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<SEC-DOCUMENT>0000867665-98-000008.txt : 19980401
<SEC-HEADER>0000867665-98-000008.hdr.sgml : 19980401
ACCESSION NUMBER: 0000867665-98-000008
CONFORMED SUBMISSION TYPE: 10-K
PUBLIC DOCUMENT COUNT: 2
CONFORMED PERIOD OF REPORT: 19971231
FILED AS OF DATE: 19980331
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:
SEC FILE NUMBER: 000-19118
FILM NUMBER: 98582958
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>ANNUAL REPORT ON FORM 10K
<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, 1997
[ ]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File Number 0-19118
ABRAXAS PETROLEUM CORPORATION
(Exact name of Registrant as specified in its charter)
Nevada 74-2584033
(State or Other Jurisdiction of I.R.S. Employer Identification Number)
Incorporation or Organization)
500 N. Loop 1604 East, Suite 100
San Antonio, Texas 78232
(Address of principal executive offices)
Registrant's telephone number,
including area code (210) 490-4788
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
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 23,
1998, (based upon the average of the $7.88 per share "Bid" and $8.13 per share
"Asked" prices), was approximately $39,756,000 on such date.
The number of shares of the issuer's Common Stock, par value $.01 per
share, outstanding as of March 23, 1998 was 6,335,517 shares of which 4,969,522
shares were held by non-affiliates.
Documents Incorporated by Reference: Portions of the registrant's Proxy
Statement relating to the 1998 Annual Meeting of Shareholders to be held on May
22, 1998 have been incorporated by reference herein (Part III).
<PAGE>
ABRAXAS PETROLEUM CORPORATION
FORM 10-K
TABLE OF CONTENTS
PART I
Page
Item 1. Business. ........................................................4
General .........................................................4
Primary operating areas .........................................5
Markets and Customers.............................................6
Risk Factors......................................................6
Regulation of Crude Oil and Natural Gas Activities...............12
Natural Gas Price Controls.......................................12
State Regulation of Crude Oil and Natural Gas Production.........14
Environmental Matters ..........................................16
Employees........................................................17
Item 2. Properties.......................................................18
Exploratory and Developmental Acreage............................18
Productive Wells.................................................18
Reserves Information.............................................19
Crude Oil and Natural Gas Production and Sales Price ............20
Drilling Activities..............................................21
Office Facilities................................................22
Other Properties.................................................22
Item 3. Legal Proceedings................................................22
Item 4. Submission of Matters to a Vote of
Security Holders...............................................22
Item 4a.Executive Officers of the Company.................................22
PART II
Item 5. Market for Registrant's Common Equity
and Related Stockholder Matters...............................23
Market Information..............................................23
Holders.........................................................23
Dividends.......................................................23
Item 6. Selected Financial Data.........................................24
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations...................24
Results of Operations...........................................24
Liquidity and Capital Resources.................................27
2
<PAGE>
Item 8. Financial Statements and Supplementary Data......................32
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure.........................32
PART III
Item 10. Directors and Executive Officers of the Registrant .............32
Item 11. Executive Compensation..........................................32
Item 12. Security Ownership of Certain Beneficial Owners and Management..32
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>
DISCLOSURE REGARDING FORWARD-LOOKING INFORMATION
This report includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934. All statements other than statements of
historical facts included in this report regarding the Company's financial
position, business strategy, budgets, reserve estimates, development and
exploitation opportunities and projects, behind pipe zones, classification of
reserves, projected costs, potential reserves, availability or sufficiency of
capital resources and plans and objectives of management for future operations
including, but not limited to, statements including, any of the terms
"anticipates", "expects", "estimates", "believes" and similar terms are
forward-looking statements. Although the Company believes that the expectations
reflected in such forward-looking statements are reasonable, it can give no
assurance that such expectations will prove to have been correct. Important
factors that could cause actual results to differ materially from the Company's
expectations ("Cautionary Statements") are disclosed under "Risk Factors" and
elsewhere in this report including, without limitation, in conjunction with the
forward-looking statements included in this report. All subsequent written and
oral forward-looking statements attributable to the Company, or persons acting
on its behalf, are expressly qualified in their entirety by the Cautionary
Statements.
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 17 acquisitions of crude oil and natural
gas producing properties totaling an estimated 52.1 million barrels of crude oil
equivalent ("MMBOE") of proved reserves at an average acquisition cost of
approximately $4.11 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 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 years ended December 31, 1996 and 1997 are set forth in Note 14 to the
Notes to the Company's Consolidated Financial Statements included elsewhere
herein.
At December 31, 1997, the Company operated 341 net wells and owned
non-operated interests in 62 net wells. Average net daily production for the
year ended December 31, 1997 was 5,285 barrels ("Bbls") of crude oil and natural
gas liquids and 57,671 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 54.7 MMBOE and $268.7 million,
respectively, at January 1, 1998. Of the Company's proved reserves at January 1,
1998, 83% were classified as proved developed reserves and 90.5% of the Present
Value of Proved Reserves at such date was attributable to such proved developed
reserves. At December 31, 1997, the Company also owned varying interests in 20
natural gas processing plants or compression facilities with capacity of 137
million cubic feet ("MMcf") per day and approximately 200 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
4
<PAGE>
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
Primary Operating Areas
Texas Gulf Coast and South Texas
At December 31, 1997, the Company's Texas Gulf Coast and south Texas
producing properties had estimated net proved reserves of 17,380 MBOE (62%
natural gas) with a PV-10 of $87.5 million, 82% of which was attributable to
proved developed reserves. For the year ended December 31, 1997, these
properties produced an average of approximately 1,189 net Bbls of crude oil and
NGLs and approximately 9,391 net Mcf of natural gas per day from 86 net wells.
