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<SEC-DOCUMENT>0000867665-99-000012.txt : 19990414
<SEC-HEADER>0000867665-99-000012.hdr.sgml : 19990414
ACCESSION NUMBER: 0000867665-99-000012
CONFORMED SUBMISSION TYPE: 10-K
PUBLIC DOCUMENT COUNT: 2
CONFORMED PERIOD OF REPORT: 19981231
FILED AS OF DATE: 19990413
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: ABRAXAS PETROLEUM CORP
CENTRAL INDEX KEY: 0000867665
STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311]
IRS NUMBER: 742584033
STATE OF INCORPORATION: NV
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-K
SEC ACT:
SEC FILE NUMBER: 000-19118
FILM NUMBER: 99592908
BUSINESS ADDRESS:
STREET 1: 500 N LOOP 1604 EAST STE 100
CITY: SAN ANTONIO
STATE: TX
ZIP: 78232
BUSINESS PHONE: 2104904788
MAIL ADDRESS:
STREET 1: 500 N LOOP 1604 EAST STE 100
CITY: SAN ANTONIO
STATE: TX
ZIP: 78232
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K
<SEQUENCE>1
<DESCRIPTION>ANNUAL REPORT ON FORM 10K
<TEXT>
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the Fiscal Year Ended December 31, 1998
[ ]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 22,
1999, (based upon the average of the $2.06 per share "Bid" and $2.44 per share
"Asked" prices), was approximately $10,725,000 on such date.
The number of shares of the issuer's Common Stock, par value $.01 per
share, outstanding as of March 22, 1999 was 6,330,426 shares of which 4,766,739
shares were held by non-affiliates.
Documents Incorporated by Reference: Portions of the registrant's Proxy
Statement relating to the 1999 Annual Meeting of Shareholders to be held on May
28, 1999 have been incorporated by reference herein (Part III).
<PAGE>
ABRAXAS PETROLEUM CORPORATION
FORM 10-K
TABLE OF CONTENTS
PART I
Page
Item 1. Business. ............................................................4
General .............................................................4
Business Strategy ....................................................5
Recent Developments...................................................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
Royalty Matters......................................................15
Environmental Matters ..............................................16
Employees............................................................18
Item 2. Properties...........................................................19
Primary Operating Areas..............................................19
Exploratory and Developmental Acreage................................20
Productive Wells.....................................................20
Reserves Information.................................................21
Crude Oil and Natural Gas Production and Sales Price ................22
Drilling Activities..................................................23
Office Facilities....................................................24
Other Properties.....................................................24
Item 3. Legal Proceedings....................................................24
Item 4. Submission of Matters to a Vote of
Security Holders...................................................24
Item 4a. Executive Officers of the Company....................................24
PART II
Item 5. Market for Registrant's Common Equity
and Related Stockholder Matters....................................25
Market Information...................................................25
Holders..............................................................26
Dividends............................................................26
Item 6. Selected Financial Data..............................................27
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations........................27
Results of Operations................................................27
Liquidity and Capital Resources......................................30
Item 7a. Quantitative and Qualitative Disclosures about Market Risk...........36
Item 8. Financial Statements and Supplementary Data..........................34
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure..............................37
2
<PAGE>
PART III
Item 10. Directors and Executive Officers of the Registrant ................37
Item 11. Executive Compensation..............................................37
Item 12. Security Ownership of Certain Beneficial Owners and Management......37
Item 13. Certain Relationships and Related Transactions......................37
PART IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K...........................................38
3
<PAGE>
DISCLOSURE REGARDING FORWARD-LOOKING INFORMATION
This report includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934. All statements other than statements of
historical facts included in this report regarding the Company's financial
position, liquidity, cash flow from operations, internal cash flow projections,
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 primarily in the
acquisition, exploration, exploitation and production of crude oil and natural
gas. Since January 1, 1991, the Company's principal means of growth has been
through the acquisition and subsequent development and exploitation of producing
properties and related assets. The Company utilizes a disciplined acquisition
strategy, focusing its efforts on producing properties and related assets
characterized by a concentration of operations, significant and quantifiable
development potential, historically low operating expenses and the potential to
reduce general and administrative ("G&A") expense per Mcfe. The Company seeks to
complement its acquisition and development activities by selectively
participating in exploration projects with experienced industry partners. The
Company's principal areas of operation are Texas and western Canada. At December
31, 1998, the Company owned interests in 766,494 gross acres (494,647 net acres)
and operates properties accounting for 69% of its PV-10, affording the Company
substantial control over the timing and incurrence of operating and capital
expenditures. PV-10 means estimated future net revenue, discounted at a rate of
10% per annum, before income taxes and with no price or cost escalation or
de-escalation in accordance with guidelines promulgated by the Securities and
Exchange Commission. An Mcf is one thousand cubic feet of natural gas. MMcf is
used to designate one million cubic feet of natural gas and Bcf refers to one
billion cubic feet of natural gas. Mcfe means thousands of cubic feet of natural
gas equivalents, using a conversion ratio of one barrel of crude oil to six Mcf
of natural gas. MMcfe means millions of cubic feet of natural gas equivalents
and Bcfe means billions of cubic feet of natural gas equivalents. The term Bbl
means one barrel of crude oil and MBbls is used to designate one thousand
barrels of crude oil.
At December 31, 1998, the Company's estimated total proved reserves were
244 Bcfe and aggregate PV-10 was $182 million. As of December 31, 1998, the
Company had net natural gas processing capacity of 108 MMcf per day through its
19 natural gas processing plants and compression facilities in Canada, giving
the Company substantial control over its Canadian production and marketing
activities.
4
<PAGE>
Business Strategy
The Company's primary business objectives are to increase its reserves,
production and cash flow through the following:
o Improved Liquidity. In March 1999, the Company sold $63.5 million aggregate
principal amount of 12.875% Senior Secured Notes due 2003 (the "Secured
Notes"). The sale of the Secured Notes increased the Company's cash balance
to approximately $21 million, allowing the Company to meet its near-term
debt service requirements and facilitating limited capital expenditures.
The Company has historically funded its operations primarily through cash
flow from operations and borrowings under the Credit Facility (as defined
below). As a result of the sale of the Secured Notes, the Company's ability
to incur additional indebtedness will be substantially limited and thus, in
the current environment of depressed crude oil and natural gas prices, the
Company will rely on cash on hand, cash flow from operations, asset sales
and equity issuances to fund crude oil and natural gas exploitation
activities and acquisitions.
o Low Cost Operations. The Company seeks to maintain low operating and G&A
expenses per Mcfe by operating a majority of its producing properties and
related assets and by maintaining a high rate of production on a per well
basis. As a result of this strategy, the Company has achieved per unit
operating and G&A expenses that compare favorably with similar companies and
that have historically been lower than currently depressed crude oil and
natural gas prices realized by the Company.
o Exploitation of Existing Properties. The Company will allocate a portion of
its operating cash flow to the exploitation of its producing properties.
