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<SEC-DOCUMENT>0000867665-97-000005.txt : 19970401
<SEC-HEADER>0000867665-97-000005.hdr.sgml : 19970401
ACCESSION NUMBER: 0000867665-97-000005
CONFORMED SUBMISSION TYPE: 10-K
PUBLIC DOCUMENT COUNT: 2
CONFORMED PERIOD OF REPORT: 19961231
FILED AS OF DATE: 19970331
SROS: NASD
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: ABRAXAS PETROLEUM CORP
CENTRAL INDEX KEY: 0000867665
STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311]
IRS NUMBER: 742584033
STATE OF INCORPORATION: NV
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-K
SEC ACT: 1934 Act
SEC FILE NUMBER: 000-19118
FILM NUMBER: 97570609
BUSINESS ADDRESS:
STREET 1: 500 N LOOP 1604 EAST STE 100
CITY: SAN ANTONIO
STATE: TX
ZIP: 78209
BUSINESS PHONE: 2104904788
MAIL ADDRESS:
STREET 1: 500 N LOOP 1604 EAST STE 100
CITY: SAN ANTONIO
STATE: TX
ZIP: 78232
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K
<SEQUENCE>1
<DESCRIPTION>ABRAXAS PETROLEUM CORPORATION FORM 10-K
<TEXT>
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the Fiscal Year Ended December 31, 1996
[ ]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission File Number 0-19118
ABRAXAS PETROLEUM CORPORATION
(Exact name of Registrant as specified in its charter)
Nevada 74-2584033
(State or Other Jurisdiction of (I.R.S. Employer Identification Number)
Incorporation or Organization)
500 N. Loop 1604 East, Suite 100
San Antonio, Texas 78232
Registrant's telephone number,
including area code (210) 490-4788
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
None
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Common Stock, par value $.01 per share
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No __
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
The aggregate market value of the voting stock (which consists solely of
shares of Common Stock) held by non-affiliates of the registrant as of March 21,
1997, (based upon the average of the $10.50 per share "Bid" and $10.75 per share
"Asked" prices), was approximately $45,911,049 on such date.
The number of shares of the issuer's Common Stock, par value $.01 per
share, outstanding as of March 21, 1997 was 5,732,101 shares of which 4,878,049
shares were held by non-affiliates.
Documents Incorporated by Reference: Portions of the registrant's Proxy
Statement relating to the 1997 Annual Meeting of Shareholders to be held on May
23, 1997 have been incorporated by reference herein (Part III).
1
<PAGE>
ABRAXAS PETROLEUM CORPORATION
FORM 10-K
TABLE OF CONTENTS
PART I
Page
Item 1. Business. ........................................................4
General ......................................................4
Principal Areas of Activity....................................5
Markets and Customers..........................................6
Risk Factors...................................................7
Regulation of Crude Oil and Natural Gas Activities............13
Natural Gas Price Controls....................................14
State Regulation of Crude Oil and Natural Gas Production......15
Environmental Regulation......................................18
Employees.....................................................18
Recent Activities.............................................18
Item 2. Properties.......................................................19
Exploratory and Developmental Acreage.........................19
Productive Wells..............................................19
Reserves Information..........................................20
Crude Oil and Natural Gas Production and Sales Price .........21
Drilling Activities...........................................22
Office Facilities.............................................23
Other Properties..............................................23
Item 3. Legal Proceedings................................................23
Item 4. Submission of Matters to a Vote of
Security Holders............................................23
Item 4a.Executive Officers of the Company.................................23
PART II
Item 5. Market for Registrant's Common Equity
and Related Stockholder Matters.............................24
Market Information............................................24
Holders.......................................................24
Dividends.....................................................24
Item 6. Selected Financial Data..........................................25
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations.................25
Results of Operations.........................................25
Liquidity and Capital Resources...............................28
2
<PAGE>
Item 8. Financial Statements and Supplementary Data......................31
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure......................31
PART III
Item 10. Directors and Executive Officers................................32
Item 11. Executive Compensation..........................................32
Item 12. Security Ownership of Certain Beneficial Owners and Management..33
Item 13. Certain Relationships and Related Transactions..................33
PART IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K....................................33
3
<PAGE>
PART I
Item 1. Business
General
Abraxas Petroleum Corporation, a Nevada corporation ("Abraxas" or the
"Company") 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, the Permian Basin of western Texas, Canada
and Wyoming. The Company's business strategy is to acquire and develop producing
crude oil and natural gas properties and related assets that contain the
potential for increased value through exploitation and development. 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 general and
administrative expenses per barrel of crude oil equivalent ("BOE"). Since
December 31, 1990, the Company has made 16 acquisitions of crude oil and natural
gas producing properties totaling an estimated 46.0 million barrels of crude oil
equivalent ("MMBOE") of proved reserves at an average acquisition cost of
approximately $3.83 per BOE.
Since January 1996, the Company has had operations in the United
States and Canada and since November 1996, the Company's operations have
consisted of two segments: exploration and production and natural gas gathering
and processing. The revenues and operating earnings for each country and each
industry segment and the identifiable assets attributable to each country and
each industry segment for the year ended December 31, 1996 are set forth in Note
15 to the Notes to Consolidated Financial Statements included elsewhere herein.
At December 31, 1996, the Company operated 364 wells and owned
non-operated interests in 155 net wells. Average net daily production for the
year ended December 31, 1996 was 1,985 barrels ("Bbls") of crude oil and natural
gas liquids and 17,397 thousand cubic feet ("Mcf") of natural gas. The Company's
proved reserves and present value (discounted at 10%) of estimated future net
cash flows (before income taxes) of proved crude oil and natural gas reserves
("Present Value of Proved Reserves") has increased from an estimated 889
thousand barrels of crude oil equivalent ("MBOE") and $11.9 million,
respectively, at January 1, 1991 to an estimated 47.5 MMBOE and $415.9 million,
respectively, at January 1, 1997. Of the Company's proved reserves at January 1,
1997, 86.6% were classified as proved developed reserves and 87.5% of the
Present Value of Proved Reserves at such date was attributable to such proved
developed reserves. The Company also owned varying interests in 13 natural gas
processing plants or compression facilities with capacity of 128.0 MMCF per day
and 197 miles of natural gas gathering systems.
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 intends to continue its
growth strategy emphasizing reserve additions through its exploitation efforts.
