31, 1995, the Company has approximately 6,470,000 shares
reserved for future issuance for conversion of its stock options, warrants,
Rights, preferred stock, CVRs, and incentive plans for the Company's Directors
and employees.
F-25
<PAGE>
9. 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
--------------------------------
1994 1995
--------------------------------
Deferred tax liabilities:
Full cost pool, including
intangible $1,292,000 $ 661,000
drilling costs ...............
State taxes ................... 187,000 187,000
Other ......................... - 101,000
--------------------------------
Total deferred tax liabilities .. 1,479,000 949,000
Deferred tax assets:
Coal mine valuation provisions 1,740,000 -
Depletion ..................... 242,000 242,000
Net operating losses .......... 4,771,000 6,163,000
Other ......................... 21,000 13,000
--------------------------------
Total deferred tax assets ....... 6,774,000 6,418,000
Valuation allowance for deferred (5,482,000) (5,656,000)
tax assets ....................
--------------------------------
Net deferred tax assets ......... 1,292,000 762,000
--------------------------------
Net deferred tax liabilities .... $ 187,000 $ 187,000
================================
At December 31, 1995, the Company had, subject to the limitations
discussed below, $18,127,000 of net operating loss carryforwards for tax
purposes, of which approximately $4,697,000 are available for utilization
without limitation. These loss carryforwards will expire from 2002 through 2010
if not utilized.
As the 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 of the Internal Revenue Code of 1986, as amended (Section 382),
occurred in December 1991. Accordingly, it is expected that the use of net
operating loss carryforwards generated prior to December 31, 1991 of $6,916,000
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 $3,607,000
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 net operating loss carryforwards generated through October 1993 of
F-26
<PAGE>
$13,430,000 will be limited to approximately $1,034,000 per year, subject to the
lower limitations described above. Of the $13,430,000 net operating loss
carryforwards existing at October 1993, it is anticipated that the maximum net
operating loss that may be utilized before it expires is $7,188,000. Future
changes in ownership may further limit the use of the Company's carryforwards.
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 $5,482,000 and $5,656,000 for deferred tax assets at
December 31, 1994 and 1995, respectively.
The reconciliation of income tax attributable to continuing operations
computed at the U.S. federal statutory tax rates to income tax expense is:
December 31
--------------------------------------------
1993 1994 1995
-------------- -------------- --------------
Tax (expense) benefit
at U.S. statutory $ 569,000 $ (38,400) $ 411,000
rates (34%) ..........
(Increase) decrease in
deferred tax asset (469,000) 31,600 (174,000)
valuation allowance ..
Deferred state income (186,749) - -
taxes ................
Other .................. (100,000) 6,800 (237,000)
-------------- -------------- --------------
$(186,749) $ - $ -
============== ============== ==============
10. Leases
The Company leases its existing primary office space for $8,591 per month
under a noncancelable lease expiring on June 30, 1998. During 1995, the Company
entered into a noncancelable lease for new primary office space at $13,700 per
month through March 2001 and $18,975 per month through March 2006.
During the years ended December 31, 1993, 1994, and 1995, the Company
incurred rent expense of approximately $143,000, $108,000, and $103,000,
respectively. Future minimum rental payments are as follows at December 31,
1995:
1996 ................................................. $ 225,816
1997 ................................................. 219,016
1998 ................................................. 217,848
1999 ................................................. 164,448
2000 ................................................. 227,700
Thereafter ........................................... 1,138,500
Aggregate future minimum rentals to be received under noncancelable
subleases as of December 31, 1995 amount to $92,664.
F-27
<PAGE>
11. Investment in Coal Properties
Over the past years the Company, through a subsidiary, had been developing
certain coal properties in Colorado. During this period, development costs along
with interest on its bank debt have been capitalized as coal properties. The
interest accrued into the subsidiary bank debt, which was nonrecourse to the
parent. Effective July 1, 1992, the subsidiary commenced expensing interest and
other related operating costs.
In March 1992, the subsidiary acquired for $15,000 a controlling interest
in an inactive Vancouver publicly traded company, Castle Minerals, Inc. (CMI).
In December 1992, the subsidiary received approval from the Vancouver Stock
Exchange, whereby the subsidiary contributed all of its coal-related assets to
CMI in exchange for additional shares amounting to approximately 86% of the
capital stock of CMI.
During 1992, the Company recorded as a charge against operations,
$3,137,000, representing interest expense and other operating costs of the coal
mine of approximately $512,000 and a reduction in the carrying value of the coal
mine by $2,625,000. The estimated fair value of the coal mine was determined
based upon an appraisal that assumes the startup of commercial production and
the availability of markets in which to sell the coal production.
On April 14, 1993, the Company entered into a letter agreement with the
lender of the subsidiary bank debt (Bank) effective March 31, 1993, wherein the
Company assumed a portion of the subsidiary bank debt by issuing a note to the
Bank in the principal amount of $1,000,000. In addition, the subsidiary issued
to the Bank its preferred stock with a par value of $2,000,000, and the Bank
canceled the subsidiary bank debt of $4,302,675. The preferred stock of the
subsidiary requires no dividends prior to April 1, 1996 and at 8% thereafter
payable in cash or property of the subsidiary, carries a liquidation preference
of $2,000,000, and is redeemable at the option of the subsidiary at $2,000,000.
The preferred stock had been recorded at management's estimate of the stock's
fair market value of $840,000 and was carried as minority interest in the
December 31, 1993 balance sheet. A pretax gain of $2,462,664, representing the
excess of the carrying value of the subsidiary bank debt over the estimated fair
value of the preferred stock and the future cash payments of the $1,000,000
subsidiary bank debt assumed by the Company, was recorded as an extraordinary
item for the year ended December 31, 1993. On October 29, 1993, the Company paid
its note of $1,000,000 plus interest to the Bank. In December 1994, the Company
discontinued its operation of the coal properties (see Note 3).
12. Benefit Plans
During 1993, the Company established a defined contribution plan (401(k))
covering all eligible employees of the Company. No contributions were made by
the Company during 1993, 1994, or 1995. 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 overall
contribution is limited to the lesser of 20% of the employee's annual
compensation or $9,240.
F-28
<PAGE>
13. Incentive Bonus Plan
In January 1995, the Company created the Technical Employees Incentive
Bonus Plan, whereby technical employees have an incentive to find and develop
crude oil and natural gas reserves on an economic basis beneficial to the
Company and its shareholders. Participants are any technical employees
(geologist, geophysicist, engineer) not covered by another incentive bonus plan.
A participant may earn a monetary bonus of up to 65% of the participant's base
salary each year. The bonuses are determined in the first quarter of each year
and are based upon the amount of new proved developed producing reserves booked
each year on approved exploration and exploitation projects taking into
consideration the cost per equivalent barrel of developing the new reserves. No
bonuses were paid under this plan in 1995.
14. Contingencies
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,
1995 and September 30, 1996, 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's financial statements.
15. Commodity Swap Agreement
In December 1995, the Company entered into a commodity swap agreement with
First Union. Under the commodity swap agreement, the Company receives or makes
payments to First Union based on the differential between a fixed and variable
price for natural gas. At December 31, 1995 and September 30, 1996, the Company
had agreed to exchange payments monthly on 5,000 MMBTU of natural gas per day,
beginning in March 1996 and extending through November 1996. Under the swap
agreement, the Company receives fixed prices averaging $1.747 per MMBTU and pays
a variable price based on the arithmetic average of the last three trading days'
settlement price of the first nearby contract for natural gas as quoted by the
New York Mercantile Exchange. For the year ended December 31, 1995, there was no
effect on income from continuing operations as there was no activity related to
the swap agreement, which begins in March 1996. At September 30, 1996, the
effect on income was a loss of $510,767.
16. Subsequent Events
In January 1996, the Company made a $3,000,000 investment in Grey Wolf, a
privately held Canadian corporation, which in turn invested these proceeds in
newly issued shares of Cascade Oil and Gas Ltd. (Cascade), an Alberta-based
corporation whose shares are traded on the Alberta Stock Exchange. The Company
owns 78% of the outstanding capital stock of Grey Wolf, and, through Grey Wolf,
the Company owns approximately 52% of the outstanding capital stock of Cascade.
Certain officers and directors of the Company own approximately 6% of the common
stock of Grey Wolf and serve as directors of Grey Wolf.
In March 1996, the Company sold all of its interest in its Portilla and
Happy Fields to an unrelated purchaser (Purchaser or Limited Partner).
Simultaneously with this sale, the Limited Partner also acquired the 50%
overriding royalty interest in the Portilla field owned by the Commingled
Pension Trust Fund (Petroleum II), the trustee of which is Morgan Guaranty Trust
Company of New York (Pension Fund). In connection with the purchase of both the
Company's interest in the Portilla and Happy Fields and the Pension Fund's
interest in the Portilla Field (together, the Properties), the Limited Partner
obtained a loan (Bank Loan) secured by the Properties and contributed the
Properties to Portilla-1996, L.P., a Texas limited partnership (Partnership). A
subsidiary of the Company, Portilla-Happy Corporation (Portilla-Happy), is the
general partner of the Partnership. The aggregate purchase price received by the
Company was $17,600,000, of which $2,000,000 was used to purchase a minority
interest in the Partnership, which has been accounted for using the equity
method. At September 30, 1996, the Company's investment in and advances to the
Partnership represents the original investment of $2,000,000 and advances made
F-29
<PAGE>
to the Partnership primarily for development drilling net of production revenue
collected by the Company on behalf of the Partnership.