Management believes that the proximity of the Company's undeveloped reserves
to existing production makes development of these properties less risky and
more cost-effective than other drilling opportunities available to the
Company. Given the Company's high degree of operating control, the timing
and incurrence of operating and capital expenditures is largely within the
Company's discretion.
o Producing Property Acquisitions. As cash flow permits, the Company intends
to continue to acquire producing crude oil and natural gas properties that
can increase cash flow, production and reserves through operational
improvements and additional development. The Company expects that the
combination of low crude oil and natural gas prices, limited access to
liquidity through the capital markets and reduced availability on commercial
bank lines will result in an increase in attractive acquisition
opportunities offered by crude oil and natural gas companies seeking
additional liquidity.
o Focused Exploration Activity. In periods of increased crude oil and natural
gas prices, the Company intends to allocate a portion of its capital budget
to the drilling of exploratory wells that have high reserve potential. The
Company believes that by devoting a relatively small amount of capital to
high impact, high risk projects while reserving the majority of its
available capital for development projects, it can reduce drilling risks
while still benefiting from the potential for significant reserve additions.
Recent Developments
In November 1998, Abraxas sold all of its interests in producing
properties located in the Wamsutter area of southwestern Wyoming (the "Wyoming
Properties") to a limited partnership (the "Partnership") for $58.6 million in
cash. A subsidiary of Abraxas owns a one percent equity interest in the
Partnership and acts as general partner of the Partnership. Abraxas also
receives a management fee and reimbursement of certain overhead costs from the
Partnership.
In January 1999, Canadian Abraxa Petroleum Limited, a wholly-owned
subsidiary of the Company ("Canadian Abraxas") acquired all of the outstanding
common shares of New Cache Petroleums Ltd. ("New Cache") for an aggregate of
$78.0 million in cash and the assumption of approximately $10.0 million in debt
(the "New Cache Debt"). New Cache is an independent energy company engaged in
the acquisition, exploration, development, production and gathering of natural
gas and crude oil. New Cache owns interests in 285 gross wells (88.5 net wells)
and 445,294 gross (256,524 net) acres located primarily in western Canada, as
well as three natural gas processing plants. At December 31, 1998, New Cache had
estimated total proved reserves of 77 Bcfe (75% natural gas) with a PV-10 of
$55.6 million all of which were proved developed.
In March 1999, the Company sold the Secured Notes. The net proceeds from
the sale of the Secured Notes, after deducting estimated offering expenses, was
5
<PAGE>
approximately $61 million. The Company used the net proceeds to repay
outstanding indebtedness under its revolving credit facility (the "Credit
Facility") of approximately $34.5 million and the New Cache Debt with the
balance of approximately $16.5 million to be used for general corporate
purposes, including interest payments on Abraxas' and Canadian Abraxas' 11.5%
Senior Notes due 2004, Series D (the "Series D Notes").
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, 1998, 4 purchasers accounted for
approximately 58% of the Company's crude oil and natural gas sales. The Company
believes that there are numerous other companies available to purchase the
Company's crude oil and natural gas and that the loss of any or all of these
purchasers would not materially affect the Company's ability to sell crude oil
and natural gas.
Risk Factors
Lack of Liquidity
The Company has historically funded its operations primarily through its
cash flow from operations and borrowings under the Credit Facility and other
credit sources. Due to severely depressed crude oil and natural gas market
prices, the Company's cash flow from operations has been substantially reduced.
The Company anticipates that it will have two principal sources of liquidity
during the next 12 months: (i) cash on hand, including the net proceeds from the
sale of the Secured Notes and after the repayment of the New Cache Debt and all
amounts outstanding under the Credit Facility and (ii) cash generated by
operations. See "-- High Degree of Leverage," "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources" and the Consolidated Financial Statements and the notes
thereto.
The Company's ability to raise funds through additional indebtedness
will be substantially limited by the terms of the Indenture governing the
Secured Notes (the "Secured Notes Indenture") and the Indenture governing the
Series D Notes (the "Series D Indenture" and, together with the Secured Notes
Indenture, the "Indentures"). Additionally, substantially all of the Company's
crude oil and natural gas properties and natural gas processing facilities are
subject to a lien or floating charge for the benefit of the holders of the
Secured Notes, further limiting the Company's ability to incur additional
indebtedness. The Company may also choose to issue equity securities or sell
certain of its assets to fund its operations, although the Indentures will
substantially limit the Company's use of the proceeds of any such asset sales.
Due to the Company's diminished cash flow from operations and the resulting
depressed prices for its common stock, there can be no assurance that the
Company would be able to obtain equity financing on terms satisfactory to the
Company.
6
<PAGE>
The Company has implemented a number of measures to conserve its cash
resources, including postponement of exploration and development projects.
However, while these measures will help conserve the Company's cash resources in
the near term, they will also limit the Company's ability to replenish its
depleting reserves, which could negatively impact the Company's operating cash
flow and results of operations in the future. See "-- Depletion of Reserves."
High Degree of Leverage
As of December 31, 1998, the Company's total debt and stockholders'
equity (deficit) were approximately $299.7 million and $(63.5) million,
respectively. In addition, the Company had $22.3 million of unused borrowing
capacity under the Credit Facility at December 31, 1998. In January 1999, the
Company and Canadian Abraxas completed the acquisition of New Cache requiring
approximately $61 million in cash and approximately $17.0 million of the
available borrowing capacity under the Credit Facility. In March 1999 the
Company sold $63.5 million of the Secured Notes and repaid all amounts due under
the Credit Facility and the New Cache Debt. After giving effect to the
acquisition of New Cache and the sale of the Secured Notes, the Company's total
debt and stockholders' equity (deficit) would have been approximately $347.5
million and $(90.0) million at December 31, 1998. The Company may incur
additional indebtedness in the future in connection with acquiring, developing
and exploiting producing properties, although the Company's ability to incur
additional indebtedness is limited by the terms of the Indentures. The Secured
Notes are secured by substantially all of the Company's existing and future oil
and gas producing properties.
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 the
Secured Notes and the Series D. Notes and will not be available for other
purposes; (ii) covenants contained in the Indentures will limit the Company's
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 will be substantially
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,
and cash currently on hand, including the proceeds from the sale of the Secured
Notes, 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 remainder of 1999. 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. The Company's cash flow from operations will be
negatively affected by among other things, currently depressed commodity prices.
Further, the Company's operating cash flow could be negatively affected by the
Company's limited ability, due to its diminished liquidity and ability to borrow
funds, to acquire producing properties, to undertake exploration and development
projects and to otherwise replenish its depleting reserves. See "-- Depletion of
Reserves."
If the Company is unable to generate cash flow from operations in the
future to service the Notes, the Series D Notes and its other debt, it may be
required to refinance all or a portion of its debt or to obtain additional
financing. The Company's ability to refinance all or a portion of its debt or to
obtain additional financing will be substantially limited under the terms of the
Indentures. Also, substantially all of the Company's crude oil and natural gas
properties and natural gas processing facilities are subject to a lien or
floating charge for the benefit of the holders of the Notes. There can be no
assurance that any such refinancing would be possible or that any additional
financing could be obtained. In addition, the Secured Notes and the Series D
Notes are subject to certain limitations on redemption. See "-- Lack of
Liquidity" and "Management's Discussion and Analysis of Financial Condition and
Results of Operations --Liquidity and Capital Resources."
7
<PAGE>
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. The
Company's ability to acquire or find additional reserves in the near future will
be severely diminished by its lack of available funds for acquisition,
exploration and development projects. The Company has implemented a number of
measures to conserve its cash resources, including postponement of exploration
and development projects. However, while these measures will help conserve the
Company's cash resources in the near term, they will also limit the Company's
ability to replenish its depleting reserves, which could negatively impact the
Company's operating cash flow in the future. See "-- Lack of Liquidity."