The Company also owns varying interests in two natural gas processing plants and
one natural gas treating plant which had aggregate capacity of approximately 51
MMcf of natural gas per day at December 31, 1997. During the year ended December
31, 1997, the plants processed an average of approximately 21.8 MMcf of natural
gas per day and extracted an average of approximately 677 Bbls of NGLs per day.
West Texas
At December 31, 1997, the Company's west Texas producing properties had
estimated net proved reserves of 9,500 MBOE (46% natural gas) with a PV-10 of
$44.2 million, 98% of which was attributable to proved developed reserves. For
the year ended December 31, 1997, these properties produced an average of
approximately 1,800 net Bbls of crude oil and NGLs and approximately 9,047 net
Mcf of natural gas per day from 171 net wells.
Wyoming
The Company acquired producing properties in the Wamsutter area of
southwestern Wyoming (the "Wyoming Properties") in September 1996. At December
31, 1997, the Wyoming Properties had estimated net proved reserves of 12,766
MBOE (65% natural gas) with a PV-10 of $56.5 million, 88 % of which was
attributable to proved developed reserves. For the year ended December 31, 1997,
the Wyoming Properties produced an average of approximately 1,740 net Bbls of
crude oil and NGLs and 15,810 net Mcf of natural gas per day from 33 net wells.
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 these proceeds in newly-issued shares of Cascade Oil & Gas Ltd.
("Cascade"), an Alberta-based corporation whose common shares are traded on The
Alberta Stock Exchange under the symbol "COL." In November 1997, Grey Wolf
merged with Cascade. The Company owns approximately 46% of the outstanding
capital stock of Cascade. Cascade owns a 10% interest in the Canadian Abraxas
Properties and the Canadian Abraxas Plants (each as defined herein) and an 8%
interest in the Pacalta Properties (as defined herein) and manages the
operations of the Company's wholly-owned subsidiary, Canadian Abraxas Petroleum
Limited ("Canadian Abraxas"), pursuant to a management agreement between
Canadian Abraxas and Cascade. Under the management agreement, Canadian Abraxas
reimburses Cascade for reasonable costs or expenses attributable to Canadian
Abraxas and for administrative expenses based upon the percentage that Canadian
Abraxas' gross revenue bears to the total gross revenue of Canadian Abraxas and
Cascade.
5
<PAGE>
In November 1996, Canadian Abraxas acquired Canadian Gas Gathering
Systems, Inc. ("CGGS"). Canadian Abraxas owns producing properties in Western
Canada (the "Canadian Abraxas Properties"), consisting primarily of natural gas
reserves, and interests ranging from 10% to 100% in approximately 200 miles of
natural gas gathering systems and 17 natural gas processing plants or
compression facilities (the "Canadian Abraxas Plants"). As of December 31, 1997,
the Canadian Abraxas Properties had estimated net proved reserves of 15,019 MBOE
(90% natural gas) with a PV-10 of $80.4 million, 95% of which was attributable
to proved developed reserves. For the year ended December 31, 1997, the Canadian
Abraxas Properties produced an average of approximately 530 net Bbls of crude
oil and NGLs and 23,403 net Mcf of natural gas per day from 110 net wells. The
Canadian Abraxas Plants had aggregate capacity of approximately 251 gross MMcf
of natural gas per day (102 net MMcf).
In October 1997, Canadian Abraxas and Cascade completed the acquisition
of the Canadian assets of Pacalta Resources Ltd. (the "Pacalta Properties") for
approximately CDN$20.0 million in cash and four million Cascade Special
Warrants. Canadian Abraxas acquired an approximate 92% interest in the Pacalta
Properties and Cascade acquired an 8% interest. Cascade has the opportunity to
acquire Canadian Abraxas' ownership upon arranging satisfactory financing in
1998. At closing, the Pacalta Properties were producing 115 net Bbls of oil per
day and 8,000 net Mcf of gas per day.
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. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Liquidity and Capital Resources.
Substantially all of the Company's crude oil and natural gas is sold at
current market prices under short term contracts, as is customary in the
industry. During the year ended December 31, 1997, three purchasers accounted
for approximately 42% of the Company's crude oil and natural gas sales and two
customers accounted for approximately 51% of gas processing revenue.. 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
Leverage and Debt Service
As of December 31, 1997, the Company's total debt and stockholders'
equity were approximately $249 million and $27 million, respectively. In
addition, the Company had $5.0 million of unused borrowing capacity under its
6
<PAGE>
revolving credit facility (the "Credit Facility") at December 31, 1997. In
January 1998, the Company and Canadian Abraxas completed the sale of $60 million
aggregate principal amount of their 11.5% Senior Notes Due 2004, Series C (the
"Series C Notes"). 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 Indentures (the "Indentures") governing the
Company's and Canadian Abraxas' 11.5% Senior Notes Due 2004, Series B (the
"Series B Notes" and, together with the Series C Notes, the "Notes") and the
Series C Notes and the Credit Facility.
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.
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,
cash currently on hand 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. 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.
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 in recent years
have been depressed by excess total domestic and imported supplies. Prices are
also affected by actions of state and local governmental agencies, the United
States and foreign governments and international cartels. While prices for crude
oil and natural gas increased during 1996 and the first quarter of 1997, they
have been depressed since the first quarter of 1997. 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, such as the decline in the price of crude
oil which has occurred since December 31, 1997, 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.
The Company periodically reviews the carrying value of its crude oil and
natural gas properties under the full cost accounting rules of the SEC. Under
these rules, capitalized costs of proved oil and natural gas properties may not
exceed the present value of proved reserves, discounted at 10%. Application of
7
<PAGE>
the ceiling test requires pricing future revenue at the unescalated prices
ineffect as of the end of each fiscal quarter and requires a write-down for
accounting purposes if the ceiling is exceeded, even if prices were depressed
for only a short period of time. The Company was required to write-down the
carrying value of its Canadian crude oil and natural gas properties at December
31, 1997 by $4.6 million and may be required to write-down the carrying value of
its crude oil and natural gas properties in the future when crude oil and
natural gas prices are depressed or unusually volatile. When a write-down is
required, it results in a charge to earnings, but does not impact cash flow from
operating activities. The Company sustained a charge to earnings of $4.6 million
at December 31, 1997 as a result of the write-down of the Canadian properties.
