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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 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).
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
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
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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
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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
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
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
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
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
9
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.
10
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
11
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.
12
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.
13
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
14
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.
15
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
16
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
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
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
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
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
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
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
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."
Year Ended December 31,
-------------------------------------------------------
1997 1996 1995 1994 1993
(In thousands except per share data)
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
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
$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
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
26
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"
27
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.
28
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 indebtedness of Abraxas and Canadian Abraxas and on parity
with the Series C Notes. The Series B Notes rank senior in right of payment to
all future subordinated indebtedness of Abraxas and Canadian Abraxas. The Series
B Notes are, however, effectively subordinated to secured indebtedness of
Abraxas and Canadian Abraxas to the extent of the value of the assets securing
such indebtedness.
The Series B Notes are unconditionally guaranteed, jointly and severally,
by certain of Abraxas' and Canadian Abraxas' future subsidiaries (the
"Subsidiary Guarantors"). The guarantees are general unsecured obligations of
the Subsidiary Guarantors and rank pari passu in right of payment to all
unsubordinated indebtedness of the Subsidiary Guarantors and senior in right of
payment to all subordinated indebtedness of the Subsidiary Guarantors. The
Guarantees are effectively subordinated to secured indebtedness of the
Subsidiary Guarantors to the extent of the value of the assets securing such
indebtedness. As of December 31, 1997, Abraxas, Canadian Abraxas and the
Subsidiary Guarantors had secured indebtedness outstanding of approximately
$33,600,000.
Upon a Change of Control (as defined in the Indenture governing the Series
B Notes), each holder of the Series B Notes will have the right to require
Abraxas and Canadian Abraxas to repurchase all or a portion of such holder's
Series B Notes at a redemption price equal to 101% of the principal amount
thereof, plus accrued and unpaid interest to the date of repurchase. In
addition, Abraxas and Canadian Abraxas will be obligated to offer to repurchase
the Series B Notes at 100% of the principal amount thereof plus accrued and
unpaid interest to the date of repurchase in the event of certain asset sales.
The net proceeds to Abraxas and Canadian Abraxas from the offering of the
Series B Notes were approximately $207.0 million after deducting underwriting
discounts and estimated offering expenses payable by Abraxas and Canadian
Abraxas. Abraxas and Canadian Abraxas used the net proceeds to (i) repay all
amounts outstanding under the Company's Bridge Facility dated September 30, 1996
with Bankers Trust Company ("BT") and other lenders in the amount of $85.0
million, (ii) acquire the outstanding capital stock of CGGS for $94.7 million,
(iii) acquire the Portilla and Happy properties and repay certain indebtedness
for $27.5 million and (iv) provide working capital for general corporate
purposes including future acquisitions and development of producing properties.
29
In January 1998, the Company and Canadian Abraxas completed the sale of
$60 million aggregate principal amount of the Series C Notes. Interest on the
Series C Notes accrues from their date of original issuance (January 27, 1998)
and is payable semi-annually in arrears on May 1 and November 1 of each year,
commencing May 1, 1998, at the rate of 11.5% per annum. The Series C Notes are
general unsecured obligations of the Company and Canadian Abraxas and rank pari
passu in right of payment to all existing and future unsubordinated indebtedness
of the Company and Canadian Abraxas and on parity with the Series B Notes. The
Series C Notes have substantially the same terms as the Series B Notes. The
Company and Canadian Abraxas sold the Series C Notes at a premium of $4,050,000
which will be amortized over the life of the Series C Notes resulting in an
effective interest rate of 10.5%. The net proceeds, after deducting estimated
offering costs, were $62,750,000, $33,400,000 of which was used to repay
outstanding indebtedness under the Credit Facility, except for $100,000 which
remained outstanding with the remainder to be used for general corporate
purposes including future acquisitions and the development of producing
properties.
On November 14, 1996, the Company entered into the Credit Facility concurrently
with the consummation of the offering of the Series A Notes. The Credit
Facility, which was amended in October 1997, provides for a revolving line of
credit with an availability of $40.0 million, subject to certain customary
conditions including a borrowing base condition.
Commitments available under the Credit Facility are subject to borrowing
base redeterminations to be performed semi-annually and, at the option of each
of the Company and the Banks, one additional time per year. Any outstanding
principal balance in excess of the borrowing base will be due and payable in
three equal monthly payments after a borrowing base redetermination. The
borrowing base will be determined in BT's sole discretion, subject to the
approval of the Banks, based on the value of the Company's reserves as set forth
in the reserve report of the Company's independent petroleum engineers, with
consideration given to other assets and liabilities.
The Credit Facility has an initial revolving term of two years and a
reducing period of three years from the end of the initial two-year period. The
commitment under the Credit Facility will be reduced during such reducing period
by eleven equal quarterly reductions. Quarterly reductions will equal 8.2% per
quarter with the remainder due at the end of the three-year reducing period.
The applicable interest rate charged on the outstanding balance of the
Credit Facility is based on a facility usage grid. If the borrowings under the
Credit Facility represent an amount less than or equal to 33.3% of the available
borrowing base, then the applicable interest rate charged on the outstanding
balance will be either (a) an adjusted rate of the London Inter-Bank Offered
Rate ("LIBOR") plus 1.25% or (b) the prime rate of BT (which is based on BT's
published prime rate) plus 0.50%. If the borrowings under the Credit Facility
represent an amount greater than or equal to 33.3% but less than 66.7% of the
available borrowing base, then the applicable interest rate on the outstanding
principal will be either (a) LIBOR plus 1.75% or (b) the prime rate of BT plus
0.50%. If the borrowings under the Credit Facility represent an amount greater
than or equal to 66.7% of the available borrowing base, then the applicable
interest rate on the outstanding principal will be either (a) LIBOR plus 2.00%
or (b) the prime rate of BT plus 0.50%. LIBOR elections can be made for periods
of one, three or six months.
The Credit Facility contains a number of covenants that, among other
things, restrict the ability of the Company to (i) incur certain indebtedness or
guarantee obligations, (ii) prepay other indebtedness including the Notes, (iii)
make investments, loans or advances, (iv) create certain liens, (v) make certain
payments, dividends and distributions, (vi) merge with or sell assets to another
person or liquidate, (vii) sell or discount receivables, (viii) engage in
certain intercompany transactions and transactions with affiliates, (ix) change
its business, (x) experience a change of control and (xi) make amendments to its
charter, by-laws and other debt instruments. In addition, under the Credit
Facility, the Company is required to comply with specified financial ratios and
tests, including minimum debt service coverage ratios, maximum funded debt to
EBITDA tests, minimum net worth tests and minimum working capital tests. As of
December 31, 1997, the Company was not in compliance with the minimal working
capital and capital expenditure requirements under the Credit Facility. Should
crude oil prices continue to decline a further write-down of the Company's oil
and gas properties may be required. If such a write-down were large enough, it
30
could result in a default in the net worth requirement under the Credit
Facility. The Company has received a waiver of these requirements through March
31, 1998.
The Credit Facility contains customary events of default, including
nonpayment of principal, interest or fees, violation of covenants, inaccuracy of
representations or warranties in any material respect, cross default and cross
acceleration to certain other indebtedness, bankruptcy, material judgments and
liabilities and change of control. The Indentures also contain a number of
covenants and events of default including covenants restricting, among other
things, the Company's and Canadian Abraxas' 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 and events of default including nonpayment of principal or
interest on the Notes, violation of covenants, cross default on other
indebtedness, bankruptcy and material judgments.
The Indentures also provide that the Company and Canadian Abraxas may not,
and may not cause or permit certain of its subsidiaries, including Canadian
Abraxas, to, directly or indirectly, create or otherwise cause to permit to
exist or become effective any encumbrance or restriction on the ability of such
subsidiary to pay dividends or make distributions on or in respect of its
capital stock, make loans or advances or pay debts owed to Abraxas, guarantee
any indebtedness of Abraxas or transfer any of its assets to Abraxas except for
such encumbrances or restrictions existing under or by reason of: (i) applicable
law; (ii) the Indenture; (iii) the Credit Facility; (iv) customary
non-assignment provisions of any contract or any lease governing leasehold
interests of such subsidiaries; (v) any instrument governing indebtedness
assumed by the Company in an acquisition, which encumbrance or restriction is
not applicable to such subsidiaries or the properties or assets of such
subsidiaries other than the entity or the properties or assets of the entity so
acquired; (vi) customary restrictions with respect to subsidiaries of the
Company pursuant to an agreement that has been entered in to for the sale or
disposition of capital stock or assets of such subsidiaries to be consummated in
accordance with the terms of the Indenture solely in respect of the assets or
capital stock to be sold or disposed of; (vii) any instrument governing certain
liens permitted by the Indenture, to the extent and only to the extent such
instrument restricts the transfer or other disposition of assets subject to such
lien; or (viii) an agreement governing indebtedness incurred to refinance the
indebtedness issued, assumed or incurred pursuant to an agreement referred to in
clause (ii), (iii) or (v) above; provided, however, that the provisions relating
to such encumbrance or restriction contained in any such refinancing
indebtedness are no less favorable to the holders of the Notes in any material
respect as determined by the Board of Directors of the Company in their
reasonable and good faith judgment than the provisions relating to such
encumbrance or restriction contained in the applicable agreement referred to in
such clause (ii), (iii) or (v).
Hedging Activities. In August 1995, the Company entered into a rate swap
agreement with a previous lender relating to $25.0 million of principal amount
of outstanding indebtedness. This agreement was assumed by the Banks . Under the
agreement, the Company pays a fixed rate of 6.15% while the Banks will pay a
floating rate equal to the USD-LIBOR-BBA rate for one month maturities, quoted
on the eighteenth day of each month, to the Company. Settlements are due
monthly. The agreement terminates in August 1998. At December 31, 1997, the fair
value of this swap, as determined by BT, was approximately $64,000.
In connection with the re-acquisition of the Portilla and Happy Fields,
the Company assumed a commodity price hedge on variable volumes of crude oil and
natural gas. Monthly settlements with amounts either due to or from Christiania
are based on the differential between a fixed and a variable price for crude oil
and natural gas. During 1997, the approximate monthly volume of crude oil sales
subject to this agreement is 15,800 barrels at a fixed price of $17.20. This
agreement reduces to approximately 13,200 barrels per month in 1998, 11,000
barrels per month in 1999, 9,200 barrels per month in 2000 and 8,200 barrels per
month in 2001 until November 1. The fixed price paid to the Company over this
five year period averages $17.55 per barrel. The natural gas component of this
agreement calls for approximately 54,000 MMBTU per month at a fixed price of
$1.80 during 1997 with volumes decreasing to 37,000 MMBTU per month in 1998,
24,000 MMBTU per month in 1999, 19,000 MMBTU per month in 2000 and 15,000 MMBTU
per month in 2001 through October. The fixed price paid to the Company over this
five year period averages $1.84 per MMBTU. At December 31, 1997, the estimated
fair market value of the Hedge Agreement is a loss of approximately $700,000.
31
The Company has also entered into a fixed price agreement relating to
approximately 7,500 net Mcf per day of natural gas. The agreement expires on
March 31, 1998 and calls for a fixed price of $2.07 per MMBTU to be paid to the
Company.
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 U.S. tax purposes, of which approximately $22.4 million may be
utilized before it expires. These loss carryforwards will expire from 2002
through 2010 if not utilized. At December 31, 1997, the Company had
approximately $2.9 million of net operating loss carryforwards for Canadian tax
purposes which expire in 2003 and 2004. 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. As a result of the issuance of additional shares of Common Stock for
acquisitions and sales of stock, an additional ownership change under Section
382 occurred in October 1993. Accordingly, it is expected that the use of all
U.S. net operating loss carryforwards generated through October 1993 or $8.2
million will be limited to approximately $1 million per year subject to the
lower limitations described above. Of the $8.2 million net operating loss
carryforwards, it is anticipated that the maximum net operating loss that may be
utilized before it expires is $5.7 million. 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.
Item 8. Financial Statements.
For the financial statements and supplementary data required by this
Item 8, see the Index to Consolidated Financial Statements and Schedules.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
Not Applicable.
PART III
Item 10. Directors and Executive Officers of the Registrant.
There is incorporated in this Item 10 by reference that portion of the
Company's definitive proxy statement for the 1998 Annual Meeting of Stockholders
which appears therein under the caption "Election of Directors". See also the
information in Item 4a of Part I of this Report.
Item 11. Executive Compensation.
There is incorporated in this Item 11 by reference that portion of the
Company's definitive proxy statement for the 1998 Annual Meeting of Stockholders
which appears therein under the caption "Executive Compensation", except for
those parts under the captions "Compensation Committee Report on Executive
Compensation", "Performance Graph" and "Report on Repricing of Options".
Item 12. Security Ownership of Certain Beneficial Owners and Management.
There is incorporated in this Item 12 by reference that portion of the
Company's definitive proxy statement for the 1998 Annual Meeting of Stockholders
which appears therein under the caption "Securities Holdings of Principal
Stockholders, Directors and Officers".
32
Item 13. Certain Relationships and Related Transactions.
There is incorporated in this Item 13 by reference that portion of the
Company's definitive proxy statement for the 1998 Annual Meeting of Stockholders
which appears therein under the caption "Certain Transactions."
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a)1. Consolidated Financial Statements Page
Report of Ernst & Young, LLP, Independent Auditors..........F-2
Consolidated Balance Sheets,
December 31, 1997 and 1996................................F-3
Consolidated Statements of Operations,
Years Ended December 31, 1997, 1996, and 1995.............F-5
Consolidated Statements of Stockholders' Equity
Years ended December 31, 1997, 1996 and 1995.............F-7
Consolidated Statements of Cash Flows
Years Ended December 31, 1997, 1996 and 1995..............F-9
Notes to Consolidated Financial Statements.................F-11
(a)2. Financial Statement Schedules
All schedules have been omitted because they are not applicable, not
required under the instructions or the information requested is set forth in the
consolidated financial statements or related notes thereto.