17. Acquisitions and Related Financing (Unaudited)
On September 30, 1996, the Company acquired interests in certain producing
crude oil and natural gas properties located in the Wamsutter area of
southwestern Wyoming (the Wyoming Properties) from Enserch Exploration, Inc. The
initially agreed to purchase price of $47,500,000 was adjusted to $45,856,000 to
reflect the preliminary estimate of net production revenue which accrued to the
Company from April 1, 1996, the effective date, until closing, net of interest
owed by the Company for the same period. As of September 30, 1996, the Company
recorded $45,856,000 in its oil and gas properties. The acquisition was financed
by borrowings under the Bridge Facility discussed below.
On September 30, 1996, the Company entered into a credit facility with
Bankers Trust Company (BTCo) and ING Capital (together the Lenders), providing a
bridge facility in the total amount of $90,000,000, consisting of a $30,000,000
revolving credit facility, with $25,000,000 initially available, a $35,000,000
term loan and a $25,000,000 term loan (the Bridge Facility). The Bridge Facility
is secured by a first priority lien on substantially all of the Company's U.S.
assets and matures on October 31, 1997. If borrowings under the Bridge Facility
have not been repaid by each of November 15, 1996 and January 1, 1997, the
Company will be obligated to pay the Lenders additional fees and/or warrants to
purchase common stock of the Company. The agreement limits the Company's debt to
the Bridge Facility, restricts the payment of dividends other than to the
existing preferred stock, and requires compliance with minimum tangible net
worth, current and interest coverage ratios and certain financial reporting
requirements.
The revolving credit facility and the $35,000,000 term loan carry interest
at LIBOR plus 2 1/4% and the $25,000,000 term loan carries interest at the
BTCo's prime rate plus 3%, increasing at 1/2% for each 90-day period thereafter
to a maximum of prime plus 4 1/2%. Under an interest rate swap agreement, the
Company pays a fixed rate of 6.15% on $25,000,000 of borrowings while the lender
under the Bridge Facility will pay a floating rate equal to the USD-LIBOR-BBA
rate for one month maturities to the Company. Settlements are due monthly. The
agreement terminates in August 1997 and may be extended for an additional year
by the lenders. On September 30, 1996, the Company borrowed $85,000,000 under
the Bridge Facility which was used to repay all amounts due First Union and to
finance the purchase of the Wyoming Properties. In connection with the Bridge
Facility the commodity swap agreement discussed in Note 15 was terminated.
On November 14, 1996, the Company repaid all amounts outstanding under the
Bridge Facility with proceeds from the offering of $215,000,000 of Senior Notes
described below and entered into an amended and restated credit agreement (New
Credit Facility). The New Credit Facility provides for a revolving line of
credit with an initial availability of $20.0 million, subject to certain
customary conditions including a borrowing base condition. No amounts were
outstanding on September 30, 1996 under the New Credit Facility.
Commitments available under the New Credit Facility are subject to
borrowing base redeterminations to be performed semi-annually and, at the option
of each of the Company and the Lenders, one additional time per year. Any
outstanding principal balance in excess of the borrowing base will be due and
payable in three equal monthly payments after a borrowing base redetermination.
The borrowing base will be determined in the Agent's sole discretion, subject to
the approval of the Lenders, based on the value of the Company's reserves as set
forth in the reserve report of the Company's independent petroleum engineers,
with consideration given to other assets and liabilities.
The New Credit Facility has an initial revolving term of two years and a
reducing period of three years from the end of the initial two-year period. The
F-30
<PAGE>
commitment under the New Credit Facility will be reduced during such reducing
period by eleven equal quarterly reductions. Quarterly reductions will equal
8.2% per quarter with the remainder due at the end of the three-year reducing
period.
The applicable interest rate charged on the outstanding balance of the New
Credit Facility is based on a facility usage grid. If the borrowings under the
New Credit Facility represent an amount less than or equal to 33.3% of the
available borrowing base, then the applicable interest rate charged on the
outstanding balance will be either (a) an adjusted rate of the London Inter-Bank
Offered Rate ("LIBOR") plus 1.25% or (b) the prime rate of the Agent (which is
based on the agent's published prime rate) plus 9.50%. If the borrowings under
the New Credit Facility represent an amount greater than or equal to 33.3% but
less than 66.7% of the available borrowing base, then the applicable interest
rate on the outstanding principal will be either (a) LIBOR plus 1.75% or (b) the
prime rate of the Agent plus 0.50%. If the borrowings under the New Credit
Facility represent an amount greater than or equal to 66.7% of the available
borrowing base, then the applicable interest rate on the outstanding principal
will be either (a) LIBOR plus 2.00% or (b) the prime rate of the Agent plus
0.50%. LIBOR elections can be made for periods of one, three or six months.
The New Credit Facility contains a number of covenants that, among other
things, restrict the ability of the Company to (i) incur certain indebtedness or
guarantee obligations, (ii) prepay other indebtedness including the Notes, (iii)
make investments, loans or advances, (iv) create certain liens, (v) make certain
payments, dividends and distributions, (vi) merge with or sell assets to another
person or liquidate, (vii) sell or discount receivables, (viii) engage in
certain intercompany transactions and transactions with affiliates, (ix) change
its business, (x) experience a change of control and (xi) make amendments to its
charter, by-laws and other debt instruments. In addition, under the New Credit
Facility, the Company is required to comply with specified financial ratios and
tests, including minimum debt service coverage ratios, maximum funded debt to
EBITDA (earnings from continuing operations before income taxes, interest
expense, depletion, deprecation and amortization and other non-cash charges)
tests, minimum net worth tests and minimum working capital tests.
The New Credit Facility contains customary events of default, including
nonpayment of principal, interest or fees, violation 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 and change of control.
In September 1996, the Company entered into an agreement with the Limited
Partner and certain noteholders (Noteholders) of the Partnership, pursuant to
which the Company agreed to purchase the Limited Partner's interest in the
Partnership and the Noteholders' notes in the aggregate principal amount of
$5,920,000 (Notes), resulting in the Company's owning, on a consolidated basis,
all of the equity interests in the Partnership. The aggregate consideration for
the purchase of the Limited Partner's interest in the Partnership and the Notes
is $6,961,000. The Company will also assume the Bank Loan which had an
outstanding principal balance of approximately $20,639,000 as of October 31,
1996, and a commodity price hedge agreement. Under the terms of the agreement,
the Company will be required to receive or make payments to BTCo and ING Capital
based on a differential between a fixed and variable price for crude oil and
natural gas through November 2001 on volumes ranging from 8,160 barrels of crude
oil to 20,000 barrels of crude oil per month and 14,850 MMBTU of natural gas to
87,406 MMBTU of natural gas per month. Under this agreement, the Company will
receive fixed prices ranging from $17.20 per barrel of crude oil to $18.55 per
barrel of crude oil and $1.793 per MMBTU of natural gas to $1.925 per MMBTU of
natural gas and will make payments based on the price for west Texas
intermediate light sweet crude oil on the NYMEX for crude oil and the Inside
FERC, Tennessee Gas Properties Co. Texas price for natural gas. Currently there
is a net unrealized loss of approximately $1.8 million under the commodity price
hedge. On November 14, 1996, the Company closed the transaction.
As a result, the Company reacquired those interests in the Portilla and
Happy Fields which it previously owned, as well as the interest in the Portilla
Field previously owned by the Pension Fund. The Company will include in its
balance sheet the amount previously removed from oil and gas properties in
F-31
<PAGE>
connection with the sale of its interest in the Portilla and Happy Fields during
the quarter ended March 31, 1996, as well as the amount of the purchase price
paid for the Pension Fund's interest in the Portilla Field, and all development
drilling expenditures incurred on the properties, less the amount of DD&A
related to the properties from the formation of the Partnership through the
closing of the transaction.
In October 1996, the Company entered into a letter of intent to purchase
100% of the outstanding capital stock of CGGS Canadian Gas Gathering Systems
Inc. (CGGS) in Calgary, Canada after the consummation of the sale of CGGS of its
Nevis gas processing plant, for approximately U.S.$85,000,000 plus the amount of
CGGS's working capital at August 1, 1996, subject to price adjustments. CGGS
owns producing oil and gas properties in Western Canada and adjacent gas
gathering and processing facilities as well as undeveloped net acres of
leaseholds. On November 14, 1996, the Company, through its wholly owned
subsidiary, Canadian Abraxas Petroleum Limited (Canadian Abraxas) closed the
transaction and immediately merged CGGS with and into Canadian Abraxas, and
Canadian Abraxas, as the surviving entity, used the net proceeds from the sale
of the Nevis gas processing plant to retire all of the outstanding debentures of
CGGS. The transaction was financed by a portion of the proceeds from the
offering of $215,000,000 of Senior Notes discussed below.