Once incurred, a write-down of crude oil and natural gas properties is not
reversible at a later date. If such a write-down were large enough, it could
result in the occurrence of an event of default under the Credit Facility that
could require the sale of some of the Company's producing properties under
unfavorable market conditions or require the Company to seek additional equity
capital. In addition, the Indentures and the Credit Facility contain certain
restrictions on certain sales of assets by the Company. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations
Liquidity and Capital Resources."
Losses From Operations
The Company has experienced recurring losses. For the years ended
December 31, 1993, 1994, 1995 and 1997, the Company recorded net losses of $2.4
million, $2.4 million, $1.2 million and $6.7 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.
Restrictions Imposed by Terms of the Company's Indebtedness
The Indentures 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. The Credit Facility also
requires 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 Indentures 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 accelerate the payment of such
indebtedness, there can be no assurance that the assets of the Company would be
sufficient to repay in full such indebtedness and the other indebtedness of the
Company, including the Notes. Substantially all of the Company's assets
including, without limitation, working capital and interests in producing
properties and related assets owned by the Company, and the proceeds thereof are
or may in the future be 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
8
<PAGE>
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 debt and 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."
Foreign Operations
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
receives 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's stockholders' equity was
negatively impacted by approximately $2.5 million during 1997 due to
fluctuations in the foreign currency translation rate. 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 contracts 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 23, 1998, the Company had 6,335,517 shares of Common Stock
outstanding of which 1,365,995 shares were held by affiliates. In addition, at
March 23, 1998, the Company had 834,000 shares of Common Stock subject to
outstanding options granted under certain stock option plans (of which 287,918
shares were vested at March 23, 1998) and 225,500 shares usable upon exercise of
warrants.
All of the shares of Common Stock held by affiliates are restricted or
control securities under Rule 144 promulgated under the Securities Act of 1933,
as amended (the "Securities Act"). The shares of the Common Stock issuable upon
exercise of the stock options have been registered under the Securities Act. The
shares of the Common Stock issuable upon exercise of the warrants are subject to
certain registration rights and, therefore, will be eligible for resale in the
public market after a registration statement covering such shares has been
declared effective. Sales of shares of Common Stock under Rule 144 or 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
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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 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
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 faces 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 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 competes against other companies in its natural gas
processing business both for supplies of natural gas and for customers to which
it sells 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, 1997. The average sales prices as of
such dates used for purposes of such estimates were $16.76 per Bbl of crude oil,
$10.89 per Bbl of NGLs and $2.08 per Mcf of natural gas. Also assumed is the
Company's making future capital expenditures of approximately $36.7 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 "Properties - Reserve
Information."
Certain Business Risks
The Company intends to continue acquiring producing crude oil and
natural gas properties or companies that own such properties. Although the
Company performs a review of the acquired properties that it believes is
consistent with industry practices, such reviews are inherently incomplete. It
generally is not feasible to review in depth every individual property involved
in each acquisition. Ordinarily, the Company will focus its review efforts on
the higher-valued properties and will sample the remainder. However, even an
in-depth review of all properties and records may not necessarily reveal
existing or potential problems nor will it permit the Company to become
sufficiently familiar with the properties to assess fully their deficiencies and
capabilities. Inspections may not always be performed on every well, and
environmental problems, such as ground water contamination, are not necessarily
observable even when an inspection is undertaken. Furthermore, the Company must
rely on information, including financial, operating and geological information,
provided by the seller of the properties without being able to verify fully all
such information and without the benefit of knowing the history of operations of
all such properties.
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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 canceled 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 Indentures 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.
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
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and business and financial contacts. The unavailability of Mr. Watson would have
a material 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, 1998 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, 1997, the Company had, subject to the limitations
discussed below, $25.1 million of net operating loss carryforwards for tax
purposes, of which approximately $22.4 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 the Company's 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 $5.9 million for deferred tax assets at December 31, 1996
and 1997, 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.
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.
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The North American Free Trade Agreement. On January 1, 1994, the North
American Free Trade Agreement ("NAFTA") among the governments of the United
States, Canada and Mexico became effective. In the context of energy resources,
Canada remains free to determine whether exports to the U.S. or Mexico will be
allowed provided that any export restrictions do not: (i) reduce the proportion
of energy resources exported relative to the total supply of the energy resource
(based upon the proportion prevailing in the most recent 36 month period); (ii)
impose an export price higher than the domestic price; or (iii) disrupt normal
channels of supply. All three countries are prohibited from imposing minimum
export or import price requirements.
NAFTA contemplates the reduction of Mexican restrictive trade practices
in the energy sector and prohibits discriminatory border restrictions and export
taxes. The agreement also contemplates clearer disciplines on regulators to
ensure fair implementation of any regulatory changes and to minimize disruption
of contractual arrangements, which is important for Canadian natural gas
exports.
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. The federal appellate
courts have largely affirmed the features of Order No. 636 and numerous related
orders pertaining to the individual pipelines. Nevertheless, because further
review of certain of these orders is still possible, various appeals remain
pending, and the FERC continues to review and modify its open access
regulations, the outcome of such proceedings and their ultimate impact on the
Company's business is uncertain.