Item 14 (b): Reports on Form 8-K Filed in the Fourth Quarter of 1997
None
(a)3.Exhibits
The following Exhibits have previously been filed by the Registrant or
are included following the Index to Exhibits.
Exhibit Number. Description
3.1 Articles of Incorporation of Abraxas. (Filed as Exhibit 3.1 to the Company's
Registration Statement on Form S-4, No. 33-36565 (the "S-4 Registration
Statement")).
3.2 Articles of Amendment to the Articles of Incorporation of Abraxas dated
October 22, 1990 (Filed as Exhibit 3.3 to the S-4 Registration Statement).
3.3 Articles of Amendment to the Articles of Incorporation of Abraxas dated
December 18, 1990. (Filed as Exhibit 3.4 to the S-4 Registration Statement).
33
3.4 Articles of Amendment to the Articles of Incorporation of Abraxas dated June
8, 1995. (Filed as Exhibit 3.4 to the Company's Registration Statement on Form
S-3, No.
333-398 (the "S-3 Registration Statement")).
3.5 Amended and Restated Bylaws of Abraxas. (Filed as Exhibit 3.5 to the S-3
Registration Statement).
4.1 Specimen Common Stock Certificate of Abraxas. (Filed as Exhibit 4.1 to the
S-4 Registration Statement).
4.2 Specimen Preferred Stock Certificate of Abraxas. (Filed as Exhibit 4.2 to
the Company's Annual Report on Form 10-K filed on March 31, 1995).
4.3 Rights Agreement dated as of December 6, 1994 between Abraxas and First
Union National Bank of North Carolina ("FUNB"). (Filed as Exhibit 4.1 to the
Company's Registration Statement on Form 8-A filed on December 6, 1994).
4.4 Amendment to Rights Agreement dated as of July 14, 1997 by and between
Abraxas and American Stock Transfer and Trust Company (Filed as Exhibit 1 to
Amendment No. 1 to the Company's Registration Statement on Form 8-A filed on
August 20, 1997).
4.5 Indenture dated November 14, 1996 by and among the Company, Canadian Abraxas
and IBJ Schroder Bank and Trust Company. (Filed as Exhibit 4.1 to the Company's
Current Report on Form 8-K dated November 27, 1996).
4.6 Indenture dated January 27, 1998 by and among the Company, Canadian Abraxas
and IBJ Schroder Bank & Trust Company (filed as Exhibit 4.1 to the Company's
Current Report on Form 8-K dated February 5, 1998).
4.7 Form of Series B Note. (Filed as Exhibit 4.7 to the Company's and Canadian
Abraxas' Registration Statement on Form S-4, No. 333-18673 (the "Exchange Offer
Registration Statement")).
4.8 Form of Series C Note (Filed as Exhibit A to Exhibit 4.b).
*10.1 Abraxas Petroleum Corporation 1984 Non-Qualified Stock Option Plan, as
amended and restated. (Filed as Exhibit 10.7 to the Company's Annual Report on
Form 10-K filed April 14, 1993).
*10.2 Abraxas Petroleum Corporation 1984 Incentive Stock Option Plan, as amended
and restated. (Filed as Exhibit 10.8 to the Company's Annual Report on Form 10-K
filed April 14, 1993).
*10.3 Abraxas Petroleum Corporation 1993 Key Contributor Stock Option Plan.
(Filed as Exhibit 10.9 to the Company's Annual Report on Form 10-K filed April
14, 1993
*10.4 Abraxas Petroleum Corporation 401(k) Profit Sharing Plan. (Filed as
Exhibit 10.4 to the Exchange Offer Registration Statement).
*10.5 Abraxas Petroleum Corporation Director Stock Option Plan. (Filed as
Exhibit 10.5 to the Exchange Offer Registration Statement).
*10.6 Abraxas Petroleum Corporation Restricted Share Plan for Directors. (Filed
as Exhibit 10.20 to the Company's Annual Report on Form 10-K filed on April 12,
1994).
34
*10.7 Abraxas Petroleum Corporation 1994 Long Term Incentive Plan. (Filed as
Exhibit 10.21 to the Company's Annual Report on Form 10-K filed on April 12,
1994).
*10.8 Abraxas Petroleum Corporation Incentive Performance Bonus Plan. (Filed as
Exhibit 10.24 to the Company's Annual Report on Form 10-K filed on April 12,
1994).
10.9 Registration Rights and Stock Registration Agreement dated as of August 11,
1993 by and among Abraxas, EEP and Endowment Energy Partners II, Limited
Partnership ("EEP II"). (Filed as Exhibit 10.33 to the Company's Registration
Statement on Form S-1, Registration No. 33-66446 (the "S-1 Registration
Statement")).
10.10 First Amendment to Registration Rights and Stock Registration Agreement
dated June 30, 1994 by and among Abraxas, EEP and EEP II. (Filed as Exhibit 10.3
to the Registrant's Current Report on Form 8-K filed on July 14, 1994).
10.11 Second Amendment to Registration Rights and Stock Registration Agreement
dated September 2, 1994 by and among Abraxas, EEP and EEP II. (Filed as Exhibit
10.3 to the Company's Annual Report on Form 10-K filed March 31, 1995)
10.12 Third Amendment to Registration Rights and Stock Registration Agreement
dated November 17, 1995 by and among Abraxas, EEP and EEP II. (Filed as Exhibit
10.17 to the Company's Annual Report on Form 10-K filed March 31, 1995)
10.13 Common Stock Purchase Warrant dated as of December 18, 1991 between
Abraxas and EEP. (Filed as Exhibit 12.3 to the Company's Current Report on Form
8-K filed January 9, 1992).
10.14 Common Stock Purchase Warrant dated as of August 1, 1993 between Abraxas
and EEP. (Filed as Exhibit 10.35 to the S-1 Registration Statement).
10.15 Common Stock Purchase Warrant dated August 11, 1993 between Abraxas and
EEP II. (Filed as Exhibit 10.36 to the S-1 Registration Statement).
10.16 Common Stock Purchase Warrant dated August 11, 1993 between Abraxas and
Associated Energy Managers, Inc. (Filed as Exhibit 10.37 to the S-1 Registration
Statement).
10.17 Letter dated September 2, 1994 from Abraxas to EEP and EEP II. (Filed as
Exhibit 10.13 to the Company's Annual Report on Form 10-K filed March 31, 1995)
10.18 Amended and Restated Credit Agreement dated as of November 14, 1996 among
Abraxas, Bankers Trust Company, Inc. (U.S.) Capital Corporation and the Lenders
named therein. (Filed as Exhibit 10.5 to the Company's Current Report on Form
8-K filed November 27, 1996).
10.19 Warrant Agreement dated as of July 27, 1994 between Abraxas and FUNB.
(Filed as Exhibit 10.3 to the Company's Current Report on Form 8-K filed August
5, 1994).
10.20 Warrant Agreement dated as of December 16, 1994, between Abraxas and FUNB.
(Filed as Exhibit 10.23 to the Company's Annual Report on Form 10-K filed March
31, 1995).
10.21 First Amendment to Warrant Agreement dated as of August 31, 1995 between
Abraxas and FUNB. (Filed as Exhibit 10.21 to the S-3 Registration Statement).
10.22 Form of Indemnity Agreement between Abraxas and each of its directors and
officers. (Filed as Exhibit 10.30 to the S-1 Registration Statement).
35
*10.23 Employment Agreement between Abraxas and Robert L. G. Watson. (Filed as
Exhibit 10.23 to the S-3 Registration Statement).
*10.24 Employment Agreement between Abraxas and Chris E. Williford. (Filed as
Exhibit 10.24 to the S-3 Registration Statement).
*10.25 Employment Agreement between Abraxas and Robert Patterson. (Filed as
Exhibit 10.25 to the S-3 Registration Statement).
*10.26 Employment Agreement between Abraxas and Stephen T. Wendel. (Filed as
Exhibit 10.26 to the S-3 Registration Statement).
10.27 Management Agreement dated November 14, 1996 by and between Canadian
Abraxas and Cascade Oil & Gas Ltd. (Filed as Exhibit 10.36 to the Exchange Offer
Registration Statement).
10.28 First Amendment to Amended and Restated Credit Agreement dated as of
October 14, 1997 by and among Bankers Trust Company, ING (U.S.) Capital
Corporation and the Lenders named therein (Filed as Exhibit 10.29 to the
Company's Registration Statement on Form S-4, No.
333-43949).
10.29 Amendment No. 2 to Amended and Restated Credit Agreement dated January 27,
1998 by and among Abraxas, Bankers Trust Company, ING (U.S.) Capital Corporation
and the Lenders named therein (filed as Exhibit 10.3 to the Company's Current
Report on Form 8-K dated February 5, 1998).
10.30 Registration Rights Agreement dated January 27, 1998 by and among Abraxas,
Canadian Abraxas and Jefferson & Co., Inc. (Filed as Exhibit 10.2 to the
Company's Current Report on Form 8-K dated February 5, 1998).
21.1 Subsidiaries of Abraxas. (Filed as Exhibit 21.1 to the Company's
Registration Statement on Form S-4, No. 333-43949).
23.1 Consent of Independent Auditors. (Filed herewith).
23.2 Consent of DeGolyer & MacNaughton. (Filed herewith).
23.3 Consent of McDaniel & Associates Consultants, Ltd. (Filed herewith).
27.1 Financial Data Schedule.
* Management Compensatory Plan or Agreement.
36
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to the signed on its
behalf by the undersigned, thereunto duly authorized.
ABRAXAS PETROLEUM CORPORATION
By: /s/ Robert L.G. Watson By:/s/Chris Williford
------------------------ ---------------------
Robert L.G. Watson, Chris Williford, Executive
President and Principal Vice President and
Executive Officer Principal Financial and
Accounting Officer
DATED:
Pursuant to the requirements of the Securities and Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the date indicated.
Signature Name and Title Date
/s/ Robert L.G. Watson Chairman of the Board, 3/28/98
Robert L.G. Watson President (Principal Executive Officer)
and Director
/s/ Chris Williford Exec. Vice President and 3/28/98
Chris Williford Treasurer (Principal Financial
and Accounting Officer) and
Director
/s/ Franklin Burke Director 3/28/98
Franklin Burke
/s/ Robert D. Gershen Director 3/28/98
Robert D. Gershen
/s/ Richard M. Kleberg, III Director 3/28/98
Richard M. Kleberg, III
/s/ Harold Carter Director 3/28/98
Harold Carter
/s/ James C. Phelps Director 3/28/98
James C. Phelps
/s/ Paul A. Powell, Jr. Director 3/28/98
Paul A. Powell, Jr.
/s/ Richard M. Riggs Director 3/28/98
Richard M. Riggs
Exhibit 23.1
Consent of Independent Auditors
We consent to the incorporation by reference in the Registration Statements
(Form S-8 No. 33-48932) pertaining to Abraxas Petroleum Corporation 1984
Non-Qualified Stock Option Plan; (Form S-8 No. 33-48934) pertaining to Abraxas
Petroleum Corporation 1984 Incentive Stock Option Plan; (Form S-8 No. 33-72268)
pertaining to the Abraxas Petroleum Corporation 1993 Key Contribution Stock
Option Plan; (Form S-8 No. 33-81416) pertaining to the Abraxas Petroleum
Corporation Restricted Share Plan for Directors; (Form S-8 No. 33-81418)
pertaining to Abraxas Petroleum Corporation 1994 Long Term Incentive Plan; (Form
S-8 No. 333-17375) pertaining to the Abraxas Petroleum Corporation Director
Stock Option Plan; (Form S-8 No. 333-17377) pertaining to the Abraxas Petroleum
Corporation 401 (K) Profit Sharing Plan; and (Form S-3 No. 333-398) of Abraxas
Petroleum Corporation and the related Prospectus of our report dated March 17,
1998, with respect to the consolidated financial statements of Abraxas Petroleum
Corporation included in this Annual Report (Form 10-K) for the year ended
December 31, 1997.
Ernst & Young LLP
San Antonio, Texas
March 27, 1998
Exhibit 23.2
Consent of DeGolyer & MacNaughton
We hereby consent to the incorporation in your Annual Report on Form 10-K of
the references to DeGolyer and MacNaughton in the "Reserves Information" section
on page 19 and to the use by reference of information contained in our Appraisal
Report as of December 31, 1997 on Certain Interests owned by Abraxas Petroleum
Corporation provided, however, that since the crude oil, condensate, natural gas
reserves estimates, as of December 31, 1997, set forth in this Report have been
combined with reserve estimates of other petroleum consultants, we are
necessarily unable to verify the accuracy of the reserves values contained in
the aforementioned Annual Report.
DeGolyer and MacNaughton
Dallas, Texas
March 24, 1998
Exhibit 23.3
Consent of Mcdaniel & Associates Consultants LTD.
We consent to the incorporation in your Annual Report on Form 10-k of the
references to McDaniel & Associates Consultants Ltd. in the "Reserves
Information" section and to the use by reference of information contained in our
Evaluation Report "Canadian Abraxas Petroleum Ltd., Evaluation of Oil & Gas
Reserves, As of December 31, 1997", dated March 6, 1998
McDaniel & Associates Consultants LTD
Calgary, Alberta
March 25, 1998
INDEX TO FINANCIAL STATEMENTS
Page
Abraxas Petroleum Corporation and Subsidiaries
Report of Independent Auditors ......................................F-2
Consolidated Balance Sheets at December 31, 1996 and 1997 ...........F-3
Consolidated Statements of Operations for the years
ended December 31, 1995, 1996 and 1997 .............................F-5
Consolidated Statements of Stockholders' Equity for the
years ended December 31, 1995, 1996 and 1997 .......................F-7
Consolidated Statements of Cash Flows for the years
ended December 31, 1995, 1996 and 1997 .............................F-9
Notes to Consolidated Financial Statements ..........................F-11
F-1
Report of Independent Auditors
The Board of Directors and Stockholders
Abraxas Petroleum Corporation
We have audited the accompanying consolidated balance sheets of Abraxas
Petroleum Corporation and Subsidiaries as of December 31, 1996 and 1997, and the
related consolidated statements of operations, stockholders' equity, and cash
flows for each of the three years in the period ended December 31, 1997. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Abraxas
Petroleum Corporation and Subsidiaries at December 31, 1996 and 1997, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1997, in conformity with generally
accepted accounting principles.