On November 14, 1996, the Company and Canadian Abraxas completed the sale
of $215,000,000 aggregate principal amount of Senior Notes due November 1, 2004.
Interest at 11.5% is payable semi-annually on May 1 and November 1. The Notes
are general unsecured obligations of the Company and Canadian Abraxas and the
Company and Canadian Abraxas are joint and several obligors. The Notes are
redeemable, in whole or in part, at the option of the Company and Canadian
Abraxas on or after November 1, 2000, and any time prior to November 1, 1999,
the Company and Canadian Abraxas may redeem up to 35% of the aggregate principal
amount of the Notes with the cash proceeds of equity offerings at a redemption
price of 111.5% of the aggregate principal amount of the Notes to be redeemed.
The terms of the Indenture related to the Notes provide for certain financial
covenants which may limit the ability of the Company to incur additional debt.
In November 1996, the Company obtained a release of the 50% overriding
royalty interest in the East White Point Field in San Patricio County, Texas and
the Stedman Island Field in Nueces County, Texas from the Pension Fund for
$9,300,000 before adjustment for accrual of net revenue to closing. The Company
will record the net purchase price of approximately $8,771,000 to its oil and
gas properties.
18. Oil and Gas Properties
The Company's investment in crude oil and natural gas properties was as
follows:
December 31
-----------------------------
1994 1995
-------------- --------------
Proved crude oil and natural gas
properties, including gas $94,542,481 $104,127,204
processing plants ..................
Accumulated depreciation, depletion,
and amortization, and valuation (24,363,918) (29,651,521)
allowances .........................
-------------- --------------
Net capitalized costs ................ $70,178,563 $74,475,683
============== ==============
F-32
<PAGE>
Costs incurred, capitalized, and expensed in crude oil and natural gas
producing activities are as follows:
December 31
--------------------------------------------
1993 1994 1995
-------------- -------------- --------------
Property acquisition costs:
Proved .................. $20,479,509 $33,597,172 $ 718,871
Unproved ................ 42,726 4,786 -
-------------- -------------- --------------
$20,522,235 $33,601,958 $ 718,871
============== ============== ==============
Property development and
exploration costs ...... $ 5,116,747 $ 7,150,943 $11,398,088
============== ============== ==============
Depreciation, depletion,
and amortization ....... $ 2,360,200 $ 3,776,823 $ 5,313,003
============== ============== ==============
Depletion per
equivalent barrel of
production ............ $ 5.03 $ 4.35 $ 4.67
============== ============== ==============
The results of operations for oil and gas producing activities are as
follows:
December 31
--------------------------------------------
1993 1994 1995
------------- ------------------------------
Revenues .............. $7,274,676 $11,114,028 $13,659,556
Production costs ...... (2,895,651) (3,693,085) (4,333,240)
Depreciation,
depletion, and
amortization ......... (2,360,200) (3,776,823) (5,313,003)
Abandoned prospects ... (22,343) - -
General and
administrative ....... (127,377) (202,579) (260,435)
Income taxes .......... - - -
------------- ------------- ------------
Results of operations
from oil and gas
producing activities
(excluding corporate
overhead and interest
costs) ............... $ 1,869,105 $ 3,441,541 $ 3,752,878
============= ============ ============
F-33
<PAGE>
SUPPLEMENTAL INFORMATION
RELATING TO
OIL AND GAS PRODUCING COMPANIES
For the Years Ended December 31, 1993, 1994, and 1995
and the Six-Month Period Ended June 30, 1996
<PAGE>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION - UNAUDITED
December 31, 1993, 1994, and 1995 and June 30, 1996
(All Supplemental Information for the Periods Presented is Unaudited)
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, 1993, 1994, and 1995, and
June 30, 1996. 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.
Liquid Natural
Hydrocarbons Gas
--------------- -------------
(Barrels) (Mcf)
Proved developed and undeveloped reserves:
Balance at December 31, 1992 ..... 1,834,846 5,660,070
Revisions of previous estimates . (298,390) (1,339,668)
Extensions and discoveries ...... 9,728 1,486,680
Purchase of minerals in place ... 3,063,401 11,822,353
Production ...................... (304,804) (985,385)
Sale of minerals in place ....... (218,510) (53,410)
--------------- -------------
Balance at December 31, 1993 ..... 4,086,271 16,590,640
Revisions of previous estimates . 854,672 5,034,435
Extensions and discoveries ...... 2,267,787 15,061,671
Purchase of minerals in place ... 2,416,646 33,288,229
Production ...................... (468,867) (2,392,855)
Sale of minerals in place ....... (19) (3,027)
--------------- -------------
Balance at December 31, 1994 ..... 9,156,490 67,579,093
Revisions of previous estimates . (1,327,795) (18,941,473)
Extensions and discoveries ...... 1,335,349 6,819,415
Purchase of minerals in place ... 213,998 2,888,885
Production ...................... (544,825) (3,552,671)
Sale of minerals in place ....... (565,975) (224,642)
--------------- -------------
Balance at December 31, 1995 ..... 8,267,242 54,568,607
Revisions of previous estimates . (353,035) (3,260,607)
Extensions and discoveries ...... 862,674 4,772,542
Purchase of minerals in place ... 230,647 1,700,440
Production ...................... (261,872) (1,758,034)
Sale of minerals in place ....... (2,104,957) (3,456,916)
--------------- -------------
Balance at June 30, 1996 ......... 6,640,699 (1) 52,566,032
=============== =============
F-34
<PAGE>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION - UNAUDITED (CONTINUED)
December 31, 1993, 1994, and 1995 and June 30, 1996
(All Supplemental Information for the Periods Presented is Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves (continued)
Liquid Natural
Hydrocarbons Gas
-------------- --------------
(Barrels) (Mcf)
Proved developed reserves:
December 31, 1993 ................ 3,468,492 15,242,500
============== ==============
December 31, 1994 ................ 5,705,678 48,973,212
============== ==============
December 31, 1995 ................ 5,999,581 44,025,782
============== ==============
June 30, 1996 .................... 4,885,838 41,902,598
============== ==============
(1) Includes 127,700 barrels of crude oil from the Company's Canadian
subsidiary, Cascade, which are not included in the Company's June 30, 1996
reserve report.
All proved reserves are located within the continental United States.
The significant downward revision in 1995 of previous liquid hydrocarbons
and natural gas was due principally to decreased estimates of recoverable
reserves in existing wells related to disappointing drilling results principally
in the East White Point field, resulting in reclassification of proved
undeveloped reserves to probable reserves.
The significant upward revision in 1994 of previous liquid hydrocarbons
and natural gas was due principally to increased estimates of recoverable
reserves in existing wells as a result of drilling and workover success in 1994,
combined with the completion of geological engineering studies on several major
fields.
The significant downward revision in 1993 of previous natural gas
quantities was due principally to the reclassification of natural gas liquids to
liquid hydrocarbons. The significant downward revision of liquid hydrocarbons
was caused by the approximate 30 percent decrease in the price of crude oil,
partially offset by the reclassification of the natural gas liquids.
F-35
<PAGE>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION - UNAUDITED (CONTINUED)
December 31, 1993, 1994, and 1995 and June 30, 1996
(All Supplemental Information for the Periods Presented is Unaudited)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves
The following disclosures concerning the standardized measure of future
cash flows from proved crude oil and natural gas reserves are presented in
accordance with Statement of Financial Accounting Standards 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, 1995 and June 30, 1996, 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 Company's basis in the
associated proved crude oil and natural gas properties, less 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.
Set forth below is the Standardized Measure relating to proved oil and gas
reserves for:
<TABLE>
<CAPTION>
Six-Month
Period
Years Ended December 31 Ended
---------------------------------------------- June 30
1993 1994 1995 1996
------------- -------------- ------------- -------------
<S> <C> <C> <C> <C>
Future cash inflows $ 91,302,460 $ 238,027,959 $ 243,968,579 $ 233,993,225
Future production
and development
costs ........... (27,045,914) (84,551,808) 79,910,127 (76,840,346)
Future income
tax expense ..... (11,109,000) (26,542,000) (28,014,454) (26,506,019)
-------------- ------------- -------------- -------------
Future net cash
flows ........... 53,147,546 126,934,151 136,043,998 130,646,860
Discount .......... (20,219,000) (49,241,151) (48,884,079) (50,073,402)
-------------- -------------- -------------- -------------
Standardized
Measure of
discounted
future net
cash relating
to proved
reserves ........ $ 32,928,546 $ 77,693,000 $ 87,159,919 $ 80,573,458
============== ============= ============= =============
</TABLE>
F-36
<PAGE>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION - UNAUDITED (CONTINUED)
December 31, 1993, 1994, and 1995 and June 30, 1996
(All Supplemental Information for the Periods Presented is Unaudited)
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:
Six-Month
Period
Year Ended December 31 Ended
-------------------------------------- June 30
1993 1994 1995 1996
------------ ------------ ----------- --------------
Standardized
Measure,
beginning of
year ......... $12,656,520 $32,928,546 $77,693,000 $87,159,919
Sales and
transfers of
oil and gas
produced, net
of production
costs ........ (4,379,025) (7,420,942) (9,351,316) (5,833,143)
Net changes in
prices and
development
and
production
costs from
prior year ... 1,597,103 2,450,058 22,559,686 10,032,893
Extensions,
discoveries,
and improved
recovery,
less related
costs ........ 1,613,724 13,509,056 13,475,100 9,467,077
Purchases of
minerals in
place ........ 31,098,560 29,162,942 3,867,205 2,935,043
Sales of
minerals in
place ........ (1,162,137) (2,000) (3,355,289) (15,308,066)
Revision of
previous
quantity
estimates .... (3,282,778) 7,346,415 (24,936,935) (5,118,486)
Change in
future income (2,989,000) 5,804,000 382,460 (2,462,218)
tax expense ..