In recent years the FERC also has pursued a number of other important
policy initiatives which could significantly affect the marketing of natural
gas. Some of the more notable of these regulatory initiatives include (i) a
series of orders in individual pipeline proceedings articulating a policy of
generally approving the voluntary divestiture of interstate pipeline owned
gathering facilities by interstate pipelines to their affiliates (the so-called
"spin down" of previously regulated gathering facilities to the pipeline's
nonregulated affiliates), (ii) the completion of rule-making involving the
regulation of pipelines with marketing affiliates under Order No. 497, (iii) the
FERC's ongoing efforts to promulgate standards for pipeline electronic bulletin
boards and electronic data exchange, (iv) a generic inquiry into the pricing of
interstate pipeline capacity, (v) efforts to refine the FERC's regulations
controlling operation of the secondary market for released pipeline capacity,
(vi) a policy statement regarding market based rates and other non-cost-based
rates for interstate pipeline transmission and storage capacity and (vii) a
proposed rule to further standardize pipeline transportation tariffs that, if
implemented as proposed, may adversely affect the reliability of scheduled
interruptible transportation. In addition, the FERC has recently requested
comments on the financial outlook of the natural gas pipeline industry
including, among other matters, whether the FERC's current rate making policies
are suitable in the current industry environment. 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.
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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 spin downs 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. The U.S. Court of
Appeals for the D.C. Circuit has now largely upheld the FERC. The Company cannot
predict what the ultimate effect of the FERC's orders pertaining to gathering
will have on its production and marketing.
State and Other Regulation. All of the jurisdictions in which the
Company owns producing crude oil and natural gas properties have statutory
provisions regulating the exploration for and production of crude oil and
natural gas, including provisions requiring permits for the drilling of wells
and maintaining bonding requirements in order to drill or operate wells and
provisions relating to the location of wells, the method of drilling and casing
wells, the surface use and restoration of properties upon which wells are
drilled and the plugging and abandoning of wells. The Company's operations are
also subject to various conservation laws and regulations. These include the
regulation of the size of drilling and spacing units or proration units and the
density of wells which may be drilled and the unitization or pooling of crude
oil and natural gas properties. In this regard, some states allow the forced
pooling or integration of tracts to facilitate exploration while other states
rely on voluntary pooling of lands and leases. In addition, state conservation
laws establish maximum rates of production from crude oil and natural gas wells,
generally prohibit the venting or flaring of natural gas and impose certain
requirements regarding the ratability of production. Some states, such as Texas
and Oklahoma, have, in recent years, reviewed and substantially revised methods
previously used to make monthly determinations of allowable rates of production
from fields and individual wells. The effect of these regulations is to limit
the amounts of crude oil and natural gas the Company can produce from its wells,
and to limit the number of wells or the location at which the Company can drill.
State regulation of gathering facilities generally includes various
safety, environmental, and in some circumstances, non-discriminatory take
requirements, but does not generally entail rate regulation. Natural gas
gathering has received greater regulatory scrutiny at both the state and federal
levels in the wake of the interstate pipeline restructuring under Order 636. For
example, Oklahoma recently enacted a prohibition against discriminatory
gathering rates and certain Texas regulatory officials have expressed interest
in evaluating similar rules.
In the event the Company conducts operations on federal or Indian oil
and gas leases, such operations must comply with numerous regulatory
restrictions, including various non-discrimination statutes, and certain of such
operations must be conducted pursuant to certain on-site security regulations
and other permits issued by various federal agencies. In addition, the Minerals
Management Service ("MMS") has recently issued a final rule to clarify the types
of costs that are deductible transportation costs for purposes of royalty
valuation of production sold off the lease. In particular, MMS will not allow
deduction of costs associated with marketer fees, cash out and other pipeline
imbalance penalties, or long-term storage fees. The Company cannot predict what,
if any, effect the new rule will have on its operations.
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
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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
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.
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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.
Environmental Matters
The Company's domestic operations are subject to numerous federal,
state, and local laws and regulations controlling the generation, use, storage,
and discharge of materials into the environment or otherwise relating to the
protection of the environment. These laws and regulations may require the
acquisition of a permit or other authorization before construction or drilling
commences; restrict the types, quantities, and concentrations of various
substances that can be released into the environment in connection with
drilling, production, and gas processing activities; suspend, limit or prohibit
construction, drilling and other activities in certain lands lying within
wilderness, wetlands, and other protected areas; require remedial measures to
mitigate pollution from historical and on-going operations such as use of pits
and plugging of abandoned wells; restrict injection of liquids into subsurface
aquifers that may contaminate groundwater; and impose substantial liabilities
for pollution resulting from the Company's operations. Environmental permits
required for the Company's operations may be subject to revocation,
modification, and renewal by issuing authorities. Governmental authorities have
the power to enforce compliance with their regulations and permits, and
violations are subject to injunction, civil fines, and even criminal penalties.
Management of the Company believes that it is in substantial compliance with
current environmental laws and regulations, and that the Company will not be
required to make material capital expenditures to comply with existing laws.
Nevertheless, changes in existing environmental laws and regulations or
interpretations thereof could have a significant impact on the Company as well
as the oil and gas industry in general, and thus the Company is unable to
predict the ultimate cost and effect of future changes in environmental laws and
regulations.
The Comprehensive Environment Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" and comparable state statutes impose
strict, joint, and several liability on certain classes of persons who are
considered to have contributed to the release of a "hazardous substance" into
the environment. These persons include the owner or operator of a disposal site
or sites where a release occurred and companies that dispose or arranged for the
disposal of the hazardous substances released at the site. Under CERCLA such
persons or companies may be liable for the costs of cleaning up the hazardous
substances that have been released into the environment and for damages to
natural resources, and it is not uncommon for neighboring land owners and other
third parties to file claims for personal injury, property damage, and recovery
of response costs allegedly caused by the hazardous substances released into the
environment. The Resource Conservation and Recovery Act ("RCRA") and comparable
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state statues govern the disposal of "solid waste" and "hazardous waste" and
authorize imposition of substantial civil and criminal penalties for
noncompliance. Although CERCLA currently excludes petroleum from the definition
of "hazardous substance," state laws affecting the Company's operations impose
cleanup liability relating to petroleum and petroleum related products. In
addition, although RCRA currently classifies certain oilfield wastes as
"non-hazardous," such exploration and production wastes could be reclassified as
hazardous wastes thereby making such wastes subject to more stringent handling
and disposal requirements.