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, the Company's ability to obtain
additional financing in the future for acquisitions and capital expenditures is
limited.
Industry Conditions; Impact on Company's Profitability
The Company's revenue, profitability and future rate of growth are
substantially dependent upon prevailing prices for crude oil and natural gas.
Crude oil and natural gas prices can be extremely volatile and in recent years
have been depressed by excess total domestic and imported supplies. Prices are
also affected by actions of state and local governmental agencies, the United
States and foreign governments and international cartels.Prices for crude oil
and natural gas have declined to historic lows on an inflation-adjusted basis.
There can be no assurance that commodity prices will rise or will not further
decrease. These external factors and the volatile nature of the energy markets
make it difficult to estimate future prices of crude oil and natural gas. The
substantial or extended decline in the prices of crude oil and natural gas has
had 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
the ceiling test requires pricing future revenue at the unescalated prices in
effect 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 crude oil and natural gas properties at December 31, 1998
by $61.2 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 $61.2 million at
December 31, 1998, as a result of the write-down. Once incurred, a write-down of
crude oil and natural gas properties is not reversible at a later date. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Liquidity and Capital Resources."
In order to manage its exposure to price risks in the marketing of its
crude oil and natural gas, the Company from time to time has entered into fixed
price delivery contracts, financial swaps and crude oil and natural gas futures
contracts as hedging devices. To ensure a fixed price for future production, the
Company may sell a futures contract and thereafter either (i) make physical
8
<PAGE>
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."
Reliance on Estimates of Proved Reserves and Future Net Revenue Information
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and the timing of
development expenditures, including many factors beyond the control of the
Company. The reserve data included in this report represent only estimates. In
addition, the estimates of future net revenue from proved reserves and the
present value thereof are based upon certain assumptions about future production
levels, prices and costs that may not prove to be correct over time. In
particular, estimates of crude oil and natural gas reserves, future net revenue
from proved reserves and the PV-10 thereof for the crude oil and natural gas
properties 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, 1998.
The average sales prices as of such date used for purposes of such estimates of
the Company were $9.95 per Bbl of crude oil, $8.97 per Bbl of NGLs and $1.90 per
Mcf of natural gas. It is also assumed that the Company will make future capital
expenditures of approximately $31.7 million in the aggregate, which are
necessary to develop and realize the value of proved undeveloped reserves on
these properties. Any significant variance in actual results from these
assumptions could also materially affect the estimated quantity and value of
reserves set forth herein. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources" and "Business -- Reserves Information."
Net Losses
The Company has experienced recurring losses. For the years ended
December 31, 1994, 1995, 1997 and 1998, the Company recorded net losses of $2.6
million, $1.6 million $6.7 million and $84.0 million, respectively. See
"Management's Discussion and Analysis of Financial Conditions and Results of
Operations" and the Company's Consolidated Financial Statements and the notes
thereto included in this document. There can be no assurance that the Company
will become profitable in the future.
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 $6.0 million during 1998 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.
Integration of Operations
The Company's future operations and earnings will be dependent, in part,
upon the Company's ability to integrate the operations of New Cache. There can
be no assurance that the Company will be able to successfully integrate such
operations with those of the Company, and a failure to do so would have a
material adverse effect on the Company's financial position, results of
operations and cash flows. Additionally, although the Company does not currently
have any specific acquisition plans, the need to focus management's attention on
integration of the new operations, as well as other factors, may limit the
Company's ability to successfully pursue acquisitions or other opportunities
related to its business for the foreseeable future. Also, successful integration
of operations will be subject to numerous contingencies, some of which are
beyond management's control. These contingencies include general and regional
economic conditions, prices for crude oil and natural gas, competition and
changes in regulation.
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,
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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 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. 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. Upon the occurrence of an event of default, holders of the
Secured Notes and the Series D Notes could elect to accelerate the payment of
the notes. There can be no assurance that the assets of the Company would be
sufficient to repay the Secured Notes and/or the Series D Notes in full. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Liquidity and Capital Resources."
Possible Delisting of Common Stock on The Nasdaq National Market
Recently, the Company received notification from The Nasdaq National
Market ("NMS") that the Company did not meet the minimum net tangible assets and
"inside bid" price requirements for NMS listed companies. The Company has also
been notified that it does not meet the minimum market value of the "public
float" for NMS listed companies. The Company has requested a hearing regarding
the proposed delisting of the Company's Common Stock on the Nasdaq National
Market and intends to request an exception from the designated criteria to
permit continued inclusion of the Company's common stock on the NMS. No
assurance can be given that the Company's request for an exception will be
granted. The Company's common stock will continue to be traded on the NMS until
action by the Nasdaq Review Panel.
If the Company's Common Stock is no longer traded on the NMS Market, the
Company intends to apply for listing its Common Stock on The American Stock
Exchange or on a regional exchange, such as the Boston Stock Exchange. If the
Company's Common Stock is not approved for listing on The American Stock
Exchange or a regional exchange, trading in the Company's Common Stock would be
conducted in the over-the-counter market in the "pink sheets" or the electronic
bulletin board administered by the National Association of Securities Dealers,
Inc. In such an event, the liquidity and market price of the Company's Common
Stock may be adversely impacted. As a result, an investor may find it more
difficult to obtain accurate stock quotations.
Shares Eligible for Future Sale
At March 22, 1999, the Company had 6,330,426 shares of Common Stock
outstanding of which 1,563,687 shares were held by affiliates. In addition, at
March 22, 1999, the Company had 1,566,810 shares of Common Stock subject to
outstanding options granted under certain stock option plans (of which 501,422
shares were vested at March 22, 1999) and 225,500 shares issuable 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
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resources necessary to acquire and develop such leases. Many of the Company's
competitors have financial resources, staff and facilities substantially greater
than those of the Company. In addition, the producing, processing and marketing
of crude oil and natural gas is affected by a number of factors which are beyond
the control of the Company, the effect of which cannot be accurately predicted.
The principal 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.
Certain Business Risks
The Company intends to continue acquiring producing crude oil and
natural gas properties or companies that own such properties. Although the
Company performs a review of the acquired properties that it believes is
consistent with industry practices, such reviews are inherently incomplete. It
generally is not feasible to review in depth every individual property involved
in each acquisition. Ordinarily, the Company will focus its review efforts on
the higher-valued properties and will sample the remainder. However, even an
in-depth review of all properties and records may not necessarily reveal
existing or potential problems nor will it permit the Company to become
sufficiently familiar with the properties to assess fully their deficiencies and
capabilities. Inspections may not always be performed on every well, and
environmental problems, such as ground water contamination, are not necessarily
observable even when an inspection is undertaken. Furthermore, the Company must
rely on information, including financial, operating and geological information,
provided by the seller of the properties without being able to verify fully all
such information and without the benefit of knowing the history of operations of
all such properties.
In addition, a high degree of risk of loss of invested capital exists in
almost all exploration and development activities which the Company undertakes.
No assurance can be given that crude oil or natural gas will be discovered to
replace reserves currently being developed, produced and sold, or that if crude
oil or natural gas reserves are found, they will be of a sufficient quantity to
enable the Company to recover the substantial sums of money incurred in their
acquisition, discovery and development. Drilling activities are subject to
numerous risks, including the risk that no commercially productive crude oil or
natural gas reservoirs will be encountered. The cost of drilling, completing and
operating wells is often uncertain. The Company's operations may be curtailed,
delayed or 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.