There can be no assurance that attractive acquisition opportunities will arise,
that the Company will be able to consummate acquisitions in the future or that
sufficient external or internal funds will be available to fund the Company's
acquisitions. The Company may also use, where appropriate, it's equity
securities as all or part of the consideration for such acquisitions.
Although the Company intends to devote most of its resources to the
exploitation and development of the producing properties acquired, the Company
intends to selectively participate in the exploration for new reserves of crude
oil and natural gas. The Company intends to develop prospects internally and to
participate with industry partners in prospects generated by other parties in
its exploration activities.
The Company periodically evaluates, and from time to time has elected
to sell, certain of its mature producing properties. Such sales enable the
Company to maintain financial flexibility, reduce overhead and redeploy the
proceeds therefrom to activities that the Company believes to have a potentially
higher financial return. See "Recent Activities".
4
<PAGE>
Principal Areas Of Activity
Texas Gulf Coast and South Texas
Portilla Field, San Patricio County, Texas The Company acquired a 50%
working interest in the Portilla Field in April 1993 and the remaining 50% in
November 1996. The field, discovered in the 1950's by Superior Oil Company,
produces from numerous Miocene, Frio and Vicksburg age sands from depths between
4,000 feet and 9,000 feet. A report prepared by independent petroleum engineers
showed estimated net proved reserves of 3.3 million barrels ("MMBbls") of crude
oil and natural gas liquids and 5.0 billion cubic feet ("Bcf") of natural gas
from this field, with a Present Value of Proved Reserves of $36.1 million at
January 1, 1997. For the year ended December 31, 1996, the field produced an
average of approximately 611 net Bbls of crude oil and 219 net Bbls of natural
gas liquids per day and sold approximately 1,867 net Mcf of natural gas per day
from 33 active wells. The Company also owns a 100% interest in a natural gas
processing plant with capacity of approximately 20 MMcf per day. The Company is
the operator of the natural gas processing plant and all of the wells in this
field.
East White Point Field, San Patricio County, Texas. The Company
acquired an approximate 30% working interest in this field in April 1993 and an
additional 30% interest in November 1996. The field produces crude oil and
natural gas from numerous sands in the Lower Frio formation from 9,000 feet to
13,000 feet. A report prepared by independent petroleum engineers showed
estimated net proved reserves of 3.2 MMBbls of crude oil and natural gas liquids
and 29.7 Bcf of natural gas from this field with a Present Value of Proved
Reserves of $60.0 million at January 1, 1997. The Company operates 11 wells and
Marathon Oil Company ("Marathon") operates another 10 wells in which the Company
has an interest in this field. For the year ended December 31, 1996, the field
produced an average of approximately 184 net Bbls of crude oil and 250 net Bbls
of natural gas liquids per day and sold 3,266 net Mcf of natural gas per day
from 19 active wells. The Company also owns an approximate 43% interest in a
natural gas processing plant. The Company is the operator of this natural gas
processing plant.
Stedman Island Field, Nueces County, Texas. The Company acquired a
25% working interest in this field in April 1993, an additional 25% in October
1995 and the remaining 50% in November 1996. The field produces crude oil and
natural gas from the Frio sands at depths of 8,500 to 10,000 feet. A report
prepared by independent petroleum engineers showed estimated net proved reserves
of 519.7 MBbls of crude oil and natural gas liquids and 10.1 Bcf of natural gas
from this field with a Present Value of Proved Reserves of $16.5 million at
January 1, 1997. During 1996, the field produced an average of approximately 50
net Bbls of crude oil and natural gas liquids and 966 net Mcf of natural gas per
day.
Permian Basin - West Texas
Delaware Area (Howe, ROC, Block 16, Taurus, Gomez, N.E. Oates and
Nine Mile Draw Fields). In connection with the acquisition of producing
properties located in West Texas from a group of sellers in July 1994 (the "West
Texas Properties"), the Company acquired working interests ranging from 18% to
100% in 35 wells, 29 of which are operated by the Company. The fields produce
from Devonian, Wolfcamp, Ellenburger and Cherry Canyon sands from depths ranging
from 6,500 feet to 17,600 feet. A report prepared by independent petroleum
engineers showed estimated net proved reserves of 4.6 MMBbls of crude oil and
natural gas liquids and 29.9 Bcf of natural gas in these fields, with a Present
Value of Proved Reserves of $91.9 million at January 1, 1997. During 1996 the
Company drilled 22 wells in this area and produced an average of 6,509 net MCF
of natural gas and 650 net Bbls of crude oil and natural gas liquids per day
from these fields.
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. The two fields produce crude oil
from Permian age carbonates between 1,700 feet and 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. A report prepared by independent petroleum engineers showed
estimated net proved reserves of 1.4 MMBbls of crude oil and natural gas liquids
from this field, with a Present Value of Proved Reserves of $8.4 million at
January 1, 1997. For the year ended December 31, 1996, the Company produced an
average of approximately 171 net Bbls of crude oil per day from these fields.
The Company is currently investigating waterflooding and development drilling to
enhance production.
5
<PAGE>
Canada
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 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 52% of the outstanding capital
stock of Cascade. Cascade owns 4.3 net producing crude oil and natural gas wells
and 12,000 net acres of undeveloped leases in southwestern Saskatchewan. A
report prepared by independent petroleum engineers showed estimated net proved
reserves of 120 MBbls of crude oil, with a Present Value of Proved Reserves of
$1.3 million (CDN) approximately $950,000 (U.S.), at January 1, 1997.
In November 1996, the Company's wholly owned subsidiary, Canadian
Abraxas Petroleum Limited ("Canadian Abraxas") acquired 100% of the outstanding
capital stock of CGGS Canadian Gas Gathering Systems Inc. ("CGGS"). 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 (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 of January 1, 1997, the Canadian Abraxas
Properties had total proved reserves of 10,382 MBOE (88.5% natural gas) with
Present Value of Proved Reserves of $85.4 million, 88.6% 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 December
31, 1996. For the twelve months ended December 31, 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% (9.7% net) was custom processed for third parties.
Wyoming
On September 30, 1996, the Company acquired producing properties in
the Wamsutter area of southwestern Wyoming (the "Wyoming Properties"). 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
January 1, 1997, the Wyoming properties had proven reserves of 10,570 MBOE
(69.2% natural gas) with Present Value of Proved Reserves of $108.2 million,
89.5% of which was attributable to proved developed reserves.