Other .......... (3,490,071) (9,377,929) (943,292) (4,657,557)
Accretion of
discount ..... 1,265,650 3,292,854 7,769,300 4,357,996
----------- ----------- ----------- -----------
Standardized
Measure, end
of year ...... $32,928,546 $77,693,000 $87,159,919 $80,573,458
=========== =========== =========== ===========
The net change in prices and production costs from prior years in the
Standardized Measure of discounted future net cash flows was predominantly due
to an approximate increase in the price of an equivalent barrel of oil of $2.39,
offset by an increase in the production cost of an equivalent barrel of oil of
$.70.
F-37
<PAGE>
AUDITORS' REPORT TO THE DIRECTORS
To the Board of Directors of
Canadian Gas Gathering Systems Inc.
We have audited the balance sheets of CGGS Canadian Gas Gathering Systems
Inc. as at October 31, 1995 and 1994 and the statements of earnings (loss) and
deficit and changes in financial position for the years ended October 31, 1995,
1994 and 1993. 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 generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial statements are free of material
misstatements. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
In our opinion, these financial statements present fairly, in all material
respects, the financial position of the Company as of October 31, 1995 and 1994
and the results of its operations and the changes in its financial position for
the years ended October 31, 1995, 1994 and 1993 in accordance with generally
accepted accounting principles.
KPMG
Chartered Accountants
Calgary, Canada
January 12, 1996
F-38
<PAGE>
<TABLE>
<CAPTION>
CGGS CANADIAN GAS GATHERING SYSTEMS INC.
BALANCE SHEETS
(In Canadian Dollars)
ASSETS
October 31 October 31
----------------------------
1994 1995 1996
------------- ---------------------------
(Unaudited)
Current assets:
<S> <C> <C> <C>
Cash and short-term deposits ..... $ 8,326,000 $ 1,274,000 $ 10,050,000
Accounts receivable .............. 11,619,000 12,850,000 13,540,000
------------ ----------- ------------
19,945,000 14,124,000 23,590,000
Capital assets (note 3) ............ 129,432,000 128,095,000 123,857,000
Deferred financing costs (note 4) .. 1,628,000 1,482,000 1,336,000
Deferred foreign exchange loss ...... 9,775,000 7,882,000 6,858,000
----------- ----------- ------------
Total assets .......................$ 160,780,000 $151,583,000 $155,641,000
============ ============ =============
</TABLE>
<TABLE>
<CAPTION>
LIABILITIES AND SHAREHOLDERS' EQUITY
October 31 October 31
-----------------------------
1994 1995 1996
-------------- --------------------------
(Unaudited)
Current liabilities:
Debenture interest payable to
<S> <C> <C> <C>
shareholders .................... $ 1,399,000 $ 1,344,000 $ 1,342,000
Accounts payable ................. 10,108,000 4,335,000 7,201,000
------------ ------------ ------------
Total current liabilities ....... 11,507,000 5,679,000 8,543,000
Long-term shareholders' debt (note 5) 114,167,000 113,070,000 113,179,000
Provision for future site
restoration ...................... 2,236,000 3,015,000 4,148,000
------------ ------------ ------------
127,910,000 121,764,000 125,870,000
Shareholders' equity:
Share capital (note 6) ........... 34,213,000 34,213,000 34,213,000
Deficit .......................... (1,343,000) (4,394,000) (4,442,000)
-------------- ------------- -----------
Total shareholders' equity 32,870,000 29,819,000 29,771,000
Commitments (note 10)
------------- ------------- --------------
Total liabilities and
shareholders' equity .......... $160,780,000 $151,583,000 $155,641,000
============= ============= ==============
</TABLE>
See accompanying notes to financial statements.
F-39
<PAGE>
<TABLE>
<CAPTION>
CGGS CANADIAN GAS GATHERING SYSTEMS INC.
STATEMENTS OF EARNINGS (LOSS) AND DEFICIT
(In Canadian Dollars)
Year Ended
Year Ended October 31 October 31
---------------------------------------- -------------
1993 1994 1995 1996
------------- -------------------------- -------------
(Unaudited)
Revenues:
<S> <C> <C> <C> <C>
Processing ................ $25,818,000 $30,408,000 $33,100,000 $36,954,000
Production ................ 28,620,000 35,855,000 22,408,000 26,791,000
Royalties, net ............ (5,321,000) (6,787,000) (3,366,000) (3,975,000)
Other income .............. 264,000 1,028,000 996,000 690,000
------------- ------------- ------------- -------------
49,381,000 60,504,000 53,138,000 60,460,000
Expenses:
Processing ................ 16,707,000 15,621,000 14,763,000 19,207,000
Production ................ 4,649,000 4,866,000 5,689,000 5,308,000
Administration (note 7) ... 3,685,000 3,960,000 4,507,000 4,117,000
Interest on acquisitions .. 1,280,000 - - -
Interest on long-term
shareholders' debt ....... 12,175,000 15,998,000 16,227,000 16,172,000
Depletion and depreciation 13,408,000 14,361,000 13,754,000 14,092,000
Amortization of deferred
financing costs .......... 146,000 146,000 146,000 146,000
Foreign exchange loss ..... 760,000 772,000 795,000 1,134,000
------------- ----------- ----------- -----------
.......................... 52,810,000 55,724,000 55,881,000 60,176,000
------------- ----------- ----------- -----------
Earnings (loss) before taxes (3,429,000) 4,780,000 (2,743,000) 284,000
Large corporation tax ....... 262,000 274,000 308,000 332,000
------------- ----------- ----------- -----------
Net earnings (loss) ......... (3,691,000) 4,506,000 (3,051,000) (48,000)
Deficit - beginning of year . (2,158,000) (5,849,000) (1,343,000) (4,394,000)
------------- ------------ ------------ ------------
Deficit - end of year ....... $(5,849,000) $(1,343,000) $(4,394,000) $(4,442,000)
============= ============ ============ ============
</TABLE>
See accompanying notes to financial statements.
F-40
<PAGE>
<TABLE>
<CAPTION>
CGGS CANADIAN GAS GATHERING SYSTEMS INC.
STATEMENTS OF CHANGES IN FINANCIAL POSITION
(In Canadian Dollars)
Year Ended
Year Ended October 31 October 31
---------------------------------------- -------------
1993 1994 1995 1996
------------- -------------------------- -------------
(Unaudited)
Operating Activities:
<S> <C> <C> <C> <C>
Net earnings (loss) ....... $(3,691,000) $4,506,000 $(3,051,000) $ (48,000)
Depletion and depreciation 13,408,000 14,361,000 13,754,000 14,092,000
Amortization of deferred
financing costs .......... 146,000 146,000 146,000 146,000
Foreign exchange loss ..... 760,000 772,000 795,000 1,134,000
Decrease (increase) in
non-cash working capital
items ................... 6,004,000 (5,443,000) (7,004,000) 2,176,000
------------ ----------- ----------- -----------
16,627,000 14,342,000 4,640,000 17,500,000
Financing Activities:
Issuance of share capital . 17,692,00 583,000 - -
Increase in long-term
shareholders' debt ....... 53,057,000 1,726,000 - -
------------ ----------- ----------- -----------
70,749,000 2,309,000 - -
Investing Activities:
Expenditures on capital
assets ................... (49,010,000) (15,024,000) (11,638,000) (8,72,000)
Decrease in deferred
revenue .................. (1,473,000) - - -
(Increase) decrease in
non-cash working capital (35,281,000) (3,771,000) (54,000) (2,000)
------------- ------------ ------------ -----------
(85,764,000) (18,795,000) (11,692,000) (8,724,000)
Increase (decrease) in cash
and short-term deposits ... 1,612,000 (2,144,000) (7,052,000) 8,776,000
Cash and Short-Term Deposits:
Beginning of year ........ 8,858,000 10,470,000 8,326,000 1,274,000
------------- ------------ ------------ ------------
End of year .............. $10,470,000 $8,326,000 $1,274,000 $10,050,000
============= ============ ============ ============
</TABLE>
See accompanying notes to financial statements.
F-41
<PAGE>
CGGS CANADIAN GAS GATHERING SYSTEMS INC.