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
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ultimate cost of compliance with such requirements. There is no assurance that
laws and regulations enacted in the future will not adversely affect the
Company's financial condition and results of operations.
Dependence on Key Personnel
The Company depends to a large extent on Robert L. G. Watson, its
Chairman of the Board, President and Chief Executive Officer, for its management
and business and financial contacts. The unavailability of Mr. Watson would have
a 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, 1999 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, 1998, the Company had, subject to the limitations
discussed below, $46.6 million of net operating loss carryforwards for U.S. tax
purposes, of which it is estimated a maximum of $43.8 million may be utilized
before it expires. These loss carryforwards will expire from 2002 through 2018
if not utilized. At December 31, 1998, the Company had approximately $11.9
million of net operating loss carryforwards for Canadian tax purposes of which
$200,000 will expire in 2002, $5.0 million will expire in 2003, $3.2 million
will expire in 2004 and $3.5 will expire in 2005. 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 $4.9 million will be limited to
approximately $235,000 per year.
During 1992, the Company acquired 100% of the common stock of an
unrelated corporation. The use of net operating loss carryforwards of $837,000
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 $8.9 million will be limited to approximately $1.0 million per year, subject
to the lower limitations described above. Of the $8.9 million 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 $6.1 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 $5.9 million and $32.8 million for deferred tax assets at
December 31, 1997 and 1998, 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. In 1993, the Congress deregulated natural gas prices for all "first
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sales" of natural gas. As a result, all sales of the Company's United States
produced crude oil, natural gas, condensate and NGLs may be sold at market
prices, unless otherwise committed by contract.
Crude oil and natural gas exported from Canada is subject to regulation
by the National Energy Board ("NEB") and the government of Canada. Exporters are
free to negotiate prices and other terms with purchasers, provided that export
contracts in excess of two years must continue to meet certain criteria
prescribed by the NEB and the government of Canada. Crude oil and natural gas
exports for a term of less than two years must be made pursuant to an NEB order,
or, in the case of exports for a longer duration, pursuant to an NEB license and
Governor in Council approval.
The provincial governments of Alberta, British Columbia and Saskatchewan
also regulates the volume of natural gas that may be removed from these
provinces for consumption elsewhere based on such factors as reserve
availability, transportation arrangements and marketing considerations.
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.
United States 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. 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 636 and numerous related orders pertaining to the individual pipelines.
The Company does not believe that Order 636 and the related restructuring
proceedings affect it any differently than other natural gas producers and
marketers with which it competes.
In recent years the FERC also has pursued a number of other important
policy initiatives which could significantly affect the marketing of natural gas
in the United States. Some of the more notable of these regulatory initiatives
include (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) various FERC's orders adopting rules proposed by the Gas Industry
Standards Board which were designed to further standardize pipeline tariffs and
business practices, (iv) a notice of proposed rulemaking that, among other
things, proposes (aa) to eliminate the cost-based price cap currently imposed on
natural gas transactions of less than one year in duration, (bb) to establish
mandatory "transparent" capacity auctions of short-term capacity on a daily
basis, and (cc) to permit interstate pipelines to negotiate terms and conditions
of service with individual customers, (v) a notice of inquiry which continues
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the FERC's review of its regulatory policies with respect to the pricing of
long-term pipeline transportation services by presenting a range of questions to
the industry dealing with current cost based pricing of new and existing
capacity and alternative rate mechanism options, including the desirability of
pricing interstate pipeline capacity utilizing market-based rates, incentive
rates, or indexed rates, and (vi) a notice of proposed rulemaking that proposes
generic procedures to expedite the FERC's handling of complaints against
interstate pipelines with the goals of encouraging and supporting consensual
resolution of complaints and organizing the complaint procedures so that all
complaints are handled in a timely and fair manner. Several of these initiatives
are intended to enhance competition in natural gas markets, although some, such
as "spin downs," may have the adverse effect of increasing the cost of doing
business on some in the industry as a result of the monopolization of those
facilities by their new, unregulated owners. As to all of these 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.
Since Order 636 FERC decisions involving onshore facilities have been
more liberal in their reliance upon traditional tests for determining what
facilities are "gathering" and therefore exempt from federal regulatory control.
In many instances, what was once classified as "transmission" may now be
classified as "gathering." The Company ships certain of its natural gas through
gathering facilities owned by others, including interstate pipelines, under
existing long term contractual arrangements. Although these FERC decisions have
created the potential for increasing the cost of shipping the Company's gas on
third party gathering facilities, the Company's shipping activities have not
been materially affected by these decisions.
Commencing in October 1993, the FERC issued a series of rules (Order
Nos. 561 and 561-A) establishing an indexing system under which oil pipelines
will be able to change their transportation rates, subject to prescribed ceiling
levels. The indexing system, which allows or may require pipelines to make rate
changes to track changes in the Producer Price Index for Finished Goods, minus
one percent, became effective January 1, 1995. In certain circumstances, these
rules permit oil pipelines to establish rates using traditional cost of service
or other methods of rate making. The Company does not believe that there rules
affect it any differently that other crude oil producers and marketers with
which it competes.
Additional proposals and proceedings that might affect the natural gas
industry in the United States are considered from time to time by Congress, the
FERC, state regulatory bodies and the courts. The Company cannot predict when or
if any such proposals might become effective or their effect if any, on the
Company's operations. The oil and gas industry historically has been heavily
regulated; thus there is no assurance that the less stringent regulatory
approach recently pursued by the FERC and Congress will continue indefinitely
into the future.
State and Other Regulation
All of the jurisdictions in which 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 and provincial regulation of gathering facilities generally
includes various safety, environmental, and in some circumstances,
non-discriminatory take requirements, but does not generally entail rate
regulation. 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, on August 19, 1997, the Texas
Railroad Commission enacted a Natural Gas Transportation Standards and Code of
Conduct to provide regulatory support for the State's more active review of
rates, services and practices associated with the gathering and transportation
of gas by an entity that provides such services to others for a fee, in order to
prohibit such entities from unduly discriminating in favor of their affiliates.
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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. Further, the MMS has been
engaged in a three-year process of promulgating new rules and procedures for
determining the value of oil produced from federal lands for purposes of
calculating royalties owed to the government. The oil and gas industry as a
whole has resisted the proposed rules under an assumption that royalty burdens
will substantially increase. The Company cannot predict what, if any, effect any
new rule will have on its operations.
Canadian Royalty Matters
In addition to Canadian federal regulation, each province has
legislation and regulations that govern land tenure, royalties, production
rates, environmental protection and other matters. The royalty regime is a
significant factor in the profitability of crude oil and natural gas production.
Royalties payable on production from lands other than Crown lands are determined
by negotiations between the mineral owner and the lessee. Crown royalties are
determined by governmental regulation and are generally calculated as a
percentage of the value of the gross production, and the rate of royalties
payable generally depends in part on prescribed preference prices, well
productivity, geographical location, field discovery date and the type and
quality of the petroleum product produced.
From time to time the governments of 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 horizontal extensions commenced at least five
years after the well was originally spudded may qualify for a royalty reduction.