ERNST & YOUNG LLP
San Antonio, Texas
March 17, 1998
F-2
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31
--------------------------
1996 1997
--------------------------
(In thousands)
Current assets:
Cash ................................. $ 8,290 $ 2,836
Accounts receivable, less allowance
for doubtful accounts:
Joint owners ...................... 1,601 2,149
Oil and gas production sales ...... 11,400 11,194
Affiliates, officers, and
stockholders ..................... 94 42
Other ............................. 1,289 1,217
------------- -----------
14,384 14,602
Equipment inventory .................. 451 367
Other current assets ................. 187 508
------------- -----------
Total current assets ................ 23,312 18,313
Property and equipment.................. 310,043 385,442
Less accumulated depreciation, 38,653 74,597
depletion, and amortization ..........
------------- -----------
Net property and equipment based on
the full cost method of accounting
for oil and gas properties of which
$37,268 and $11,519 at December 31,
1996 and 1997, respectively, were
excluded from amortization ......... 271,390 310,845
Deferred financing fees, net of
accumulated amortization of $280 and
$1,540 at December 31, 1996 and 1997,
respectively ......................... 9,335 8,072
Restricted cash ........................ 90 40
Other assets ........................... 715 1,258
============= ==========
Total assets ......................... $ 304,842 $ 338,528
============= ==========
See accompanying notes.
F-3
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (CONTINUED)
LIABILITIES AND STOCKHOLDERS' EQUITY
December 31
--------------------------
1996 1997
--------------------------
(In thousands)
Current liabilities:
Accounts payable ....................... $ 9,960 $ 17,120
Oil and gas production payable ......... 2,378 2,819
Accrued interest ....................... 3,206 4,622
Income taxes payable ................... 145 164
Other accrued expenses ................. 1,132 2,732
Payable to affiliates .................. 58 -
------------- -----------
Total current liabilities ............. 16,879 27,457
Long-term debt:
Senior notes ........................... 215,000 215,000
Credit facility ........................ - 31,500
Other................................... 32 2,117
------------- -----------
215,032 248,617
Other long-term obligations .............. 87 -
Deferred income taxes .................... 32,928 27,751
Minority interest in foreign subsidiary .. 2,157 4,813
Future site restoration ................. 2,103 3,077
Commitments and contingencies
Stockholders' equity:
Convertible preferred stock 8%,
authorized 1,000,000 shares; issued and
outstanding 45,741 and -0- shares at
December 31, 1996 and 1997, respectively - -
Common stock, par value $.01 per
share - authorized 50,000,000
shares; issued 5,806,812 and
6,422,540 shares at December 31,
1996 and 1997, respectively ......... 58 63
Additional paid-in capital ............. 50,926 51,118
Accumulated deficit .................... (12,517) (19,185)
Treasury stock, at cost, 74,711 and
53,023 shares at December 31, 1996 and
1997, respectively .................... (405) (281)
Accumulated other comprehensive income
(loss) ................................ (2,406) (4,902)
------------- -----------
Total stockholders' equity ............... 35,656 26,813
------------- -----------
Total liabilities and stockholders'
equity .............................. $ 304,842 $ 338,528
============= ===========
See accompanying notes.
F-4
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31
----------------------------------------
1995 1996 1997
------------- --------------------------
(In thousands except per share data)
Revenue:
Oil and gas production
revenues ................. $ 13,660 $ 25,749 $ 65,826
Gas processing revenues ... - 600 3,568
Rig revenues .............. 108 139 334
Other .................... 49 165 1,203
----------- ----------- -----------
13,817 26,653 70,931
Operating costs and expenses:
Lease operating and
production taxes ......... 4,333 5,858 14,881
Gas processing costs ...... - 262 1,252
Depreciation, depletion, and
amortization ............. 5,434 9,605 30,581
Rig operations ............ 125 169 296
Proved property impairment - - 4,600
General and administrative 1,042 1,933 4,171
----------- ----------- -----------
10,934 17,827 55,781
----------- ----------- -----------
Operating income............. 2,883 8,826 15,150
Other (income) expense:
Interest income ........... (34) (254) (320)
Amortization of deferred
financing fee ............ 214 280 1,260
Interest expense .......... 3,911 6,241 24,620
Other expense (income)..... - 373 (369)
----------- ----------- -----------
4,091 6,640 25,191
----------- ----------- -----------
Income (loss) before taxes and
extraordinary item ........ (1,208) 2,186 (10,041)
Income tax expense (benefit):
Current ................... - 176 244
Deferred .................. - - (4,135)
Minority interest in income of
consolidated foreign
subsidiary ................ - 70 335
----------- ----------- -----------
Income (loss) before
extraordinary item ........ (1,208) 1,940 (6,485)
F-5
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (CONTINUED)
Year Ended December 31
----------------------------------------
1995 1996 1997
------------- --------------------------
(In thousands except per share data)
Extraordinary item:
Debt extinguishment costs $ - $ (427) $ -
----------- ----------- -----------
Net income (loss) ......... (1,208) 1,513 (6,485)
Less dividend requirement
on cumulative preferred
stock ................... (366) (366) (183)
----------- ----------- -----------
Net income (loss)
applicable to common
stock ................... $ (1,574) $ 1,147 $ (6,668)
=========== =========== ===========
Earnings (loss) per common share:
Income (loss) before
extraordinary item .... $ (.34) $ .27 $ (1.11)
Extraordinary item ...... - (.07) -
----------- ----------- -----------
Net income (loss) per
common share ............. $ (.34) $ .20 $ (1.11)
=========== =========== ===========
Earnings (loss) per common
share - assuming dilution:
Income (loss) before
extraordinary item .... $ (.34) $ .23 $ (1.11)
Extraordinary item ...... - (.06) -
----------- ----------- -----------
Net income (loss) per
common share - assuming
dilution ................. $ (.34) $ .17 $ (1.11)
=========== =========== ===========
See accompanying notes.
F-6
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(In thousands except share amounts)
Accumulated
Convertible Other
Preferred Stock Common Stock Treasury Stock Additional Comprehensive
---------------- ---------------- ---------------- Paid-In Accumulated Income
Shares Amount Shares Amount Shares Amount Capital Deficit (Loss) Total
----------------------------------------------------------- ------------------------------------
Balance at
December 31, 1994 45,741 $ 4,573 4,461,890 $ 45 - $ - $36,217 $(12,090) $ (244) $28,501
Comprehensive
income (loss):
Net loss ....... - - - - - - - (1,208) - (1,208)
----------
Comprehensive
income (loss) (1,208)
Issuance of
common stock
for
compensation .. - - 7,872 - - - 74 - - 74
Issuance of
common stock .. - - 1,330,000 13 - - 10,050 - - 10,063
Treasury stock
purchased, net - - - - 2,571 (1) - - - (1)
Changes in
preferred
stock par
value ......... - (4,573) - - - - 4,573 - - -
Dividend on
preferred
stock ......... - - - - - - - (366) - (366)
----------------------------------------------------------- -----------------------------------
Balance at
December 31, 1995 45,741 - 5,799,762 58 2,571 (1) 50,914 (13,664) $ (244) 37,063
Comprehensive
income (loss):
Net income ..... - - - - - - - 1,513 - 1,513
Other
comprehensive
income:
Change in
unrealized
holding loss
on
securities .. - - - - - - - - 244 244
Foreign
currency
translation
adjustment .. - - - - - - - - (2,406) (2,406)
----------
Comprehensive (649)
income (loss)
Issuance of
common stock
for
compensation .. - - 5,050 - (2,500) 1 41 - - 42
Expenses paid
related to
private
placement
offering ...... - - - - - - (42) - - (42)
Options
exercised ..... - - 2,000 - - - 13 - - 13
Treasury stock
purchased ..... - - - - 74,640 (405) - - - (405)
purchased .....
Dividend on
preferred
stock ......... - - - - - - - (366) - (366)
-----------------------------------------------------------------------------------------------
Balance at
December 31, 1996 45,741 - 5,806,812 58 74,711 (405) 50,926 (12,517) (2,406) 35,656
Comprehensive
income (loss):
Net loss ....... - - - - - - - (6,485) - (6,485)
Other
comprehensive
income:
Foreign
currency
translation
adjustment .. - - - - - - - - (2,496) (2,496)
----------
Comprehensive
income (loss).. (8,981)
F-7
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (continued)
(In thousands except share amounts)
Accumulated
Convertible Other
Preferred Stock Common Stock Treasury Stock Additional Comprehensive
---------------- ---------------- ---------------- Paid-In Accumulated Income
Shares Amount Shares Amount Shares Amount Capital Deficit (Loss) Total
----------------------------------------------------------- ------------------------------------
Issuance of
common stock
for
compensation .. - $ - 7,735 $ - (21,688) $ 124 $ 186 $ $ - $ 310
Conversion of
preferred
stock into
common stock .. (45,741) - 508,183 5 - - (5) - - -
Options
exercised ..... - - 2,000 - - - 11 - - 11
Dividend on
preferred
stock ......... - - - - - - - (183) - (183)
Warrants
exercised ..... - - 97,810 - - - - - - -
exercised .....
------------------------------------------------------------------------------------------------
Balance at
December 31, 1997 - $ - 6,422,540 $ 63 53,023 $ (281) 51,118 $(19,185) $(4,902) $26,813
================================================================================================
See accompanying notes.
F-8
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31
-----------------------------------------
1995 1996 1997
------------- ------------- -------------
(In thousands)
Operating Activities
Net income (loss) ............................. $ (1,208) $ 1,513 $ (6,485)
Adjustments to reconcile net
income (loss) to net cash
provided by operating
activities:
Minority interest in
income of foreign
subsidiary ............................... -- 70 335
Depreciation, depletion,
and amortization ......................... 5,434 9,605 30,581
Proved property impairment ................. -- -- 4,600
Deferred income tax benefit ................ -- -- (4,135)
Amortization of deferred
financing fees ........................... 214 280 1,260
Issuance of common stock
for compensation ......................... 74 42 310
Loss on marketable
securities ............................... -- 235 --
Net loss from debt
restructurings ........................... -- 427 --
Changes in operating assets and liabilities:
Accounts receivable ..................... (807) (6,013) (444)
Equipment inventory ..................... (29) (82) 76
Other assets ............................ 2 (133) (325)
Accounts payable and
accrued expenses ...................... (79) 7,009 10,402
Oil and gas production
payable ............................... 919 591 466
--------- --------- ---------
Net cash provided by .......................... 4,520 13,544 36,641
operating activities
Investing Activities
Capital expenditures,
including purchases
and development of
properties .................................. (12,330) (87,793) (84,111)
Payment for purchase of
CGGS,
net of cash acquired ........................ -- (85,362) --
Proceeds from sale of oil
and gas
properties and equipment
inventory ................................... 2,556 242 9,606
Purchase of interest in real
estate partnership .......................... (311) -- --
Proceeds from sale of
marketable securities ....................... -- 335 --
--------- --------- ---------
Net cash used in investing
activities .................................. (10,085) (172,578) (74,505)
F-9
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
Year Ended December 31
----------------------------------------
1995 1996 1997
----------------------------------------
(In thousands)
Financing Activities
Preferred stock dividends ........................ $ (366) $ (366) $ (183)
Issuance of common stock, net
of expenses .................................... 10,063 (29) 11
Purchase of treasury stock, net .................. (1) (405) --
Proceeds from long-term borrowings ............... 5,950 305,400 33,620
Payments on long-term borrowing .................. (5,646) (131,969) --
Deferred financing fees .......................... (186) (9,688) (123)
Other ............................................ -- 87 --
---------- ----------- -----------
Net cash provided by
financing activities ........................... 9,814 163,030 33,325
Effect of exchange rate
changes on cash ................................ -- -- (965)
---------- ----------- -----------
Increase (decrease) in cash ...................... 4,249 3,996 (5,504)
Cash at beginning of year ........................ 135 4,384 8,380
---------- ----------- -----------
Cash at end of year,
including restricted cash ...................... $ 4,384 $ 8,380 $ 2,876
========== =========== ===========
Supplemental Disclosures
Supplemental disclosures of cash flow information:
Interest paid ................................. $ 3,884 $ 3,863 $ 24,170
========== =========== ===========
Supplemental schedule of noncash investing and financing activities:
During 1996, the Company purchased all of the capital stock of CGGS Canadian
Gas Gathering Systems, Inc. for $85,362,000, net of cash acquired. In
conjunction with the acquisition, liabilities assumed were as follows (in
thousands):
Fair value of assets acquired ....................... $ 123,970
Cash paid for the capital stock ..................... (85,362)
-------------
Liabilities assumed ................................. $ 38,608
=============
During 1997, the Company's subsidiary, Cascade Oil & Gas Ltd. acquired
certain crude oil and gas producing properties through the issuance of its
common shares and special warrants valued at approximately$3,700,000.
See accompanying notes.
F-10
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1995, 1996, and 1997
1. Organization and Significant Accounting Policies
Nature of Operations
Abraxas Petroleum Corporation (the Company or Abraxas) is an independent
energy company engaged in the exploration for and the acquisition, development,
and production of crude oil and natural gas primarily along the Texas Gulf
Coast, in the Permian Basin of western Texas, and in Canada and Wyoming, and the
processing of natural gas primarily in Canada. The consolidated financial
statements include the accounts of the Company and its subsidiaries. All
significant intercompany accounts and transactions have been eliminated in
consolidation.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates. Management
believes that it is reasonably possible that estimates of proved crude oil and
natural gas revenues could significantly change in the future.
Concentration of Credit Risk
Financial instruments which potentially expose the Company to credit risk
consist principally of trade receivables, interest rate and crude oil and
natural gas price swap agreements. Accounts receivable are generally from
companies with significant oil and gas marketing activities. The Company
performs ongoing credit evaluations and, generally, requires no collateral from
its customers. For further information regarding the Company's swap
arrangements, see Notes 4 and 15.