NOTES TO FINANCIAL STATEMENTS
(Information as to October 31, 1996 and for the Year Then Ended is Unaudited)
The Company was incorporated on March 9, 1990 under the Canada Business
Corporations Act. The Company was formed to invest in gas plants, gas gathering
systems and related gas reserves in Canada. Morrison Petroleums Ltd., a
shareholder, manages the Company.
1. Summary of Significant Accounting Policies
The financial statements are prepared in accordance with generally
accepted accounting principles in Canada.
Foreign Currency Translation
Monetary assets and monetary liabilities are translated at the exchange
rate in effect at the balance sheet date. Gains and losses on translation are
recorded in the statement of earnings, except that gains or losses on monetary
liabilities with a fixed or ascertainable life are deferred and amortized over
the repayment period.
Joint Ventures
The Company's exploration and production activities related to oil and gas
are substantially conducted in joint participation with others and, accordingly,
the accounts reflect only the Company's proportionate interest in such
activities.
Capital Assets
The Company follows the full cost method of accounting for exploration and
development expenditures wherein all costs related to the exploration for and
the development of oil and gas reserves are capitalized. These costs include
leasehold acquisition costs, carrying charges of non-producing properties, costs
of drilling and completing wells, and oil and gas production equipment. Proceeds
received from the disposal of properties are normally credited against
accumulated costs unless this would result in a significant change in the
depletion rate, in which case, a gain or loss is computed and reflected in the
earnings statement.
The Company carries its oil and gas properties at the lower of capitalized
cost and net recoverable value. Net recoverable value is future net revenues
from proven reserves plus unproven properties at cost less impairment, if any,
net of the provision for future site restoration. Future net revenues are
determined using unit prices and production costs in effect at year-end and
include an allowance for future overhead costs, site restoration, financing
charges and income taxes that will be incurred in earning these revenues.
Petroleum and natural gas properties are depleted and tangible production
equipment is depreciated using the unit-of-production method based upon the
estimated proven oil and gas reserves after royalties. Reserves are converted to
common units based on the approximate equivalent energy content of each unit of
reserves, which results in a conversion ratio of six thousand cubic feet of gas
to one barrel of oil equivalent.
Processing facilities are depreciated on a straight-line basis over the
estimated useful life of each facility.
F-42
<PAGE>
CGGS CANADIAN GAS GATHERING SYSTEMS INC.
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
Provision for Future Site Restoration
Provision is made for future site restoration costs. This provision is
charged to earnings over the estimated life of the proven oil and gas reserves
and processing facilities using the unit of production and the straight-line
methods respectively, and is included with depletion and depreciation.
Royalties
Crown, freehold and overriding royalties and mineral taxes are net of
Alberta Royalty Tax Credits.
Deferred Financing Costs
The deferred financing costs are associated with obtaining the
subscriptions for units (see Note 2). These costs were amortized evenly over
fifteen years.
2. Formation and Unit Subscriptions
Under the Unit Subscription Agreement, the investors have subscribed for
units at U.S. $100,000 per unit consisting of U.S. $75,000 of debentures and
U.S. $25,000 of Class A shares (2,500 Class A shares at a price of U.S. $10 per
share) in a 3-to-1 ratio. The Company received commitments for unit
subscriptions totaling U.S. $114,700,000 (U.S. $86,025,000 of debentures and
2,867,500 Class A shares at U.S. $10 per share). At October 31, 1996, 1995 and
1994 98.12% of the subscriptions were paid for and debentures and shares issued.
On September 14, 1994, the Board of Directors approved a resolution to end
any further acquisitions by the investors and to close out the investor
obligations.
At October 31, 1996, U.S. $84,411,829 of debentures and U.S. $28,137,367
Class A shares were issued and outstanding.
Under Amendment No. 4 to the Unit Subscription Agreement dated May 15,
1995, in 1995 the Company is permitted to expend all of its funds from
operations after debt servicing and all applicable corporate tax, on capital
enhancements, repairs and maintenance. In 1996 and subsequent years, subject to
approval by eighty percent of all shareholders, the Company is permitted to
expend two-thirds of its funds from operations after debt servicing and all
applicable corporate tax on, capital enhancements, repairs and maintenance.
F-43
<PAGE>
CGGS CANADIAN GAS GATHERING SYSTEMS INC.
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
3. Capital Assets
October 31
-------------------------------------------
1994 1995 1996
-------------- ----------------------------
(unaudited)
Oil and Gas Properties:
Cost ................... $42,310,000 $43,361,000 $44,963,000
Accumulated depletion .. (20,267,000) (24,540,000) (28,197,000)
-------------- ----------------------------
22,043,000 18,821,000 16,766,000
-------------- ----------------------------
Tangible Production
Equipment:
Cost ................... 7,889,000 9,402,000 10,239,000
Accumulated depreciation (3,523,000) (4,450,000) (5,283,000)
-------------- ----------------------------
4,366,000 4,952,000 4,956,000
-------------- ----------------------------
Processing Facilities:
Cost ................... 118,623,000 127,696,000 133,979,000
Accumulated depreciation (15,600,000) (23,374,000) (31,844,000)
-------------- ----------------------------
103,023,000 104,322,000 102,135,000
-------------- ----------------------------
$129,432,000 $128,095,000 $123,857,000
============== ============================
During 1996 no acquisition fees (1995 - $0, 1994 - $27,000) were included
in the cost of capital assets. A provision for future site restoration of
$1,132,347 (1995 - $779,000, 1994 - $740,000, 1993 - $644,935) was expensed
during 1996.
4. Deferred Financing Costs
October 31
--------------------------------------
1994 1995 1996
--------------------------------------
(unaudited)
Deferred financing costs $2,187,000 $2,187,000 $2,187,000
Accumulated amortization (559,000) (705,000) (851,000)
--------------------------------------
$1,628,000 $1,482,000 $1,336,000
======================================
5. Long-Term Shareholders' Debt
The debentures are payable in U.S. dollars fifteen years from the date of
issue which is in the period 2005 to 2008. The debentures bear interest at 14%
per annum payable on a quarterly basis.
The Company is entitled, if the after-tax cash flow is not sufficient to
make interest payments, to satisfy interest payments by issuing additional
debentures valued at an amount equal to 100% of the principal amount thereof,
and Class A shares at $10.00 per share.
The debentures are held by the Class A shareholders.
F-44
<PAGE>
CGGS CANADIAN GAS GATHERING SYSTEMS INC.
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
6. Share Capital
Authorized
Unlimited Class A voting common shares.
Unlimited Class B non-voting common shares.
The Class B shares are not entitled to dividends. Upon payout, as defined
in the Company's Articles, each Class B share may be converted to a Class A
share and the Class B shareholders have a call option to purchase, in the
aggregate, 25% of the then outstanding debentures at a price of U.S. $10 for
each U.S. $75,000 principal amount of debentures.
Class B shares are issued equal to 33% of the Class A shares issued
pursuant to subscription calls. Class B shares are issued for U.S. $.01 per
share.
Issued for Cash
Class A Class B
---------------------------------------------------
Inception to October 31,
1993 2,770,599 $33,619,000 923,530 $11,000
Issued during 1994 43,139 582,000 14,380 -
------------- ------------- -------- --------
Balance at October 31,
1994, 1995 and 1996
(unaudited) 2,813,738 $34,201,000 937,910 $11,000
============= ============= ======== ========
7. Administration
Pursuant to the administration and management agreements, the following
expenses have been recorded:
Year Ended October 31
---------------------------------------------------
1993 1994 1995 1996
-------------------------------------- ------------
(unaudited)
Management fees ....... $2,105,000 $2,384,000 $2,613,000 $2,531,000
Administration fees ... 1,394,000 1,959,000 1,628,000 1,632,000
------------ ----------- ----------- ------------
3,499,000 4,343,000 4,241,000 4,163,000
Directors' fees and
expenses ............ 38,000 63,000 311,000 113,000
General corporate
expenses ............ 148,000 550,000 400,000 299,000
----------- ----------- ----------- -----------
3,685,000 4,956,000 4,952,000 4,575,000
Recoveries ............ - (996,000) (445,000) (458,000)
------------ ----------- ----------- -----------
$3,685,000 $3,960,000 $4,507,000 $4,117,000
============ =========== =========== ===========
F-45
<PAGE>
CGGS CANADIAN GAS GATHERING SYSTEMS INC.
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
General corporate expenses include third-party professional fees,
insurance and other items of a general corporate nature.
8. Income Taxes
At October 31, 1996, the Company has estimated deductions for income tax
purposes which exceed the related book value by $3,400,000, the potential
benefit of which have not been recognized in these financial statements. For
income tax purposes, the Company has reported non-capital loss carryforwards of
$50,350,000 at October 31, 1996, which expire as follows: 1997 - $415,000; 1998
- - $1,658,000; 1999 - $12,543,000; 2000 - $11,991,000; 2001 - $9,061,000; 2002 -
$11,247,000; 2003 - $3,435,000.
9. Related Party Transactions
At times, the Company enters into agreements and transactions related to
gas plants and gas reserves with Morrison Petroleums Ltd. and Canadian Gas
Gathering Systems II, Inc. These transactions are carried out in accordance with
industry standard terms.
During 1995, a consulting fee of $158,000 was paid to a founder and
director.