The Company currently owns or leases, and has in the past owned or
leased, numerous properties that for many years have been used for the
exploration and production of oil and gas. Although the Company has utilized
operating and disposal practices that were standard in the industry at the time,
hydrocarbons or other wastes may have been disposed of or released on or under
the properties owned or leased by the Company or on or under other locations
where such wastes have been taken for disposal. In addition, many of these
properties have been operated by third parties whose treatment and disposal or
release of hydrocarbons or other wastes was not under the Company's control.
These properties and the wastes disposed thereon may be subject to CERCLA, RCRA,
and analogous state laws.
Federal regulations also require certain owners and operators of
facilities that store or otherwise handle oil, such as the Company, to prepare
and implement spill prevention, control and countermeasure plans and spill
response plans relating to possible discharge of oil into surface waters. The
federal Oil Pollution Act ("OPA") contains numerous requirements relating to
prevention of and response to oil spills into waters of the United States. For
facilities that may affect state waters, OPA requires an operator to demonstrate
$10 million in financial responsibility.
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. The Act sets out
environmental standards and compliance for releases, clean-up and reporting. The
Act also provides a range of enforcement actions and penalties.
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.
Moreover, the Company maintains insurance against costs of clean-up operations,
but it is 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.
Employees
As of March 23, 1998, Abraxas and its subsidiaries had 74 full-time
employees, including two executive officers, 6 non-executive officers, 5
petroleum engineers, 2 landmen, 2 geologists, 30 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.
17
<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, 1997:
Developed and Undeveloped Acreage
As of December 31, 1997
Developed Acreage (1) Undeveloped Acreage (2)
---------------------------- -----------------------------
Gross Acres (3) Net Acres (4)Gross Acres (3) Net Acres
(4)
------------- ------------ ------------- --------------
Canada 227,794 111,888 402,246 286,041
Texas 41,393 24,143 12,369 9,591
N. Dakota 1,864 1,021 -- --
Montana 320 10 -- --
Kansas 640 142 -- --
Wyoming 5,239 3,620 14,020 9,476
Alabama 720 23 -- --
------------- ------------ ------------- --------------
Total 277,970 140,847 428,635 305,108
- ---------------
(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).
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, 1997:
Productive Wells (1)
As of December 31, 1997
State/Country Crude Oil Natural Gas
-------------------------- ----------------------------
Gross(2) Net(3) Gross(2) Net(3)
-------------- ------------ ------------ ------------ -------------
Canada 57.0 12.7 212.0 97.2
Texas 332.0 194.8 105.0 67.2
N. Dakota 4.0 1.7 - -
Montana 1.0 0.1 - -
New Mexico - - 1.0 0.1
Wyoming 3.0 0.2 43.0 30.0
Alabama 1.0 - 1.0 -
Kansas 3.0 0.7 - -
============ ============ ============ =============
Total 401.0 210.2 362.0 194.5
============ ============ ============ =============
- ------------
(1) Productive wells are producing wells and wells capable of production.
(2) A gross well is a well in which Abraxas owns an interest. The number of
gross wells is the total number of wells in which Abraxas owns an
interest.
(3) A net well is deemed to exist when the sum of fractional ownership
working interests in gross wells equals one. The number of net wells is
the sum of Abraxas' fractional working interest owned in gross wells.
(4) Included in the above wells are 23 gross and 21 net crude oil and 11
gross and 3 net natural gas wells with multiple completions.
18
<PAGE>
Substantially all of Abraxas' existing crude oil and natural gas
properties are pledged to secure Abraxas' indebtedness under the Credit
Facility. 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, 1998, January 1, 1997 and January 1, 1996 and of Canadian Abraxas
as of January 1, 1997, by DeGolyer & MacNaughton, of Dallas, Texas. The reserves
of Canadian Abraxas and Cascade as of January 1, 1998 have been estimated by
McDaniel & Associates Consultants Ltd. of Calgary, Alberta. Crude oil and
natural gas reserves, and the estimates of the present value of future net
revenues therefrom, were determined based on then current prices and costs.
Reserve calculations involve the estimate of future net recoverable reserves of
crude oil and natural gas and the timing and amount of future net revenues to be
received therefrom. Such estimates are not precise and are based on assumptions
regarding a variety of factors, many of which are variable and uncertain.
The following table sets forth certain information regarding estimates
of the Company's crude oil, natural gas liquids and natural gas reserves as of
January 1, 1998 January 1, 1997 and January 1, 1996:
Estimated Proved Reserves
----------------------------------------
Proved Proved Total
Developed Undeveloped Proved
------------ ------------ --------------
As of January 1, 1996
Crude oil (MBbls) 3,992 1,516 5,508
NGLs (MBbls) 2,007 752 2,759
Natural gas (MMcf) 44,026 10,543 54,569
As of January 1, 1997
Crude oil (MBbls) 7,871 1,930 9,801 (1)
NGLs (MBbls) 7,090 1,144 8,234
Natural gas (MMcf) 157,660 19,600 177,260
As of January 1,1998
Crude oil (MBbls) 7,075 1,873 8,948 (1)
NGLs (MBbls) 7,178 1,651 8,829 (2)
Natural gas (MMcf) 186,490 34,824 221,314 (3)
- ------------------
(1) Includes 120,000 and 128,900 barrels of crude oil reserves owned by
Cascade of which 57,600 and 69,451 barrels are applicable to the minority
interests share of these reserves as of December 31, 1996 and 1997,
respectively.