Equipment Inventory
Equipment inventory consists of casing, tubing, and compressing equipment
and is carried at the lower of cost or market.
Oil and Gas Properties
The Company follows the full cost method of accounting for crude oil and
natural gas properties. Under this method, all costs associated with acquisition
of properties and successful as well as unsuccessful exploration and development
activities are capitalized. The Company does not capitalize internal costs.
Depreciation, depletion, and amortization (DD&A) of capitalized crude oil and
natural gas properties and estimated future development costs, excluding
unevaluated, unproved properties, are based on the unit-of-production method
based on proved reserves. Net capitalized costs of crude oil and natural gas
properties, less related deferred taxes, are limited, by country, to the lower
of unamortized cost or the cost ceiling, defined as the sum of the present value
of estimated 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. Excess costs are
charged to proved property impairment expense. No gain or loss is recognized
upon sale or disposition of crude oil and natural gas properties, except in
unusual circumstances.
F-11
Unevaluated properties not currently being amortized included in oil and
gas properties were approximately $37,268,000 and $11,519,000 at December 31,
1996 and 1997, respectively. The properties represented by these costs were
undergoing exploration activities or are properties on which the Company intends
to commence activities in the future. The Company believes that the unevaluated
properties at December 31, 1997 will be substantially evaluated in six to
thirty-six months and it will begin to amortize these costs at such time.
Other Property and Equipment
Other property and equipment are recorded on the basis of cost.
Depreciation of processing facilities and other property and equipment is
provided over the estimated useful lives using the straight-line method. Major
renewals and betterments are recorded as additions to the property and equipment
accounts. Repairs that do not improve or extend the useful lives of assets are
expensed.
Hedging
The Company periodically enters into derivative contracts to hedge the
risk of future crude oil and natural gas fluctuations. Such contracts may either
fix or support crude oil and natural gas prices or limit the impact of price
fluctuations with respect to the Company's sales of crude oil and natural gas.
Gains and losses on such hedging activities are recognized in oil and gas
production revenues when hedged production is sold.
Stock-Based Compensation
Statement of Financial Accounting Standards No. 123, "Accounting for
Stock-Based Compensation," encourages, but does not require, companies to record
compensation cost for stock-based employee compensation plans at fair value. The
Company has chosen to continue to account for stock-based compensation using the
intrinsic value method prescribed in Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees," and related interpretations.
Accordingly, compensation cost for stock options is measured as the excess, if
any, of the quoted market price of the Company's stock at the date of the grant
over the amount an employee must pay to acquire the stock (see Note 6).
Foreign Currency Translation
The functional currency for the Company's Canadian operations is the
Canadian dollar. The Company translates the functional currency into U.S.
dollars based on the current exchange rate at the end of the period for the
balance sheet and a weighted average rate for the period on the statement of
operations. Translation adjustments are reflected as Accumulated Other
Comprehensive Income in Stockholders' Equity.
Fair Value of Financial Instruments
The Company includes fair value information in the notes to consolidated
financial statements when the fair value of its financial instruments is
different from the book value. The Company assumes the book value of those
financial instruments that are classified as current approximates fair value
because of the short maturity of these instruments. For noncurrent financial
instruments, the Company uses quoted market prices or, to the extent that there
are no available quoted market prices, market prices for similar instruments.
F-12
Restoration, Removal and Environmental Liabilities
The estimated costs of restoration and removal of major processing
facilities are accrued on a straight-line basis over the life of the property.
The estimated future costs for known environmental remediation requirements are
accrued when it is probable that a liability has been incurred and the amount of
remediation costs can be reasonably estimated. These amounts are the
undiscounted, future estimated costs under existing regulatory requirements and
using existing technology.
Revenue Recognition
The Company recognizes crude oil and natural gas revenue from its interest
in producing wells as crude oil and natural gas is sold from those wells net of
royalties. Revenue from the processing of natural gas is recognized in the
period the service is performed.
Deferred Financing Fees
Deferred financing fees are being amortized on a level yield basis over
the term of the related debt.
Federal Income Taxes
The Company records income taxes under Financial Accounting Standards
Board Statement No. 109 using the liability method. Under this method, deferred
tax assets and liabilities are determined based on differences between financial
reporting and tax bases of assets and liabilities and are measured using the
enacted tax rates and laws that will be in effect when the differences are
expected to reverse.
Earnings per Share
In 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 128, Earnings per Share. Statement 128
replaced the previously reported primary and fully diluted earnings per share
with basic and diluted earnings per share. Unlike primary earnings per share,
basic earnings per share excludes any dilutive effects of options, warrants and
convertible securities. Diluted earnings per share is very similar to the
previously reported fully diluted earnings per share. Earnings per share amounts
for all periods have been restated to conform to the requirements of Statement
128.
Comprehensive Income
During 1997, the Company adopted Statement No. 130, Reporting
Comprehensive Income. Statement No. 130 establishes new rules for the reporting
and display of comprehensive income and its components; however, the adoption of
this Statement had no impact on the Company's net income or stockholders'
equity. Statement No. 130 requires unrealized gains or losses on the Company's
available-for-sale securities and the foreign currency translation adjustments,
which prior to adoption were reported separately in stockholders' equity, to be
included in other comprehensive income. Prior year financial statements have
been reclassified to conform to the requirements of Statement No. 130.
Impact of Statement of Financial Accounting Standards No. 131
Also in June 1997, the Financial Accounting Standards Board issued
Statement No. 131, Disclosures about Segments of an Enterprise and Related
Information. Statement No. 131 establishes standards for the reporting of
financial information from operating segments in annual and interim financial
statements. This Statement requires that financial information be reported on
the basis that it is reported internally for evaluating segment performance and
deciding how to allocate resources to segments. Statement No. 131 will become
effective in 1998.
F-13
Reclassifications
Certain balances for 1995 and 1996 have been reclassified for comparative
purposes.
2. Acquisitions and Divestitures
Pacalta Properties Acquisition
In October 1997, Canadian Abraxas Petroleum Limited (Canadian Abraxas), a
wholly owned subsidiary of the Company, and Cascade Oil and Gas Ltd. (Cascade)
completed the acquisition of the Canadian assets of Pacalta Resources Ltd.
(Pacalta Properties) for approximately $14,000,000 (CDN$20,000,000) in cash and
four million Cascade special warrants valued at approximately $1,375,000.
Canadian Abraxas acquired an approximate 92% interest in the Pacalta Properties,
and Cascade acquired an approximate 8% interest. Cascade has the opportunity to
acquire the Canadian Abraxas' ownership upon arranging satisfactory financing in
the future. The Cascade special warrants are exchangeable into an equal number
of Cascade common shares.
The acquisition was accounted for as a purchase, and the purchase price
was allocated to the crude oil and natural gas properties based on the fair
values of the properties acquired. The transaction was financed through an
advance from the Company with funds which were obtained through borrowings under
the Company's Credit Facility. Revenues and expenses from the Pacalta Properties
have been included in the consolidated financial statements since October 1997.
Pennant Acquisition
In September 1997, Cascade acquired all the common shares if Pennant
Petroleum Ltd. in exchange for the issuance of 7,585,000 common shares of
Cascade valued at approximately $2,278,000. The acquisition was accounted for as
a purchase and the purchase price was allocated to the crude oil and natural gas
properties based on the fair values of the properties acquired. Revenues and
expenses from Pennant have been included in the consolidated financial
statements since October 1997.
Wyoming Properties Acquisition
On September 30, 1996, the Company acquired interests in certain producing
crude oil and natural gas properties located in the Wamsutter area of
southwestern Wyoming (the Wyoming Properties) from Enserch Exploration, Inc. The
initially agreed to purchase price of $47,500,000 was adjusted to $45,122,000 to
reflect adjustments of net production revenue which accrued to the Company from
April 1, 1996, the effective date, until closing, net of interest owed by the
Company for the same period and transaction costs. The acquisition was accounted
for as a purchase and the purchase price was allocated to crude oil and natural
gas properties based on the fair values of the properties acquired. The
transaction was financed through borrowings under the Company's bridge facility
referred to in Note 4. Revenues and expenses from the Wyoming Properties have
been included in the consolidated financial statements since September 30, 1996.
CGGS Acquisition
On November 14, 1996, the Company, through its wholly owned subsidiary,
Canadian Abraxas purchased 100% of the outstanding capital stock of CGGS
Canadian Gas Gathering Systems Inc. (CGGS) for approximately $85,500,000, net of
the CGGS cash acquired and including transaction costs. CGGS owns producing oil
and gas properties in western Canada and adjacent processing facilities as well
as undeveloped leasehold properties. Immediately after the purchase, CGGS was
merged with and into Canadian Abraxas. The acquisition was accounted for as a
purchase and the purchase price was allocated to the assets and liabilities
based on estimated fair values. The transaction was financed by a portion of the
proceeds from the offering of $215,000,000 of Notes referred to in Note 4.
Revenues and expenses from Canadian Abraxas have been included in the
consolidated financial statements since November 14, 1996.
F-14
Grey Wolf Acquisition
In January 1996, the Company made a $3,000,000 investment in Grey Wolf
Exploration Ltd. (Grey Wolf), a privately-held Canadian corporation, which, in
turn, invested these proceeds in newly-issued shares of Cascade, an Alberta,
Canada corporation whose common shares are traded on The Alberta Stock Exchange.
The acquisition was accounted for as a purchase and the purchase price was
allocated to the assets and liabilities based on the fair values. Revenues and
expenses have been included in the consolidated financial statements since
January 1996. During 1997, Cascade acquired 100% of the common stock of Grey
Wolf in exchange for the issuance of additional Cascade common shares to the
Grey Wolf shareholders and the cancellation of the common shares of Cascade held
by Grey Wolf. This transaction resulted in the share ownership of Cascade
previously held by Grey Wolf being passed to the Grey Wolf shareholders, and
Grey Wolf was merged into Cascade.
Portilla and Happy Fields Acquisition
In March 1996, the Company sold all of its interest in its Portilla and
Happy Fields to an unrelated purchaser (Purchaser or Limited Partner).
Simultaneously with this sale, the Limited Partner also acquired the 50%
overriding royalty interest in the Portilla Field owned by the Commingled
Pension Trust Fund Petroleum II, the trustee of which is Morgan Guaranty Trust
Company of New York (Pension Fund). In connection with the purchase of both the
Company's interest in the Portilla and Happy Fields and the Pension Fund's
interest in the Portilla Field (together, the Portilla and Happy Properties),
the Limited Partner obtained a loan (Bank Loan) secured by the Properties and
contributed the Properties to Portilla-1996, L.P., a Texas limited partnership
(Partnership). A subsidiary of the Company, Portilla-Happy Corporation
(Portilla-Happy), was the general partner of the Partnership. The aggregate
purchase price received by the Company was $17,600,000, of which $2,000,000 was
used to purchase a minority interest in the Partnership.
On November 14, 1996, the Company closed an agreement with the Limited
Partner and certain noteholders (Noteholders) of the Partnership, pursuant to
which the Company obtained the Limited Partner's interest in the Partnership and
the Noteholders' notes in the aggregate principal amount of $5,920,000 (Notes),
resulting in the Company's owning, on a consolidated basis, all of the equity
interests in the Partnership. The aggregate consideration paid to the Limited
Partner and the Noteholders was $6,961,000. The Company also paid off the Bank
Loan which had an outstanding principal balance of approximately $20,051,000,
and assumed a crude oil and natural gas price swap agreement (see Note 15).
As a result of obtaining the Limited Partner's interest in the
Partnership, the Company reacquired those interests in the Portilla and Happy
Fields which it previously owned, as well as the interest in the Portilla Field
previously owned by the Pension Fund. The Company has included in its balance
sheet the amount previously removed from oil and gas properties in connection
with the sale of its interest in the Portilla and Happy Fields during the
quarter ended March 31, 1996, as well as the amount of the purchase price paid
for the Pension Fund's interest in the Portilla Field, and all development
drilling expenditures incurred on the properties, less the amount of DD&A
related to the properties from the formation of the Partnership through the
closing of the transaction. The purchase was financed by a portion of the
proceeds from the offering of the Notes referred to in Note 4. The Company
recorded its share of the net loss of the Partnership from March 1996 to
November 1996 of $513,000. The Company also assumed and wrote off the remaining
deferred financing fees and organization costs of the Partnership. Gross
revenues and expenses from both the Company's original interest in the Portilla
and Happy Fields as well as the interest in the Portilla Field previously owned
by the Pension Fund have been included in the consolidated financial statements
since November 14, 1996.
East White Point and Stedman Island Fields Acquisition
In November 1996, the Company obtained a release of the 50% overriding
royalty interest in the East White Point Field in San Patricia County, Texas and
the Stedman Island Field in Nueces County, Texas from the Pension Fund for
$9,271,000 before adjustment for accrual of net revenue to closing. The
acquisition was accounted for as a purchase and the purchase price was allocated
F-15
to crude oil and natural gas properties based on the fair values of the
properties acquired. The transaction was financed through proceeds of the sale
of the Notes referred to in Note 4. Revenues and expenses from these properties
have been included in the consolidated financial statements since November 1,
1996. The Company recorded the net purchase price of approximately $9,271,000 to
its oil and gas properties.
Miscellaneous Working Interests
During 1996, the Company also acquired additional working interests in
certain producing crude oil and natural gas properties in which the Company had
existing working interest ownership. The net purchase price amounted to
approximately $1,221,000. Revenues and expenses have been included in the
consolidated financial statement from the date of purchase.
Texas Gulf Coast Properties Acquisition
In October 1995, the Company acquired additional working interests in
certain producing crude oil and natural gas properties in which the Company had
an existing working interest ownership. The net purchase price to Abraxas
amounted to approximately $635,000. Revenues and expenses have been included in
the consolidated financial statements since October 1, 1995.