Markets and Customers
The revenues 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 and the Canadian economies (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 revenues, profitability and cash flow.
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.
6
<PAGE>
In connection with the reacquisition of the Portilla and Happy Fields
in November 1996, the Company assumed certain commodity swaps on variable
volumes of oil and gas. The agreements settle monthly with amounts either due to
or from Christiania Bank, New York Branch ("Christiania") based on the
differential between a fixed and a variable price for crude oil and natural gas.
During 1997, the approximate monthly volume of crude oil sales subject to this
swap agreement is 15,800 barrels at a fixed price of $17.20. This agreement
reduces to approximately 13,200 barrels per month in 1998, 11,000 barrels per
month in 1999, 9,100 barrels per month in 2000 and 8,200 barrels per month in
2001 until November 1. The fixed price paid to the Company over this five year
period averages $17.55 per barrel. The natural gas component of this agreement
calls for approximately 54,000 MMBTU per month at a fixed price of $1.80 during
1997 with volumes decreasing to 37,000 MMBTU per month in 1998, 24,000 MMBTU per
month in 1999, 19,000 MMBTU per month in 2000, and 15,000 MMBTU per month in
2001 through October. The fixed price paid to the Company over this five year
period averages $1.84 per MMBTU.
The Company has also entered into two fixed price agreements, each
relating to approximately 3,750 net MMBTU per day of natural gas. The first of
these two agreements expires on March 31, 1997 and calls for a fixed price of
$1.52 per MMBTU being paid to the Company. The second agreement expires on
October 31, 1997 and provides a fixed price of $1.42 per MMBTU to the Company.
The Company has also recently entered into a costless collar relating
to 1,000 barrels a day of oil sales for the period February 1, 1997 through
December 31, 1997. This agreement guarantees a minimum price of $19.00 per
barrel to the Company and provides that any amount above $25.60 per barrel be
remitted by the Company to the counterparty to the agreement.
Substantially all of the remainder 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, seven
purchasers accounted for approximately 66% 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.
Risk Factors
Industry Conditions; Impact on Company's Profitability
The Company's revenues, 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 prior to 1996
were depressed by excess total domestic and imported supplies. While prices for
crude oil and natural gas increased during 1996 and have remained at these
levels during the first quarter of 1997, there can be no assurance that current
price levels for crude oil and natural gas can be sustained. Prices are also
affected by actions of state and local agencies, the United States and foreign
governments and international cartels. 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
Company's outstanding indebtedness 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. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Liquidity and
Capital Resources".
7
<PAGE>
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.
Losses From Operations
The Company has experienced recurring losses. For the years ended
December 31, 1993, 1994 and 1995, the Company recorded net losses of $2.4
million, $2.4 million and $1.2 million, respectively. Although the Company had
net income of $ 1.5 million for the year ended December 31, 1996, there can be
no assurance that the Company will not experience operating losses 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,
formations with abnormal pressures, cratering and crude oil spills 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.
Leverage and Debt Service
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.
As of December 31, 1996, the Company's total debt and stockholders'
equity were approximately $215.0 million and $35.7 million, respectively. In
addition, the Company had $20.0 million of unused borrowing capacity under the
Credit Facility (as defined below) at December 31, 1996. 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
(the "Indenture") governing its 11.5% Senior Notes Due 2004 (the "Notes") and
the Credit Facility.
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 Company's Consolidated Financial Statements
and the notes thereto 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.
8
<PAGE>
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.
The Company's Credit Facility ("the Credit Facility") with Bankers
Trust Company, as agent, ING (U.S.) Capital Corporation, as co-agent and Union
Bank of California, N.A. (collectively the "Banks") contains a number of
covenants, including the following: (1) the ratio of current assets to current
liabilities (exclusive of any part of the loan which is current) shall not be
less than 1:1, (2) the ratio of (a) EBITDA to (b) Interest expense, measured as
of the last day of any calendar quarter for the twelve month period then ended,
shall not be less than 1.50 to 1.00 as of the last day of any calendar quarter
through June 30, 1997 or to be less than 1.75 to 1.00 as of the last day of any
calendar quarter after June 30, 1997 and (3) Consolidated Tangible Net Worth
must be greater than $30,000,000 at any time. The Credit Facility also contains
covenants related to maintaining corporate existence, maintaining title to all
of the collateral free and clear of all liens except for the Banks liens and
those permitted by the Banks, maintaining all mineral interests in good repair
and in compliance with all laws, maintaining insurance, paying all taxes, not
paying dividends except as required on the Company's Series 1995-B Preferred
Stock and not selling any of the collateral securing the loans. The Company is
currently in compliance with these covenants.
Restrictions Imposed by Terms of the Company's Indebtedness
The Indenture and the Credit Facility 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 Credit Facility contains additional and more restrictive covenants. The
Indenture and the Credit Facility also 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 "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 Credit
Facility. Upon the occurrence of an event of default under the Credit Facility,
the lenders thereunder could elect to declare all amounts outstanding under the
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 Credit Facility acelerate 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 are
pledged as security under the Credit Facility. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Liquidity and
Capital Resources."
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
revenues or the Company's borrowing base under the 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."
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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 CGGS and the
Wyoming Properties into the previous operations of the Company. The operations
of CGGS and the Wyoming Properties vary in geography from that of the Company's
previous operations, and with respect to CGGS, to some extent, in scope and
type, from the Company's previous operations. 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 is successful in integrating the new operations, the
acquisition of CGGS in particular has significantly increased the Company's
dependence on international operations, specifically those in Canada, and
therefore the Company is subject to various additional political, economic and
other uncertainties. Among other risks, the Company's operations are 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, the Company 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 the Company will operate. Long-term contracts will not
protect the Company from shut-ins or supply curtailments by natural gas
supplies. 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 the Company will be able to do so on a
similar basis in the future.
Shares Eligible for Future Sale
At March 21, 1997, the Company had 5,732,101 shares of Common Stock
outstanding of which 854,052 shares were held by affiliates. Of the shares held
by non-affiliates, 1,330,000 shares were sold in November 1995 in a private
placement (the "Private Placement") of 1,330,000 units each consisting of one
share of Common Stock and one Contingent Value Right ("CVR"). In addition, at
March 21, 1997, the Company had 550,810 shares of Common Stock subject to
outstanding options granted under certain stock option plans (of which 149,482
shares were vested at March 21, 1997), 437,500 shares issuable upon exercise of
warrants and up to 1,995,000 shares of Common Stock issuable upon maturity of
the CVRs in November 1997. The actual number of shares issuable upon maturity of
the CVRs is dependent upon the difference between the target price (which is
$12.50 in 1997) and the median of the averages of the closing bid prices of the
Common Stock on the Nasdaq Stock Market during three consecutive 20-trading day
periods immediately preceding the maturity date.