A 24-month, 8,000 cubic meters exemption is available to production from a well
that has not produced for a 12-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
CDN $1 million). Crude oil produced from low productivity wells, enhanced
recovery schemes (such as injection wells) and experimental projects is also
subject to royalty reductions.
The Alberta government 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 meter and 35% for prices above CDN $210 per cubic
meter. The ARTC rate is currently applied to a maximum of CDN $2.0 million of
Alberta Crown royalties payable for each producer or associated group of
producers. Crown royalties on production from producing properties acquired from
corporations claiming maximum entitlement to ARTC will generally not be eligible
for ARTC. The rate is established quarterly based on average "par price", as
determined by the Alberta Department of Energy for the previous quarterly
period. On December 22, 1997, the Government of Alberta gave notice that it
intended to review the ARTC program with expected changes to take effect prior
to 2001.
The Government of Saskatchewan's fiscal regime for the oil and gas
industry provides an incentive to encourage the drilling on new vertical oil
wells through a revised royalty/tax structure for mew vertical oil wells and 15
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incremental production from new of expanded water flood projects.. This "third
tier" Crown royalty rate is price sensitive and varies between heavy and
non-heavy oil (from a minimum off 10% for heavy oil at a base price to a maximum
of 35% for non-heavy oil at a price above the base price). Previous time-based
royalty/tax holidays applicable to vertically drilled oil wells have been
replaced with volume-based royalty/tax reduction incentives in which a maximum
royalty of 5% will apply to various volumes depending on the depth and nature of
the well (up to 25,000 cubic meters of oil in the case of deep exploratory
wells). The maximum royalty applicable to the first 12,000 cubic meters of oil
has been increased from 5% to 10% for production from certain horizontal wells.
In addition, royalty/tax holidays for deep horizontal wells have been replaced
with a 25,000 cubic meters volume incentive (5% maximum royalty). Oil produced
from qualified reactivated oil wells are subject to a maximum new royalty rate
of 5% for the first 5 years following the re-activation in the case of wells
reactivated after 1993 and shut-in or suspended prior to January 1, 1993. With
respect to qualifying exploratory natural gas wells, the first 25 million cubic
meters of natural gas produced will be subject to an incentive maximum royalty
rate of 5%. On February 9, 1998, the Government of Saskatchewan announced
further royalty incentive programs to encourage oil and gas exploration.
Producers of oil and natural gas in British Columbia are also required
to pay annual rental payments in respect to Crown lease and royalties and
freehold production taxes in respect of oil and gas produced from Crown and
freehold lands respectively. The amount payable as a royalty in respect of oil
depends on the vintage of the oil (whether it was produced from a pool
discovered before or after October 31, 1975), the quantity of oil produced in a
month and the value of the oil. Oil produced from newly discovered pools may be
exempt from the payment of a royalty for the first 36 months of production. The
royalty payable on natural gas is determined by a sliding scale based on a
reference price which is the greater of the amount obtained by the producer and
at prescribed minimum price. Gas produced in association with oil has a minimum
royalty of 8% while the royalty in respect of other gas may not be less that
15%.
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 operations are subject to numerous federal, state,
provincial and local laws and regulations controlling the generation, use,
storage, and discharge of materials into the environment or otherwise relating
to the protection of the environment. These laws and regulations may require the
acquisition of a permit or other authorization before construction or drilling
commences; restrict the types, quantities, and concentrations of various
substances that can be released into the environment in connection with
drilling, production, and 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.
In the United States, 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 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
16
<PAGE>
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. The Company's operations are also impacted by
regulations governing the disposal of naturally occurring radioactive materials
("NORM"). The Company must comply with the Clean Air Act and comparable state
statutes which prohibit the emissions of air contaminants, although a majority
of the Company's activities are exempted under a standard exemption. Moreover,
owners, lessees and operators of oil and gas properties are also subject to
increasing civil liability brought by surface owners and adjoining property
owners. Such claims are predicated on the damage to or contamination of land
resources occasioned by drilling and production operations and the products
derived therefrom, and are usually causes of action based on negligence,
trespass, nuisance, strict liability and fraud.
United States federal regulations also require certain owners and
operators of facilities that store or otherwise handle 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. State laws mandate crude oil cleanup
programs with respect to contaminated soil.
The Company's Canadian operations are also subject to environmental
regulation pursuant to local, provincial and federal legislation which generally
require operations to be conducted in a safe and environmentally responsible
manner. Canadian environmental legislation provides for restrictions and
prohibitions relating to the discharge of air, soil and water pollutants and
other substances produced in association with certain crude oil and natural gas
industry operations, and environmental protection requirements, including
certain conditions of approval and laws relating to storage, handling,
transportation and disposal of materials or substances which may have an adverse
effect on the environment. Environmental legislation can affect the location of
wells and facilities and the extent to which exploration and development is
permitted. In addition, legislation requires that well and facilities sites be
abandoned and reclaimed to the satisfaction of the provincial authorities. A
breach of such legislation may result in the imposition of fines of issuance of
clean-up orders.
Certain federal environmental laws that may affect the Company include
the Canadian Environmental Assessment Act which ensures that the environmental
effects of projects receive careful consideration prior to licenses or permits
being issued, to insure that projects that are to be carried out in Canada or on
federal lands do not cause significant adverse environmental effects outside the
jurisdictions in which they are carried out, and to ensure that there is an
opportunity for public participation in the environmental assessment process;
the Canadian Environmental Protection Act ("CEPA") which is the most
comprehensive federal environmental statute in Canada, and which controls toxic
substances (broadly defined), includes standards relating to the discharge of
air, soil and water pollutants, provides for broad enforcement powers and
remedies and imposes significant penalties for violations; the National Energy
Board Act which can impose certain environmental protection conditions on
approvals issued under the Act; the Fisheries Act which prohibits the depositing
of a deleterious substance of any type in water frequented by fish or in any
place under any condition where such deleterious substance may enter any such
water and provides for significant penalties; the Navigable Waters protection
Act which requires any work which is built in, on, over, under, thorough or
across any navigable water to be approved by the Minister of Transportation, and
which attracts severe penalties and remedies for non-compliance, including
removal of the work.
In Alberta, environmental compliance has been governed by the Alberta
Environmental Protection and Enhancement Act ("AEPEA") since September 1, 1993.
In addition to consolidation a variety of environmental statutes, the AEPEA also
imposes certain new environmental responsibilities on oil and natural gas
operators in Alberta. The AEPEA sets out environmental standards and compliance
for releases, clean-up and reporting. The Act provides for a broad range of
liabilities, enforcement actions and penalties.
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<PAGE>
British Columbia's Environmental Assessment Act become effective June
30, 1995. This legislation rolls the previous processes for the review of major
energy projects into a single environmental assessment process which
contemplates public participation in the environmental review.
Saskatchewan's Environmental Management and Protection Act is the
primary environmental legislation for that province. This Act provides
significant enforcement and penalty provisions, and includes a compensation
scheme respecting losses or damage from spills. The Clean Air Act provides a
permitting scheme for certain industrial activities, broad enforcement
provisions and significant penalties for non-compliance. The Environmental
Assessment Act provides that certain development activities which can affect the
environment must undergo environmental assessment and approval from the
provincial government.
The Company is not currently involved in any administrative, judicial or
legal proceedings arising under domestic or foreign federal, state, or local
environmental protection laws and regulations, or under federal or state common
laws, 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 suspension or cessation of operations in the affected area.