The condensed pro forma financial information for the periods presented
below summarize on an unaudited pro forma basis approximate results of the
Company's consolidated operations for the years ended December 31, 1995 and 1996
assuming the acquisitions of the Wyoming Properties, CGGS, Grey Wolf, the
Portilla and Happy Properties, and the East White Point and Stedman Island
Fields occurred at January 1, 1995. The pro forma information does not
necessarily represent what the actual consolidated results would have been for
these periods and is not intended to be indicative of future results.
December 31
-------------------------
1995 1996
------------------------
(In thousands except
per share data)
(Unaudited)
Revenues ............................... $ 46,132 $60,077
========= =========
Income (loss) before extraordinary item $(16,430) $(6,665)
========= =========
Net income (loss) ...................... $(16,430) $(7,092)
========= =========
Income (loss) per common share:
Before extraordinary item ............ $ (3.54) $ (.98)
Net income (loss) .................... $ (3.54) $ (1.04)
Divestiture
In July 1995, the Company sold its C.S. Dean Unit for approximately
$2,550,000. In January 1997, the Company sold its interest in its crude oil and
natural gas processing properties in the Hoole area in Alberta, Canada for net
proceeds of approximately $8,700,000 which was credited to the Canadian full
cost pool.
F-16
3. Property and Equipment
The major components of property and equipment, at cost, are as follows:
Estimated
Useful 1996 1997
Life
----------- ----------- -----------
Years (In thousands)
Land, buildings, and improvements 15 $ 269 $ 291
Crude oil and natural gas
properties .................... - 268,358 344,199
Natural gas processing plants ... 18 40,100 39,113
Equipment and other ............. 7 1,316 1,839
---------- -----------
$310,043 $385,442
========== ===========
4. Long-Term Debt
Long-term debt consists of the following:
December 31
1996 1997
----------- -----------
(In thousands)
11.5% Senior Notes due 2004, Series B (see
below). ............................... $215,000 $215,000
Credit facility due to Bankers Trust
Company, ING
Capital and Union Bank of California (see
below). ............................... - 31,500
Credit facility due to a Canadian bank,
providing for borrowings to
approximately $2,800,000 at the
bank's prime rate plus .25%, 5.5% at
December 31, 1997..................... - 2,096
Other ................................... 32 21
----------- -----------
215,032 248,617
Less current maturities ................. - -
----------- -----------
$215,032 $248,617
=========== ===========
On November 14, 1996, the Company and Canadian Abraxas completed the sale
of $215,000,000 aggregate principal amount of Senior Notes due November 1, 2004
(Notes). In January 1997, the Notes were exchanged for Series B Notes, which
have been registered under the Securities Act of 1933 (Series B Notes). The form
and terms of the Series B Notes are the same as the Notes issued on November 14,
1996. Interest at 11.5% is payable semi-annually in arrears on May 1 and
November 1 of each year, commencing on May 1, 1997. The Series B Notes are
general unsecured obligations of the Company and Canadian Abraxas and rank pari
passu in right of payment to all future subordinated indebtedness of the Company
and Canadian Abraxas. The Series B Notes are, however, effectively subordinated
in right of payment to all existing and future secured indebtedness to the
extent of the value of the assets securing such indebtedness. The Company and
Canadian Abraxas are joint and several obligors on the Series B Notes. The
Series B Notes are redeemable, in whole or in part, at the option of the Company
and Canadian Abraxas on or after November 1, 2000, at the redemption price of
105.75% through October 31, 2001, 102.87% through October 31, 2002 and 100.00%
thereafter plus accrued interest. In addition, any time on or prior to November
1, 1999, the Company and Canadian Abraxas may redeem up to 35% of the aggregate
principal amount of the Series B Notes originally issued with the cash proceeds
of one or more equity offerings at a redemption price of 111.5% of the aggregate
principal amount of the Series B Notes to be redeemed plus accrued interest,
provided, however, that after giving effect to such redemption, at least
$139,750,000 aggregate principal amount of Series B Notes remains outstanding.
The Series B Notes were issued under the terms of an Indenture dated November
14, 1996 that contains, among others, certain covenants which generally limit
the ability of the Company to incur additional indebtedness other than specific
F-17
indebtedness permitted under the Indenture, including the Credit Facility
discussed below, provided however, if no event of default is continuing, the
Company may incur indebtedness if after giving pro forma effect to the
incurrence of such debt both the Company's consolidated earnings before
interest, taxes, depletion and amortization (EBITDA) coverage ratio would be
greater than 2.25 to 1.0 if prior to November 1, 1997, and at least equal to 2.5
to 1.0 thereafter, and the Company's adjusted consolidated net tangible assets,
as defined, are greater than 150% of the aggregate consolidated indebtedness of
the Company or the Company's adjusted consolidated net tangible assets are
greater than 200% of the aggregate consolidated indebtedness of the Company. The
Indenture also contains other covenants affecting the Company's ability to pay
dividends on its common stock, sell assets and incur liens.
On September 30, 1996, the Company entered into a credit facility with
Bankers Trust Company (BTCo) and ING Capital (together the Lenders), providing a
bridge facility in the total amount of $90,000,000 and borrowed $85,000,000
which was used to repay all amounts due under its previous credit agreement and
to finance the purchase of the Wyoming Properties.
On November 14, 1996, the Company repaid all amounts outstanding under the
bridge facility with proceeds from the offering of $215,000,000 of Notes
described above and entered into an amended and restated credit agreement
(Credit Facility) with the Lenders and Union Bank of California. On October 14,
1997, the Company amended the Credit Facility to provide for a revolving line of
credit with an availability of $40,000,000, subject to a borrowing base
condition. At December 31, 1996 and 1997, $-0- and $31,500,000 were outstanding
under the Credit Facility.
Commitments available under the Credit Facility are subject to borrowing
base redeterminations to be performed semi-annually and, at the option of each
of the Company and the Lenders, one additional time per year. Amounts due under
the Credit Facility will be secured by the Company's oil and gas properties and
plants. Any outstanding principal balance in excess of the borrowing base will
be due and payable in three equal monthly payments after a borrowing base
redetermination. The borrowing base will be determined in the agent's sole
discretion, subject to the approval of the Lenders, based on the value of the
Company's reserves as set forth in the reserve report of the Company's
independent petroleum engineers, with consideration given to other assets and
liabilities.
The Credit Facility has an initial revolving term of two years and a
reducing period of three years from the end of the initial two-year period. The
commitment under the Credit Facility will be reduced during such reducing period
by eleven equal quarterly reductions. Quarterly reductions will equal 8.2% per
quarter with the remainder due at the end of the three-year reducing period.
The applicable interest rate charged on the outstanding balance of the
Credit Facility is based on a facility usage grid. If the borrowings under the
Credit Facility represent an amount less than or equal to 33.3% of the available
borrowing base, then the applicable interest rate charged on the outstanding
balance will be either (a) an adjusted rate of the London Inter-Bank Offered
Rate ("LIBOR") plus 1.25% or (b) the prime rate of the agent (which is based on
the agent's published prime rate) plus 0.50%. If the borrowings under the Credit
Facility represent an amount greater than or equal to 33.3% but less than 66.7%
of the available borrowing base, then the applicable interest rate on the
outstanding principal will be either (a) LIBOR plus 1.75% or (b) the prime rate
of the agent plus 0.50%. If the borrowings under the Credit Facility represent
an amount greater than or equal to 66.7% of the available borrowing base, then
the applicable interest rate on the outstanding principal will be either (a)
LIBOR plus 2.00% or (b) the prime rate of the agent plus 0.50%. LIBOR elections
can be made for periods of one, three or six months. The interest rate at
December 31, 1997 was 7.80%.
The Credit Facility contains a number of covenants that, among other
things, restrict the ability of the Company to (i) incur certain indebtedness or
guarantee obligations, (ii) prepay other indebtedness including the Notes, (iii)
make investments, loans or advances, (iv) create certain liens, (v) make certain
payments, dividends and distributions, (vi) merge with or sell assets to another
person or liquidate, (vii) sell or discount receivables, (viii) engage in
certain intercompany transactions and transactions with affiliates, (ix) change
its business, (x) experience a change of control and (xi) make amendments to its
charter, by-laws and other debt instruments. In addition, under the Credit
F-18
Facility the Company is required to comply with specified financial ratios and
tests, including minimum debt service coverage ratios, maximum funded debt to
EBITDA tests, minimum net worth tests and minimum working capital tests. The
Company is obligated to pay the Lenders on a quarterly basis a commitment fee of
0.50% per annum on the average unused portion of the commitment in effect from
time to time. The Credit Facility contains customary events of default,
including nonpayment of principal, interest or fees, violation of covenants,
inaccuracy of representations or warranties in any material respect, cross
default and cross acceleration to certain other indebtedness, bankruptcy,
material judgments and liabilities and change of control. As of December 31,
1997, the Company was not in compliance with the working capital and capital
expenditures requirements under the Credit Facility. the Company has received a
waiver of these requirements through March 31, 1998. Under the provisions of the
Credit Facility, The Company is required to maintain working capital (as defined
in the agreement) of at least 1.00 to 1.00. At December 31, 1997 the Company's
working capital was less than the required amount, however, subsequent to
December 31, 1997 the Company repaid all outstanding amounts under the Credit
Facility except $100,000, which management believes will restore its working
capital ratio to the required amount. Accordingly, amounts payable under the
Credit Facility are classified as long-term in the accompanying balance sheet.
Should crude oil prices continue to decline, a further write-down of the
Company's oil and gas properties may be required (see Note 16). If such a
write-down were large enough, it could result in a default in the net worth
requirement under the Credit Facility.
As part of the bridge facility, the Company entered into an interest rate
swap agreement (the Swap) covering the period from September 18, 1996 to August
18, 1998. The Swap effectively changes the interest rate on $25,000,000 of
floating rate debt to a fixed rate of 6.15% per annum for that time period. Net
payments due under this agreement are included as adjustments to interest
expense. At December 31, 1997, the fair value of this Swap, as determined by
BTCo was approximately $64,000 and has been recorded as interest expense at
December 31, 1997. The Company is exposed to credit loss in the event of
nonperformance by the counterparty. The amount of such exposure is generally the
unrealized gains in such agreement.
In January 1998, the Company and Canadian Abraxas completed the sale of
$60,000,000 aggregate principal amount of 11.5% Senior Notes due 2004, Series C
(Series C Notes). The Series C Notes are general unsecured obligations of the
Company and Canadian Abraxas and rank pari passu in right to all existing and
future indebtedness of the Company and Canadian Abraxas and on parity with the
Series B Notes and senior in right of payment to all future subordinated
indebtedness of the Company and Canadian Abraxas. The Series C Senior Notes
carry similar redemption provisions to the Series B Notes and are subject to the
terms of the Indenture dated January 27, 1998 which is substantially similar to
the Indenture governing the Series B Notes. The Company and Canadian Abraxas
sold the Series C Notes at a premium of $4,050,000 which will be amortized over
the life of the Series C Notes resulting in an effective rate of interest of
10.5%. The net proceeds, after deducting estimated offering costs, were
$62,750,000, $33,400,000 of which was used to repay outstanding indebtedness
under the Credit Facility, except for $100,000 which remained outstanding with
the remainder used for general corporate purposes.
The Company's principal source of funds to meet debt service and capital
requirements is net cash flow provided by operating activities, which is
sensitive to the prices the Company receives for its crude oil and natural gas.
The Company periodically enters into hedge agreements to reduce its exposure to
price risk in the spot market for natural gas. However, a substantial portion of
the Company's production will remain subject to such price risk. Additionally,
significant capital expenditures are required for drilling and development, and
other equipment additions. The Company believes that cash provided by operating
activities and other financing sources, including, if necessary, the sale of
certain assets and additional long-term debt, will provide adequate liquidity
for the Company's operations, including its capital expenditure program, for the
next twelve months. No assurance, however, can be given that the Company's cash
flow from operating activities will be sufficient to meet planned capital
expenditures and debt service in the future. Should the Company be unable to
generate sufficient cash flow from operating activities to meet its obligations
and make planned capital expenditures, the Company could be forced to reduce
such expenditures, sell assets or 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.
F-19
During 1996 and 1997, the Company capitalized $465,000 and $966,000 of
interest expense, respectively.
The fair value of the Notes was approximately $236,500,000 as of December
31, 1997. The fair values of the credit facilities approximate their carrying
values as of December 31, 1997. The Company has approximately $1,800,000 of
standby letters of credit and a $30,000 performance bond open at December 31,
1997. Approximately $40,000 of cash is restricted and in escrow related to
certain of the letters of credit and bond.
5. Stockholders' Equity
Common Stock
Holders of common stock are entitled to one vote for each share and are
not entitled to preemptive rights to subscribe to additional shares of common
stock issued by the Company. Holders are entitled to receive dividends as may be
declared by the Board of Directors, subject to the rights of holders of
preferred stock and the terms of the Company's credit agreement, which restrict
the payment of dividends.
In 1994, the Board of Directors adopted a Stockholders' Rights Plan and
declared a dividend of one Common Stock Purchase Right (Rights) for each share
of common stock. The Rights are not initially exercisable. Subject to the Board
of Directors' option to extend the period, the Rights will become exercisable
and will detach from the common stock ten days after any person has become a
beneficial owner of 20% or more of the common stock of the Company or has made a
tender offer or exchange offer (other than certain qualifying offers) for 20% or
more of the common stock of the Company.
Once the Rights become exercisable, each Right entitles the holder, other
than the acquiring person, to purchase for $20 one-half of one share of common
stock of the Company having a value of four times the purchase price. The
Company may redeem the Rights at any time for $.01 per Right prior to a
specified period of time after a tender or exchange offer. The Rights will
expire in November 2004, unless earlier exchanged or redeemed.