All of the shares of Common Stock held by affiliates are restricted
or control securities under Rule 144 promulgated under the Securities Act of
1933, as amended (the "Securities Act"). The shares of the Common Stock issuable
upon exercise of the stock options have been registered under the Securities
Act. In addition, the Company has filed a registration statement covering the
shares of the Common Stock issued in the Private Placement and the shares of
Common Stock issuable upon maturity of the CVRs. All of such shares will be
offered only by means of a prospectus. The shares of the Common Stock issuable
upon exercise of the warrants are subject to certain registration rights and,
therefore, will be eligible for resale in the public market after a registration
statement covering such shares has been declared effective. Sales of shares of
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Common Stock under Rule 144 or pursuant to a registration statement could have a
material adverse effect on the price of the Common Stock and could impair the
Company's ability to raise additional capital through the sale of its equity
securities.
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
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 Revenues; Depletion of
Reserves
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 set forth in this report represent only estimates. In
addition, the estimates of future net revenues 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 Present Value of Proved Reserves for the
crude oil and natural gas properties described in this report are based on the
assumption that future crude oil and natural gas prices remain the same as crude
oil and natural gas prices at December 31, 1996. The average sales prices as of
such dates used for purposes of such estimates were $23.19 per Bbl of crude oil,
$16.31 per Bbl of NGLs and $2.96 per Mcf of natural gas. Also assumed is the
Company's making future capital expenditures of approximately $23.1 million in
the aggregate necessary to develop and realize the value of proved undeveloped
reserves on its 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 - Reserve
Information."
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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 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 condition, 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 governmental 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 Credit Agreement, the
Company's ability to obtain additional financing in the future for acquisitions
and capital expenditures may be limited.
Title to Properties
As is customary in the crude oil and natural gas industry, the
Company performs a minimal title investigation before acquiring undeveloped
properties, which generally consists of obtaining a title report from legal
counsel covering title to the major properties and due diligence reviews by
independent landmen of the remaining properties. The Company believes that it
has satisfactory title to such properties in accordance with standards generally
accepted in the crude oil and natural gas industry. A title opinion is obtained
prior to the commencement of any drilling operations on such properties. The
Company's properties are subject to customary royalty interests, liens incident
to operating agreements, liens for current taxes and other burdens, none of
which the Company believes materially interferes with the use of, or affect the
value of, such properties. All of the Company's United States properties are
also subject to the liens of the Banks.
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Government Regulation
The Company's business is subject to certain federal, state 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.
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. 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. The Company has entered into employment
agreements with Mr. Watson and each of the Company's vice presidents. The
employment agreements terminate on December 31, 1997 except that the term may be
extended for an additional year if by December 1 of the prior year neither the
Company nor the officer has given notice that it does not wish to extend the
term. Except in the event of a change in control, Mr. Watson's and each of the
vice president's employment is terminable at will by the Company for any reason,
without notice or cause.
Limitations on the Availability of the Company's Net Operating Loss
Carryforwards
At December 31, 1996, the Company had, subject to the limitations
discussed below, $17.5 million of net operating loss carryforwards for tax
purposes, of which approximately $16.1 million are available for utilization
without limitation. These loss carryforwards will expire from 2002 through 2010
if not utilized. As a result of the acquisition of certain partnership interests
and crude oil and natural gas properties in 1990 and 1991, an ownership change
under Section 382 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 $4.9
million will be limited to approximately $235,000 per year. During 1992 the
Company acquired 100% of the outstanding capital stock of an unrelated
corporation. The use of the net operating loss carryforwards of $1.1 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
sales of stock, an additional ownership change under Section 382 occurred in
October 1993. Accordingly, it is expected that the use of the $8.2 million of
net operating loss carryforwards generated through October 1993 will be limited
to approximately $1 million per year subject to the lower 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 operating
loss carryforwards under the criteria set forth under FASB Statement No. 109.
Therefore, the Company has established a valuation allowance of $5.7 million and
$5.7 million for deferred tax assets at December 31, 1996 and 1995,
respectively.
Regulation of Crude Oil and Natural Gas Activities
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.
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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, 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
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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.
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.
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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
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
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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
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%.
17
<PAGE>
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 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.
Employees
As of March 21, 1997, Abraxas and its subsidiaries had 64 full-time
employees, including two executive officers, four non-executive officers, four
petroleum engineers, one landman, two geologists, 24 secretarial, accounting and
clerical personnel and 27 field personnel. Additionally, Abraxas also retains
contract pumpers on a month-to-month basis. Abraxas retains independent
geologic, geophysical and engineering consultants from time to time on a limited
basis and expects to continue to do so in the future.
Recent Activities
In January 1997, Canadian Abraxas sold its interest in the Hoole Area
(the "Hoole Area") for approximately $9.3 million. The Hoole Area consists of
9,728 gross acres (3,311 net acres) and 6.0 gross wells (3.2 net wells), none of
which are operated by Canadian Abraxas. As of January 1, 1997, the Hoole Area
natural gas properties had total proved reserves of 1,268.0 MBOE with a Present
Value of Proved Reserves of $11.2 million, all 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 December
31, 1996. For the twelve months ended December 31, 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.
18
<PAGE>
Item 2. Properties.
Exploratory and Developmental Acreage
Abraxas' principal crude oil and natural gas properties consist of
non-producing and producing crude oil and natural gas leases, including reserves
of crude oil and natural gas in place. The following table indicates Abraxas'
interest in developed and undeveloped acreage as of December 31, 1996:
<TABLE>
<CAPTION>
Developed and Undeveloped Acreage
As of December 31, 1996
Developed Acreage(1) Undeveloped Acreage(2)
State Gross Acres(3) Net Acres(4) Gross Acres(3) Net Acres(4)
<S> <C> <C> <C> <C>
Canada 88,085(5) 47,140(5) 92,284 41,005
Texas 41,115 23,153 22,477 13,864
Wyoming 5,239 3,620 14,020 9,476
N. Dakota 1,864 1,021 -- --
Alabama 720 23 -- --
Kansas 640 142 -- --
Montana 320 10 -- --
New Mexico 320 42 -- --
TOTAL 138,303 75,151 128,781 64,345
</TABLE>
(1) Developed acreage consists of acres spaced or assignable to productive
wells.