(2) Includes 131,300 barrels of natural gas liquids reserves owned by Cascade
of which 70,889 barrels are applicable to the minority interests share of
these reserves as of December 31, 1997.
(3) Includes 7,446 Mmcf of natural gas reserves owned by Cascade of which
4,020 Mmcf are applicable to the minority interests share of these
reserves as of December 31, 1997.
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 judgment. As
a result, estimates of different engineers often vary. In addition, estimates of
19
<PAGE>
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.
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, 1997:
1997 1996 1995
--------------- -------------- ---------------
Crude oil production
(Bbls) 936,716 425,188 401,445
Natural gas production
(Mcf) 21,050,045 6,350,069 3,552,671
Natural gas liquids
production (Bbls) 992,266 299,509 143,380
Average sales price per
Bbl of crude oil ($) $ 18.63 $ 20.85 $ 17.16
Average sales price per
MCF of natural gas ($) $ 1.79 $ 1.97 $ 1.47
Average sales price per
Bbl of natural gas
liquids ($) $ 10.75 $ 14.55 $ 10.83
Average cost of
production ($) per
BOE produced (1) $ 2.74 $ 3.28 $ 3.81
(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.
20
<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, 1997:
1997 1996 1995
------------------ ---------------- ----------------
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
-------- ------- -------- ------- -------- ------
Exploratory (3)
Productive (4)
Crude oil - - 2.0 1.2 1.0 .72
Natural gas 10.0 7.9 2.0 1.2 - -
Dry holes (5) 2.0 1.8 4.0 1.4 1.0 1
-------- ------- ------- ------- -------- ------
Total 12.0 9.7 8.0 3.8 2.0 1.72
======== ======= ======= ======= ======== ======
Development (6)
Productive
Crude oil 25.0 22.3 20.0 15.8 12.0 9.1
Natural gas 20.0 14.9 10.0 3.7 2.0 .6
Service (7) - - 1.0 1.0 - -
Dry holes (5) 3.0 2.0 - - 1.0 .3
-------- ------- -------- ------- -------- ------
Total 48.0 39.2 31.0 20.5 15.0 10.0
======== ======= ======= ======= ======== ======
- ------------------
(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.
As of March 23, 1998, the Company has five wells in process of drilling.
21
<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 1,090 square feet in
Midland, are leased until March 2006 from unaffiliated parties at an aggregate
rate of approximately $18,000 per month. Cascade leases 8,683 square feet of
office space in Calgary, Alberta pursuant to a lease with an unaffiliated third
party which expires on December 31, 2001 at a rate of approximately CDN $15,000
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
Hornburg Litigation. In May 1995 John H. Hornburg and certain other
individuals filed a lawsuit against the Company alleging negligence and gross
negligence, tortious interference with contract, conversion and waste. In March
1998, a jury found against the Company in the amount of $1,332,825 plus
attorneys fees and pre-judgment interest. At March 31, 1998, no judgment had
been entered. The Company intends to file various post-judgment motions
including a motion for judgment notwithstanding the verdict and a motion for new
trial, as well as an appeal, if necessary.. The Company has not established a
reserve to account for the damages awarded to the plaintiffs by the jury.
Other Litigation. From time to time, the Company is involved in
litigation relating to claims arising out of its operations in the normal course
of business. As of March 23, 1998, 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, 1997.
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 1998 annual
meeting of directors and until his successor is duly elected and qualified.
Robert L. G. Watson, age 47, 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 46, 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.
22
<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 1995, 1996 and 1997.
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
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
1997
First Quarter............................$14.00 $8.88
Second Quarter............................14.13 10.00
Third Quarter.............................15.75 12.50
Fourth Quarter............................19.50 13.88
Holders
As of March 23, 1998 Abraxas had 6,335,517 shares of common stock
outstanding and had approximately 1,865 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 Indentures, prohibited 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".
23
<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 of the Company and Notes thereto, and other
financial information included herein. See "Financial Statements."
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------------------
1997 1996 1995 1994 1993
(In thousands except per share data)
<S> <C> <C> <C> <C> <C>
Total revenue $ 70,931 $ 26,653 $ 13,817 $ 11,349 $ 7,494
Income (loss)from continuing
operations $ (6,485) $ 1,940 $ (1,209) $ 113 $ (1,580)
Income (loss) per common share from
continuing operations $ (1.11) $ .23 $ (.34) $ .02 $ (.91)
Weighted average shares outstanding 6,025 6,794 4,635 4,310 1,947
Total assets $ 338,528 $ 304,842 $ 85,067 $ 75,361 $ 43,396
Long-term debt $ 248,617 $ 215,032 $ 41,601 $ 41,296 $ 12,529
Total shareholders' equity $ 26,813 $ 35,656 $ 37,062 $ 28,502 $ 25,143
</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,
----------------------------------
(dollars in thousands, except
per unit data)
1997 1996 1995
--------- ----------- ----------
Operating revenue:
Crude oil sales $17,453 $8,864 $5,218
NGLs sales 10,668 4,359 1,553
Natural gas sales 37,705 12,526 6,889
Gas Processing revenue 3,568 600 -
Other 1,537 304 157
========= =========== ==========
Total operating revenue $70,931 $26,653 $13,817
========= =========== ==========
Operating income $15,150 $ 8,826 $ 2,883
Crude oil production (MBbls) 936.7 425.2 401.4
NGLs production (MBbls) 992.3 299.5 143.4
Natural gas production (MMcf) 21,050.0 6,350.0 3,552.7
Average crude oil sales prices (per Bbl) $ 18.63 $ 20.85 $ 17.16
Average NGLs sales price (per Bbl) $ 10.75 $ 14.55 $ 10.83
Average natural gas sales price (per Mcf) $ 1.79 $ 1.97 $ 1.47
Comparison of Year Ended December 31, 1997 to Year Ended December 31, 1996
Operating Revenue. During the year ended December 31, 1997, operating
revenue from crude oil, natural gas and natural gas liquids sales, and natural
gas processing revenues increased by $43.1 million from $26.3 million in 1996 to
24
<PAGE>
$69.4 million in 1997. This increase was primarily attributable to increased
volumes which were partially offset by a decline in commodity prices. Volume
increased from 1,783 MBOE to 5,437 MBOE for the year ended December 1997. Crude
oil and natural gas liquids sales volumes increased by 166% to 1,929 MBOE during
1997 compared to 725 MBOE in 1996, natural gas sales volumes increased by 231%
to 21.1 Bcf in 1997 compared to 6.3 Bcf in 1996. The increases in volumes were
attributable to a full year of production from property acquisitions completed
during the fourth quarter of 1996 as well as increased production attributable
to the Company's ongoing development program on existing and acquired
properties. Acquisitions and the subsequent development of the acquired
properties contributed 1,182 MBbls of oil and natural gas liquids and 15.9 Bcf
of natural gas. Development of existing properties contributed 747 MBbls of oil
and natural gas liquids and 5.2 Bcf of natural gas during 1997. Average sales
prices in 1997 were $18.63 per Bbl of crude oil, $10.75 per Bbl of natural gas
liquid and $1.79 per Mcf of natural gas compared to $20.85 per Bbl of crude oil,
$14.55 per Bbl of natural gas liquids and $1.97 per Mcf of natural gas in 1996.