In November 1995, the Company issued 1,330,000 units, each consisting of
one share of common stock and one Contingent Value Right (CVR), through a
private placement, resulting in net proceeds of $10,063,000. Each CVR allows the
holder the right to acquire additional shares of common stock under certain
circumstances. See further discussion of CVRs below. Loss per share, calculated
on a supplemental basis as if the foregoing event had occurred at the beginning
of 1995, would have been $(.19) for the year ended December 31, 1995. The
supplemental earnings per share assumes that interest expense would have been
reduced by $456,000 from the prepayment of $5,300,000 of long-term debt from the
proceeds of the issuance of the units for the year ended December 31, 1995.
Contingent Value Rights
The CVRs were issued under the CVR Agreement between the Company, the
purchasers, and a rights agent. The CVR Agreement provides that, subject to
adjustment as described below, the Company shall issue for each CVR on the
Extended Maturity Date (November 17, 1997), a number of shares of common stock,
if any, equal to (a) the Target Price ($12.50 on the Extended Maturity Date)
minus the current market value divided by (b) the current market value,
provided, however, that in no event shall more than 1.5 shares of common stock
be issued in exchange for each CVR at the Extended Maturity Date. Such
determination by the Company shall be final and binding on the Company and the
holders of CVRs.
If the median of the average prices of the common stock for the three
20-trading day periods immediately preceding the Extended Maturity Date, equals
or exceeds $12.50 on the Extended Maturity Date, no shares of the common stock
will be issuable with respect to the CVRs. In addition, the CVRs will terminate
if the per share market value equals or exceeds the Target Price for any period
of 30 consecutive trading days during the period from and after November 17,
1996 to and including November 17, 1997.
F-20
On June 20, 1997, the CVRs expired with no issuance of additional shares
under the CVR Agreement.
Convertible Preferred Stock
In June 1994, in connection with an acquisition, 45,741 shares of the
Company's Series B 8%, nonvoting cumulative convertible preferred stock with a
par value of $100 were issued. The preferred shares are convertible into 508,183
shares of the Company's common stock. Preferred stock dividends during each of
1995 and 1996 amounted to $366,000 and, during 1997, amounted to $183,000.
During 1995, the Company exchanged the Series B 8%, nonvoting cumulative
convertible preferred stock for an equal number of shares of Series 1995-B
cumulative convertible preferred stock which have a par value of $.01 per share
and a stated value of $100 per share. Effective July 1, 1997, the holders of the
Company's preferred stock converted all of such shares into 508,183 shares of
the Company's common stock. The Board of Directors of the Company is authorized
to approve the issuance of one or more classes or series of preferred stock
without further authorization of the Company's stockholders.
Treasury Stock
In March 1996, the Board of Directors authorized the purchase in the open
market of up to 500,000 shares of the Company's outstanding common stock, the
aggregate purchase price not to exceed $3,500,000.
During the year ended December 31, 1996, the Company purchased 74,640
shares of its common stock at a cost of $405,000, which were recorded as
treasury stock. No shares were purchased during 1997.
6. Stock Option Plans and Warrants
Stock Options
The Company grants options to its officers, directors, and key employees
under its 1984 Incentive Stock Option Plan, Non-Qualified Stock Option Plan, Key
Contributor Stock Option Plan, Long-Term Incentive Plan, and Director Stock
Option Plan.
The Company has elected to follow Accounting Principles Board Opinion No.
25, "Accounting for Stock Issued to Employees" (APB 25) and related
Interpretations in accounting for its employee stock options because, as
discussed below, the alternative fair value accounting provided for under FASB
Statement No. 123, "Accounting for Stock-Based Compensation," requires use of
option valuation models that were not developed for use in valuing employee
stock options. Under APB 25, because the exercise price of the Company's
employee stock options equals the market price of the underlying stock on the
date of grant, no compensation expense is recognized.
The Company's various stock option plans have authorized the grant of
options to management and directors personnel for up to approximately 1,395,000
shares of the Company's common stock. All options granted have ten year terms
and vest and become fully exercisable over four years of continued service at
25% on each anniversary date. At December 31, 1997, approximately 467,000
options remain available for grant.
Pro forma information regarding net income and earnings per share is
required by Statement 123, which also requires that the information be
determined as if the Company has accounted for its employee stock options
granted subsequent to December 31, 1994 under the fair value method of that
Statement. The fair value for these options was estimated at the date of grant
using a Black-Scholes option pricing model with the following weighted-average
assumptions for 1995, 1996, and 1997, respectively: risk-free interest rates of
6.25%, dividend yields of -0-%; volatility factors of the expected market price
of the Company's common stock of .383, .383 and .529, respectively; and a
weighted-average expected life of the option of six years.
F-21
The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions including the expected stock price
volatility. Because the Company's employee stock options have characteristics
significantly different from those of traded options, and because changes in the
subjective input assumptions can materially affect the fair value estimate, in
management's opinion, the existing models do not necessarily provide a reliable
single measure of the fair value of its employee stock options.
For purposes of pro forma disclosures, the estimated fair value of the
options is amortized to expense over the options' vesting period. The Company's
pro forma information follows (in thousands except for earnings per share
information):
1995 1996 1997
--------------------------------
(In thousands)
Pro forma net income (loss) ......... $(1,286) $ 1,250 $(7,325)
Pro forma net income (loss) per
common share ...................... $ (.36) $ .15 $ (1.25)
Pro forma net income (loss) per
common share - assuming dilution .. $ (.36) $ .13 $ (1.25)
A summary of the Company's stock option activity, and related information
for the years ended December 31, follows:
1995 1996 1997
--------------------- -------------------- -------------------
Weighted Weighted Weighted
Average Average Average
Options Exercise Options Exercise Options Exercise
(000s) Price (000s) Price(1) (000s) Price
------- ------------- -------------------- -------------------
Outstanding-beginning
of year ........ 103 $ 7.93 219 $ 6.71 (1) 551 $ 6.63
Granted .......... 158 9.50 358 6.58 285 11.26
Exercised ........ - - (2) 6.75 (2) 5.50
Forfeited ........ (42) 9.86 (24) 9.21 - -
------- ------- -------
Outstanding-end
of year ........ 219 $ 8.69 551 $ 6.63 834 $ 8.27
======= ======= =======
Exercisable at
end of year .... 53 $ 8.06 93 $ 6.65 222 $ 6.66
======= ======= =======
Weighted-average
fair value of
options granted
during the year $ 2.85 $ 3.46 $ 8.00
Exercise prices for options outstanding as of December 31, 1997 ranged
from $5.00 to $13.62. The weighted-average remaining contractual life of those
options is 8.4 years.
(1) In March 1996, the Company amended the exercise price to $6.75 per
share on all previously issued options with an exercise price greater than
$6.75 per share.
Stock Awards
In addition to stock options granted under the plans described above, the
Long-Term Incentive Plan also provides for the right to receive compensation in
cash, awards of common stock, or a combination thereof. In 1995, 1996, and 1997,
the Company made direct awards of common stock of 4,800 shares, 1,000 shares and
14,748 shares, respectively, at weighted average fair values of $9.40, $5.00 and
$10.75 per share, respectively.
F-22
The Company also has adopted the Restricted Share Plan for Directors which
provides for awards of common stock to nonemployee directors of the Company who
did not, within the year immediately preceding the determination of the
director's eligibility, receive any award under any other plan of the Company.
In 1995, 1996, and 1997, the Company made direct awards of common stock of 3,072
shares, 4,050 shares and 7,235 shares, respectively, at weighted average fair
values of $9.40, $6.25 and $9.87 per share, respectively.
During 1996, the Company's stockholders approved the Abraxas Petroleum
Corporation Director Stock Option Plan (Plan), which authorizes the grant of
nonstatutory options to acquire an aggregate of 104,000 common shares to those
persons who are directors and not officers of the Company. During 1996, each of
the seven eligible directors was granted an option to purchase 8,000 common
shares at $6.75. These options are included in the above table. No options were
granted during 1997.
Stock Warrants
In connection with an amendment to one of the Company's previous credit
agreements, the Company granted stock warrants to the lender covering 424,000
shares of its common stock at an average price of $9.79 a share. The warrants
are exercisable in whole or in part through December 1999 and are
nontransferable without the consent of the Company. During 1997, the lender
exercised 212,000 of its warrants on a cashless basis and was issued 97,810
shares of the Company's common stock.
Additionally, warrants to purchase 13,500 shares of the Company's common
stock at $7.00 per share remain outstanding from previous grants.
At December 31, 1997, the Company has approximately 4,700,000 shares
reserved for future issuance for conversion of its stock options, warrants,
Rights, and incentive plans for the Company's directors and employees.
7. Income Taxes
Deferred income taxes reflect the net tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts used for income tax purposes. Significant components of
the Company's deferred tax liabilities and assets are as follows:
December 31
--------------------
1996 1997
--------------------
(In thousands)
Deferred tax liabilities:
Full cost pool, including intangible
drilling costs ................................. $34,298 $31,128
State taxes ..................................... 187 67
Other ........................................... 61 103
--------------------
Total deferred tax liabilities .................... 34,546 31,298
Deferred tax assets:
Depletion ....................................... 431 930
Net operating losses ............................ 6,831 8,520
Other ........................................... 12 12
--------------------
Total deferred tax assets ......................... 7,274 9,462
Valuation allowance for deferred tax assets ....... (5,656) (5,915)
--------------------
Net deferred tax assets ........................... 1,618 3,547
--------------------
Net deferred tax liabilities ...................... $32,928 $27,751
====================
F-23
Significant components of the provision (benefit) for income taxes are as
follows:
1996 1997
-------------------
Current:
Federal ...................................... $ - $ -
State ........................................ - -
Foreign ...................................... 176 244
-------------------
$176 $ 244
===================
Deferred:
Federal ...................................... $ - $ -
State ........................................ - -
Foreign ...................................... - (4,135)
-------------------
$ - $(4,135)
===================
At December 31, 1997, the Company had, subject to the limitations
discussed below, $25,059,000 of net operating loss carryforwards for U.S. tax
purposes, of which it is estimated a maximum of $22,353,000 may be utilized
before it expires. These loss carryforwards will expire from 2002 through 2010
if not utilized. At December 31, 1997, the Company had approximately $2,943,000
of net operating loss carryforwards for Canadian tax purposes of which $830,000
will expire in 2003 and $2,113,000 will expire in 2004.
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 the U.S.
net operating loss carryforwards generated prior to December 31, 1991 of
$4,909,000 will be limited to approximately $235,000 per year.
During 1992, the Company acquired 100% of the common stock of an unrelated
corporation. The use of net operating loss carryforwards of $1,121,000 acquired
in the acquisition are limited to approximately $115,000 per year.
As a result of the issuance of additional shares of common stock for
acquisitions and sales of common stock, an additional ownership change under
Section 382 occurred in October 1993. Accordingly, it is expected that the use
of all U.S. net operating loss carryforwards generated through October 1993
(including those subject to the 1991 and 1992 ownership changes discussed above)
of $8,224,000 will be limited to approximately $1,034,000 per year, subject to
the lower limitations described above. Of the $8,224,000 net operating loss
carryforwards existing at October 1993, it is anticipated that the maximum net
operating loss that may be utilized before it expires is $5,692,000. Future
changes in ownership may further limit the use of the Company's carryforwards.
In addition to the Section 382 limitations, uncertainties exist as to the
future utilization of the operating loss carryforwards under the criteria set
forth under FASB Statement No. 109. Therefore, the Company has established a
valuation allowance of $5,656,000 and $5,915,000 for deferred tax assets at
December 31, 1996 and 1997, respectively.
F-24
The reconciliation of income tax attributable to continuing operations
computed at the U.S. federal statutory tax rates to income tax expense is:
December 31
--------------------------------------------
1995 1996 1997
-------------- -------------- --------------
(In thousands)
Tax (expense) benefit
at U.S. statutory
rates (34%) .......... $ 411 $ (743) $ 3,414
(Increase) decrease in
deferred tax asset
valuation allowance .. (174) (1) (259)
Higher effective rate
of foreign operations - (49) (244)
Percentage depletion ... - 189 499
Other .................. (237) 428 481
-------------- -------------- --------------
$ - $ (176) $ 3,891
============== ============== ==============
8. Related Party Transactions
Accounts receivable from affiliates, officers, and stockholders represent
amounts receivable relating to joint interest billings on properties which the
Company operates and advances made to officers.
In connection with a note payable to the Company's President, principal
and interest payments amounted to $355,000 in the year ended December 31, 1995.
The note was fully paid in 1995.
Wind River Resources Corporation ("Wind River"), all of the capital stock
of which is owned by the Company's President, owns a twin-engine airplane. The
airplane is available for business use by employees of the Company from time to
time at $385 per hour. The Company paid Wind River a total of $81,000, $101,000
and $330,000 for use of the plane during 1995, 1996 and 1997, respectively.
The Company's President and certain directors of the Company were founders
of Grey Wolf and in April 1995 purchased 900,000 shares of the capital stock of
Grey Wolf (initially representing 39% of the outstanding shares) for an
aggregate of CDN$90,000 (or CDN$0.10 per share) in cash. In January 1996, the
Company purchased 20,325,096 shares of the capital stock of Grey Wolf
(representing 78% of the outstanding shares) for an aggregate of $3,000,000
(approximately CDN$4.1 million or CDN$.20 per share) in cash.
In January 1996, Grey Wolf purchased newly issued shares of Cascade
representing 66 2/3% of Cascade's capital stock. As described in Note 2, in 1997
Grey Wolf merged with Cascade. At December 31, 1997, the Company owns
approximately 46% of Cascade. The Company's President as well as certain
directors directly own approximately 5% of Cascade. Additionally the Company's
President owns options to purchase up to 800,000 shares of Cascade capital stock
at an exercise price of CDN$.20 per share, and certain of the Company's
directors own options to purchase in the aggregate up to 1,000,000 shares of
Cascade capital stock at an exercise price of CDN$.20 per share. Cascade
currently has 76,981,000 shares, including special warrants, of capital stock
outstanding.
Cascade owns a 10% interest in the Canadian Abraxas oil and gas properties
and the Canadian Abraxas gas processing plants and an 8% interest in the Pacalta
Properties and manages the operations of 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.