(2) Undeveloped acreage is considered to be those leased acres on which wells
have not been drilled or completed to a point that would permit the
production of commercial quantities of oil and gas, regardless of whether
or not such acreage contains proved reserves.
(3) Gross acres refers to the number of acres in which Abraxas owns a working
interest.
(4) Net acres represents the number of acres attributable to an owner's
proportionate working interest and/or royalty interest in a lease (e.g., a
50% working interest in a lease covering 320 acres is equivalent to 160
net acres).
(5) Includes 9,728 gross acres and 3,311 net acres in the Hoole Area. See
"Business - Recent Activities".
Productive Wells
The following table sets forth the total gross and net productive
wells of Abraxas, expressed separately for crude oil and natural gas, as of
December 31, 1996:
Productive Wells(1)
- --------------------------------------------------------------------------
STATE/ CRUDE NATURAL
COUNTRY OIL GAS
- --------------------------------------------------------------------------
Gross(2) Net(3) Gross(2) Net(3)
Texas 258.0 180.6 98.0 63.6
Canada(4) 15.0 12.5 132.0 55.2(4)
Kansas 4.0 0.8 -- --
N. Dakota 4.0 1.7 -- --
Alabama 2.0 0.1 1.0 0.1
Montana 1.0 0.1 -- --
Wyoming 1.0 0.1 29.0 21.3
New Mexico -- -- 1.0 0.1
----- ----- ----- -----
TOTAL 285.0 195.9 261.0 140.3
- ------------
(1) Productive wells are producing wells and wells capable of production.
19
<PAGE>
(2) A gross well is a well in which Abraxas owns a working interest. The
number of gross wells is the total number of wells in which Abraxas owns a
working interest.
(3) A net well is deemed to exist when the sum of fractional ownership working
interests in gross wells equals one. The number of net wells is the sum of
Abraxas' fractional working interest owned in gross wells.
(4) Includes 6.0 gross wells and 3.2 net wells in the Hoole Area. See
"Business - Recent Activities".
Substantially all of Abraxas' existing crude oil and natural gas
properties are pledged to secure Abraxas' indebtedness under its' credit
agreement. See "Management's Discussion of Financial Condition and Results of
Operations--Liquidity and Capital Resources".
Reserves Information
The crude oil and natural gas reserves of Abraxas have been estimated
as of January 1, 1997, January 1, 1996 and January 1, 1995 and of Canadian
Abraxas as of January 1, 1997, by DeGolyer & MacNaughton, of Dallas, Texas.
Crude oil and natural gas reserves, and the estimates of the present value of
future net revenues therefrom, were determined based on then current prices and
costs. Reserve calculations involved the estimate of future net recoverable
reserves of crude oil and natural gas and the timing and amount of future net
revenues to be received therefrom. Such estimates are not precise and are based
on assumptions regarding a variety of factors, many of which are variable and
uncertain.
The following table sets forth certain information regarding
estimates of Abraxas' crude oil, natural gas liquids and natural gas reserves as
of January 1, 1997, January 1, 1996 and January 1, 1995.
ESTIMATED PROVED RESERVES
----------------------------------------
Proved Proved Total
Developed Undeveloped Proved
----------- ----------- -----------
As of January 1, 1995
Crude Oil, Bbls 3,616,510 3,032,818 6,649,328
Natural Gas Liquids, Bbls 2,089,168 417,994 2,507,162
Natural Gas, Mcf 48,973,212 18,605,881 67,579,093
As of January 1, 1996
Crude Oil, Bbls 3,991,804 1,516,012 5,507,816
Natural Gas Liquids, Bbls 2,007,777 751,649 2,759,426
Natural Gas, Mcf 44,025,782 10,542,825 54,568,607
As of January 1, 1997 (1)
Crude Oil, Bbls 7,871,308(2) 1,930,240 9,801,548(2)
Natural Gas Liquids, Bbls 7,089,755 1,144,341 8,234,096
Natural Gas, Mcf 157,660,157 19,599,554 177,259,711
(1) Includes reserves of Canadian Abraxas (Including 1,268 MBOE
attributable to the Hoole Area).
(2) Includes 120,400 barrels of crude oil reserves owned by Cascade of
which 57,600 barrels are applicable to the minority interest's share
of the reserves.
There are numerous uncertainties inherent in estimating crude oil and
natural gas reserves and their estimated values, including many factors beyond
the control of the producer. The reserve data set forth herein represent only
estimates. Reserve engineering is a subjective process of estimating underground
accumulations of crude oil and natural gas that cannot be measured in an exact
manner. The accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgement.
As a result, estimates of different engineers often vary. In addition, estimates
of reserves are subject to revision by the results of drilling, testing and
production subsequent to the date of such estimates. Accordingly, reserve
estimates are often different from the quantities of crude oil and natural gas
that are ultimately recovered. The meaningfulness of such estimates is highly
dependent upon the accuracy of the assumptions upon which they are based.
20
<PAGE>
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, Natural Gas Liquids, and Natural Gas Production and Sales Prices
The following table presents the net crude oil, net natural gas liquids
and net natural gas production for Abraxas, the average sales price per Bbl of
crude oil and natural gas liquids and per Mcf of natural gas produced and the
average cost of production per BOE of production sold, for the three years ended
December 31, 1996:
1996 1995 1994
--------- --------- ---------
Crude oil production (Bbls) 425,188 401,445 355,710
Natural gas production (Mcf) 6,350,069 3,552,671 2,392,855
Natural gas liquids
Production (Bbls) 299,509 143,380 113,157
Average sales price per
Bbl of crude oil($) $20.85 $17.16 $15.47
Average sales price per
Mcf of natural gas($) $1.97 $1.47 $1.85
Average sales price per
Bbl. of natural gas liquids $14.55 $10.83 $10.54
Average cost of production
($) per BOE produced (1) $3.28 $3.81 $4.26
(1) Oil and gas were combined by converting gas to a barrel oil equivalent
("BOE") on the basis of 6 Mcf gas =1 Bbl of oil. Production costs include
direct operating costs, ad valorem taxes and gross production taxes.