10. Commitments
The Company has a Management Agreement with Morrison Petroleums Ltd. to
provide services with respect to evaluation, acquisition, development and
construction of projects and Consulting Agreements with two other founders. The
Agreements are for ten years and provide for annual management and consulting
fees to be paid to the three parties totaling 1.5% of the original cost of all
projects, subject to certain adjustments as provided in the Agreements.
The Company has an Administration Agreement with Morrison Petroleums Ltd.
to provide administrative functions to the Company. This Agreement is for ten
years and provides for an annual administration fee of 5% of the net operating
income as defined in the agreement.
Under these agreements, fees were incurred and accrue to the founders as
follows:
Morrison Gas B.
Petroleums Systems Feshbach
Ltd. III & Sons
------------- ----------- -----------
Year ended October 31, 1993 $3,187,000 $496,000 $192,000
Year ended October 31, 1994 3,653,000 443,000 247,000
Year ended October 31, 1995 3,485,000 485,000 271,000
Year ended October 31, 1996
(unaudited)............. 3,363,000 513,000 287,000
F-46
<PAGE>
CGGS CANADIAN GAS GATHERING SYSTEMS INC.
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
Of the above fees which accrued to the founders, the following amounts
were outstanding at the periods ended as follows:
Morrison Gas B.
Petroleums Systems Feshbach
Ltd. III & Sons
------------ ----------- -----------
Year ended October 31,
1994 ................... $854,000 $92,000 $53,000
Year ended October 31,
1995 ................... 850,000 88,000 40,000
Year ended October 31,
1996 ................... 616,000 131,000 1,000
In addition, under the Administration Agreement, where Morrison Petroleums
Ltd is the operator of a gas system, capital and operating overhead is recovered
from the Company by Morrison Petroleums Ltd. following guidelines prescribed by
the Petroleum Accountants Society of Canada, Accounting Procedure at negotiated
rates.
11. Subsequent Events
Subsequent to October 31, 1996 the Company became a wholly owned
subsidiary of Abraxas Petroleum Corporation. Prior to the change in ownership,
the Company sold its interest in the Nevis gas plant and related facilities to
Morrison Petroleums, Ltd for a consideration of $120,000,000, converted its U.S.
dollar denominated debt to Canadian dollars and repaid the debt.
12. Differences Between Canadian and United States Generally Accepted Accounting
Principles
These financial statements have been prepared in accordance with Canadian
generally accepted accounting principles ("Canadian GAAP") which, in the case of
the Company, conforms with United States generally accepted accounting
principles ("US GAAP") in all material respects except as follows:
(a)In accordance with U.S. GAAP, exchange gains and losses arising on
translation of long-term monetary liabilities, unless designated as a
hedge, are included in income currently instead of deferred and
amortized over the lives of such long term liabilities.
(b)The Company has applied Statement of Financial Accounting Standards
Number 109 "Accounting for Income Taxes" ("SFAS 109") effective
November 1, 1992. SFAS 109 requires the Company to account for income
taxes using the liability method for US GAAP purposes. There was no
cumulative effect or effect on current results as a consequence of
adopting SFAS 109.
F-47
<PAGE>
CGGS CANADIAN GAS GATHERING SYSTEMS INC.
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
The impact of these changes on the Company's financial statements is as
follows:
Statement of Earnings
Year Ended October 31
------------------------------------------------------
1993 1994 1995 1996
------------- ------------- --------------------------
(unaudited)
Net earnings (loss) as
reported ............ $(3,691,000) $4,506,000 $(3,051,000) $(1,384,000)
Foreign currency
translation ......... (4,409,000) (1,829,000) 1,893,000 1,024,000
------------ ----------- ------------ ------------
Net earnings (loss) in
accordance with U.S.
GAAP ................$ (8,100,000) $2,677,000 $(1,158,000) $ (360,000)
============ ========== ============ ============
Increase
As Reported (Decrease) U.S. GAAP
------------- ------------- -------------
October 31, 1994
Deferred foreign exchange
loss ................... $9,775,000 $(9,775,000) $ -
Deficit .................. (1,343,000) 9,776,000 (11,119,000)
October 31, 1995
Deferred foreign exchange
loss ................... 7,882,000 (7,882,000) -
Deficit .................. (4,394,000) 7,883,000 (12,277,000)
October 31, 1996
Deferred foreign exchange
loss ................... 6,858,000 (6,858,000) -
Deficit .................. (5,778,000) 6,859,000 (12,637,000)
13. Changes in non-cash working capital components
Years Ended October 31
------------------------------------------------------
1993 1994 1995 1996
------------- ------------- --------------------------
(unaudited)
Decrease (increase) in
non-cash working
capital
Operating:
Accounts receivable $ (5,558,000) $ (562,000) $(1,231,000) $ (690,000)
Accounts payable 11,562,000 (4,881,000) (5,773,000) 2,866,000
------------ ------------ ------------ -----------
$ 6,004,000 $(5,443,000) $(7,004,000) $2,176,000
============ ============ ============ ===========
Investing:
Accounts payable $(38,023,000) $ -- $ -- $ --
Debenture interest
payable to
shareholders 2,742,000 (3,771,000) (54,000) (2,000)
------------- ------------ ------------ -------------
$(35,281,000) $(3,771,000) $ (54,000) $ (2,000)
============= ============ ============ =============
F-48
<PAGE>
Independent Auditors' Report
To the Board of Directors of
Enserch Exploration, Inc.
We have audited the accompanying statements of revenues and direct
operating expenses of Enserch Exploration, Inc.'s Wamsutter Area Package (the
"Package") (see Note 1) to be sold to Abraxas Petroleum Corporation for the
years ended December 31, 1995, 1994, and 1993. These financial statements are
the responsibility of the management of Enserch Exploration, Inc., as operator
of the properties. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. 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.
The accompanying statements of revenues and direct operating expenses
reflect the revenues and direct operating expenses attributable to the Package
as described in Note 1 to the financial statements and are not intended to be a
complete presentation of the revenues and expenses of the Package.
In our opinion, the accompanying financial statements present fairly, in
all material respects, the revenues and direct operating expenses of the Package
as described in Note 1 for the years ended December 31, 1995, 1994, and 1993, in
accordance with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Dallas, Texas
June 26, 1996
F-49
<PAGE>
ENSERCH EXPLORATION, INC.'S WAMSUTTER AREA PACKAGE
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
Nine Months Ended
Year Ended December 31 September 30
------------------------------- -----------------
1993 1994 1995 1995 1996
------- -------- -------- ------- --------
(in thousands) (Unaudited)
Revenues:
Oil, gas and related
product sales ............ $10,655 $10,171 $ 7,542 $ 5,262 $ 7,280
Direct operating expenses:
Lease operating expenses ... 431 640 1,029 894 776
Severance and
property taxes ............ 1,108 1,291 1,113 778 1,068
------- ------- ------- ------- -------
1,539 1,931 2,142 1,672 1,844
------- ------- ------- ------- -------
Excess of revenues over
direct operating
expenses ................... $ 9,116 $ 8,240 $ 5,400 $ 3,590 $ 5,436
======= ======= ======= ======= =======
The accompanying notes are an integral part of these statements.
F-50
<PAGE>
ENSERCH EXPLORATION, INC.'S WAMSUTTER AREA PACKAGE
NOTES TO STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES
1. The Properties
The accompanying statements represent the revenues and direct operating
expenses attributable to the net interest in Enserch Exploration, Inc.'s ("EEX")
Wamsutter Area Package producing wells and certain non-producing leases to be
sold to Abraxas Petroleum Corporation ("Abraxas"). The properties are located in
Sweetwater and Canton County, Wyoming. EEX acquired the properties on June 8,
1995 when it purchased all of the capital stock of Dalen Corporation. Effective
January 1, 1996, Dalen Corporation was merged into EEX.
Historical financial statements reflecting financial position, results of
operations and cash flows required by generally accepted accounting principles
are not presented, as such information is neither readily available on an
individual property basis nor meaningful for the properties acquired because the
entire acquisition cost is being assigned to oil and gas properties.
Accordingly, these statements of revenues and direct operating expenses are
presented in lieu of the financial statements required under Rule 3-05 of
Securities and Exchange Commission Regulation S-X.
The accompanying statements of revenues and direct operating expenses
represent EEX's net working interest in the properties to be acquired by Abraxas
and are presented on the full cost accrual basis of accounting. Depreciation,
depletion and amortization, allocated general and administrative expense,
interest expense and income, and income taxes have been excluded because the
property interests acquired represent only a portion of a business and the
expenses incurred are not necessarily indicative of the expenses to be incurred
by Abraxas.
2. Contingent Liabilities
Given the nature of the properties acquired and as stipulated in the
purchase agreement, Abraxas is subject to loss contingencies pursuant to
existing or expected environmental laws, regulations, and losses covering the
acquired properties.
3. Oil and Gas Reserves (Unaudited)
The following table of estimated proved and proved developed reserves of
oil and gas related to the Wamsutter Area Package properties has been prepared
utilizing estimates of period-end reserve quantities provided by independent
petroleum consultants.