The Company also had gas processing revenue of $3.6 million in 1997 as a result
of the acquisition of CGGS in November 1996. Prior to the acquisition, the
Company was not engaged in third party gas processing.
Lease Operating Expenses. Lease operating expenses ("LOE") and natural
gas processing costs increased by $10.0 million from $6.1 million for the year
ended December 31, 1996 to $16.1 million for the same period of 1997. LOE
increased by $9.0 million to $14.9 million primarily due to the greater number
of wells owned by the Company for the year ended December 31, 1997 compared to
the year ended December 31, 1996. The Company's LOE on a per BOE basis for 1997
was $2.74 per BOE as compared to $3.28 per BOE in 1996. Natural gas processing
cost increased to $1.3 million in 1997 as compared to $262,000 in 1996. The
increase in gas processing expense was due to the acquisition of CGGS in
November 1996. Prior to the acquisition, the Company was not engaged in third
party gas processing
G & A Expenses. General and administrative ("G & A") expenses increased
from $1.9 million for the year ended December 31, 1996 to $4.2 million for the
year ended December 31, 1997, as a result of the Company's hiring additional
staff, including an increase in personnel to manage and develop properties
acquired in the fourth quarter of 1996. The Company's G & A expense on a per BOE
basis was $0.77 per BOE in 1997 compared to $1.08 per BOE for 1996.
DD & A Expenses. Due to the increase in sales volumes of crude oil and
natural gas, depreciation, depletion and amortization ("DD & A") expense
increased by $21.0 million from $9.6 million for the year ended December 31,
1996 to $30.6 million for the year ended December 31, 1997. The Company's DD&A
expense on a per BOE basis for 1997 was $5.62 per BOE as compared to $5.38 per
BOE in 1996.
Interest Expenses and Preferred Dividends. Interest expense and
preferred dividends increased by $18.1 million from $6.4 million to $24.5
million for the year end December 31, 1997, compared to 1996 . This increase was
attributable to increased borrowings by the Company to finance the acquisitions
consummated during 1996. In November 1996, the Company issued $215 million in
principal amount of the Series B Notes. During 1997, the Company made additional
borrowings under the Credit Facility. Long-term debt increased from $215.0
million at December 31, 1996 to $248.6 million at December 31, 1997. During
1997, the Company paid $183,000 in preferred dividends in 1997 as compared to
$366,000 in 1996. Preferred dividends were eliminated on July 1, 1997 as the
result of the conversion of all outstanding preferred stock into Abraxas Common
Stock.
Ceiling Limitation Write-down. The Company records the carrying value of
its crude oil and natural gas properties using the full cost method of
accounting for oil and gas properties. Under this method, the Company
capitalizes the cost to acquire, explore for and develop oil and gas properties.
Under the full cost accounting rules, the net capitalized cost of crude oil and
natural gas properties less related deferred taxes, are limited by country, to
the lower of unamortized cost on the cost ceiling, defined as the sum of the
present value of estimated unescalated future net revenues from proved reserves
discounted at 10 percent, plus the cost of properties not being amortized, if
any, plus the lower of cost or estimated fair value of unproved properties
included in the costs being amortized, if any, less related income taxes. If the
net capitalized cost of crude oil and natural gas properties exceeds the ceiling
limit, the Company is subject to a ceiling limitation write-down to the extent
of such excess. A ceiling limitation write-down is a charge to earnings which
does not impact cash flow from operating activities. However, such write-downs
25
<PAGE>
do impact the amount of the Company's stockholder's equity. The risk that the
Company will be required to write-down the carrying value of its oil and gas
assets increases when oil and gas prices are depressed or volatile. In addition,
write-downs may occur if the Company has substantial downward revisions in its
estimated proved reserves or if purchasers or governmental action cause an
abrogation of, or if the Company voluntarily cancels, long-term contracts for
its natural gas. For the year ended December 31, 1997, the Company recorded a
write-down of $4.6 million, $3.0 million after tax, related to its Canadian
properties. No assurance can be given that the Company will not experience
additional write-downs in the future. Should commodity prices continue to
decline, a further write-down of the carrying value of the Company's crude oil
and natural gas properties may be required. See Note 16 of Notes to Consolidated
Financial Statements.