21
<PAGE>
Drilling Activities
The following table sets forth Abraxas' gross and net working
interests in exploratory, development, and service wells drilled during the
three years ended December 31, 1996:
<TABLE>
<CAPTION>
1996 1995 1994
--------------------- --------------------- -----------------------
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
--------- -------- --------- -------- --------- --------
<S> <C> <C> <C> <C> <C> <C>
Exploratory(3) - - - - - -
Productive(4) - - - - - -
Crude oil 2.0 1.2 1 .72 - -
Natural gas 2.0 1.2 - - 1 2
Dry holes(5) 4.0 1.4 1 1 2 5
--------- -------- ---------- -------- --------- --------
Total 8.0 3.8 2 1.72 3 7
========= ======== ========== ======== ========= ========
Development(6)
Productive - - - -
Crude oil 20.0 15.8 12 9.1 3 1.5
Natural gas 10.0 3.7 2 .6 6 2.1
Service(7) 1.0 1.0 - - - -
Dry holes(5) - - 1 .3 - -
--------- -------- ---------- -------- --------- --------
Total 31.0 20.5 15 10.0 9 3.6
========= ======== ========== ======== ========= ========
</TABLE>
- ------------------
(1) A gross well is a well in which Abraxas owns an interest.
(2) The number of net wells represents the total percentage of working
interests held in all wells (e.g., total working interest of 50% is
equivalent to 0.5 net well. A total working interest of 100% is
equivalent to 1.0 net well).
(3) An exploratory well is a well drilled to find and produce crude oil or
natural gas in an unproved area, to find a new reservoir in a field
previously found to be producing crude oil or natural gas in another
reservoir, or to extend a known reservoir.
(4) A productive well is an exploratory or a development well that is not a
dry hole.
(5) A dry hole is an exploratory or development well found to be incapable of
producing either crude oil or natural gas in sufficient quantities to
justify completion as a crude oil or natural gas well.
(6) A development well is a well drilled within the proved area of a crude
oil or natural gas reservoir to the depth of stratigraphic horizon (rock
layer or formation) noted to be productive for the purpose of extracting
proved crude oil or natural gas reserves.
(7) A service well is used for water injection in secondary recovery projects
or for the disposal of produced water.
22
<PAGE>
Office Facilities
The Company's executive and administrative offices are located at 500
N. Loop 1604 East, Suite 100, San Antonio, Texas 78232. The Company owns a 16%
limited partnership interest in the Partnership which owns the 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 2006 from unaffiliated parties at an aggregate rate of
$13,166 per month.
Other Properties
The Company owns 10 acres of land, an office building, shop,
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 20 vehicles which are used in the field by
employees.
Item 3. Legal Proceedings
From time to time, the Company is involved in litigation relating to
claims arising out of its operations in the normal course of business. As of
March 21, 1997, the Company was not engaged in any legal proceedings that are
expected, individually or in the aggregate, to have a material adverse effect on
the Company.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted to a vote of security holders of the Company
during the fourth quarter of the fiscal year ended December 31, 1996.
Item 4a. Executive Officers of the Company
Certain information is set forth below concerning the executive
officers of the Company, each of whom has been selected to serve until the 1997
annual meeting of directors and until his successor is duly elected and
qualified.
Robert L. G. Watson, age 46, has served as President and a director
of the Company since 1977. Prior to joining the Company, Mr. Watson was employed
in various petroleum engineering positions. From 1970 to 1972, Mr. Watson was
employed by DeGolyer & MacNaughton, an independent petroleum engineering firm
and from 1972 through 1977, Mr. Watson was employed by Tesoro Petroleum
Corporation, a crude oil and natural gas exploration and production company. Mr.
Watson received the degree of Bachelor of Science in Mechanical Engineering from
Southern Methodist University in 1972 and Master of Business Administration from
the University of Texas at San Antonio in 1974.
Chris E. Williford, age 45, was elected Vice President, Treasurer and
Chief Financial Officer of the Company in January 1993, and as Executive Vice
President and a director of the Company in May 1993. Prior to joining the
Company, 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 degree of Bachelor of Science in Business
Administration from Pittsburg State University in 1973.
23
<PAGE>
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.
Market Information
Abraxas Common Stock is traded on the NASDAQ Stock Market and
commenced trading on May 7, 1991. The following table sets forth certain
information as to the high and low bid quotations quoted on NASDAQ for 1994,
1995 and 1996. Information with respect to over-the-counter bid quotations
represents prices between dealers, does not include retail mark-ups, mark-downs
or commissions, and may not necessarily represent actual transactions.
Period High Low
---------- ------ -----
1994
First Quarter........................$13.50 $9.00
Second Quarter........................13.50 9.75
Third Quarter.........................13.13 9.00
Fourth Quarter .......................11.50 9.25
1995
First Quarter........................$10.25 $8.50
Second Quarter.........................9.63 8.00
Third Quarter..........................8.88 7.94
Fourth Quarter.........................8.88 6.13
1996
First Quarter.........................$7.75 $4.13
Second Quarter.........................7.25 5.00
Third Quarter..........................7.13 4.75
Fourth Quarter........................10.50 5.75
Holders
As of March 21, 1997 Abraxas had 5,732,101 shares of common stock
outstanding and had approximately 1,900 Stockholders of record.
Dividends
Abraxas has not paid any cash dividends on its Common Stock and it is
not presently determinable when, if ever, Abraxas will pay cash dividends in the
future. The Credit Agreement and the Indenture, prohibits the payment of cash
dividends and stock dividends on the Company's Common Stock. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Liquidity and Capital Resources".
24
<PAGE>
Item 6. Selected Financial Data
The following selected financial data are derived from the
consolidated financial statements of Abraxas. The data should be read in
conjunction with the consolidated financial statements, related notes, and other
financial information included herein.
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------------------
1996 1995 1994 1993 1992
--------- -------- -------- -------- -------
(In thousands, except per share data)
<S> <C> <C> <C> <C> <C>
Total revenue $ 26,653 $13,817 $11,349 $ 7,494 $ 2,691
Income (loss) from continuing operations $ 1,940 $(1,209) $ 113 $(1,580) $(1,072)
Income (loss) per common share and common
equivalent from continuing operations $ .23 $ (.34) $ .02 $ (.91) $ (1.23)
Weighted average shares
outstanding 6,794 4,635 4,310 1,947 1,074
Total Assets $304,842 $85,067 $75,361 $43,396 $18,017
Long-term debt $215,032 $41,601 $41,296 $12,529 $ 6,602
Total shareholders' equity $ 35,656 $37,062 $28,502 $25,143 $ 2,233
</TABLE>
Item 7. Management's Discussion And Analysis Of Financial Condition And Results
Of Operations
The following is a discussion of the Company's consolidated 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. See "Financial Statements".