Oil Gas
(Bbl) (a) (Mcf)
------------- -------------
At January 1, 1993 .... 547,125 43,339,881
Production .......... (65,283) (4,498,193)
Other changes, net .. 28,903 553,355
------------- -------------
At January 1, 1994 .... 510,745 39,395,043
Production .......... (288,763) (4,712,683)
Other changes, net .. 1,915,650 1,298,888
------------- -------------
At January 1, 1995 .... 2,137,632 35,981,248
Production .......... (303,076) (4,285,734)
Other changes, net .. l,390,493 8,838,026
============= =============
At January 1, 1996 .... 3,225,049 40,533,540
============= =============
F-51
<PAGE>
ENSERCH EXPLORATION, INC.'S WAMSUTTER AREA PACKAGE
NOTES TO STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES
Oil Gas
(Bbl) (Mcf)
------------- -------------
Proved Developed
Reserves:
At January 1, 1993 .... 547,125 43,339,881
At January 1, 1994 .... 510,745 39,395,043
At January 1, 1995 .... 2,137,632 35,981,248
At January 1, 1996 .... 2,942,115 36,559,004
- ------------------
(a) Includes condensate and natural gas liquids attributable to leasehold
interests of 2,655,476 Bbls for January 1, 1996 and 1,669,664 Bbls for
January 1, 1995. Prior to l994, gas was not processed to extract natural
gas liquids.
4. Standardized Measure (Unaudited)
Discounted future net cash flows relating to proved gas and oil reserve
quantities (unaudited) have been prepared using estimated future production
rates and associated production and development costs. Continuation of economic
conditions existing at the balance sheet date was assumed. Accordingly,
estimated future net cash flows were computed by applying prices and contracts
in effect at period end to estimated future production of proved gas and oil
reserve, estimating future expenditures to develop proved reserves and
estimating costs to produce the proved reserves based on average costs for the
period. Average prices used in the computations were: Gas (per Mcf) $2.08 in
1995, $1.45 in 1994 and $2.40 in 1993; Oil (per barrel) $11.17 in 1995, $7.22 in
1994 and $13.52 in 1993.
Because reserve estimates are imprecise and changes in the other variables
are unpredictable, the standardized measure should be interpreted as indicative
of the order of magnitude only and not as precise amounts.
1995 1994 1993
-------------------------------------
Standardized Measure (in
thousands):
Future cash inflows ........ $ 120,278 $ 67,597 $ 101,445
Future production and (25,971) (17,121) (19,710)
development costs ........
Future income-tax expense .. (16,137) (14,873) (25,525)
-------------------------------------
Future net cash flows ...... 78,170 35,603 56,210
Less 10% annual discount ... 35,565 14,095 23,727
=====================================
Standardized measure of
discounted future net
cash flows ............... $ 42,605 $ 21,508 $ 32,483
=====================================
Change in Standardized Measure
(in thousands):
Sales and transfers of gas
and oil produced, net of
production costs ......... $ (5,400) $ (8,240) $ (9,116)
Changes in prices, net of
production and future
development costs ........ 14,280 (21,828) 4,903
Accretion of discount ...... 2,151 3,248 3,326
Net change in income taxes . 190 5,765 240
Additions, revisions and
offer changes ............ 9,876 10,080 (125)
=====================================
Total .................. $ 21,097 $ (10,975) $ (772)
=====================================
F-52
<PAGE>
Report of Independent Auditors
Board of Directors
Abraxas Petroleum Corporation
We have audited the accompanying statements of combined oil and gas revenues and
direct operating expenses of the Certain Overriding Royalty Interests in the
Portilla Field Acquired by Abraxas Petroleum Corporation (Abraxas) for the years
ended December 31, 1994 and 1995. These statements are the responsibility of
Abraxas' management. Our responsibility is to express an opinion on the
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the statements of combined oil and gas
revenues and direct operating expenses are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the statements of combined oil and gas revenues and direct
operating expenses. An audit also includes assessing the basis of accounting
used and significant estimates made by management, as well as evaluating the
overall presentation of the statements. We believe that our audits provide a
reasonable basis for our opinion.
The accompanying statements of combined oil and gas revenues and direct
operating expenses were prepared for the purpose of complying with the rules and
regulations of the Securities and Exchange Commission as described in Note 1,
are not intended to be a complete presentation of the combined oil and gas
revenues and expenses of Certain Overriding Royalty Interests in the Portilla
Field Acquired by Abraxas.
In our opinion, the statements referred to above present fairly, in all material
respects, the combined oil and gas revenues and direct operating expenses of
Certain Overriding Royalty Interests in the Portilla Field Acquired by Abraxas
for the years ended December 31, 1994 and 1995 in conformity with generally
accepted accounting principles.
ERNST & YOUNG LLP
San Antonio, Texas
August 30, 1996
F-53
<PAGE>
CERTAIN OVERRIDING ROYALTY INTERESTS IN THE PORTILLA FIELD
ACQUIRED BY ABRAXAS PETROLEUM CORPORATION
STATEMENTS OF COMBINED OIL AND GAS REVENUES
AND DIRECT OPERATING EXPENSES
Nine Months Ended
Year Ended December 31 September 30
-------------------------- ------------------------
1994 1995 1995 1996
-------------------------- ------------------------
(Unaudited)
Oil and gas revenues $3,529,234 $3,675,596 $2,608,169 $2,821,855
Direct operating expenses:
Production taxes 908,421 835,092 590,019 621,656
---------- ------------ ----------- ---------
Oil and gas revenues in
excess of direct
operating expenses $2,620,813 $2,840,504 $2,018,150 $2,200,199
========== ========== ========== ==========
See accompanying notes.
F-54
<PAGE>
CERTAIN OVERRIDING ROYALTY INTERESTS IN THE PORTILLA FIELD
ACQUIRED BY ABRAXAS PETROLEUM CORPORATION
NOTES TO STATEMENTS OF COMBINED OIL AND GAS REVENUES
AND DIRECT OPERATING EXPENSES
Years Ended December 31, 1994 and 1995
(Information as to the Nine Months Ended September 30, 1995
and 1996 is Unaudited)
1. Basis of Presentation
The accompanying statement of combined oil and gas revenues and direct
operating expenses represents the results from certain oil and gas producing
properties located in the Portilla Field, San Patricia County, Texas --
(Properties) which were previously owned by the Commingled Pension Trust Fund
(Petroleum II) (the Pension Fund) which were acquired in connection with the
acquisition by Abraxas Petroleum Corporation (Abraxas). Abraxas acquired the
remaining 75% partnership interest in Portilla-1996, L.P., the limited partner
of which acquired the above interests from the Pension Fund on March 21, 1996
and contributed such interest to the Partnership.
Full historical financial statements reflecting financial position,
results of operations, and cash flows required by generally accepted accounting
principles are not presented, as such information is not readily available on an
individual property basis nor meaningful for the properties acquired because the
entire acquisition cost is being assigned to oil and gas properties.
Accordingly, these statements of combined oil and gas revenues and direct
operating expenses are presented in lieu of the financial statements required
under Rule 3-05 of Regulation S-X of the Securities and Exchange Commission.
The accompanying statements of combined oil and gas revenues and direct
operating expenses represent the net overriding royalty interests in the
Properties to be acquired by Abraxas and are presented on the accrual basis of
accounting. Depreciation, depletion and amortization, general and administrative
expenses, interest expense, and federal and state income taxes have been
excluded because the property interests acquired represent only a portion of a
business and the expenses incurred are not necessarily indicative of the
expenses to be incurred by Abraxas.
The unaudited statements of combined oil and gas revenues and direct
operating expenses for the nine months ended September 30, 1995 and 1996
include, in the opinion of management, all material adjustments (consisting of
only normal recurring adjustments) necessary for a fair presentation. The
results of the nine months ended September 30, 1996, are not necessarily
indicative of the results to be expected for the full year.
F-55
<PAGE>
CERTAIN OVERRIDING ROYALTY INTERESTS IN THE PORTILLA FIELD
ACQUIRED BY ABRAXAS PETROLEUM CORPORATION
NOTES TO STATEMENTS OF COMBINED OIL AND GAS REVENUES
AND DIRECT OPERATING EXPENSES (CONTINUED)
2. Supplemental Information Relating to Oil and Gas Producing Activities
(Unaudited)
The following table presents the estimate of the net proved crude oil and
natural gas quantities related to the interests in the Properties acquired and
have been prepared utilizing the estimates of reserve quantities prepared by
independent petroleum reserve engineers.
Liquid Natural
Hydrocarbons Gas
-------------- --------------
(Barrels) (Mcf)
Proved developed and undeveloped reserves:
Balance at December 31, 1993 ........... 2,060,000 7,309,000
Revisions of previous estimates ....... 240,000 (1,374,000)
Production ............................ (207,000) (256,000)
-------------- --------------
Balance at December 31, 1994 ........... 2,093,000 5,679,000
Revisions of previous estimates ....... (245,000) (2,290,000)
Production ............................ (176,000) (497,000)
Other changes, net .................... 306,000 681,000
-------------- --------------
Balance at December 31, 1995 ........... 1,978,000 3,573,000
Revisions of previous estimates ....... (417,000) (974,000)
Production ............................ (81,000) (209,000)
Other changes, net .................... 208,000 10,000
-------------- --------------
Balance at June 30, 1996 ............... 1,688,000 2,400,000
============== ==============
Proved developed reserves:
December 31, 1994 ...................... 1,782,000 4,727,000
December 31, 1995 ...................... 1,722,000 3,378,000
June 30, 1996 .......................... 1,677,000 2,331,000
All of the above reserves are located in the United States.