F-25
9. Commitments and Contingencies
Operating Leases
During the years ended December 31, 1995, 1996, and 1997, the Company
incurred rent expense of approximately $103,000, $179,000 and $228,000,
respectively. Future minimum rental payments are as follows at December 31,
1997:
1998 .................................................... $289,000
1999 ..................................................... 290,000
2000 ..................................................... 306,000
2001 ..................................................... 354,000
2002 ..................................................... 247,000
Thereafter ............................................... 854,000
Contingencies
In May 1995, certain plaintiffs 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 $1,332,000 plus attorneys' fees and pre-judgment interest.
As of March 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.
Management believes, based on the advice of legal counsel, that the plaintiffs'
claims are without merit and that damages should not be recoverable under this
action; however, the ultimate effect on the Company's financial position and
results of operations cannot be determined at this time. The Company has not
established a reserve for this matter at December 31, 1997.
Additionally, from time to time, the Company is involved in litigation
relating to claims arising out of its operations in the normal course of
business. At December 31, 1997, the Company was not engaged in any legal
proceedings that are expected, individually or in the aggregate, to have a
material adverse effect on the Company.
F-26
10. Earnings per Share
The following table sets forth the computation of basic and diluted
earnings per share:
1995 1996 1997
----------- ----------- -----------
Numerator:
Net income (loss) $(1,208,000) $1,513,000 $(6,485,000)
Preferred stock dividends 366,000 366,000 183,000
----------- ----------- -----------
Numerator for basic earnings per
share - income (loss) available
to common stockholders (1,574,000) 1,147,000 (6,668,000)
Effect of dilutive securities:
Preferred stock dividends - - -
----------- ----------- -----------
Numerator for diluted earnings per
share - income available to
common stockholders after assumed
conversions (1,574,000) 1,147,000 (6,668,000)
Denominator:
Denominator for basic earnings per
share - weighted-average shares 4,635,412 5,757,105 6,025,294
Effect of dilutive securities:
Stock options and warrants - 24,277 -
Convertible preferred stock - - -
Assumed issuance under the CVR - 1,013,060 -
Agreement
----------- ----------- -----------
- 1,037,337 -
----------- ----------- -----------
Dilutive potential common shares
Denominator for diluted earnings
per share - adjusted
weighted-average shares and
assumed conversions 4,635,412 6,794,442 6,025,294
Basic earnings (loss) per share:
Income (loss) before
extraordinary item $ (.34) $ .27 $ (1.11)
Extraordinary item - (.07) -
=========== =========== ===========
$ (.34) $ .20 $ (1.11)
=========== =========== ===========
Diluted earnings (loss) per share:
Income (loss) before
extraordinary item $ (.34) $ .23 $ (1.11)
Extraordinary item - (.06) -
=========== =========== ===========
$ (.34) $ .17 $ (1.11)
=========== =========== ===========
For additional disclosures regarding the preferred stock, CVRs, employee
stock options, and warrants, see Notes 5 and 6.
For the years ended December 31, 1995 and 1997, none of the shares
issuable in connection with stock options, warrants, conversion of preferred
stock or the CVR Agreement are included in diluted shares. Inclusion of these
shares would be antidilutive due to losses incurred in those years. In addition,
for the year ended December 31, 1996 shares issuable in connection with the
conversion of the preferred stock were not included in diluted shares because
the effect was antidilutive.
F-27
Stock options and warrants to purchase approximately 875,000 shares of
common stock at a weighted average per share price of $8.36 were outstanding
during 1996 but were not included in the computations of diluted earnings per
share because the options' and warrants' exercise price was greater than the
average market price of the common shares and, therefore, the effect would be
antidilutive.
11. Quarterly Results of Operations (Unaudited)
Selected results of operations for each of the fiscal quarters during the
years ended December 31, 1996 and 1997 are as follows:
1st 2nd 3rd 4th
Quarter Quarter Quarter Quarter
----------- ---------- ---------- -----------
(In thousands, except per share data)
Year Ended December 31, 1996
Net revenue ....................................... $ 4,477 $ 3,305 $ 3,616 $ 15,255
Operating income .................................. 1,486 365 744 6,231
Income (loss) before
extraordinary item ............................... 599 (240) (236) 1,817
Net income (loss) ................................. 599 (240) (605) 1,759
Earnings (loss) per
common share:
Income (loss) before
extraordinary item ............................ .09 (.04) (.04) .30
Net income (loss)
per common share .............................. .09 (.04) (.10) .29
Earnings (loss) per common share assuming dilution:
Income (loss) before
extraordinary item ............................ .08 (.04) (.04) .25
Net income (loss)
per common share - ............................ .08 (.04) (.10) .24
assuming dilution .............................
Year Ended December 31, 1997
Net revenue ....................................... $ 19,216 $ 15,772 $ 15,703 $ 20,240
Operating income (loss)............................ 7,791 4,090 3,902 (633)
Net income (loss) ................................. 1,454 (2,010) (2,042) (3,887)
Earnings (loss) per
common share ..................................... .24 (.37) (.33) (.61)
Earnings (loss) per
common share - ................................... .22 (.37) (.33) (.61)
assuming dilution
During the fourth quarter of 1996, the Company completed several
acquisitions as described in Note 2 which affected net revenues, gross profit
and net income.
During the fourth quarter of 1997, the Company recorded a write-down of
its Canadian proved crude oil and natural gas properties of approximately
$4,600,000, $3,000,000, net of taxes, under the ceiling limitation.
Certain previously reported financial information has been reclassified to
conform with the current presentation.
F-28
12. Benefit Plans
The Company has a defined contribution plan (401(k)) covering all eligible
employees of the Company. No contributions were made by the Company during 1995.
During 1996 and 1997, the Company contributed 2,500 and 7,440 shares,
respectively, of its common stock held in the treasury to the Plan and recorded
the fair value of $12,500 and $41,850, respectively, as compensation expense.
The employee contribution limitations are determined by formulas which limit the
upper one-third of the plan members from contributing amounts that would cause
the plan to be top-heavy. The overall contribution is limited to the lesser of
20% of the employee's annual compensation or $9,240.
In January 1995, the Company created the Technical Employees Incentive
Bonus Plan, whereby technical employees have an incentive to find and develop
crude oil and natural gas reserves on an economic basis beneficial to the
Company and its shareholders. Participants are any technical employees
(geologist, geophysicist, engineer) not covered by another incentive bonus plan.
A participant may earn a monetary bonus of up to 65% of the participant's base
salary each year. The bonuses are determined in the first quarter of each year
and are based upon the amount of new proved developed producing reserves booked
each year on approved exploration and exploitation projects taking into
consideration the cost per equivalent barrel of developing the new reserves.
During 1995, 1996, and 1997, the Company incurred no bonus expense.
13. Summary Financial Information of Canadian Abraxas Petroleum Ltd.
The following is summary financial information of Canadian Abraxas, a
wholly owned subsidiary of the Company. Canadian Abraxas is jointly and
severally liable for the entire balance of the Series B Notes ($215,000,000), of
which $84,612,000 was utilized by Canadian Abraxas in connection with the
acquisition of CGGS. The Company has not presented separate financial statements
and other disclosures concerning Canadian Abraxas because management has
determined that such information is not material to the holders of the Notes.
December 31,
1996 1997
----------- -----------
(In thousands)
BALANCE SHEET
Assets
Total current assets ............................ $ 6,174 $ 4,738
Oil and gas and processing properties ........... 115,671 109,968
Other assets .................................... 3,302 3,761
=========== ===========
$125,147 $118,467
=========== ===========
Liabilities and Stockholder's Equity
Total current liabilities ....................... $ 3,624 $ 3,625
11.5% Senior Notes due 2004 ..................... 84,612 74,682
Notes payable to Abraxas Petroleum Corporation .. - 18,844
Other liabilities ............................... 34,797 30,295
Stockholder's equity (deficit) .................. 2,114 (8,979)
----------- -----------
$125,147 $118,467
=========== ===========
F-29
November 14,
1996, Date of
Acquisition, Year Ended
to December 31,
December 31, 1997
1996
--------------- --------------
(In thousands)
STATEMENTS OF OPERATIONS
Revenues ............................... $ 3,972 $19,264
Operating costs and expenses ........... (2,292) (16,617)
Proved property impairment ............. - (4,600)
Interest expense ....................... (1,331) (9,952)
Other income ........................... 23 202
Income tax (expense) benefit ........... (175) 3,815
--------------- --------------
Net income (loss) .................... $ 197 $(7,888)
=============== ==============
14. Business Segments
The Company conducts its operations through two industry segments, the
exploration for and the acquisition, development and production of crude oil and
natural gas (E&P) and the processing of natural gas (Processing). The E&P
segment acquires and explores for, develops, produces and markets crude oil,
condensate, natural gas liquids and natural gas. The Processing segment
processes natural gas owned by third parties. The Company's significant E&P
operations are located in the Texas Gulf Coast, the Permian Basin of western
Texas, Canada and Wyoming. The Processing segment engages in the processing of
natural gas. Natural gas processing involves the custom processing of natural
gas for third parties. Segment income excludes interest income, interest expense
and unallocated general corporate expenses. Identifiable assets are those assets
used in the operations of the segment. Corporate assets consist primarily of
deferred financing fees and other property and equipment. The Company's revenues
are derived primarily from the sale of crude oil, condensate, natural gas
liquids and natural gas to marketers and refiners and from processing fees from
the custom processing of natural gas. As a general policy, collateral is not
required for receivables; however, the credit of the Company's customers is
regularly assessed. The Company is not aware of any significant credit risk
relating to its customers and has not experienced significant credit losses
associated with such receivables.
In 1997 three customers accounted for approximately 42% of oil and natural
gas production revenues and two customers accounted for approximately 51% of gas
processing revenues. In 1996 four customers accounted for approximately 63% of
oil and natural gas production revenues and three customers accounted for
approximately 54% of gas processing revenues. In 1995 one customer accounted for
approximately 20% of oil and natural gas production.
F-30
Business segment information about the Company's 1996 operations is as
follows:
E&P Processing Total
----------- ----------- -----------
(In thousands)
Revenues ....................... $26,053 $ 600 $10,681
=========== =========== ===========
Operating profit ............... $10,660 $ 21 $10,681
=========== ===========
General corporate .............. (2,044)
Interest expense and
amortization of deferred
financing fees ............... (6,521)
-----------
Income from before income
taxes ....................... $ 2,116
===========
Identifiable assets ............ $253,707 $40,700 $294,407
=========== ===========
Corporate assets ............... 10,435
-----------
Total assets ................. $304,842
===========
Depreciation and depletion for E&P and Processing was approximately
$9,143,000 and $291,000, respectively. Capital expenditures for E&P and
Processing were $145,600,000 and $27,300,000, respectively.
Business segment information about the Company's 1997 operations is as
follows:
E&P Processing Total
----------- ----------- -----------
(In thousands)
Revenues ....................... $67,363 $ 3,568 $70,931
=========== =========== ===========
Operating profit ............... $18,039 $ (226) $17,813
=========== ===========
General corporate .............. (2,309)
Interest expense and
amortization of deferred
financing fees ............... (25,880)
-----------
Loss before income taxes ..... $(10,376)
===========
Identifiable assets ............ $292,087 $37,159 $329,246
=========== ===========
Corporate assets ............... 9,282
-----------
Total assets ................. $338,528
===========
Depreciation and depletion for E&P and Processing was approximately
$27,813,000 and $2,310,000, respectively. Capital expenditures for E&P and
Processing were approximately $84,300,000 and $1,500,000, respectively.
During 1995 the Company's operations were entirely in the E&P segment.
F-31
Business segment information about the Company's 1996 operations in
different geographic areas is as follows:
U.S. Canada Total
------------- ------------- -------------
(In thousands)
Revenues ..................... $ 21,999 $ 4,654 $ 26,653
============= ============= =============
Operating profit ............. $ 8,987 $ 1,694 $ 10,681
============= =============
General corporate ............ (2,044)
Interest expense and
amortization of deferred
financing fees ............. (6,521)
=============
Income before income taxes . $ 2,116
=============
Identifiable assets at
December 31, 1997 .......... $ 168,141 $ 126,266 $ 294,407
============= =============
Corporate assets ............. 10,435
-------------
Total assets ............... $ 304,842
=============
Business segment information about the Company's 1997 operations in
different geographic areas is as follows:
U.S. Canada Total
------------- ------------- -------------
(In thousands)
Revenues ..................... $ 50,172 $ 20,759 $ 70,931
============= ============= =============
Operating profit (loss)....... $ 19,938 $ (2,125) $ 17,813
============= =============
General corporate ............ (2,309)
Interest expense and
amortization of deferred
financing fees ............. (25,880)
=============
Loss before income taxes ... $ (10,376)
=============
Identifiable assets at
December 31, 1997 .......... $ 198,277 $ 130,969 $ 329,246
============= =============
Corporate assets ............. 9,282
-------------
Total assets ............... $ 338,528
=============
During 1995 the Company's operations were entirely in the United States.
15. Commodity Swap Agreements
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.
Pursuant to certain hedge agreements, either the Company or the
counterparty thereto is required to make payment to the other at the end of each
F-32
month. During the period from March 1996 through November 1996, payments were
exchanged equal to the product of 5,000 MMBtu of natural gas per day and the
difference between a specified fixed price and a variable price for natural gas
based on the arithmetic average of the last three trading days' settlement price
quoted for natural gas contracts on the New York Mercantile Exchange (NYMEX).
This hedge agreement provided for the Company to make payments to the
counterparty to the extent that the market price exceeds the fixed price of
$1.747 per MMBtu and for the counterparty to make payments to the Company to the
extent the market price was less than $1.747 per MMBtu. A loss of $511,000 was
incurred during the period of hedged production.