Results of Operations
The factors which most significantly affect the Company's results of
operations are (1) the sales prices of crude oil, natural gas liquids and
natural gas, (2) the level of total sales volumes of crude oil, natural gas
liquids and natural gas, (3) the level of and interest rates on borrowings and
(4) the level and success of exploration and development activity.
Selected Operating Data. The following table sets forth certain
operating data of the Company for the periods presented:
Years Ended December 31
1996 1995 1994
Operating revenue (in thousands):
Natural gas sales..................... $12,526 $6,889 $5,501
Crude oil sales........................ 8,864 5,218 4,420
Natural gas liquid sales.............. 4,359 1,553 1,193
Gas Processing Revenue................. 600 -- --
Other.................................. 304 157 235
------- ------- -------
Total operating revenue................ $26,653 $13,817 $11,349
======= ======= =======
Operating income (loss) in thousands... $8,826 $2,883 $2,923
Natural gas production (Mmcfs).......... 6,350.0 3,552.7 2,392.9
Crude oil production (Mbbls)............ 425.2 401.4 355.7
Natural gas liquids production (Mbbls).. 299.5 143.4 113.2
Average natural gas sales price ($/Mcf). $1.97 $1.47 $1.85
Average crude oil sales price ($/Bbl)... $20.85 $17.16 $15.47
Average natural gas liquids sales price
($/Bbl)............................... $14.55 $10.83 $10.54
25
<PAGE>
Comparison of Year Ended December 31, 1996 to Year Ended December 31, 1995
Operating Revenue. During the year ended December 31, 1996, operating
revenue from crude oil, natural gas and natural gas liquids sales, and natural
gas processing revenues increased 92% from $13.7 million in 1995 to $26.3
million. This increase was primarily attributable to increased crude oil and
natural gas liquids sales volumes of 33.0% and natural gas sales volumes of
78.7% which was attributable to increased production from the producing
properties that the Company owned for the entire year as well as producing
properties acquired during the year. This increase more than offset the loss of
operating revenue from the Portilla and Happy fields during the portion of the
year that the Company did not own the properties. During 1995, the Portilla and
Happy Fields contributed $4.6 million in operating revenue compared to $2.0
million in 1996. Crude oil and NGLs sales volumes increased from 545 MBbls to
725 MBbls, from 1995 to 1996 and natural gas sales volumes increased from 3.6
BCF to 6.4 BCF, from 1995 to 1996 as a result of increased production volumes
from the Company's properties other than Portilla and Happy in 1996 as compared
to 1995 and the acquisitions of the Wyoming Properties, the stock of CGGS and
the Company's ongoing development drilling program. Portilla and Happy
contributed 226.0 MBbls of crude oil and NGLs (41.5% of Company total) and 492.6
MMcf of natural gas (13.9% of Company total) during 1995 as compared to 91.7
MBbls of crude oil and NGLs (12.7% of Company total) and 215.6 MMcf of natural
gas (3.4% of Company total) for 1996. Average sales prices were $20.85 per Bbl
of crude oil, $14.55 per Bbl of natural gas liquids and $1.97 per Mcf of natural
gas for the year ended December 31, 1996 compared with $17.16 per Bbl of crude
oil, $10.83 per Bbl of natural gas liquid and $1.47 per MMcf of natural gas for
the year ended December 31, 1995. A general strengthening of crude oil and
natural gas prices at the wellhead during 1996 resulted in a higher average
sales prices received by the Company during the year ended December 31, 1996
compared to the same period in 1995.
Lease Operating Expenses. Lease operating expenses and natural gas
processing costs ("LOE"), increased by 41.2% from $4.3 million for the year
ended December 31, 1995 to $6.1 million for the same period of 1996, primarily
due to the greater number of wells owned by the Company for the year ended
December 31, 1996 compared to the year ended December 31, 1995. The Company's
LOE on a per BOE basis for 1996 was $3.28 per BOE as compared to $3.81 per BOE
in 1995.
G & A Expenses. General and administrative expenses increased 85.5%
from $1.0 million for the year ended December 31, 1995, to $1.9 million for the
year ended December 31, 1996, as a result of the Company's hiring additional
staff, including establishment of a Canadian administrative office, to manage
the additional properties acquired by the Company and subsequent development of
those properties. The Company's G & A expense on a per BOE basis was $1.08 per
BOE in 1996 compared to $0.92 per BOE for 1995.
DD & A Expenses. Due to the increase in sales volumes of crude oil
and natural gas, depreciation, depletion and amortization expense increased
76.8% from $5.4 million for the year ended December 31, 1995 to $9.6 million for
the year ended December 31, 1996. The Company's DD&A expense on a per BOE basis
for 1996 was $5.38 per BOE as compared to $4.78 per BOE in 1995.
Interest Expense and Preferred Dividends. Interest expense and
preferred dividends increased 54.5%, from $4.3 million to $6.6 million for the
year end December 31, 1996, compared to the 1995 period. This increase is
attributable to increased borrowings by the Company to finance the acquisitions
consumated during 1996. Long-term debt increased from $41.6 million at December
31, 1995 to $215.0 million at December 31, 1996.
Comparison of Year Ended December 31, 1995 to Year Ended December 31, 1994
Operating Revenue. During the year ended December 31, 1995, operating
revenue from crude oil, natural gas and natural gas liquids sales increased by
22.9% from $11.1 million in 1994 to $13.7 million. This increase was primarily
attributable to an increase in crude oil and natural gas liquids sales volumes
of 16% and natural gas sales volumes of 48%. The increases in sales volumes of
crude oil, natural gas liquids and natural gas from 1994 to 1995 were primarily
a result of the acquisition of 80% of the overriding royalty interest previously
granted to a lender (the "ORRI") and the West Texas Properties by the Company in
June 1994 and July 1994 respectively, and the Company's ongoing development
drilling program. Average sales prices were $17.16 per Bbl of crude oil, $10.83
per Bbl of natural gas liquids and $1.47 per Mcf of natural gas for the year
ended December 31, 1995 compared with $15.47 per Bbl of crude oil, $10.54 per
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Bbl of natural gas liquid and $1.85 per Mcf of natural gas for the year ended
December 31, 1994. 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
compared to the same period in 1994. This decrease was partially offset by an
increase in crude oil prices received by the Company in 1995 as compared to
1994.