The Company has a Corporate Environmental Policy and a detailed
Environmental Management System in place to ensure continued compliance with
environmental, health and safety laws and regulations. The Company believes that
is has obtained and is in compliance with all material environmental permits,
authorizations and approvals.
Title to Properties
As is customary in the crude oil and natural gas industry, the Company
makes only a cursory review of title to undeveloped crude oil and natural gas
leases at the time they are acquired by the Company. However, before drilling
commences, the Company requires a thorough title search to be conducted, and any
material defects in title are remedied prior to the time actual drilling of a
well begins. To the extent title opinions or other investigations reflect title
defects, the Company, rather than the seller of the undeveloped property, is
typically obligated to cure any title defect at its expense. If the Company were
unable to remedy or cure any title defect of a nature such that it would not be
prudent to commence drilling operations on the property, the Company could
suffer a loss of its entire investment in the property. The Company believes
that it has good title to its crude oil and natural gas properties, some of
which are subject to immaterial encumbrances, easements and restrictions. The
crude oil and natural gas properties owned by the Company are also typically
subject to royalty and other similar non-cost bearing interests customary in the
industry. The Company does not believe that any of these encumbrances or burdens
will materially affect the Company's ownership or use of its properties.
Employees
As of March 22, 1999, Abraxas and its subsidiaries had 86 full-time
employees, including six executive officers, six non-executive officers, six
petroleum engineers, one landmen, one geophysicist, four geologists, seven
managers, 28 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.
18
<PAGE>
Item 2. Properties.
Primary Operating Areas
Texas
The Company's U.S. operations are concentrated in South and West Texas
with over 99% of the PV-10 of the Company's U.S. crude oil and natural gas
properties located in those two regions. The Company operates 84% of its wells
in Texas. Operations in South Texas are concentrated along the Edwards trend in
Live Oak and Dewitt Counties and in the Frio/Vicksburg trend in San Patricio
County. The Company owns an average 71% working interest in 115 wells with
average daily production of 863 net Bbls of crude oil and NGLs and 10,285 net
Mcf of natural gas per day for the year ended December 31, 1998. The Company's
West Texas operations are concentrated along the deep Devonian/Ellenberger
formations and shallow Cherry Canyon sandstones in Ward County, the Spraberry
trend in Midland County and in the Sharon Ridge Clearfork Field in Scurry
County. The Company owns an average 72% working interest in 264 wells with
average daily production of 1,264 net Bbls of crude oil and NGLs and 6,926 net
Mcf of natural gas per day for the year ended December 31, 1998. During 1998, a
total of 11 new wells (9.6 net) were drilled by the Company in Texas with a 100%
success rate.
Western 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 were traded on The
Alberta Stock Exchange. In November 1997, Grey Wolf merged with Cascade, which
later changed its name to Grey Wolf Exploration Inc. Abraxas and Canadian
Abraxas own approximately 48% of the outstanding capital stock of Grey Wolf. The
shares of Grey Wolf are traded on the Alberta Stock Exchange and the Toronto
Stock Exchange under the symbol "GWX." Grey Wolf manages the operations of
Canadian Abraxas pursuant to a management agreement between Canadian Abraxas and
Grey Wolf. Under the management agreement, Canadian Abraxas reimburses Grey Wolf
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 Grey Wolf.
The Company owns producing properties in Western Canada, consisting
primarily of natural gas reserves, and interests ranging from 10% to 100% in
approximately 200 miles of natural gas gathering systems and 19 natural gas
processing plants. As of December 31, 1998, Canadian Abraxas and Grey Wolf had
estimated net proved reserves of 98,905 Mmcfe (88% natural gas) with a PV-10 of
$87.3 million, 95% if which was attributable to proved developed reserves. For
the year ended December 31, 1998, the Canadian properties produced an average of
approximately 999 net Bbls of crude oil and NGL's per day and 48,435 net Mcf of
natural gas per day from 100.8 net wells. The natural gas processing plants had
aggregate capacity of approximately 263 MMcf of natural gas per day (108.5 net
MMcf).
In January 1999, Canadian Abraxas acquired all of the outstanding common
shares of New Cache for an aggregate of $78.0 million in cash and the assumption
of the New Cache Debt which was repaid in March 1999 from the proceeds of the
sale of the Secured Notes. As of December 31, 1998, New Cache had estimated
total proved reserves of 77 Bcfe (75% natural gas) with a PV-10 of $55.6
million, all of which was attributable to proved developed reserves. For the
year ended December 31, 1998, New Cache produced an average of approximately
1,389 net Bbls of crude oil and NGL's per day and 25.3 net MMcf of natural gas
per day. New Cache owns interests in 285 gross wells (88.5 net wells) and
445,294 gross (256,524 net) acres as well as three natural gas processing
plants.
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<PAGE>
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, 1998:
Developed and Undeveloped Acreage
As of December 31, 1998
Developed Acreage (1) Undeveloped Acreage (2)
---------------------------- -----------------------------
Gross Acres (3) Net Acres (4)Gross Acres (3) Net Acres
(4)
------------- ------------ ------------- --------------
Canada 213,763 120,470 439,782 290,427
Texas 43,659 27,090 17,704 14,646
N. Dakota 1,544 985 -- --
Oklahoma 3,041 1,405 -- --
Colorado 160 36 -- --
Mississippi 40 2 -- --
New Mexico 160 30 -- --
Kansas 1,280 277 -- --
Wyoming 9,139 6,965 36,182 32,314
Alabama 40 -- -- --
------------- ------------ ------------- --------------
Total 272,826 157,260 493,668 337,387
- ---------------
(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, 1998:
Productive Wells (1)
As of December 31, 1998
State/Country Crude Oil Natural Gas
-------------------------- ----------------------------
Gross(2) Net(3) Gross(2) Net(3)
----------------- ------------ ------------ ------------ -------------
Canada 50.0 10.6 201.0 90.2
Texas 276.0 201.1 103.0 78.5
N. Dakota 2.0 1.4 - -
Oklahoma 5.0 1.8 5.0 2.0
Colorado 1.0 0.2 - -
Mississippi 1.0 0.1 - -
New Mexico 1.0 0.2 - -
Wyoming - - 13.0 2.0
Alabama 1.0 - - -
Kansas 3.0 0.7 1.0 0.2
============ ============ ============ =============
Total 340.0 216.1 323.0 172.9
============ ============ ============ =============
- ------------
(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.
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Substantially all of Abraxas' existing crude oil and natural gas
properties are pledged to secure Abraxas' indebtedness under the Secured Notes.
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, 1999, January 1, 1998 and January 1, 1997 and of Canadian Abraxas
as of January 1, 1997, by DeGolyer & MacNaughton, of Dallas, Texas. The reserves
of Canadian Abraxas and Grey Wolf as of January 1, 1999 and 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, 1999, January 1, 1998 and January 1, 1997:
Estimated Proved Reserves
----------------------------------------
Proved Proved Total
Developed Undeveloped Proved
----------- ------------ --------------
As of January 1, 1997(1)
Crude oil (MBbls) 7,871 1,930 9,801
NGLs (MBbls) 7,090 1,144 8,234
Natural gas (MMcf) 157,660 19,600 177,260
As of January 1, 1998(1)(2)(3)
Crude oil (MBbls) 7,075 1,873 8,948
NGLs (MBbls) 7,178 1,651 8,829
Natural gas (MMcf) 186,490 34,824 221,314
As of January 1, 1999(1)(2)(3)
Crude oil (MBbls) 3,985 1,628 5,613
NGLs (MBbls) 1,834 248 2,082
Natural gas (MMcf) 144,588 52,890 197,478
- ------------------
(1) Includes 120,000, 128,900 and 31,900 barrels of crude oil reserves owned
by Grey Wolf of which 57,600, 69,500 and 16,400 barrels are applicable
to the minority interests share of these reserves as of January 1, 1997,
1998 and 1999, respectively.