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 the Portilla and Happy fields during the portion of the year
that the Company did not own the properties. The Company sold these properties
in March 1996 and reacquired these properties in November 1996. 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 capital
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. LOE and natural gas processing costs 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. G & A 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, DD & A 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
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increased borrowings by the Company to finance the acquisitions consummated
during 1996. Long-term debt increased from $41.6 million at December 31, 1995 to
$215.0 million at December 31, 1996.
General 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; however,
gas and crude oil prices weakened somewhat during 1997, crude oil prices have
continued to be depressed in 1998.. The average natural gas prices realized by
the Company were $1.79 per Mcf in 1997 compared with $1.97 per Mcf at December
31, 1996 and $1.47 per Mcf at December 31, 1995. During, 1997, crude oil prices
averaged $18.63 per Bbl compared to $20.85 during 1996 and $17.16 per Bbl during
1995. Although the Company had operating and net income during 1996, losses were
incurred in 1995 and 1997 and there can be no assurance that operating income
and net earnings will be achieved in future periods. 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. Ifcrude oil
prices remain at depressed levels or if natural gas prices return to depressed
levels , or if the Company's production levels decrease, the Company's revenues,
cash flow from operations and profitability will be materially adversely
affected.
Liquidity and Capital Resources
General: Capital expenditures in 1995, 1996 and 1997 were approximately
$12.3 million, $173.2 million and $87.8 million, respectively. The table below
sets forth the components of these capital expenditures on a historical basis
for the three years ended December 31, 1995, 1996 and 1997.
Year Ended December 31
---------------------------------
(dollars in thousands)
1997 1996 1995
---- ---- ----
Expenditure category:
Property acquisitions (1) $24,210 $154,484 $ 719
Development 61,414 18,465 11,472
Facilities and other 2,140 206 139
------- -------- -------
Total $87,764 $173,155 $12,330
======= ======== =======
(1) Acquisition cost includes 7,585,000 common shares and 4,000,000
special warrants of Cascade Oil & Gas Ltd. valued at approximately $3.7 million
in 1997 related to the acquisition of certain crude oil and natural gas
producing properties.
Acquisitions of crude oil and natural gas producing properties during
1996 accounted for the majority of the capital expenditures made by the Company.
during 1995 and 1997, expenditures were primarily for the development of
existing properties. These expenditures were funded through internally generated
cash flow and borrowings under the Credit Facility.
At December 31, 1997, the Company had current assets of $18.3 million
and current liabilities of $27.5 million resulting in a working capital deficit
of $9.2 million. This compares to working capital of $6.4 million at December
31, 1996. The material components of the Company's current liabilities at
December 31, 1997 include trade accounts payable of $17.1 million, revenues due
third parties of $2.8 million and accrued interest of $4.6 million.
Stockholders' equity decreased from $35.7 million at December 31, 1996 to $26.8
million at December 31, 1997 primarily due to a net loss incurred in 1997,
including the impact of the write-down in the Company's assets resulting from
the impairment of the full cost pool. See "Ceiling Limitation Write-down"
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The Company's current budget for capital expenditures for 1998 other than
acquisition expenditures is $68.4 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. Should the price of crude oil continue to
decline or if natural gas prices decline, the Company's cash flows will decrease
which may result in a reduction in the capital expenditures budget.
The Company will have three principal sources of liquidity during the next
12 months: (i) cash on hand, including the net proceeds of the offering of the
Series C Notes, (ii) borrowing capacity under the Credit Facility and (iii) cash
flow from operations. While the availability of capital resources cannot be
predicted with certainty and is dependent upon a number of factors including
factors outside of management's control, management believes that the net
proceeds of the offering of the Series C Notes, the Company's cash flow from
operations plus availability under the Credit Facility will be adequate to fund
operations and planned capital expenditures. The Company may also sell
additional equity or debt securities in order to fund operations and planned
capital expenditures as well as to finance future acquisitions.
The Credit Facility has an availability of $40.0 million. As of December
31, 1997, there was $31.5 million outstanding under the Credit Facility. A
portion of the proceeds of the offering of the Series C Notes were used to
re-pay the outstanding balance of the Credit Facility (except for $100,000 which
remains outstanding).
Operating activities for the year ended December 31, 1997 provided $36.6
million of cash to the Company. Investing activities required $74.5 million
during 1997 primarily for the acquisition and development of producing
properties. Financing provided $33.3 million during 1997.
Operating activities for the year ended December 31, 1996, provided $13.5
million of cash. Investing activities required $172.6 million primarily for the
acquisition of the Wyoming Properties, CGGS and Portilla and Happy. Financing
provided $163.0 million during 1996.
During 1995, operating activities provided $4.5 million of cash. Investing
activities during 1995 utilized $10.1 million of cash primarily for the
development of existing properties. Total cash provided from financing
activities for 1995 was $8 million as the result of the sale of 1,330,000 shares
of Common Stock and contingent value rights during November 1995 which resulted
in net proceeds of $10.1 million.
The Company is heavily dependent on crude oil and natural gas prices which
have historically been volatile. Although the Company has hedged a portion of
its natural gas production and intends to continue this practice, future crude
oil and natural gas price declines would have a material adverse effect on the
Company's overall results, and therefore, its liquidity. Furthermore, low crude
oil and natural gas prices could affect the Company's ability to raise capital
on terms favorable to the Company.
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Long-Term Indebtedness. On November 14, 1996, Abraxas and Canadian Abraxas
consummated the offering of $215 million of their 11.5% Senior Notes due 2004,
Series , (the "Series A Notes"), which were exchanged for the Series B Notes in
February 1998. Interest on the Series B 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 Series B 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 Series B 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 Series B 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 Series B Notes remains outstanding.
The Series B 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