Lease Operating Expenses. LOE increased 17.3% from $3.7 million for
the year ended December 31, 1994 to $4.3 million for the same period of 1995,
primarily due to the greater number of wells owned by the Company during the
year ended December 31, 1995 compared to 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.
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. Due to the increase in sales volumes of crude oil
and natural gas, depreciation, depletion and amortization expense increased
43.4% from $3.8 million for the year ended December 31, 1994 to $5.4 million for
the year ended December 31, 1995. The Company's DD&A expenses on a per BOE basis
for the year ended December 31, 1994 was $4.37 per BOE compared to $4.78 per BOE
in 1995.
Interest Expenses and Preferred Dividends. As a result of the
Company's borrowing $28 million to acquire the West Texas Properties in July
1994, interest expense increased 62.5% from $2.4 million in 1994 to $3.9 million
in 1995. Long term debt increased from $41.3 million at December 31, 1994 to
$41.6 million at December 31, 1995.
The Company has incurred operating losses and net losses for a number
of years. The Company's revenues, profitability and future rate of growth are
substantially dependent upon prevailing prices for crude oil and natural gas and
the volumes of crude oil, natural gas and natural gas liquids produced by the
Company. Natural gas prices increased substantially during 1996. For the year
ended December 31, 1996 average natural gas prices realized by the Company were
$1.97 per Mcf compared with $1.47 per Mcf at December 31, 1995 and $1.85 per Mcf
at December 31, 1994. Although the Company had operating and net income during
1996, there can be no assurance that operating income and net earnings will be
achieved in future periods. At December 31, 1996, U.S. crude oil prices were
$23.55 per Bbl compared to $18.13 at December 31, 1995 and $15.59 per Bbl at
December 31, 1994. In addition, because the Company's proved reserves will
decline as crude oil, natural gas and natural gas liquids are produced, unless
the Company is successful in acquiring properties containing proved reserves or
conducts successful exploration and development activities, the Company's
reserves and production will decrease. In the event natural gas prices return to
depressed levels or if crude oil prices begin to decrease, or if the Company's
production levels decrease, the Company's revenues, cash flow from operations
and profitability will be materially adversely affected.
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Liquidity and Capital Resources
Capital expenditures in 1994, 1995 and 1996 were $40.9 million, $9.7
million and $172.9 million, respectively. The table below sets forth the
components of these capital expenditures on a historical basis for the three
years ended December 31, 1994, 1995 and 1996.
Year Ended December 31
------------------------------------
(In thousands)
1996 1995 1994
--------- --------- --------
Expenditure category:
Property acquisition (1) $154,484 $ 719 $33,709
(Divestitures) (242) (2,556) (70)
Development 18,465 11,472 7,151
Facilities and other 206 139 158
-------- ------- -------
Total $172,913 $ 9,774 $40,948
======== ======= =======
(1) Acquisition costs includes 45,741 shares of Preferred Stock valued at
$4.6 million in 1994.
Acquisitions of crude oil and natural gas producing properties
beginning during 1991 and continuing through the year ended December 31, 1996
account for the majority of the capital expenditures made by the Company since
January 1, 1991. These expenditures were funded through internally generated
cash flow, borrowings from the Company's previous lenders and the Banks, the
issuance of shares of the Company's Common and Preferred Stock to property
sellers and the issuance of the Senior Notes.
At December 31, 1996, the Company had current assets of $23.3 million
and current liabilities of $16.9 million resulting in working capital of $6.4
million. This compares to working capital of $2.6 million at December 31, 1995.
The material components of the Company's current liabilities at December 31,
1996 include trade accounts payable of $10.0 million, revenues due third parties
of $2.4 million and accrued interest of $3.2 million. Shareholders' equity
decreased from $37.1 million at December 31, 1995 to $35.7 million at December
31, 1996 primarily due to an unrealized foreign currency translation adjustment
of $2.4 million.
The Company's current budget for capital expenditures for 1997 other
than acquisition expenditures is $35.2 million. Such expenditures will be made
primarily for the development of existing properties. Additional capital
expenditures may be made for acquisition of producing properties if such
opportunities arise, but the Company currently has no agreements, arrangements
or undertakings regarding any material acquisitions. 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.
On November 14, 1996, Abraxas and Canadian Abraxas consummated the
offering of $215 million of the Notes. Interest on the Notes accrues from their
date of original issuance (the "Issue Date") and is 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. The Notes are redeemable, in whole or in part, at the
option of Abraxas and Canadian Abraxas, on or after November 1, 2000, at the
redemption prices set forth below, plus accrued and unpaid interest to the date
of redemption, if redeemed during the 12-month period commencing on November 1
of the years set forth below:
Year Percentage
---- ----------
2000 105.75%
2001 102.875%
2002 and thereafter 100%
In addition, at any time on or prior to November 1, 1999, Abraxas and
Canadian Abraxas 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, 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.
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The Notes are joint and several obligations of Abraxas and Canadian
Abraxas, and rank pari passu in right of payment to all existing and future
unsubordinated indebtedness of Abraxas and Canadian Abraxas. The Notes rank
senior in right of payment to all future subordinated indebtedness of Abraxas
and Canadian Abraxas. The Notes are, however, effectively subordinated to
secured indebtedness of Abraxas and Canadian Abraxas to the extent of the value
of the assets securing such indebtedness.
The Notes are unconditionally guaranteed, jointly and severally, by
certain of Abraxas' and Canadian Abraxas' future subsidiaries (the "Subsidiary
Guarantors"). The guarantees are general unsecured obligations of the Subsidiary
Guarantors and 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 are
effectively subordinated to secured indebtedness of the Subsidiary Guarantors to
the extent of the value of the assets securing such indebtedness. As of December
31, 1996, Abraxas, Canadian Abraxas and the Subsidiary Guarantors had no secured
indebtedness outstanding.
Upon a Change of Control (as defined in the Indenture governing the
Notes), each holder of the Notes will have the right to require Abraxas and
Canadian Abraxas 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, Abraxas and Canadian
Abraxas will be obligated to offer to repurchase the Notes at 100% of the
principal amount thereof plus accrue