(2) Includes 131,300 and 443,500 barrels of natural gas liquids reserves
owned by Grey Wolf of which 70,889 and 227,600 barrels are applicable to
the minority interests share of these reserves as of January 1, 1998 and
1999, respectively.
(3) Includes 7,446 and 28,610 Mmcf of natural gas reserves owned by Grey
Wolf of which 4,020 and 14,700 Mmcf are applicable to the minority
interests share of these reserves as of January 1, 1998 and 1999,
respectively.
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
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<PAGE>
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
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, 1998:
1998 1997 1996
--------------- -------------- ---------------
Crude oil production (Bbls) 728,560 936,716 425,188
Natural gas production(Mcf) 24,929,866 21,050,045 6,350,069
Natural gas liquids
production (Bbls) 867,443 992,266 299,509
Mmcfe 34,506 32,624 10,698
Average sales price per
Bbl of crude oil ($) $13.65 $18.63 $20.85
Average sales price per
MCF of natural gas ($) $ 1.54 $ 1.79 $ 1.97
Average sales price per
Bbl of natural gas
liquids ($) $ 6.81 $10.75 $14.55
Average sales price per Mcfe($) $ 1.57 $ 2.02 $ 2.40
Average cost of production($)
per BOE produced (1) $ 2.93 $ 2.74 $ 3.28
(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.
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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, 1998:
1998 1997 1996
--------------------- ------------------ ----------------
Gross(1) Net(2) Gross Net Gross Net
--------- --------- -------- ------- -------- ------
Exploratory(3)
Productive(4)
Crude oil 1.0 1.0 - - 2.0 1.2
Natural gas 7.0 5.6 10.0 7.9 2.0 1.2
Dry holes(5) 9.0 7.3 2.0 1.8 4.0 1.4
--------- --------- --------- ------- -------- ------
Total 17.0 13.9 12.0 9.7 8.0 3.8
========= ========= ========= ======= ======== ======
Development(6)
Productive
Crude oil 3.0 2.4 25.0 22.3 20.0 15.8
Natural gas 30.0 23.9 20.0 14.9 10.0 3.7
Service(7) 1.0 1.0 - - 1.0 1.0
Dry holes 3.0 2.2 3.0 2.0 - -
--------- --------- --------- ------- -------- ------
Total 37.0 29.5 48.0 39.2 31.0 20.5
========= ========= ========= ======= ======== ======
(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 22, 1999, the Company had one well in process of drilling.
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<PAGE>
Office Facilities
The Company's executive and administrative offices are located at 500 N.
Loop 1604 East, Suite 100, San Antonio, Texas 78232. The Company owns a 16%
limited partnership interest in the Partnership which owns the office building.
The Company also has an office in Midland, Texas. These offices, consisting of
approximately 12,650 square feet in San Antonio and 1,090 square feet in
Midland, are leased until March 2006 from unaffiliated parties at an aggregate
rate of approximately $18,000 per month. Grey Wolf 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. New Cache leases 7,427 square feet of office space in Calgary,
Alberta pursuant to a lease which expires on July 1, 2001 at a rate of
approximately CDN $12,400 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 21 vehicles which are used in the field by employees.
Item 3. Legal Proceedings
General. 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 22, 1999, 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.
Hornburg Litigation. 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 and on May 22, 1998 final judgment in the amount of $1.3
million was entered. The Company has filed an appeal. Management believes 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 had not established a reserve for this matter at December 31, 1998.
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, 1998.
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 1999 annual
meeting of directors and until his successor is duly elected and qualified.
Robert L. G. Watson, age 48, has served as Chairman of the Board,
President, Chief Executive Officer and a director of Abraxas since 1977. Since
May 1996, Mr. Watson has also served as Chairman of the Board and a director of
Grey Wolf. In November 1996, Mr. Watson was elected Chairman of the Board,
President and as a director of Canadian Abraxas. In January 1999, Mr. Watson was
elected Chairman of the Board and director of New Cache. Prior to joining
Abraxas, Mr. Watson was employed in various petroleum engineering positions with
Tesoro Petroleum Corporation, a crude oil and natural gas exploration and
production company, from 1972 through 1977, and DeGolyer & McNaughton, an
independent petroleum engineering firm, from 1970 to 1972. Mr. Watson received a
Bachelor of Science degree in Mechanical Engineering from Southern Methodist
University in 1972 and a Master of Business Administration degree from the
University of Texas at San Antonio in 1974.
Chris E. Williford, age 48, was elected Vice President, Treasurer and
Chief Financial Officer of Abraxas in January 1993, and as Executive Vice
President and a director of Abraxas in May 1993. In November 1996, Mr. Williford
was elected Vice President and Assistant Secretary of Canadian Abraxas. In
January 1999, Mr. Williford was elected Assistant Secretary of New Cache. Prior
to joining Abraxas, Mr. Williford was Chief Financial Officer of American
Natural Energy Corporation, a crude oil and natural gas exploration and
production company, from July 1989 to December 1992 and President of Clark
Resources Corp., a crude oil and natural gas exploration and production company,
from January 1987 to May 1989. Mr. Williford received a Bachelor of Science
degree in Business Administration from Pittsburgh State University in 1973.
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<PAGE>
Robert W. Carington, Jr., age 37, was elected Executive Vice President
and a director of the Company in July 1998. Prior to joining the Company, Mr.
Carington was a Managing Director with Jefferies & Company, Inc. Prior to
joining Jefferies & Company, Inc. in January 1993, Mr. Carington was a Vice
President at Howard, Weil, Labouisse, Friedrichs, Inc. Prior to joining Howard,
Weil, Labouisse, Freidrichs, Inc., Mr. Carington was a petroleum engineer with
Unocal Corporation from 1983 to 1990. Mr. Carington received a degree of
Bachelor of Science in Mechanical Engineering from Rice University in 1983 and a
Masters of Business Administration from the University of Houston in 1990.
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 1996, 1997 and 1998.
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
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
1998
First Quarter............................$15.00 $7.00
Second Quarter............................11.25 8.25
Third Quarter............................. 9.50 5.31
Fourth Quarter............................ 7.56 4.00
Recently, the Company received notification from The NMS that the
Company did not meet the minimum net tangible assets and "inside bid" price
requirements for NMS listed companies. The Company has also been notified that
it does not meet the minimum market value of the "public float" for NMS listed
companies. The Company has requested a hearing regarding the proposed delisting
of the Company's Common Stock on the NMS and intends to request an exception
from the designated criteria to permit continued inclusion of the Company's
common stock on the NMS. No assurance can be given that the Company's request
for an exception will be granted. The Company's common stock will continue to be
traded on the Nasdaq NMS until action by the Nasdaq Review Panel..