In November 1996, the Company assumed Hedge Agreements extending through
October 2001 with a counterparty involving the following notional quantities and
fixed prices:
Crude Oil Natural Gas
------------------------------------------------------
Notional Notional
Quantity Fixed Quantity Fixed
per Month Price per Month Price
(barrels) (barrel) (MMBtu) (MMBtu)
------------- -------------------------- -------------
1997 15,810 $ 17.20 53,712 $ 1.797
1998 13,175 $ 17.20 36,601 $ 1.793
1999 11,050 $ 17.47 24,489 $ 1.820
2000 9,180 $ 17.78 18,794 $ 1.872
2001 8,160 $ 18.08 14,850 $ 1.902
These hedge agreements provide for the Company to make payments to the
counterparty to the extent the market prices determined based on the price for
west Texas intermediate light sweet crude oil on the NYMEX for crude oil and the
Inside FERC, Tennessee Gas Pipeline Co.; Texas (Zone O) price for natural gas
exceeds the above fixed prices and for the counterparty to make payments to the
Company to the extent the market prices are less than the above fixed prices.
The Company accounts for the related gains or losses (a loss of $453,000 in 1996
and a loss of $952,000 in 1997) in crude oil and natural gas revenue in the
period of the hedged production. The average notional quantity of crude oil and
natural gas under the hedge agreements each month for 1998 is equal to
approximately 15% and 1.5%, respectively, of the Company's expected monthly
production for 1998 based on the Company's January 1, 1998 reserve reports. At
December 31, 1997, the estimated fair market value of the hedge agreements is a
loss of approximately $700,000.
16. Proved Property Impairment
In 1997 the Company recorded a write-down of its proved crude oil and
natural gas properties of approximately $4,600,000, $3,000,000 after taxes,
under the ceiling limitation prescribed for companies following the full cost
method of accounting for its oil and gas properties. The write-down was related
to the Company's Canadian cost center and was due primarily to a decrease in
spot market prices for its crude oil and natural gas. Under full cost accounting
rules, the net capitalized costs of oil and gas properties, less related
deferred taxes, are limited by country, to the lower of unamortized cost or the
cost ceiling as discussed in Note 1. The risk that the Company will be required
to write-down the carrying value of its crude oil and natural gas properties
increases when crude oil and natural gas prices are depressed or volatile.
Should prices continue to decline, a further write-down of the Company's crude
oil and natural gas properties may be required. 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.
17. Subsequent Event
In November 1997, the Company entered into an agreement and plan of merger
(agreement) to purchase all of the outstanding capital stock of Vessels Energy,
F-33
Inc. (Vessels) in exchange for common stock of the Company, which agreement was
subject to stockholder approval of both companies. In February 1998 the
agreement was not approved by the Vessels stockholders and was terminated. In
accordance with the termination provisions of the agreement, Vessels paid the
Company a fee of $1,500,000. The Company incurred approximately $519,000
($274,000 through December 31, 1997 which is included in other accounts
receivable) of expenses in connection with the negotiation of the agreement.
Such cost will be offset against the fee received from Vessels, which will
result in a gain of approximately $981,000 in 1998. Additionally, through
December 31, 1997, the Company incurred approximately $133,000, which is
included in other accounts receivable, in drilling costs in connection with
farm-out agreements with Vessels which is to be reimbursed to the Company
subsequent to December 31, 1997.
18. Supplemental Oil and Gas Disclosures (Unaudited)
The accompanying table presents information concerning the Company's crude
oil and natural gas producing activities as required by Financial Accounting
Standards 69, "Disclosures about Oil and Gas Producing Activities." Capitalized
costs relating to oil and gas producing activities are as follows:
December 31
-----------------------------
1996 1997
-------------- --------------
(In thousands)
Proved crude oil and natural gas $231,090 $332,680
properties .........................
Unproved properties .................. 37,268 11,519
-------------- --------------
Total ............................... 268,358 344,199
Accumulated depreciation, depletion,
and amortization, and impairment ... (38,368) (70,717)
-------------- --------------
Net capitalized costs ............. $229,990 $273,482
============== ==============
F-34
Costs incurred in oil and gas property acquisitions, exploration and
development activities are as follows:
Years Ended December 31
----------------------------------------------------------------------------------------------
1995 1996 1997
------------------------------- --------------------------------------------------------------
Total U.S. Canada Total U.S. Canada Total U.S. Canada
-------------------- ---------- -------------------- -------------------- --------------------
(In thousands)
Property acquisition
costs:
Proved .............. $ 719 $ 719 $ - $87,005 $37,609 $49,396 $13,800 $ - $13,800
Unproved ............ - - - 37,268 8,230 29,038 8,958 - 8,958
-------------------- ---------- -------------------- -------------------- --------------------
$ 719 $ 719 $ - $124,273 $45,839 $78,434 $22,758 $ - $22,758
==================== ========== ==================== ==================== ====================
Property development
and exploration costs $11,398 $11,398 $ - $18,133 $18,115 $ 18 $61,414 $53,363 $ 8,051
==================== ========== ==================== ==================== ====================
The results of operations for oil and gas producing activities are as
follows:
Years Ended December 31
----------------------------------------------------------------------------------------------
1995 1996 1997
------------------------------- --------------------------------------------------------------
Total U.S. Canada Total U.S. Canada Total U.S. Canada
-------------------- ---------- -------------------- -------------------- --------------------
(In thousands)
Revenues .......... $13,660 $13,660 $ - $25,749 $21,758 $3,991 $65,826 $49,031 $16,795
Production costs .. (4,333) (4,333) - (5,858) (5,193) (665) (14,881) (10,749) (4,132)
Depreciation,
depletion, and
amortization ..... (5,313) (5,313) - (9,103) (7,695) (1,408) (27,803) (18,992) (8,811)
amortization .....
Proved property
impairment ....... - - - - - - (4,600) - (4,600)
General and
administrative ... (261) (261) - (483) (401) (82) (1,042) (721) (321)
Income taxes
(expense) benefit. - - - (148) - (148) 427 - 427
---------- ---------- ---------- --------- ----------- -------- ---------- --------- --------
Results of operations
from oil and gas
producing activities
(excluding corporate
overhead and
interest costs) ..... $3,753 $ 3,753 $ - $10,157 $ 8,469 $1,688 $17,927 $18,569 $ (642)
========== ========== ========== ========= ========== ========= ========= ========= ========
Depletion rate per
barrel of oil
equivalent ....... $ 4.67 $ 4.67 $ - $ 5.12 $ 5.10 $ 5.29 $ 5.62 $ 5.05 $ 6.98
========== ========== ========== ========= ========== ========= ========= ========= ========
F-35
Estimated Quantities of Proved Oil and Gas Reserves
The following table presents the Company's estimate of its net proved
crude oil and natural gas reserves as of December 31, 1995, 1996, and 1997. The
Company's management emphasizes that reserve estimates are inherently imprecise
and that estimates of new discoveries are more imprecise than those of producing
oil and gas properties. Accordingly, the estimates are expected to change as
future information becomes available. The estimates have been prepared by
independent petroleum reserve engineers.
Total United States Canada
----------------------- ----------------------- --------------------------
Liquid Natural Liquid Natural Liquid Natural
Hydrocarbons Gas Hydrocarbons Gas Hydrocarbons Gas
----------------------- ------------- ------------------------ -----------
(Barrels) (Mcf) (Barrels) (Mcf) (Barrels) (Mcf)
(In Thousands)
Proved developed and undeveloped reserves:
Balance at December 31, 1994 ..... 9,156 67,579 9,156 67,579 - -
Revisions of previous estimates . (1,328) (18,941) (1,328) (18,941) - -
Extensions and discoveries ...... 1,335 6,819 1,335 6,819 - -
Purchase of minerals in place ... 214 2,889 214 2,889 - -
Production ...................... (544) (3,553) (544) (3,553) - -
Sale of minerals in place ....... (566) (224) (566) (224) - -
----------------------- ------------- ------------------------ -----------
Balance at December 31, 1995 ..... 8,267 54,569 8,267 54,569 - -
Revisions of previous estimates . 680 (2,561) 680 (2,561) - -
Extensions and discoveries ...... 1,752 10,194 1,746 10,060 6 134
Purchase of minerals in place ... 8,062 121,408 6,694 65,135 1,368 56,273
Production ...................... (724) (6,350) (670) (5,042) (54) (1,308)
Sale of minerals in place ....... (2) - (2) - - -
----------------------- ------------- ------------------------ -----------
Balance at December 31, 1996 ..... 18,035 177,260 16,715 122,161 1,320(1) 55,099
Revisions of previous estimates . (1,083) (4,554) (1,096) (10,343) 13 5,789
Extensions and discoveries ...... 2,262 48,405 2,190 40,877 72 7,528
Purchase of minerals in place ... 585 27,575 197 150 388 27,425
Production ...................... (1,929) (21,050) (1,736) (12,508) (193) (8,542)
Sale of minerals in place ....... (93) (6,322) (9) (42) (84) (6,280)
----------------------- ------------- ------------------------ -----------
Balance at December 31, 1997 ..... 17,777 221,314 16,261 140,295 1,516(1) 81,019(2)
======================= ============= ======================== ===========
(1) Includes 120,400 and 260,200 barrels of liquid hydrocarbon reserves owned by
Cascade of which approximately 57,600 and 140,200 barrels are applicable to the
minority interest's share of these reserves at December 31, 1996 and 1997,
respectively.
(2) Includes 7,446 MMcf of natural gas reserves owned by Cascade of which 4,012
MMcf are applicable to the minority interest's share of these reserves at
December 31, 1997.
F-36
Estimated Quantities of Proved Oil and Gas Reserves (continued)
Total United States Canada
----------------------- ----------------------- -----------------------
Liquid Natural Liquid Natural Liquid Natural
Hydrocarbons Gas Hydrocarbons Gas Hydrocarbons Gas
----------------------- ------------- ----------------------- ----------
(Barrels) (Mcf) (Barrels) (Mcf) (Barrels) (Mcf)
(In Thousands)
Proved developed reserves:
December 31, 1995 ................ 6,000 44,026 6,000 44,026 - -
======================= ============= ======================= ==========
December 31, 1996 ................ 14,961 157,660 13,641 103,639 1,320 54,021
======================= ============= ======================= ==========
December 31, 1997 ................ 14,254 186,490 12,750 109,456 1,504 77,034
======================= ============= ======================= ==========
The significant downward revision in 1995 of previous liquid hydrocarbons
and natural gas was due principally to decreased estimates of recoverable
reserves in existing wells related to disappointing drilling results principally
in the East White Point Field, resulting in reclassification of proved
undeveloped reserves to probable reserves.
F-37
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves
The following disclosures concerning the standardized measure of future
cash flows from proved crude oil and natural gas reserves are presented in
accordance with Statement of Financial Accounting Standards No. 69. The
standardized measure does not purport to represent the fair market value of the
Company's proved crude oil and natural gas reserves. An estimate of fair market
value would also take into account, among other factors, the recovery of
reserves not classified as proved, anticipated future changes in prices and
costs, and a discount factor more representative of the time value of money and
the risks inherent in reserve estimates.
Under the standardized measure, future cash inflows were estimated by
applying period-end prices at December 31, 1997, adjusted for fixed and
determinable escalations, to the estimated future production of year-end proved
reserves. Future cash inflows were reduced by estimated future production and
development costs based on year-end costs to determine pre-tax cash inflows.
Future income taxes were computed by applying the statutory tax rate to the
excess of pre-tax cash inflows over the tax basis of the properties. Operating
loss carryforwards, tax credits, and permanent differences to the extent
estimated to be available in the future were also considered in the future
income tax calculations, thereby reducing the expected tax expense.
Future net cash inflows after income taxes were discounted using a 10%
annual discount rate to arrive at the Standardized Measure.
F-38
Set forth below is the Standardized Measure relating to proved oil and gas
reserves for:
Years Ended December 31
-------------------------------------------------------------- ----------------------------------
1995 1996 1997
-------------------------------------------------------------- ----------------------------------
Total U.S. Canada Total U.S. Canada Total U.S. Canada
---------- ------------------------------ -------------------- ----------------------- ----------
(In thousands)
Future cash inflows . $243,969 $243,969 $ - $1,009,420 $824,776 $184,644 $714,048 $530,627 $183,421
Future production
and development
costs.............. (79,910) (79,910) - (251,749) (201,498) (50,251) (249,604) (186,445) (63,159)
Future income tax
expense ........... (28,015) (28,015) - (207,834) (157,508) (50,326) (82,998) (48,736) (34,262)
---------- --------- --------- ------------ -------- -------- --------- --------- ---------
Future net cash
flows ............. 136,044 136,044 - 549,837 465,770 84,067 381,446 295,446 86,000
Discount ............ (48,884) (48,884) - (220,016) (193,221) (26,795) (129,367) (107,259) (22,108)
---------- --------- --------- ------------ -------- -------- --------- --------- ---------
Standardized Measure
of discounted
future net cash
relating to proved
reserves .......... $ 87,160 $ 87,160 $ - $ 329,821 $272,549 $ 57,272 $252,079 $188,187 $63,892
========== ========= ========= ========== ======== ======== ========= ========= ========
F-39
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserves
The following is an analysis of the changes in the Standardized Measure:
Year Ended December 31
----------------------------------------
1995 1996 1997
------------- --------------------------
(In thousands)
Standardized Measure,
beginning of year......... $ 77,693 $ 87,160 $ 329,821
Sales and transfers of oil
and gas produced, net of
production costs ......... (9,351) (19,887) (50,945)
Net changes in prices and
development and production
costs from prior year .... 22,560 65,917 (190,174)
Extensions, discoveries, and
improved recovery, less
related costs ............ 13,475 30,699 49,471
Purchases of minerals in
place .................... 3,867 244,930 27,586
Sales of minerals in place . (3,355) (24) (5,720)
Revision of previous quantity
estimates ................ (24,937) 2,257 (8,150)
Change in future income tax
expense .................. 382 (87,393) 70,858
Other ...................... (943) (2,554) (12,389)
Accretion of discount ...... 7,769 8,716 41,721
------------- ------------ ------------
Standardized Measure, end of
year .................... $ 87,160 $ 329,821 $ 252,079
============= ============ ============
F-40