F-56
<PAGE>
CERTAIN OVERRIDING ROYALTY INTERESTS IN THE PORTILLA FIELD
ACQUIRED BY ABRAXAS PETROLEUM CORPORATION
NOTES TO STATEMENTS OF COMBINED OIL AND GAS REVENUES
AND DIRECT OPERATING EXPENSES (CONTINUED)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves
The following disclosures concerning the standardized measure of future
cash flows from proved crude oil and natural gas reserves are presented in
accordance with Statement of Financial Accounting Standards No. 69. The
standardized measure does not purport to represent the fair market value of the
Properties' 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 prices at December 31, 1995 and June 30, 1996 to the estimated future
production of period-end proved reserves. Future cash inflows were reduced by
estimated future production and development costs based on period-end costs to
determine pre-tax cash inflows. The Properties are not, nor is the Owner, a
separate tax paying entity. Accordingly, the standardized measure of discounted
future net cash flows from proved reserves is presented before deduction of
federal income taxes.
Future net cash inflows were discounted using a 10% annual discount rate
to arrive at the Standardized Measure.
F-57
<PAGE>
CERTAIN OVERRIDING ROYALTY INTERESTS IN THE PORTILLA FIELD
ACQUIRED BY ABRAXAS PETROLEUM CORPORATION
NOTES TO STATEMENTS OF COMBINED OIL AND GAS REVENUES
AND DIRECT OPERATING EXPENSES (CONTINUED)
Set forth below is the Standardized Measure relating to proved oil and gas
reserves for December 31, 1995 and June 30, 1996:
December 31 June 30
---------------------------
1994 1995 1996
------------- ------------- -------------
Standardized Measure:
Future cash inflows ..... $40,963,000 $43,052,000 $38,232,000
Future production and
development costs ...... 12,078,000 13,490,000 12,268,000
------------- ------------- -------------
28,885,000 29,562,000 25,964,000
Discount ................ (11,498,000) (10,622,000) (11,703,000)
------------- ------------- -------------
Discounted future net cash
flows before income
taxes ................... $17,387,000 $18,940,000 $14,261,000
============= ============= =============
Change in Standardized Measure (in thousands):
Standardized Measure,
beginning of period .... $11,427,000 $17,387,000 $18,940,000
Sales and transfers
of gas and oil
produced, net of
production costs ... (2,621,000) (2,841,000) (1,482,000)
Changes in prices,
net of production
and future
development costs .. 6,639,000 2,661,000 627,000
Revisions of
previous quantity
estimates .......... 63,000 (3,168,000) (4,001,000)
Accretion of
discount .......... 1,854,000 1,739,000 947,000
Additions,
revisions, and
other changes ...... 25,000 3,162,000 (770,000)
------------- ------------- -------------
Standardized Measure,
end of period ........ $17,387,000 $18,940,000 $14,261,000
============= ============= =============
F-58
<PAGE>
Report of Independent Auditors
The Board of Directors and Shareholders
Canadian Abraxas Petroleum Limited (a Canadian corporation)
We have audited the accompanying balance sheet of Canadian Abraxas
Petroleum Limited as of September 30, 1996. This balance sheet is the
responsibility of the Company's management. Our responsibility is to express an
opinion on this balance sheet based on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statement is free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statement. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the balance sheet referred to above presents fairly, in
all material respects, the financial position of Canadian Abraxas Petroleum
Limited at September 30, 1996, in conformity with generally accepted accounting
principles.
ERNST & YOUNG LLP
San Antonio, Texas
October 7, 1996
F-59
<PAGE>
CANADIAN ABRAXAS PETROLEUM LIMITED
BALANCE SHEET
September 30, 1996
ASSETS
Subscription receivable ........................ $ 1
==========
Total assets ................................ $ 1
==========
LIABILITIES AND SHAREHOLDER'S EQUITY
Shareholder's equity:
Common stock, no par value; unlimited number
of shares authorized, issued and outstanding
-0- shares (Subscribed 1 share).............. $ 1
Preferred stock, no par value; unlimited
number of shares authorized, issued and
outstanding -0- shares ...................... -
==========
Total liabilities and shareholder's equity .............. $ 1
==========
See accompanying notes.
F-60
<PAGE>
CANADIAN ABRAXAS PETROLEUM LIMITED
NOTES TO BALANCE SHEET
September 30, 1996
1. Organization and Operations
Canadian Abraxas Petroleum Limited, a Canadian Corporation (Canadian
Abraxas), was capitalized by Abraxas Petroleum Corporation for the principal
purpose of acquiring 100% of the outstanding capital stock of CGGS Canadian Gas
Gathering Systems, Inc. (CGGS), after the consummation of the sale of the Nevis
Plant. CGGS owns producing properties in western Canada, consisting primarily of
natural gas reserves, natural gas gathering systems, and processing facilities.
Canadian Abraxas has conducted no business and has no employees or operating
history as of September 30, 1996. Due to the absence of business activity as of
September 30, 1996, no statement of operations or cash flows is presented.
2. Subsequent Events (unaudited)
On November 14, 1996, Abraxas Petroleum Corporation, through its wholly
owned subsidiary, Canadian Abraxas, closed the acquisition of CGGS with a
portion of the proceeds from the issuance of $215,000,000 of Senior Notes due
2004 (Notes). Abraxas Petroleum Corporation and Canadian Abraxas are jointly and
severally liable for all obligations under the Notes. In connection with the
close of the transaction, Canadian Abraxas incurred a liability of approximately
$82,000,000 of the $215,000,000 liability. The Notes are redeemable, in whole or
in part, at the option of the Company and Abraxas Petroleum Corporation on or
after November 1, 2000, and any time prior to November 1, 1999, the Company and
Abraxas Petroleum Corporation may redeem up to 35% of the aggregate principal
amount of the Notes with cash proceeds of equity offerings at a redemption price
of 111.5% of the aggregate principal amount of the Notes to be redeemed. The
terms of the Indenture related to the Notes provide for certain financial
covenants which may limit the ability of the Company to incur additional debt.
Additionally, in connection with the close of the transaction, CGGS was
immediately merged with and into Canadian Abraxas, and Canadian Abraxas, as the
surviving entity, used the net proceeds from the sale of the Nevis gas
processing plant to retire all of the outstanding debentures of CGGS.
F-61
<PAGE>
A-1
<PAGE>
No person is authorized in connection
with any offer made hereby to give any
information or to make any
representation not contained in this
Prospectus in connection with the
offering made hereby and, if given or
made, such information or representation
must not be relied upon as having been
authorized by the Issuers. This
Prospectus does not constitute an offer
to sell, or a solicitation of an offer
to purchase, any securities in any
jurisdiction in which, or to any person
to whom, it is unlawful to make such
offer or solicitation. Neither the
delivery of this Prospectus or the
accompanying Letter of Transmittal or
both together nor any exchange of
securities made hereunder shall, under
any circumstances, create any inference ABRAXAS PETROLEUM
that there has not been any change in CORPORATION
the affairs of the Issuers since the
date hereof.
------------------------- CANADIAN ABRAXAS
PETROLEUM LIMITED
TABLE OF CONTENTS
Page
Summary............................5
Risk Factors......................19
Purpose of the Exchange Offer.....11
Resale of the Exchange Note.......27
Plan of Distribution..............27
The Exchange Offer................28
Exchange Agent....................34
Use of Proceeds...................35
Capitalization....................36
Pro Forma Financial Information...37
Selected Consolidated Financial
Information..................... 45 Offer to Exchange
Management's Discussion and 11.5% Senior Notes Due 2004, Series B
Analysis of Financial Condition for any and all Outstanding
and Resultsof Operations... .....47 11.5% Senior Notes due 2004, Series A
Business..........................54
Management........................74
Executive Compensation............77
Securities Holdings of Principal
Stockholders Directors and
Officers.........................80
Description of the Notes..........83
Description of Capital Stock.....111
Certain United States and Canadian
Income Tax Considerations......118
Transactions with Related Parties123
Book-Entry; Delivery and Form....123
Available Information............125
Enforceability of Civil
Liabilities Against Foreign
Persons.........................125
Legal Matters....................126
Experts..........................126
Glossary of Terms................127
Index to Consolidated
Financial Statements............F-1
Until March 3, 1997 (25 days after
the date of this Prospectus) all dealers [LOGO]
effecting transactions in the registered
securities, whether or not participating
in this distribution, may be required to
deliver a Prospectus. This is in
addition to the obligation of dealers to
deliver a prospectus when acting as
underwriters and with respect to their
unsold allotments or subscriptions.
Prospectus
February 5, 1997