If the Company's Common Stock is no longer traded on The Nasdaq National
Market, the Company intends to apply for listing its Common Stock on The
American Stock Exchange or on a regional exchange, such as the Boston Stock
Exchange. If the Company's Common Stock is not approved for listing on The
American Stock Exchange or a regional exchange, trading in the Company's Common
Stock would be conducted in the over-the-counter market in the "pink sheets" or
the electronic bulletin board administered by the National Association of
Securities Dealers, Inc. In such an event, the liquidity and market price of the
Company's Common Stock may be adversely impacted. As a result, an investor may
find it more difficult to obtain accurate stock quotations.
25
<PAGE>
Holders
As of March 22, 1999 Abraxas had 6,330,426 shares of common stock
outstanding and had approximately 1,650 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 Indentures prohibit 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".
26
<PAGE>
Item 6. Selected Financial Data
The following selected financial data are derived from the consolidated
financial statements of Abraxas. The data should be read in conjunction with the
Consolidated Financial Statements of the Company and Notes thereto, and other
financial information included herein. See "Financial Statements."
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------------
1998 1997 1996 1995 1994
-------- -------- -------- -------- --------
(In thousands except per share data)
<S> <C> <C> <C> <C> <C>
Total revenue $ 60,804 $ 70,931 $ 26,653 $13,817 $11,349
Income (loss) from continuing operations $(83,960) $ (6,485) $ 1,940 $(1,208) $ 113
Income (loss) per common share from
continuing operations $ (13.26) $ (1.11) $ .23 $ (.34) $ .02
Weighted average shares outstanding 6,331 6,025 6,794 4,635 4,310
Total assets $291,498 $338,528 $304,842 $85,067 $75,361
Long-term debt $299,698 $248,617 $215,032 $41,601 $41,296
Total shareholders' equity (deficit) $(63,522) $ 26,813 $ 35,656 $37,062 $28,502
</TABLE>
Item 7. Management's Discussion And Analysis Of Financial Condition And Results
Of Operations
The following is a discussion of the Company's consolidated financial
condition, results of operations, liquidity and capital resources. This
discussion should be read in conjunction with the Consolidated Financial
Statements of the Company and the Notes thereto. See "Financial Statements".
Results of Operations
The factors which most significantly affect the Company's results of
operations are (1) the sales prices of crude oil, natural gas liquids and
natural gas, (2) the level of total sales volumes of crude oil, natural gas
liquids and natural gas, (3) the level of and interest rates on borrowings and
(4) the level and success of exploration and development activity.
Selected Operating Data. The following table sets forth certain
operating data of the Company for the periods presented:
Years Ended December 31,
-----------------------------------------
(dollars in thousands, except
per unit data)
1998 1997 1996
------------- ------------ ------------
Operating revenue:
Crude oil sales $ 9,948 $ 17,453 $ 8,864
NGLs sales 5,905 10,668 4,359
Natural gas sales 38,410 37,705 12,526
Gas Processing revenue 3,159 3,568 600
Other 2,663 1,537 304
============= ============ ============
Total operating revenue $60,084 $ 70,931 $ 26,653
============= ============ ============
Operating income (loss) $ (56,500) $ 15,150 $ 8,826
Crude oil production (MBbls) 728.6 936.7 425.2
NGLs production (MBbls) 867.4 992.3 299.5
Natural gas production (MMcf) 24,929.9 21,050.0 6,350.0
Average crude oil sales price (per Bbl) $ 13.65 $ 18.63 $ 20.85
Average NGLs sales price (per Bbl) $ 6.81 $ 10.75 $ 14.55
Average natural gas sales price (per Mcf) $ 1.54 $ 1.79 $ 1.97
27
<PAGE>
Comparison of Year Ended December 31, 1998 to Year Ended December 31, 1997
Operating Revenue. During the year ended December 31, 1998, operating
revenue from crude oil, natural gas and natural gas liquids sales, and natural
gas processing revenues decreased by $12.0 million from $69.4 million in 1997 to
$57.4 million in 1998, of which $11.8 million was attributable to the Wyoming
Properties. This decrease was primarily attributable to a decline in commodity
prices. Production volumes increased from 32,624 MMcfe in 1997 to 34,506 MMcfe
for the year ended December 1998, of which 8,609 MMcfe were attributable to the
Wyoming Properties. Crude oil and natural gas liquids sales volumes decreased by
17.2% from 1,930 MBbls in 1997 to 1,596 MBbls during 1998, and natural gas sales
volumes increased by 18.4% from 21.1 Bcf in 1997 to 24.9 Bcf in 1998. The
increase in natural gas sales volumes was attributable to increased production
attributable to the Company's ongoing development program on existing and
acquired properties. Crude oil sales volumes decreased 22.2% to 729 MBbls during
1998 from 937 MBbls in 1997 due primarily to the Company's decreased emphasis on
crude oil development projects during 1998 because of the continuing decline in
crude oil prices. Natural gas liquids sales volumes decreased 12.6% to 867 MBbls
in 1998 from 992 MBbls in 1997. Approximately 66 MBbls of the decline in natural
gas liquids was attributable to the loss of production from the Company's
Wyoming Properties. In the ten and one-half months that the Company owned the
Wyoming Properties during 1998, they contributed 89 MBbls of crude oil, 454
MBbls of natural gas liquids and 5.4 Bcf of natural gas production. Average
sales prices in 1998 were $13.65 per Bbl of crude oil, $6.81 per Bbl of natural
gas liquids and $1.54 per Mcf of natural gas compared to $18.63 per Bbl of crude
oil, $10.75 per Bbl of natural gas liquids and $1.79 per Mcf of natural gas in
1997. The Company also had gas processing revenue of $3.1 million in 1998 as
compared to $3.6 million in 1997.
Lease Operating Expense. Lease operating expense ("LOE") and natural gas
processing costs increased by $2.0 million from $16.1 million for the year ended
December 31, 1997 to $18.1 million for the same period of 1998, of which $2.0
million was attributable to the Wyoming Properties. The increase was due
primarily to the greater number of wells owned by the Company for the year ended
December 31, 1998 compared to the year ended December 31, 1997. The Company's
LOE on a per Mcfe basis for 1998 was $0.49 per Mcfe as compared to $0.46 per
Mcfe in 1997. Natural gas processing cost remained constant at $1.2 million in
1998 as compared to $1.2 million in 1997.
G&A Expense. G&A expense increased from $4.2 million for the year ended
December 31, 1997 to $5.3 million for the year ended December 31, 1998, as a
result of the Company's hiring additional staff. The sale of the Wyoming
Properties will not have a material effect on G&A expense. The Company's G&A
expense on a per Mcfe basis was $0.16 per Mcfe in 1998 compared to $0.13 per
Mcfe for 1997.
DD&A Expense. Due to the increase in sales volumes of crude oil and
natural gas, depreciation, depletion and amortization ("DD&A") expense increased
by $600,000 from $30.6 million for the year ended December 31, 1997 to $31.2
million for the year ended December 31, 1998, of which $3.4 million was
attributable to the Wyoming Properties. The Company's DD&A expense on a per Mcfe
basis for 1998 was $0.90 per Mcfe as compared to $0.94 per Mcfe in 1997.
Interest Expense and Preferred Dividends. Interest expense and preferred
dividends increased by $6.2 million from $24.6 million to $30.8 million for the
year end December 31, 1998 compared to 1997. This increase was attributable to
inc